-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, SneFMGDjdR+elOREX6lbsZub6QPBfxGdpRjeXDM3GpvNNdRwc6f0rxiUAJEWuqI6 5fVqOFx7Glllm2cisVEbaQ== 0000950136-02-000636.txt : 20020415 0000950136-02-000636.hdr.sgml : 20020415 ACCESSION NUMBER: 0000950136-02-000636 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 20011231 FILED AS OF DATE: 20020308 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PUBLIC SERVICE ELECTRIC & GAS CO CENTRAL INDEX KEY: 0000081033 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 221212800 STATE OF INCORPORATION: NJ FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-00973 FILM NUMBER: 02569765 BUSINESS ADDRESS: STREET 1: 80 PARK PLZ STREET 2: PO BOX 570 CITY: NEWARK STATE: NJ ZIP: 07101-0570 BUSINESS PHONE: 9734307000 MAIL ADDRESS: STREET 1: 80 PARK PLZ STREET 2: PO BOX 570 CITY: NEWARK STATE: NJ ZIP: 07101-0570 10-K 1 file001.txt FORM 10-K UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2001 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to ---------------- ----------------
Commission Registrant, State of Incorporation, I.R.S. Employer File Number Address, and Telephone Number Identification No. - -------------------- ---------------------------------------------------------------- ------------------------ 001-00973 PUBLIC SERVICE ELECTRIC AND GAS COMPANY 22-1212800 (A New Jersey Corporation) 80 Park Plaza P.O. Box 570 Newark, New Jersey 07101-0570 973 430-7000 http://www.pseg.com Securities registered pursuant to Section 12(b) of the Act: Name of Each Exchange Title of Each Class Title of Each Class On Which Registered - -------------------------------------- --------------------------------------------- ------------------------------- Cumulative Preferred Stock First and Refunding Mortgage Bonds: $100 par value Series: Series Due 4.08% 9 1/8% BB 2005 4.18% 9 1/4% CC 2021 4.30% 8 7/8% DD 2003 5.05% 6 7/8% MM 2003 5.28% 6 1/2% PP 2004 6 1/8% RR 2002 New York Stock Exchange 7% SS 2024 7 3/8% TT 2014 6 3/4% UU 2006 6 3/4% VV 2016 6 1/4% WW 2007 6 3/8% YY 2023 8% 2037 5% 2037
Monthly Income Preferred Securities (Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debenture, $25 par value at 8.00%, issued by Public Service Electric and Gas Capital, L.P. (Registrant) and registered on the New York Stock Exchange. Quarterly Income Preferred Securities (Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures), $25 par value at 8.125%, issued by PSE&G Capital Trust II (Registrant) and registered on the New York Stock Exchange. Securities registered pursuant to Section 12(g) of the Act:
Registrant Title of Class ----------- -------------- Public Service Electric and Gas Company 6.92% Cumulative Preferred Stock $100 par value Medium-Term Notes, Series A
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports) and (2) have been subject to such filing requirements for the past 90 days. Yes [ X ] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] As of January 31, 2002, Public Service Electric and Gas Company had issued and outstanding 132,450,344 shares of Common Stock, without nominal or par value, all of which were privately held, beneficially and of record by Public Service Enterprise Group Incorporated. TABLE OF CONTENTS
Page PART I Item 1. Business............................................................................................. 1 General.............................................................................................. 1 Risk Factors......................................................................................... 2 Competitive Environment.............................................................................. 4 Regulatory Issues.................................................................................... 5 Customers............................................................................................ 9 Employee Relations................................................................................... 9 Segment Information.................................................................................. 9 Environmental Matters................................................................................ 9 Item 2. Properties........................................................................................... 10 Item 3. Legal Proceedings.................................................................................... 12 Item 4. Submission of Matters to a Vote of Security Holders.................................................. 14 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters................................ 14 Item 6. Selected Financial Data.............................................................................. 14 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................ 15 Corporate Structure.................................................................................. 15 Overview of 2001 and Future Outlook.................................................................. 15 Results of Operations................................................................................ 17 Liquidity and Capital Resources...................................................................... 22 Capital Requirements................................................................................. 24 Qualitative and Quantitative Disclosures About Market Risk........................................... 25 Accounting Issues.................................................................................... 26 Forward Looking Statements........................................................................... 27 Item 7A. Qualitative and Quantitative Disclosures About Market Risk........................................... 28 Item 8. Financial Statements and Supplementary Data.......................................................... 28 Consolidated Financial Statements.................................................................... 29 Notes to Consolidated Financial Statements........................................................... 34 Financial Statement Responsibility................................................................... 51 Independent Auditors' Report......................................................................... 52 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure................. 53 PART III Item 10. Directors and Executive Officers..................................................................... 53 Item 11. Executive Compensation............................................................................... 54 Item 12. Security Ownership of Certain Beneficial Owners and Management....................................... 59 Item 13. Certain Relationships and Related Transactions....................................................... 59 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K...................................... 60 Schedule II--Valuation and Qualifying Accounts....................................................... 61 Signatures........................................................................................... 62 Exhibit Index........................................................................................ 63
i PUBLIC SERVICE ELECTRIC AND GAS COMPANY PART I ------ ITEM 1. BUSINESS GENERAL Unless the context otherwise indicates, all references to "PSE&G," "we," "us" or "our" herein means Public Service Electric & Gas Company, a New Jersey corporation with its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. We are a wholly-owned subsidiary of Public Service Enterprise Group Incorporated (PSEG) and an operating public utility company engaged principally in the transmission and distribution of electric energy and gas service in New Jersey. In August 2000, pursuant to the terms of the Final Decision and Order (Final Order) issued by the New Jersey Board of Public Utilities (BPU) under the New Jersey Energy Master Plan and the New Jersey Electric Discount and Energy Competition Act (Energy Competition Act), we transferred our electric generation-related assets and liabilities and our wholesale power contracts to an affiliate, PSEG Power LLC (Power). Our wholly-owned subsidiary, PSE&G Transition Funding LLC (Transition Funding) was formed to issue securitization bonds in connection with the partial recovery of our BPU approved stranded costs. We provide electric and gas service in areas of New Jersey in which approximately 5.5 million people, about 70% of the State's population, reside. Our electric and gas service area is a corridor of approximately 2,600 square miles running diagonally across New Jersey from Bergen County in the northeast to an area below the City of Camden in the southwest. The greater portion of this area is served with both electricity and gas, but some parts are served with electricity only and other parts with gas only. This heavily populated, commercialized and industrialized territory encompasses most of New Jersey's largest municipalities, including its six largest cities--Newark, Jersey City, Paterson, Elizabeth, Trenton and Camden--in addition to approximately 300 suburban and rural communities. This service territory contains a diversified mix of commerce and industry, including major facilities of many corporations of national prominence. Our load requirements are almost evenly split among residential, commercial and industrial customers. We believe that we have all the franchises (including consents) necessary for our electric and gas distribution operations in the territory we serve. Such franchise rights are not exclusive. We distribute electric energy and gas to end-use customers within our designated service territory. All electric and gas customers in New Jersey have had the ability to choose an electric energy and/or gas supplier. We supply customers that are not served by a third party supplier (TPS). Pursuant to BPU requirements, we also serve as the supplier of last resort for electric and gas customers within our service territory. Our revenues are based upon tariffs approved by the BPU and the Federal Energy Regulatory Commission (FERC) for these services (see Regulatory Issues). The demand for electric energy and gas by our customers is affected by customer conservation, economic conditions, weather and other factors not within our control. Electric Energy Supply We have contracted with Power to provide the capacity and electricity necessary to meet the needs of customers who do not choose a TPS. Power will provide this basic generation service (BGS) obligation through July 31, 2002. For each annual period thereafter, we are required to determine the BGS supplier by competitive bid in accordance with BPU requirements. On June 29, 2001 we and the other three BPU regulated New Jersey electric utility companies submitted a joint filing to the BPU setting forth an auction proposal for the provision of BGS supply beginning August 1, 2002. On December 10, 2001 the BPU approved an Internet auction to determine who will supply BGS to utilities, which commenced on February 4, 2002. This competitive auction covered the BGS supply requirement for the period August 1, 2002 to July 31, 2003. As conditions of qualification, applicants agreed that if they became auction winners, they would execute the BGS Master Service Agreement within two days of BPU Certification of the results and they would demonstrate compliance with the credit worthiness requirements. On February 15, 2002 the BPU approved the auction results under which we secured contracts for our expected peak load of 9,600 megawatts (MW). 1 PUBLIC SERVICE ELECTRIC AND GAS COMPANY In addition, we purchase energy under various non-utility generation (NUG) contracts and sell such energy to Power with the costs and proceeds applied to the non-utility generation market transition clause (NTC) component of our rates (see Note 4. Regulatory Assets and Liabilities of Notes to Consolidated Financial Statements (Notes)). Rates for electricity sold in the wholesale energy market are not subject to BPU ratemaking and are competitive in nature. Effective August 1, 2002, we will sell the generation from the NUGs to the wholesale market. Gas Supply We supplement natural gas with purchased refinery/landfill gas and liquefied petroleum gas produced from propane. The adequacy of supply of all types of gas is affected by the nationwide availability of all sources of fuel for energy production. As of December 31, 2001, our daily gas capacity was as follows:
Type of Gas Therms Per Day ----------------------------------------------------------------- --------------------- Natural gas.................................................... 24,379,300 Liquefied petroleum gas........................................ 2,200,000 Refinery/landfill gas.......................................... 123,000 -------------------- Total................................................. 26,702,300 =====================
About 40% of our daily gas requirements are provided through firm transportation, which is available every day of the year. The remainder comes from field storage, liquefied natural gas, seasonal purchases, contract peaking supply, propane and refinery/landfill gas. Our total gas sold to and transported to our various customer classes in 2001 was approximately 3.7 billion therms. Included in this amount were 1 billion therms of gas delivered to customers under our transportation tariffs and individual cogeneration contracts. During 2001, we purchased approximately 3.3 billion therms of gas for our gas operations directly from natural gas producers and marketers. These supplies were transported to New Jersey by four interstate pipeline suppliers. The majority of our gas transportation and supply contracts expire at various times over the next 10 years. Since the quantities of gas available to us under our supply contracts are more than adequate in warm months, we nominate part of such quantities for storage, to be withdrawn during the winter season when demand peaks. Underground storage capacity currently is approximately 800 million therms. For a discussion of the transfer of our gas supply business to Power, see Regulatory Issues-Gas Contract Transfer. The demand for gas by our customers is affected by customer conservation, economic conditions, weather, the price relationship between gas and alternative fuels and other factors not within our control. Rates for gas sold in interstate commerce are not subject to cost of service ratemaking but are subject to competitive pricing. We were able to meet all of the demands of our firm customers during the 2000-2001 winter season and expect to continue to meet such energy-related demands of our firm customers during the 2001-2002 and 2002-2003 winter seasons. However, the sufficiency of supply could be affected by several factors not within our control, including curtailments of natural gas by our suppliers, the severity of the winter and the availability of feedstocks for the production of supplements to our natural gas supply. We presently do not anticipate any difficulty in obtaining adequate supplies of natural gas over the next several years. RISK FACTORS The following factors should be considered when reviewing our business, and are relied upon by us in issuing any forward-looking statements. Such factors could affect actual results and cause such results to differ materially from those expressed in any forward-looking statements made by, or on behalf of, us. 2 PUBLIC SERVICE ELECTRIC AND GAS COMPANY Failure to Obtain Adequate and Timely Rate Relief May Have an Adverse Impact As a public utility, our rates are regulated by the BPU and the FERC. These rates are designed to recover our operating expenses and allow us to earn a fair return on our rate base, which primarily consists of our property, plant and equipment less various adjustments. These rates include our electric and gas tariff rates subject to regulation by the BPU as well as our transmission rates contained in the Pennsylvania-New Jersey-Maryland Power Pool (PJM) Open Access Transmission Tariff subject to regulation by the FERC. Our base rates are set by the BPU for electric distribution and gas distribution and are effective until the time a new rate case is brought to the BPU. These base rate cases generally take place every few years. Certain limited categories of costs, such as societal benefits and gas residential commodity costs, are recovered through adjustment charges that are periodically trued-up to actual costs and reset. If these costs exceed the amount included in our adjustment charges, there will be a negative impact on our cash flows. Our rates for electric transmission are subject to change based on policies and procedures established by the FERC. If our operating expenses (other than costs recovered through adjustment charges) exceed the amount included in our base rates or in our FERC jurisdictional rates, there will be a negative impact on earnings and operating cash flows. Deregulation and the Unbundling of Energy Supplies and Services and the Establishment of a Competitive Energy Marketplace. As a result of deregulation and the unbundling of energy supplies and services, the gas and electric retail markets are now open to competition from other suppliers. Increased competition from these companies could reduce the quantity of our retail sales and have a negative impact on our cash flows. Inability to Raise Capital on Favorable Terms to Refinance Existing Indebtedness or to Fund Capital Commitments Our capital is provided by equity contributions from PSEG, internally-generated cash flows and borrowings from third parties. In order to meet our capital requirements, we may require access to debt capital from outside sources on acceptable terms. We can give no assurances that our current and future capital structure, operating performance or financial condition will permit us to access the capital markets or to obtain other financing at the times, in the amounts and on the terms necessary or advisable for us to successfully carry out our business strategy or to service our indebtedness. Changes in the Economic and Electricity and Gas Consumption Growth Rates Our regulated rates are designed to recover our operating expenses and earn a fair return on our rate base. These rates are based on forecasted consumption over the period covered by the base rate cases. A decrease in actual consumption could have a negative impact on our earnings and cash flows. Economic conditions generally affect the amount of energy consumption. Environmental Regulation May Limit Our Operations We are required to comply with numerous statutes, regulations and ordinances relating to the safety and health of employees and the public, the protection of the environment and land use. These statutes, regulations and ordinances are constantly changing. While we believe that we have obtained all material environmental-related approvals required as of the date hereof to own and operate our facilities or that such approvals have been applied for and will be issued in a timely manner, we may incur significant additional costs because of compliance with these requirements. Failure to comply with environmental statutes, regulations and ordinances could have a material effect on us, including potential civil or criminal liability and the imposition of clean-up liens or fines and expenditures of funds to bring our facilities into compliance. We can give no assurance that we will be able to: 3 PUBLIC SERVICE ELECTRIC AND GAS COMPANY o obtain all required environmental approvals that we do not yet have or that may be required in the future; o obtain any necessary modifications to existing environmental approvals; o maintain compliance with all applicable environmental laws, regulations and approvals; o recover any resulting costs through future rates. Delay in obtaining or failure to obtain and maintain in full force and effect any such environmental approvals, or delay or failure to satisfy any applicable environmental regulatory requirements, could prevent construction of new facilities or operation of our existing facilities and could result in significant additional cost to us. Insurance Coverage May Not Be Sufficient We have insurance for our facilities, including all-risk property damage insurance and commercial general public liability insurance, in amounts and with deductibles that we consider appropriate. We can give no assurance that such insurance coverage will be available in the future on commercially reasonable terms nor that the insurance proceeds received for any loss of or any damage to any of our facilities will be sufficient to permit us to continue to make payments on our debt. Additionally, certain properties that we own may not be insured in the event of terrorist activity. Recession, Acts of War or Terrorism Could Have An Adverse Impact Consequences of the September 11, 2001 terrorist attacks on the United States are difficult to predict. The consequences of a prolonged recession and market conditions may include the continued uncertainty of energy prices and the capital and commodity markets. We cannot predict the impact of any continued economic slowdown or fluctuating energy prices; however, such impact could have a material adverse effect on our financial condition, results of operations and net cash flows. Like other operators of major industrial facilities, our fuel storage facilities and transmission and distribution facilities may be targets of terrorist activities that could result in disruption of our ability to distribute some portion of our energy products. Any such disruption could result in a significant decrease in revenues and/or significant additional costs to repair, which could have a material impact on our financial condition, results of operations and net cash flows. COMPETITIVE ENVIRONMENT The regulatory structure which has historically governed the electric and gas utility industries in the United States continues to be in transition. Deregulation is essentially complete in New Jersey and is complete or underway in certain other states in the Northeast and across the United States. States have acted independently to deregulate the electric and gas utilities. Recent experience in California, with energy shortages, high costs and financial difficulties of utilities and the Enron bankruptcy have caused some States to re-evaluate and, in some cases, stop the move toward deregulation. The deregulation and restructuring of the nation's energy markets, the unbundling of energy and related services, the diverse strategies within the industry related to holding, buying or selling generation capacity and the anticipated resulting industry consolidation have had a profound effect on us, providing us with new opportunities and exposing us to new risks (see Risk Factors and Overview of 2001 and Future Outlook of Management's Discussion & Analysis of Financial Condition and Results of Operations (MD&A)). As a regulated monopoly, our electric and gas transmission and distribution business has minimal risks from competition. Also, there has been minimal financial impact on PSE&G's transmission and distribution business due to customers choosing alternate electric or gas suppliers. 4 PUBLIC SERVICE ELECTRIC AND GAS COMPANY REGULATORY ISSUES State Regulation As a New Jersey public utility, we are subject to comprehensive regulation by the BPU including, among other matters, regulation of intrastate rates and service and the issuance and sale of securities. As a participant in the ownership of certain transmission facilities in Pennsylvania, we are subject to regulation by the Pennsylvania Public Utility Commission (PPUC) in limited respects in regard to such facilities. We are also subject to the rules and regulations of the New Jersey Department of Environmental Protection (NJDEP). New Jersey Energy Master Plan Proceedings and Related Orders Following the enactment of the Energy Competition Act, the BPU rendered its Final Order relating to our rate unbundling, stranded costs and restructuring proceedings providing, among other things, for the transfer to an affiliate of all of our electric generation facilities, plant and equipment for $2.443 billion and all other related property, including materials, supplies and fuel at the net book value thereof, together with associated rights and liabilities. Pursuant to the Final Order, we transferred our electric generating facilities and wholesale power contracts to Power and its subsidiaries on August 21, 2000 in exchange for a promissory note from Power in an amount equal to the purchase price of $2.786 billion. Power paid the promissory note on January 31, 2001 at which time the transferred assets were released from the lien of our First and Refunding Mortgage. The Energy Competition Act and the related BPU proceedings, including the Final Order, referred to as the Energy Master Plan Proceedings, opened the New Jersey energy markets to competition by allowing all New Jersey retail electric and gas customers to select their suppliers. For further discussion of the Energy Master Plan Proceedings, see Note 3. Regulatory Issues and Accounting Impacts of Deregulation of Notes. In accordance with the Final Order, we reduced customer rates initially by 5%, an additional 2% after the securitization transaction in February of 2001 and another 2% in August 2001. We are scheduled to reduce rates another 4.9% in August 2002, for a total 13.9% rate reduction since August 1999. These rate reductions reduce the market transition charge (MTC) revenue that we remit to Power as part of the BGS contract. BGS Auction The BPU approved an auction to identify energy suppliers for our BGS obligation beginning on August 1, 2002. On February 15, 2002 the BPU approved the BGS auction results and we secured contracts from a number of suppliers for our expected peak load of 9,600 MW. We will pay $.0511 per kWh to obtain electricity for customers for the period August 1, 2002 to July 31, 2003. Customers will continue to pay below-market regulated rates (BGS shopping credit) for this one-year period. Under our current rate structure, the difference will be deferred and recovered with interest in the future. We will sell the power we receive from NUG contracts into the wholesale energy market, which should offset this underrecovery. We estimate that the underrecovery relating to the BGS for the period ending July 31, 2003 will amount to approximately $250 million with a net amount of $125 million after factoring in sales of power relating to NUG contracts. If a supplier defaults on its obligation to provide energy to us or if our peak load exceeds our contracted supply, the energy needed for us to meet our requirements will be purchased at market prices in accordance with the procedures approved by the BPU. To the extent that the market prices exceed the auction contract price, the difference will be deferred and collected from our customers as provided in the BPU Order approving the auction process. 5 PUBLIC SERVICE ELECTRIC AND GAS COMPANY Electric Base Rate Case In accordance with the Final Order, we expect to file an electric base rate case during 2002 that would be effective on August 1, 2003. This case may impact our earnings and cash flows; however, we cannot predict the actual effects at this time. Affiliate Standards In February 2000, the BPU approved affiliate standards and fair competition standards which apply to transactions between a public utility and those of its affiliates that provide competitive services to retail customers in New Jersey. On March 15, 2000, the BPU issued a written order (Affiliate Standards) related to these matters. We filed a compliance plan on June 15, 2000 to describe the internal policy and procedures necessary to ensure compliance with such Affiliate Standards. The BPU has conducted an audit of New Jersey utilities' competitive activities and compliance with such Affiliate Standards and is expected to issue an order on the audit in 2002. The adoption of Affiliate Standards did not have a material adverse effect on our financial condition, results of operations or net cash flows. Gas Unbundling The Energy Competition Act also required that all customers have the ability to choose a competitive gas supplier. During 2000, the BPU issued a written order providing for the unbundling of firm rate schedules into commodity and transportation components and for changes in existing rate schedules. The new rates were implemented for all service provided on and after August 1, 2000. The main features of the gas unbundling are: the development of a Societal Benefits Clause (SBC) to recover specific costs including, social programs, Demand Side Management costs (DSM), a Remediation Adjustment Clause (RAC) and consumer education; the development of a Realignment Adjustment Charge to recover lost revenues incurred by us (subject to certain criteria) as a result of customers switching from commodity service to transportation service; the reallocation of approximately $40 million from transportation rates to commodity and balancing rates; an incentive of approximately 0.9 cents per therm for all customers who leave us to shop with a TPS and an additional incentive of 1.4 cents per therm for residential customers who leave us to shop with a TPS. Gas Contract Transfer On August 11, 2000, we filed a gas merchant restructuring plan with the BPU. On January 9, 2002, the BPU approved an amended stipulation, which permitted the transfer of our gas supply business, including our interstate capacity, storage and gas supply contracts to a subsidiary of Power, which will, under a requirements contract, provide the gas supply to us to serve our Basic Gas Supply Service (BGSS) customers. The gas contract transfer is expected to reduce volatility in our cash flows. Gas residential commodity costs are currently recovered through adjustment charges that are periodically trued-up to actual costs and reset. After the transfer, we will pay Power the amount we charge our gas distribution customers for the commodity. Industrial and commercial BGSS customers will be priced under our Market Priced Gas Service (MPGS). Residential BGSS customers will remain under current pricing until April 1, 2004 after which, subject to further BPU approval, those residential gas customers would also move to MPGS service. Gas Base Rate Case and Commodity Charges The BPU has granted us authority to change the Monthly Pricing Mechanism (MPM) in our Levelized Gas Adjustment Clause (LGAC) to cover currently estimated gas price increases on a per month basis, exercisable in any month without an annual limit. In May 2001, we filed a petition with the BPU for authority to revise our gas property depreciation rates (Depreciation Case). In this filing, we requested authority to implement our proposed depreciation rates 6 PUBLIC SERVICE ELECTRIC AND GAS COMPANY simultaneously for book purposes and ratemaking purposes when the BPU implements new tariffs designed to recover the additional annual revenues resulting from the gas base rate case discussed below. Also in May 2001, we filed a petition with the BPU requesting an increase in gas base rates of $171 million for gas delivery service (Gas Base Rate Case). The requested increase was for an overall gas revenue increase of 7.06% to reflect current costs. We filed the Gas Base Rate Case because the gas base rates, in effect since November 1991, did not reasonably reflect capital investments and other costs required to maintain the gas utility infrastructure. The BPU consolidated the Depreciation Case and the Gas Base Rate Case. In November 2001, we filed and served our 2001 LGAC filing, requesting approximately a 10% reduction. We requested that such filing be retained by the BPU and implemented simultaneously with the order in the Gas Base Rate Case. Also in November 2001, we made a compliance filing with the BPU to implement an approximate 3% increase through the Gas Cost Underrecovery Adjustment (GCUA) surcharge effective December 1, 2001. This surcharge is designed to recover our October 2001 gas underrecovery balance of $130 million. In January 2002, the BPU issued an order approving the increase. In January 2002, the BPU issued an order approving a Settlement under which we will receive an additional $90 million of gas base rate revenues, approximately $8 million of which results from gas depreciation rate changes. This occured simultaneously with the implementation of our compliance filing to implement our previously approved GCUA surcharge to recover our October 31, 2001 gas cost underrecovery balance of approximately $130 million over a three-year period with interest and the reduction of our 2001-2003 Commodity Charges (formerly LGAC) by approximately $140 million. All three rate changes became effective on January 9, 2002. The $8 million gas depreciation rate changes are due primarily to the shortening of the useful lives for general plant and equipment. This adjustment will have no impact on earnings, as it will be offset by increased operating cash flows in a normal business environment. Assuming current cost levels and a normal business environment, the $82 million balance of our gas base rate increase will have a positive impact on earnings and operating cash flows. The settlement set our gas rate base at approximately $1.6 billion, our rate of return on this rate base at 8.27% and our cost of capital or total return on equity of our gas operations at 10%. As a result of the settlement, we agreed not to request another gas base rate increase that would take effect prior to September 1, 2004. The $130 million rate increase relating to the GCUA will have no impact on earnings and will increase operating cash flows in a normal business environment. The reduction in our 2001-2003 commodity charges relates to our residential customers and will have no impact on earnings and will decrease operating cash flows assuming current cost levels and a normal business environment. Focused Audit For information regarding the 1992 BPU proceeding concerning the relationship of us to PSEG's non-utility businesses (Focused Audit), see Liquidity and Capital Resources of MD&A. Federal Regulation Our operations are subject to regulation by the FERC with respect to certain matters, including interstate sales and exchanges of electric transmission, capacity and energy. FERC RTO Orders and PJM Interconnection LLC (PJM) In December 1999, FERC promulgated a Final Rule (Order 2000) in the Regional Transmission Organization (RTO) rulemaking proceeding. In October 2000, PJM and nine PJM transmission owners, including us, made a filing with FERC stating that PJM is an RTO that meets or exceeds the requirements of Order 2000. Included in this filing was a PJM rate proposal designed to provide for deferral recovery of reasonable, risk-adjusted returns on new 7 PUBLIC SERVICE ELECTRIC AND GAS COMPANY transmission investments in the PJM region, an accelerated recovery period for such new investments, and a rate moratorium of current charges through December 31, 2004. In July 2001, FERC issued a series of orders that, amongst other things, rejected the rate design proposal, established generation interconnection proceedings and called for the creation of four large regional transmission organizations (RTOs) to facilitate competitive regional markets in the U.S. FERC rejected several smaller RTO proposals and directed transmission owners and independent system operators (ISOs) to combine into much larger RTOs, dramatically altering their proposed geographic size and configuration. In August 2001, the PJM transmission owners requested a rehearing of the PJM RTO Order. The matter is still pending. In the Northeast region, FERC conditionally approved the PJM RTO proposal (subject to several modifications and compliance filings) and rejected the New York ISO and ISO-New England RTO proposals. FERC directed that the three existing ISOs for PJM, New York and New England, as well as the systems involved in PJM West, form a single Northeast RTO, based on the "PJM platform" and "best practices" of all three ISO's. FERC directed that the parties in the region engage in mediation (with FERC oversight) to prepare a proposal and timetable for the merger of the ISOs into a single RTO. At the end of the 45-day mediation period, the Administrative Law Judge assigned to the matter submitted a report to the Commission with an attached business plan for implementation of the single northeast RTO possibly as soon as the fourth quarter of 2003. In January 2002, PJM and the Midwest ISO announced that they had entered into negotiations to create a virtual uniform seamless market encompassing their two RTOs, shortly after the FERC approved the Midwest ISO as an RTO. In addition, ISO New England and the New York ISO agreed to jointly develop a common electricity market and evaluate a New England - New York RTO. FERC has started a series of conferences to discuss the technical issues related to its consideration of a standard market design - products and protocols - for wholesale electric power markets. The goal of these conferences is to gain a mutual understanding of similarities and differences between various market designs and to allow participants to provide further detail on market operations. We have been supportive of the incorporation of both capacity and spot energy markets as part of any standardized market design. The information from these conferences will be used to issue a formal Notice of Proposed Rulemaking (NOPR) on a standard market design later this year. FERC issued an advance notice of proposed rulemaking seeking comments to help form the basis for a proposed rule to standardize power-plant interconnection requirements to ease market entry for new generation. FERC also will, as part of the rulemaking, reconsider its policy addressing how transmission owners treat the cost of system upgrades necessary to accommodate new generation, potentially resulting in a new methodology. The ultimate outcome of this rulemaking and its impact upon us cannot be predicted. The impact of these developments on us is uncertain because specific rules will not be known for some time and are subject to FERC approval, which cannot be assured. Other Regulatory Issues Tax Sharing Agreement The issue of PSEG sharing the benefits of consolidated tax savings with us or our customers was addressed by the BPU in 1995 in a letter which informed us that the issue of consolidated tax savings can be discussed in the context of a future base rate case or plan for an alternative form of regulation. PSEG believes that our taxes should be treated on a stand-alone basis for ratemaking purposes, based on the separate nature of the utility and non-utility 8 PUBLIC SERVICE ELECTRIC AND GAS COMPANY businesses. Neither PSEG nor we are able to predict what action, if any, the BPU may take concerning consolidated tax savings in future proceedings. CUSTOMERS As of December 31, 2001, we provided service to approximately 2.0 million electric customers and approximately 1.6 million gas customers. Our service territory contains a diversified mix of commerce and industry. Our load requirements are almost evenly split among residential, commercial and industrial customers. EMPLOYEE RELATIONS As of December 31, 2001, we had 6,554 employees, 5,033 of which are union members. We have a three-year collective bargaining agreement in place with three of our union groups, covering 3,636 employees, which expires on April 30, 2005. We also have a collective bargaining agreement with the Utility Co-Workers Association, covering 1,397 employees, that expires on April 30, 2002 and plan to negotiate a new agreement, which cannot be assured. We believe that we maintain satisfactory relationships with our employees. For information concerning employee pension plans and other postretirement benefits, see Note 10. Pension, Other Postretirement Benefit and Savings Plans of Notes. SEGMENT INFORMATION Financial information with respect to our business segments is set forth in Note 11. Financial Information by Business Segments of Notes. ENVIRONMENTAL MATTERS Federal, regional, state and local authorities regulate the environmental impacts of our operations. Areas of regulation include air quality, water quality, site remediation, land use, waste disposal, aesthetics and other matters. Compliance with environmental requirements has caused us to modify the day-to-day operation of our facilities, to participate in the cleanup of various properties that have been contaminated and to modify, supplement and replace existing equipment and facilities. During 2001, we expended approximately $4 million for capital related expenditures to improve the environment and comply with laws and regulations and estimate that we will expend approximately $9 million, $5 million and $2 million in the years 2002 through 2004, respectively, for such purposes. Control of Hazardous Substances Manufactured Gas Plant Remediation Program For information regarding our Manufactured Gas Plant Remediation Program, see Note 8. Commitments and Contingent Liabilities of Notes. Hazardous Substances Certain Federal and state laws authorize the Environmental Protection Agency (EPA) and the NJDEP, among other agencies, to issue orders and bring enforcement actions to compel responsible parties to investigate and take remedial actions at any site that is determined to present an actual or potential threat to human health or the environment because of an actual or threatened release of one or more hazardous substances. Because of the nature of 9 PUBLIC SERVICE ELECTRIC AND GAS COMPANY our businesses, including the distribution of gas and, formerly, the manufacture of gas and production of electricity, various by-products and substances are or were produced or handled which contain constituents classified by Federal and State authorities as hazardous. For discussions of these hazardous substance issues and a discussion of potential liability for remedial action regarding the Passaic River, see Note 8. Commitments and Contingent Liabilities. For a discussion of remediation/clean-up actions involving us, see Item 3. Legal Proceedings. Other liabilities associated with environmental remediation include natural resource damages. The Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and the New Jersey Spill Compensation and Control Act (Spill Act) authorize Federal and state trustees for natural resources to assess "damages" against persons who have discharged a hazardous substance, which discharge resulted in an "injury" to natural resources. Until recently, the State trustee, NJDEP, has not aggressively pursued natural resource damages. In 1997, the NJDEP adopted changes to the Technical Requirements for Site Remediation pursuant to the Spill Act. Among these changes was a new provision requiring all persons conducting remediation to characterize "injuries" to natural resources. Further, these changes required persons to address those injuries through restoration or damages. We cannot assess the magnitude of the potential impact of this regulatory change. Although not currently estimable, these costs could be material. The EPA has determined that a six mile stretch of the Passaic River in the area of Newark, New Jersey is a facility within the meaning of that term under the CERCLA and that, to date, at least thirteen corporations, including us, may be potentially liable for performing required remedial actions to address potential environmental pollution at the Passaic River facility. We have one former electric plant and four former manufactured gas plants within the Passaic River "facility". We cannot predict what action, if any, the EPA or any third party may take against us with respect to these matters, or in such event, what costs we may incur to address any such claims. However, such costs may be material. The EPA conducted an inspection of Spill Prevention Control and Countermeasure (SPCC) Plan compliance at three of our substation facilities in 1997. The EPA identified certain procedural and substantive deficiencies in the SPCC Plans for these sites. We have submitted revised SPCC Plans to the EPA for these sites and are currently working with the EPA to finalize these SPCC Plans. In 1998, we evaluated SPCC Plan compliance at all of SPCC substations and identified deficiencies. The necessary upgrades are now in the process of being made. It is anticipated that these upgrades will take several years to complete. Uranium Enrichment Decontamination and Decommissioning Fund In accordance with the Energy Policy Act (EPAct), domestic entities that own nuclear generating stations are required to pay into a decontamination and decommissioning fund, based on their past purchases of U.S. government enrichment services. Since these amounts are being collected from our customers over a period of 15 years, this obligation remained with us following the generation asset transfer to Power in 2000. Under this legislation, our original obligation for the nuclear generating stations in which we had an interest was $73 million (adjusted for inflation). Since 1993, $48 million has been paid, approximately $5 million annually, resulting in a balance due of $25 million. We believe that we are not subject to collection of any such fund payments under the EPAct. Along with other nuclear generator owners, we have filed suit in the U.S. Court of Claims and in the U.S. District Court, Southern District of New York to recover these costs. ITEM 2. PROPERTIES Our First and Refunding Mortgage (Mortgage), securing the bonds issued thereunder, constitutes a direct first mortgage lien on substantially all of our property. 10 PUBLIC SERVICE ELECTRIC AND GAS COMPANY Our electric lines and gas mains are located over or under public highways, streets, alleys or lands, except where they are located over or under property owned by us or occupied by us under easements or other rights. These easements and rights are deemed by us to be adequate for the purposes for which they are being used. We believe that we maintain insurance coverage against loss or damage to our principal properties, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost. Electric Transmission and Distribution Properties As of December 31, 2001, our transmission and distribution system included approximately 21,760 circuit miles, of which approximately 6,363 miles were underground, and approximately 836,068 poles, of which approximately 536,780 poles were jointly owned. Approximately 99% of this property is located in New Jersey. In addition, as of December 31, 2001, we owned five electric distribution headquarters and four subheadquarters in four operating divisions, all located in New Jersey. Gas Distribution Properties As of December 31, 2001, the daily gas capacity of our 100%-owned peaking facilities (the maximum daily gas delivery available during the three peak winter months) consisted of liquid petroleum air gas (LPG) and liquefied natural gas (LNG) and aggregated 2,973,000 therms (approximately 2,886,000 cubic feet on an equivalent basis of 1,030 Btu/cubic foot) as shown in the following table:
Daily Capacity Plant Location (Therms) - ----- -------- -------- Burlington LNG.................................. Burlington, NJ 773,000 Camden LPG...................................... Camden, NJ 280,000 Central LPG..................................... Edison Twp., NJ 960,000 Harrison LPG.................................... Harrison, NJ 960,000 --------------- Total..................................... 2,973,000 ===============
As of December 31, 2001, we owned and operated approximately 16,888 miles of gas mains, owned 11 gas distribution headquarters and two subheadquarters all in two operating regions located in New Jersey and owned one meter shop in New Jersey serving all such areas. In addition, we operated 61 natural gas metering or regulating stations, all located in New Jersey, of which 28 were located on land owned by customers or natural gas pipeline companies supplying us with natural gas and were operated under lease, easement or other similar arrangement. In some instances, the pipeline companies owned portions of the metering and regulating facilities. Office Buildings and Facilities We lease substantially all of a 26-story office tower for our corporate headquarters at 80 Park Plaza, Newark, New Jersey, together with an adjoining three-story building. We also lease other office space at various locations throughout New Jersey for district offices and offices for various corporate groups and services. We also own various other sites for training, testing, parking, records storage, research, repair and maintenance, warehouse facilities and for other purposes related to our business. In addition to the facilities in New Jersey and Pennsylvania as discussed above, as of December 31, 2001, we owned 39 switching stations in New Jersey with an aggregate installed capacity of 30,417,670 kilovolt-amperes and 249 substations with an aggregate installed capacity of 7,446,000 kilovolt-amperes. In addition, six substations in New Jersey having an aggregate installed capacity of 108,000 kilovolt-amperes were operated on leased property. 11 PUBLIC SERVICE ELECTRIC AND GAS COMPANY ITEM 3. LEGAL PROCEEDINGS See information on the following regulatory proceedings at the pages indicated: (1) Pages 5, 15, 16, 38 and 39. Proceedings before the BPU in the matter of the Energy Master Plan Phase II Proceeding to investigate the future structure of the Electric Power Industry, Docket Nos. EX94120585Y, EO97070461, EO97070462, EO97070463, and EX01050303. (2) Pages 6 and 7 regarding our Gas Base Rate Filings, Docket Nos. GR01050328 and GR01050297. (3) Page 10 regarding the DOE not taking possession of spent nuclear fuel, Docket No. 01-551C. (4) Pages 9 and 46 regarding our MGP Remediation Program. (5) Page 46 Investigation and additional investigation by the EPA regarding the Passaic River site. Docket No. EX93060255. In addition, see the following environmental related matters involving governmental authorities. Based on current information, we do not expect expenditures for any such site, individually or all such current sites in the aggregate, to have a material effect on our financial condition, results of operations and net cash flows. (1) Claim made in 1985 by U.S. Department of the Interior under CERCLA with respect to the Pennsylvania Avenue and Fountain Avenue municipal landfills in Brooklyn, New York, for damages to natural resources. The U.S. Government alleges damages of approximately $200 million. To our knowledge there has been no action on this matter since 1988. (2) Duane Marine Salvage Corporation Superfund Site is in Perth Amboy, Middlesex County, New Jersey. The EPA had named PSE&G as one of several potentially responsible parties (PRPs) through a series of administrative orders between December 1984 and March 1985. Following work performed by the PRPs, the EPA declared on May 20, 1987 that all of its administrative orders had been satisfied. The NJDEP, however, named us as a PRP and issued its own directive dated October 21, 1987. Remediation is currently ongoing. (3) Various Spill Act directives were issued by NJDEP to PRPs, including us with respect to the PJP Landfill in Jersey City, Hudson County, New Jersey, ordering payment of costs associated with operating and maintenance expenses, interim remedial measures and a Remedial Investigation and Feasibility Study (RI/FS) in excess of $25 million. The directives also sought reimbursement of NJDEP's past and future oversight costs and the costs of any future remedial action. (4) Claim by the EPA, Region III, under CERCLA with respect to a Cottman Avenue Superfund Site, a former non-ferrous scrap reclamation facility located in Philadelphia, Pennsylvania, owned and formerly operated by Metal Bank of America, Inc. We, other utilities and other companies are alleged to be liable for contamination at the site and we have been named as a PRP. A 60% Complete Remedial Design document was submitted to the EPA in March 2001. This document presents the design details that will implement the EPA selected remediation remedy. The costs of remedy implementation are estimated to range from $14 million to $24 million. Our share of the remedy implementation costs is estimated between $4 million and $8 million. Additionally, with respect to this site, the United States of America application in the matter entitled United States of America, et. al., v. Union Corporation, et. al., Civil Action No. 80-1589, United States District Court for the Eastern District of Pennsylvania, seeking leave of court to file an amended complaint adding claims under the CERCLA was granted. One other utility and us were named as third party defendants in the foregoing captioned matter. An application to intervene in the captioned matter as third party defendants, filed by seven other utilities alleged to be liable for contamination at the Site, has also been granted by the Court. (5) The Klockner Road site is located in Hamilton Township, Mercer County, New Jersey, and occupies approximately two acres on our Trenton Switching Station property. We have entered into a memorandum of agreement (MOA) with the NJDEP for the Klockner Road site pursuant to which we will conduct an RI/FS and remedial action, if warranted, of the site. Preliminary investigations indicated the potential presence of soil and groundwater contamination at the site. 12 PUBLIC SERVICE ELECTRIC AND GAS COMPANY (6) In 1991, the NJDEP issued Directive and Notice to Insurers Number Two (Directive Two) to 24 Insurers and 52 Respondents, including us, in connection with an investigation and remediation of the Global Landfill Site in Old Bridge Township, Middlesex County, New Jersey seeking recovery of past and anticipated future NJDEP response costs ($37 million). Other participating PRPs and us have agreed with NJDEP to a partial settlement of such costs and to perform the remedial design and remedial action. In 1996, 13 of the Directive Two Respondents, including us, filed a contribution action pursuant to CERCLA and the Spill Act against approximately 190 parties seeking contribution for an equitable share of all liability for response costs incurred and to be incurred in connection with the site. In September 1997, the NJDEP issued a Superfund record of decision (ROD) with estimated cost of $3.7 million. The Directive Two Respondents' foregoing contribution claims have been resolved by settlement. (7) In 1991, the NJDEP issued Directive and Notice To Insurers Number One (Directive No. One) to 50 insurers and 20 respondents, including us, seeking from the respondents payment of $5.5 million of NJDEP's anticipated costs of remedial action and of administrative oversight at the Combe Fill South Sanitary Landfill in Washington and Chester Townships, Morris County, New Jersey (Combe Site). The $5.5 million represents NJDEP's 10% share of total estimated site remediation costs and administrative oversight costs pursuant to a cooperative agreement with the United States concerning the selected remedial action for the site. In 1996, the NJDEP issued Directive Number Two (Directive No. Two) to 37 respondents, including us, directing the respondents to arrange for the operation, maintenance and monitoring of the implemented remedial action described therein or pay the NJDEP's future costs of these activities, estimated to be $39 million. In addition, Directive No. Two directs the respondents to prepare a work plan for the development and implementation of a Natural Resource Damage Restoration Plan. In October 1998, the NJDEP and The United States of America filed separate cost recovery actions pursuant to CERCLA and/or the Spill Act against approximately 30 parties seeking recovery of their respective shares of past and future site investigation and remediation response and administrative oversight costs incurred and to be incurred at the site. Third party contribution actions were also filed in each of the foregoing cost recovery actions seeking contribution for an equitable share of all liability for these same costs from approximately 170 third party defendants. We are named as a defendant in the NJDEP cost recovery action and a named third party defendant in the contribution action filed in the United States' lawsuit. (8) Spill Act Multi-Site Directive (Directive) issued by the NJDEP to PRPs, including us, listing four separate sites, including the former solid waste bulking and transfer facility called the Marvin Jonas Transfer Station (Sewell Site) in Deptford Township, Gloucester County, New Jersey. With regard to the Sewell Site, this Directive ordered approximately 350 PRPs, including us, to enter into an Administrative Consent Order (ACO) with NJDEP, requiring to remediate the Sewell Site. We and certain other de minimis parties have accepted a settlement offer in 2001 from other PRPs to resolve our liability for response and removal costs at the site. (9) The New York State Department of Environmental Conservation (NYSDEC) has named us as one of many potentially responsible parties for contamination existing at the former Quanta Resources Site in Long Island City, New York. Waste oil storage, processing, management and disposal activities were conducted at the site from approximately 1960 to 1981. It is believed that waste oil from our and Power's current and former facilities was taken to the Quanta Resources Site. NYSDEC has requested that the potentially responsible parties reimburse the state for the costs NYSDEC has expended at the site and to conduct an investigation and remediation of the site. We and the other PRPs are negotiating with NYSDEC the terms of an agreement that will set forth these requirements, and are negotiating among ourselves an agreement for the sharing of the associated costs. 13 PUBLIC SERVICE ELECTRIC AND GAS COMPANY ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Inapplicable. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS All of our common stock is owned by PSEG. ITEM 6. SELECTED FINANCIAL DATA The information presented below should be read in conjunction with our Consolidated Financial Statements and Notes thereto.
Years Ended December 31, ---------------------------------------------------------------- 2001 2000 1999 1998 1997 ------------ ------------ ----------- ------------ -------- (Millions of Dollars, where applicable) Total Operating Revenues........................... $6,091 $7,359 $7,640 $7,422 $6,103 Income Before Extraordinary Item................... $235 $587 $653 $602 $528 Extraordinary Item (A)............................. -- -- (804) -- -- Net Income (Loss).................................. $235 $587 $(151) $602 $528 As of December 31: Total Assets.................................... $12,936 $15,267 $14,724 $14,669 $14,844 Long-Term Liabilities: Long-Term Debt (B)............................ $4,977 $3,590 $3,099 $4,045 $4,127 Other Noncurrent Liabilities (C).............. $725 $690 $1,535 $741 $586 Preferred Stock With Mandatory Redemption.......... $75 $75 $75 $75 -- Monthly Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures................. $60 $210 $210 $210 $210 Quarterly Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures.............. $95 $303 $303 $303 $303 Ratio of Earnings to Fixed Charges (D)............. 1.83 3.15 3.58 3.27 2.74 Ratio of Earnings to Fixed Charges plus Preferred Securities Dividend Requirements (D)............ 1.79 3.04 3.46 3.15 2.64
(A) See Note 3. Regulatory Issues and Accounting Impacts of Deregulation. (B) Increase in debt related to the securitization transaction in 2001. (C) Excludes Deferred Income Taxes, ITC and the Excess Depreciation Reserve portion of Regulatory Liabilities. (D) Excludes income and expenses from Extraordinary Item. 14 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Unless the context otherwise indicates, all references to "PSE&G," "we," "us" or "our" herein means Public Service Electric & Gas Company (PSE&G), a New Jersey corporation with its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. This discussion makes reference to our Consolidated Financial Statements and related Notes to the Consolidated Financial Statements (Notes) and should be read in conjunction with such statements and notes. CORPORATE STRUCTURE We are a wholly-owned subsidiary of Public Service Enterprise Group Incorporated (PSEG), we are an operating public utility company engaged principally in the transmission and distribution of electric energy and gas service in New Jersey. On August 21, 2000, pursuant to the terms of the Final Order issued by the New Jersey Board of Public Utilities (BPU) under the New Jersey Energy Master Plan (Energy Master Plan Proceedings) and the New Jersey Electric Discount and Energy Competition Act (Energy Competition Act), we transferred our electric generation-related assets and liabilities and our wholesale power contracts to our affiliate, PSEG Power LLC (Power) and its subsidiaries in exchange for a promissory note in an amount equal to the total purchase price of $2.786 billion. Power paid the promissory note on January 31, 2001 at which time the transferred assets were released from the lien of our First and Refunding Mortgage. We continue to own and operate our regulated electric and gas transmission and distribution business. Our bankruptcy-remote subsidiary, PSE&G Transition Funding LLC (Transition Funding), issued $2.525 billion of securitization bonds in January of 2001 in partial recovery of our stranded cost resulting from New Jersey deregulation and restructuring. An additional $540 million of our stranded costs is being recovered from our customers over a four-year transition period ending July 31, 2003 through a Market Transition Charge (MTC). OVERVIEW OF 2001 AND FUTURE OUTLOOK The electric and gas utility industries in the United States and around the world continue to experience significant change. Deregulation, restructuring, privatization and consolidation are creating new and different opportunities and risks for us. Our success will depend upon our ability to obtain adequate and timely rate relief, control our costs and provide reliable, safe service. The Energy Competition Act and the related BPU proceedings, including the Final Order, have dramatically reshaped the utility industry in New Jersey and have directly affected how we will conduct business, and therefore, our financial prospects in the future. We operate under cost-based regulation by the BPU for our distribution operations and by the Federal Energy Regulatory Commission (FERC) for our electric transmission operations. As such, our earnings are largely determined by the regulation of our rates. We expect to continue to have steady earnings in the future as we continue our transmission and distribution of electric energy and gas service in New Jersey. Our success will be determined by our ability to maintain system reliability and safety, effectively manage costs and obtain timely and adequate rate relief. The risks from this business are relatively modest and generally relate to the regulatory treatment of the various rate and other issues by the BPU and the FERC. In the Final Order, the BPU concluded that we should recover up to $2.94 billion (net of tax) of our generation-related stranded costs, through securitization of $2.4 billion and an opportunity to recover up to $540 million (net of tax) of our unsecuritized generation-related stranded costs on a net present value basis through a market transition charge (MTC). Following the issuance of the Final Order, the BPU issued its Finance Order approving, among other things, the issuance and sale of $2.525 billion of transition bonds, including an estimated $125 million of transaction costs, by Transition Funding. On January 31, 2001, Transition Funding purchased our property right in the securitization transition charge (STC) and remitted the proceeds of the issuance of the transition bonds as consideration for such property right. We used these proceeds to retire a portion of our outstanding debt and equity. In accordance with the Final Order, we reduced customer rates initially by 5%, an additional 2% after the securitization transaction in February 2001 and another 2% in August 2001. We are scheduled to reduce rates by 4.9% in August 2002, for a total 13.9% rate reduction since August 1999. These rate reductions are reflected in the MTC rate charged to customers. Since the MTC revenue is remitted to power, our earnings are not impacted by these rate reductions. As a result of the generation asset transfer, our earnings and cash flows have been and will continue to be lower than those in periods prior to the transfer. 15 PUBLIC SERVICE ELECTRIC AND GAS COMPANY We have contracted with Power to provide the capacity and electricity necessary to meet the energy needs of customers who have not chosen an alternate third party supplier (TPS). Power will provide this basic generation service (BGS) obligation through July 31, 2002. Under this contract, we pay a fixed amount to Power that equals the amount we collect from customers; therefore, there is no impact to earnings. For each annual period after July 31, 2002, we are required to determine the BGS supplier by competitive bid in accordance with BPU requirements. On June 29, 2001 we and the other three regulated New Jersey electric utility companies submitted a joint filing to the BPU setting forth an auction proposal for the provision of BGS supply beginning August 1, 2002. On December 10, 2001 the BPU approved an Internet auction to determine who will supply BGS to utilities, which was held on February 4, 2002. On February 15, 2002 the BPU approved the BGS auction results and we secured contracts from a number of suppliers for our expected peak load of 9,600 megawatts (MW). We will pay $.0511 per kWh to obtain electricity for customers for the period August 1, 2002 to July 31, 2003. Customers will continue to pay below-market regulated rates (BGS shopping credit) for this one-year period. Under our current rate structure, the difference will be deferred and recovered with interest in the future. We will sell the power we receive from NUG contracts into the wholesale energy market, which should offset this underrecovery. We estimate that the underrecovery relating to the BGS for the period ending July 31, 2003 will amount to approximately $250 million with a net amount of $125 million after factoring in sales of power relating to NUG contracts. If a supplier defaults on its obligation to provide energy to us or if our peak load exceeds our contracted supply, the energy needed for us to meet our requirements will be purchased at market prices in accordance with the procedures approved by the BPU. To the extent that the market prices exceed the auction contract price, the difference will be deferred and collected from our customers as provided in the BPU Order approving the auction process. In accordance with the Final Order, we expect to file an electric base rate case during 2002 that would be effective on August 1, 2003. This case may impact our earnings and cash flows; however, we cannot predict the actual effects at this time. In January 2002, the BPU issued an order approving a Settlement under which we will receive an additional $90 million of gas base rate revenues, approximately $8 million of which results from gas depreciation rate changes. This occurred simultaneously with the implementation of our compliance filing to implement our previously approved GCUA surcharge to recover our October 31, 2001 gas cost underrecovery balance of approximately $130 million over a three-year period with interest and the reduction of our 2001-2003 Commodity Charges (formerly LGAC) by approximately $140 million. All three rate changes became effective on January 9, 2002. The $8 million gas depreciation rate changes are due primarily to the shortening of the useful lives on our other gas plant assets. This adjustment will have no impact on earnings and will result in increased operating cash flows in a normal business environment. Assuming current cost levels and a normal business environment, the $82 million balance of our gas base rate increase will have a positive impact on earnings and operating cash flows. The settlement set our gas rate base at approximately $1.6 billion, our rate of return on this rate base at 8.27% and our cost of capital or total return on equity of our gas operations at 10%. As a result of the settlement, we agreed that gas base rates would not be increased until at least September 1, 2004. The $130 million rate increase relating to the GCUA will have no impact on earnings and will increase operating cash flows in a normal business environment. The reduction in our 2001-2003 commodity charges relates to our residential customers and will have no impact on earnings and will decrease operating cash flows assuming current cost levels and a normal business environment. On August 11, 2000, we filed a gas merchant restructuring plan with the BPU which provides for, among other things, the transfer of our gas supply business, including our transportation, storage and peaking contracts to a subsidiary of Power and a requirements contract between us and Power's subsidiary enabling us to fulfill our basic gas supply service. On January 9, 2002, the BPU approved this transfer and a Requirements Contract to provide the gas supply 16 PUBLIC SERVICE ELECTRIC AND GAS COMPANY to us to serve our Basic Gas Supply Service (BGSS) customers. The transfer is anticipated to take place in April 2002. The gas supply transfer is expected to reduce volatility in our cash flows. Gas residential commodity costs are currently recovered through adjustment charges that are periodically trued-up to actual costs and reset. After the gas contract transfer, Power will charge us for the amount we recover from gas distribution customers. Industrial and commercial BGSS customers will be priced under our Market Priced Gas Service (MPGS). Residential BGSS customers will remain under current pricing until April 1, 2004 after which, subject to further BPU approval, those residential gas customers would also move to MPGS service. To the extent that the discussion that follows reports on business conducted under full monopoly regulation of the utility businesses, it must be understood that such businesses have changed due to the deregulation of the electric generation and natural gas commodity sales businesses and the subsequent sale of the generation business to Power. Past results are not an indication of future business prospects or financial results. RESULTS OF OPERATIONS For the Year Ended December 31, 2001 compared to the Year Ended December 31, 2000 Operating Revenues Electric Transmission and Distribution Transmission and Distribution revenues increased $34 million or 2% in 2001 as compared to 2000 primarily due to the effects of weather and overall sales growth. Power Supply Power Supply revenues increased approximately $1.2 billion in 2001 as compared to 2000 primarily due to the generation asset transfer to Power in August 2000. These revenues represent the BGS and MTC tariff rates charged by us to our customers who are not served by another supplier and Non-Utility Transition Charge (NTC) rates charged by us to our customers to recover the above market costs related to energy purchased by us under various NUG Contracts. Power Supply revenues in 2001 also include sales to Power of energy purchased under the NUG contracts. These sales are made to Power at the locational marginal price (LMP) in the PJM Market. For periods prior to the transfer of the generation business to Power in August 2000, Power Supply revenues include the sales of energy purchased under the NUG Contracts at LMP. Any difference between the amounts we pay under the NUG Contracts and the amount we recover through the NTC and sales at LMP are deferred as a regulatory asset or liability. The BGS and MTC revenues are offset by a corresponding expense in Power Supply Costs for the amount paid to Power under the BGS Contract. The MTC tariff rate decreased 2% in February 2001 effective with the implementation of securitization in accordance with the BPU's Final Order. Effective August 1, 2001, we implemented a 2% rate reduction as required by the Final Order, bringing the total rate decrease to 9% since August 1, 1999. These rate reductions amounted to approximately $100 million in 2001 and were funded through the MTC component of rates, which, along with BGS 17 PUBLIC SERVICE ELECTRIC AND GAS COMPANY revenues, is remitted to Power through Power Supply Costs. An additional 4.9% rate reduction, effective August 1, 2002, will further reduce revenues and costs. Generation Following the transfer of our generation business to Power in August 2000, we no longer record Generation revenues. These revenues, which reflected generation sold to regulated utility customers and on the wholesale energy market, were replaced with Power Supply revenues which are offset by power purchased from Power to meet our BGS obligation. Gas Distribution Gas Distribution revenues increased $153 million or 7% in 2001 as compared to 2000 primarily due to higher gas rates and sales in the appliance service business. Customer rates in all classes of business have increased in 2001 to recover a portion of the higher natural gas costs. The commercial and industrial classes fuel recovery rates vary monthly according to the market price of gas. The BPU also approved increases in the fuel component of the residential class rates of 16% in November 2000 and 2% for each month from December 2000 through July 2001. These increased revenues were offset by higher gas distribution costs, discussed below, and lower sales volumes in the fourth quarter of 2001 than the comparable period in 2000, primarily resulting from warmer weather. Trading Together with the transfer of our generation business to Power, we transferred our trading operations to Power in August 2000 and therefore no longer have Trading revenues. Operating Expenses Power Supply Power Supply costs increased approximately $1.2 billion in 2001 as compared to 2000 primarily due to the generation asset transfer to Power in August 2000. These costs represent the amount paid to Power under the BGS Contract. These amounts also include purchases of energy under various NUG contracts. Prior to August 2000, the Power Supply costs represented only purchases of energy under various NUG contracts as we operated our own generation business. The BGS and MTC costs paid to Power reflect the rate reductions discussed above. Gas Costs Gas Costs increased $167 million or 12% in 2001 as compared to 2000 primarily due to higher natural gas costs. The increase was partially offset by lower natural gas purchases due to lower sales volumes resulting from comparably warmer weather in the fourth quarter of 2001 as compared to the same period in 2000. Due to the LGAC, gas costs are increased or decreased to offset a corresponding increase or decrease in fuel revenues with no impact on income. Generation Costs Following the transfer of our generation business to Power in August 2000, we no longer record Generation Costs, which were primarily comprised of fuel used to generate electricity. These costs were replaced with Power Supply Costs which include the power purchased to meet our BGS obligation. Trading Costs Together with the transfer of our generation business to Power, we transferred our trading operations to Power in August 2000 and therefore no longer have Trading Costs. 18 PUBLIC SERVICE ELECTRIC AND GAS COMPANY Operations and Maintenance Operations and Maintenance expense decreased $286 million or 23% in 2001 as compared to 2000 primarily due to the elimination of $328 million in Operations and Maintenance expenses resulting from the transfer of the generation business to Power in August 2000. The decrease was partially offset by the deferral of costs incurred during 2000 in connection with deregulation that we expect to recover in future rates. Depreciation and Amortization Depreciation and Amortization expense increased $93 million or 32% in 2001 as compared to 2000 primarily due to approximately $180 million of amortization of the regulatory asset recorded for our stranded costs, which commenced with the issuance of the transition bonds on January 31, 2001. This increase was partially offset by the elimination of $77 million of Depreciation and Amortization expense resulting from the transfer of the generation business to Power in August 2000. Taxes Other Than Income Taxes Taxes Other Than Income Taxes decreased $29 million or 18% in 2001 as compared to 2000. This decrease was partially due to a reduction in net taxable sales subject to the Transition Energy Facility Assessment (TEFA) tax and the phaseout of the TEFA. The TEFA was enacted as part of energy tax reform and was scheduled to be phased out by 2003. Recent legislation delayed the phase-out until 2007. Interest Expense Net Interest Expense increased $102 million or 41% in 2001 as compared to 2000 primarily due to interest of approximately $148 million on the bonds issued by Transition Funding on January 31, 2001, discussed below, combined with approximately $78 million lower interest earned in 2001, as compared to 2000. The reduction in interest earned in 2001 resulted from the repayment of intercompany loans by PSEG and Power in April 2001 relating to the transfer of the generation business. These increases were partially offset by $118 million in lower interest resulting from reduced short-term and long-term debt. Preferred Securities Dividends Preferred Securities Dividends decreased $22 million or 48% in 2001 as compared to 2000 primarily due to the redemption of $240 million and $208 million of preferred securities in March 2001 and June 2001. Income Taxes Income taxes decreased $318 million or 78% in 2001 as compared to 2000. These decreases were primarily due to lower pre-tax operating income due to the transfer of the generation business to Power in August of 2000. In addition, taxes decreased due to normal adjustments as a result of closing the 1994-96 IRS audit and upon filing the actual tax return for the year 2000. For the Year Ended December 31, 2000 compared to the Year Ended December 31, 1999 Operating Revenues For the purpose of this discussion, bundled revenues recorded through July 31, 1999 have been allocated by unbundling the generation component of revenue from our bundled rate for the generation, transmission and distribution of energy and adding any other generation-related revenues, such as ancillary services. The resulting revenue amounts are as follows: 19 PUBLIC SERVICE ELECTRIC AND GAS COMPANY
2000 1999 -------------------- ------------------- (Millions of Dollars) Electric Transmission and Distribution $1,447 $1,352 Power Supply 1,141 127 Generation 1,110 2,602 -------------------- ------------------- Total Operating Electric Revenues $3,698 $4,081 ==================== ===================
Electric Transmission and Distribution Electric Transmission and Distribution revenues increased $95 million or 7% in 2000 as compared to 1999 primarily due to more favorable weather in 2000. Power Supply Power Supply revenues increased approximately $1 billion in 2000 as compared to 1999 primarily due to the generation asset transfer to Power in August 2000. Following the transfer, these revenues represent the BGS and MTC tariff rates charged by us to our customers who are not served by another supplier, which were approximately $830 million. In addition, following the unbundling of rates in August 1999, Power Supply revenues include the amount charged by us to our customers through NTC rates to recover the above market costs related to energy purchased by us under various NUG Contracts. Power Supply revenues in 2000 also include sales to Power of energy purchased under the NUG contracts. These sales are made to Power at the LMP in the PJM Market. For periods subsequent to the unbundling of rates and prior to the transfer of the generation business to Power in August 2000, Power Supply revenues also include the sales of energy purchased under the NUG Contracts at LMP. Any difference between the amounts we pay under the NUG Contracts and the amount we recover through the NTC and sales at LMP, are deferred as a regulatory asset or liability. The BGS and MTC revenues are offset by a corresponding expense in Power Supply Costs for the amount paid to Power under the BGS Contract. Generation Generation revenues decreased approximately $1.5 billion in 2000 as compared to 1999 primarily due to the transfer of our generation business to Power in August 2000. These revenues were replaced with Power Supply revenues, which are offset by power purchased from Power to meet our BGS obligation. Also contributing to the decrease was the implementation of a 5% rate reduction on August 1, 1999 which decreased revenues by approximately $100 million, a $76 million pre-tax charge to income related to MTC recovery in the third quarter of 2000 and a reduction in revenues resulting from customer migration. However, the reduction in revenues resulting from customer migration was substantially offset by higher interchanged sales. Gas Distribution Gas Distribution revenues increased $423 million or 25% in 2000 as compared to 1999 primarily due to increases in natural gas prices being passed along to customers under certain transportation only contracts. Under these contracts, we are responsible only for delivery of gas to these customers. Such customers are responsible for payment to us for the cost of the commodity and as our costs for these customers increase, the customers rates will increase. Also contributing to this increase were higher sales resulting from colder weather in the fourth quarter of 2000 as compared to the same period in 1999 and higher rates approved by the BPU to allow us to recover increasing natural gas costs. Trading Trading revenues decreased $321 million or 17% in 2000 as compared to 1999 primarily due to the transfer of our trading operations to ER&T, effective August 1, 2000. 20 PUBLIC SERVICE ELECTRIC AND GAS COMPANY Operating Expenses Power Supply Power Supply costs increased approximately $1 billion in 2000 as compared to 1999. For 2000, following the transfer of the generation business to Power, these costs represent the amount paid to Power under the BGS Contract. These amounts also include purchases of energy under various NUG contracts. Prior to August 2000, the Power Supply costs represented only purchases of energy under various NUG contracts as we operated our own generation business. The BGS and MTC costs paid to Power reflect the rate reductions discussed above. Gas Costs Gas Costs increased $391 million or 38% in 2000 as compared to 1999 primarily due to higher natural gas costs. Due to the Levelized Gas Adjustment Clause, gas costs are increased or decreased to offset a corresponding increase or decrease in fuel revenues with no impact on income. Generation Costs Generation costs decreased by $450 million or 58% in 2000 as compared to 1999 primarily due to the transfer of the generation business to Power in August 2000. These costs were replaced with Power Supply costs, discussed above. Trading Costs Trading Costs decreased $328 million or 18% in 2000 as compared to 1999 primarily due to the transfer of our trading operations to ER&T, effective August 1, 2000. Operations and Maintenance Operations and Maintenance expense decreased $312 million or 20% in 2000 as compared to 1999 primarily due to the elimination of Operations and Maintenance expenses resulting from the transfer of our generation business to Power in August 2000. Depreciation and Amortization Depreciation and Amortization expense decreased $238 million or 45% in 2000 as compared to 1999 primarily due to an impairment write-down of generation related asset balances recorded as of April 1, 1999, pursuant to Statement of Financial Accounting Standards (SFAS) No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS 121). The balance of the decrease is due to the elimination of Depreciation and Amortization expense resulting from the transfer of the generation business to Power in August 2000. Taxes Other Than Income Taxes Taxes Other Than Income Taxes include the Transitional Energy Facility Assessment (TEFA). Taxes Other Than Income Taxes decreased $28 million or 14% in 2000 as compared to 1999. This decrease was partially due to New Jersey energy tax reform and the five-year phase out of the TEFA commencing in January 1999. Effective January 1, 2000, revised rates became effective which reflected two years phase out of the TEFA. The balance of the decrease is primarily due to the transfer of our generation business to Power in August 2000. Interest Expense Net Interest Expense decreased $133 million or 34% in 2000 as compared to 1999 primarily due to approximately $150 million of interest earned from Power relating to the intercompany loans for the generation business transfer in August 2000, partially offset by increased short-term debt outstanding in anticipation of the securitization financing. 21 PUBLIC SERVICE ELECTRIC AND GAS COMPANY Income Taxes Income taxes decreased $103 million or 20% in 2000 as compared to 1999 primarily due to lower pre-tax income, due to the transfer of the generation business to Power in August 2000, coupled with lower effective tax rates relating to the amortization of the excess depreciation reserve for electric distribution. LIQUIDITY AND CAPITAL RESOURCES All of our publicly traded debt has received investment grade ratings from each of the three major credit rating agencies. The changes in the energy industry and the recent bankruptcy of Enron Corp. are attracting increased attention from the rating agencies, which regularly assess business and financial matters. Given the changes in the industry, attention to and scrutiny of our performance, capital structure and competitive strategies by rating agencies will likely continue. These changes could affect the bond ratings, cost of capital and market prices of our securities. We will continue to evaluate our capital structure, financing requirements, competitive strategies and future capital expenditures to maintain our current credit ratings. The current ratings of our securities are shown below and reflect the respective views of the rating agencies, from whom an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time or that they will not be revised or withdrawn entirely by the rating agencies, if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely effect the market price of our securities and serve to increase our cost of capital.
Moody's Standard & Poor's Fitch -------------------------------------------------------------------------------------------- Mortgage Bonds A3 A- A Preferred Securities Baa1 BBB A- Commercial Paper P2 A2 F1
External financing may consist of public and private capital market debt and equity transactions, bank revolving credit and term loan facilities and/or commercial paper. Some of these transactions involve special purpose entities. These are corporations, limited liability companies or partnerships formed in accordance with applicable tax, accounting and legal requirements in order to achieve specified beneficial financial advantages, such as favorable tax, legal liability or accounting treatment. All such special purpose entities utilized by us and our subsidiaries have been consolidated in our financial reporting. The availability and cost of external capital could be affected by our performance as well as by the performance of our affiliates. This could include the degree of structural or regulatory separation between us and our non-utility affiliates and the potential impact of affiliate ratings on credit quality. Additionally, compliance with applicable financial covenants will depend upon future financial position and levels of earnings and net cash flows, as to which no assurances can be given. Our credit agreements contain cross-default provisions under which a default by us involving specified levels of indebtedness in other agreements would result in a default and the potential acceleration of payment under such credit agreements. 22 PUBLIC SERVICE ELECTRIC AND GAS COMPANY In addition, our credit agreements generally contain provisions under which the lenders could refuse to advance loans in the event of a material adverse change in our business or financial condition. In the event that we or the lenders in any of our credit agreements determine that a material adverse change has occurred, loan funds may not be advanced. Such lenders, or the debt holders under any of our indentures, could determine that debt payment obligations may be accelerated as a result of a cross-default. These occurrences could severely limit our liquidity and restrict our ability to meet our debt, capital and, in extreme cases, operational cash requirements. Any inability to satisfy required covenants and/or borrowing conditions would have a similar impact. This would have a material adverse effect on our financial condition, results of operations and net cash flows, and those of our subsidiaries. Our debt indentures and credit agreements do not contain any "ratings triggers" that would cause an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a downgrade we may be subject to increased interest costs on certain bank debt. Capital resources and investment requirements could be affected by the outcome of proceedings by the BPU pursuant to its Energy Master Plan and Energy Competition Act and the requirements of the 1992 Focused Audit conducted by the BPU, of the impact of PSEG's non-utility businesses, owned by PSEG Energy Holdings (Energy Holdings), on us. As a result of the Focused Audit, the BPU ordered that, among other things: (1) PSEG will not permit Energy Holdings' investments to exceed 20% of our consolidated assets without prior notice to the BPU; (2) Our Board of Directors would provide an annual certification that the business and financing plans of Energy Holdings will not adversely affect us; (3) PSEG will (a) limit debt supported by the minimum net worth maintenance agreement between PSEG and PSEG Capital to $650 million and (b) make a good-faith effort to eliminate such support over a six to ten year period from May 1993; and (4) Energy Holdings will pay us an affiliation fee of up to $2 million a year, which is to be used to reduce customer rates. In the Final Order the BPU noted that, due to significant changes in the industry and, in particular, our corporate structure as a result of the Final Order, modifications to or relief from the Focused Audit order might be warranted. We have notified the BPU that PSEG will eliminate PSEG Capital debt by the second quarter of 2003 and that we believe that the Final Order otherwise supercedes the requirements of the Focused Audit. While we believe that this issue will be satisfactorily resolved, no assurances can be given. In addition, if PSEG were no longer to be exempt under the Public Utility Holding Company Act of 1935 (PUHCA), we would be subject to additional regulation by the SEC with respect to financing and investing activities. We believe that this would not have a material adverse effect on our financial condition, results of operations and net cash flows. Over the next several years, we will be required to refinance maturing debt, incur additional debt and retain earnings to fund investment activity. Any inability to obtain required additional external capital or to extend or replace maturing debt and/or existing agreements at current levels and reasonable interest rates may affect our financial condition, results of operations and net cash flows. In March 2001, we reduced the maximum size of our commercial paper program from $1.5 billion to $900 million. Effective March 8, 2002, this amount will be further reduced to $550 million. To provide liquidity for this program, we have three revolving credit facilities with a group of banks totaling $900 million ($550 million effective March 8, 2002), each of which expires in June 2002. In addition, we have an uncommitted line of credit with a bank. As of December 31, 2001, we had no short-term debt outstanding. Under our Mortgage, we may issue new First and Refunding Mortgage Bonds against previous additions and improvements and/or retired Mortgage Bonds provided that our ratio of earnings to fixed charges calculated in 23 PUBLIC SERVICE ELECTRIC AND GAS COMPANY accordance with our Mortgage is at least 2:1. At December 31, 2001, our Mortgage coverage ratio was 3:1. As of December 31, 2001, the Mortgage would permit up to approximately $1 billion aggregate principal amount of new Mortgage Bonds to be issued against previous additions and improvements. We will need to obtain BPU authorization to issue any incremental debt financing necessary for our capital program including refunds of maturing debt and opportunistic refinancing. In January 2002, we filed a petition with the BPU for authorization to issue $1 billion of long-term debt through December 31, 2003. In December 2001, we filed a shelf registration statement on Form S-3 for the issuance of $1 billion of debt and tax deferred preferred securities, which was declared effective by the SEC in February 2002. In January 2001, $2.525 billion of transition bonds were issued by Transition Funding in eight classes with maturities ranging from 1 year to 15 years. We also received payment from Power on its $2.786 billion promissory note used to finance the transfer of our generation business to Power. The proceeds from these transactions were used to pay for certain debt issuance and related costs for securitization, retire a portion of our outstanding short-term debt, reduce our common equity, loan funds to PSEG and make various short-term investments. In March 2001, we redeemed all of our $150 million of 9.375% Series A cumulative monthly income preferred securities, all of our $75 million of 5.97% preferred stock, $15 million of our 6.75% preferred stock and $52 million of our floating rate notes due December 7, 2002. In June 2001, we redeemed the remaining $248 million outstanding of floating rate notes due December 7, 2002. In June 2001, we redeemed all of our $208 million of 8.625% Series A cumulative quarterly income preferred securities. In November 2001, $100 million of our Mortgage Bonds, Series FF matured. Also in November 2001, we redeemed $105 million of our variable rate Pollution Control Notes. In December 2001, we redeemed an additional $19 million of our variable rate Pollution Control Notes. Since 1986, we have made regular cash payments to PSEG in the form of dividends on outstanding shares of our common stock. We paid common stock dividends of $112 million and $638 million to PSEG for the years ended December 31, 2001 and 2000, respectively. We have issued Deferrable Interest Subordinated Debentures in connection with the issuance of tax deductible preferred securities. If payments on those Deferrable Interest Subordinated Debentures are deferred, in accordance with their terms, we may not pay any dividends on our common or preferred stock until such default is cured. Currently, there has been no deferral or default. CAPITAL REQUIREMENTS Forecasted Expenditures We have substantial commitments as part of our ongoing construction programs. We expect that the majority of our capital requirements over the next five years will come from internally generated funds, with the balance to be provided by the issuance of debt and equity contributions from PSEG. For the year ended December 31, 2001, we made net plant additions of $398 million, excluding Allowance for Funds Used During Construction (AFDC) related to improvements in our transmission and distribution system, gas system and common facilities. Our projected construction expenditures for the next five years range from $440 million to $485 million per year. 24 PUBLIC SERVICE ELECTRIC AND GAS COMPANY Our construction expenditures are primarily to maintain the safety and reliability of our electric and gas transmission and distribution facilities. Our ongoing construction programs are continuously reviewed and periodically revised as a result of changes in economic conditions, revised load forecasts, business strategies, site changes, cost escalations under construction contracts, requirements of regulatory authorities and laws, the timing of and amount of electric and gas transmission and/or distribution rate changes and our ability of us to raise necessary capital. Disclosures about Contractual Obligations The following tables, reflect our contractual cash obligations in the respective periods in which they are due.
Less Total Amounts Than Contractual Cash Obligations Committed 1 year 2 - 3 years 4 - 5 years Over 5 years (Millions of Dollars) ------------------------------------------------------------------------------ Long - Term Debt $5,645 $547 $638 $272 $4,188 Capital Lease Obligations 102 8 16 16 62 Operating Leases 13 3 5 4 1 ------------------------------------------------------------------------------ Total Contractual Cash Obligations $5,760 $558 $659 $292 $4,251 ==============================================================================
QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK The market risk inherent in our market risk sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices and interest rates as discussed in the Notes to Consolidated Financial Statements. Our policy is to use derivatives to manage risk consistent with our business plans and prudent practices. PSEG has a Risk Management Committee comprised of executive officers, which we utilize for an independent risk oversight function to ensure compliance with corporate policies and prudent risk management practices. We are exposed to credit losses in the event of non-performance or non-payment by counterparties. We also have a credit management process, which is used to assess, monitor and mitigate our counterparty exposure. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on our financial condition, results of operations or net cash flows. We use natural gas futures and swaps to reduce exposure to price fluctuations from factors such as weather, changes in demand and changes in supply to manage the price risk associated with gas supply to our customers. These instruments, in conjunction with physical gas supply contracts, are designed to cover estimated gas customer commitments. We have entered into 330 MMBTU of gas futures, swaps and options to hedge forecasted requirements. As of December 31, 2001, the fair value of those instruments was $(137) million with a maximum term of approximately one year. We utilize derivatives to hedge our gas purchasing activities which, when realized, are recoverable through our LGAC. Accordingly, the offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability. As a result of the gas contract transfer that is anticipated to take place in April 2002, our price risk relating to gas purchases will be transferred to Power. As a result, after that date, we will not be utilizing these derivative instruments in our gas distribution business. Through the BGS auction, we have contracted for our expected peak load of 9,600 MW. If our peak load should exceed this amount or one of our suppliers defaults on their contract, we may have to purchase power on the open market and use commodity contracts during periods of high demand. To the extent that the market prices exceed the 25 PUBLIC SERVICE ELECTRIC AND GAS COMPANY auction contract price, the difference will be deferred and collected from our customers as provided in the BPU Order approving the auction process. Given the absence of a PJM price cap in situations involving emergency purchases and the potential for plant outages, extreme price movements can occur and could have a material impact on our financial condition and net cash flows. We are subject to the risk of fluctuating interest rates in the normal course of business. Our policy is to manage interest rate risk through the use of fixed rate debt, floating rate debt and interest rate swaps. As of December 31, 2001, a hypothetical 10% change in market interest rates would result in a $4 million change in annual interest costs related to our short-term and floating rate debt. Transition Funding has entered into an interest rate swap on its sole class of floating rate transition bonds. The notional amount of the interest rate swap is approximately $497 million. The interest rate swap is indexed to the three-month LIBOR rate. The fair value of the interest rate swap was approximately $(18) million as of December 31, 2001 and was recorded as a derivative liability, with an offsetting amount recorded as a regulatory asset on the Consolidated Balance Sheet. This amount will vary over time as a result of changes in market conditions. ACCOUNTING ISSUES Critical Accounting Policies and Other Accounting Matters Our most critical accounting policies include the application of: SFAS No. 71 "Accounting for the Effects of Certain Types of Regulation" (SFAS 71) for our regulated transmission and distribution business and SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended (SFAS 133), to account for our various hedging transactions. Accounting for the Effects of Regulation We prepare our financial statements in accordance with the provisions of SFAS No. 71, which differs in certain respects from the application of Generally Accepted Accounting Principles (GAAP) by non-regulated businesses. In general, SFAS 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated entity is required to defer the recognition of costs (a regulatory asset) or the recognition of obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, we have deferred certain costs, which will be amortized over various future periods. To the extent that collection of such costs or payment of liabilities is no longer probable as a result of changes in regulation and/or our competitive position, the associated regulatory asset or liability is charged or credited to income. As a result of New Jersey deregulation legislation and regulatory orders issued by the BPU, certain regulatory assets and liabilities were recorded. The amortization of two of these regulatory liabilities will have a significant effect on our annual earnings. They include the estimated amount of MTC revenues to be collected in excess of the authorized amount of $540 million and the amount of excess electric distribution depreciation reserves. The amount of these regulatory liabilities will be amortized to earnings over the four-year transition period from August 1, 1999 through July 31, 2003. The MTC was authorized by the BPU as an opportunity to recover up to $540 million (net of tax) of our unsecuritized generation-related stranded costs on a net present value basis. As a result of the appellate reviews of the Final Order, our securitization transaction was delayed until the first quarter of 2001, causing a delay in the implementation of the Securitization Transition Charge (STC), which would have reduced the MTC. As a result, MTC was being recovered at a faster rate than intended under the Final Order and a significant overrecovery was 26 PUBLIC SERVICE ELECTRIC AND GAS COMPANY probable. In order to properly recognize the recovery of the allowed unsecuritized stranded costs over the transition period, we recorded a regulatory liability and a charge to net income of $76 million, pre-tax, or $45 million, after tax, in the third quarter of 2000 for the cumulative amount of estimated collections in excess of the allowed unsecuritized stranded costs for the period prior to the generation-related asset transfer to Power. We then began deferring a portion of these revenues each month to recognize the estimated collections in excess of the allowed unsecuritized stranded costs. As of December 31, 2001, this deferred amount was $168 million and is aggregated with the Societal Benefits Clause. The amortization of the Excess Electric Distribution Depreciation Reserve is another significant regulatory liability affecting our earnings. As required by the BPU, we reduced our depreciation reserve for our electric distribution assets by $569 million and recorded such amount as a regulatory liability to be amortized over the period from January 1, 2000 to July 31, 2003. In 2000 and 2001, $125 million was amortized and recorded as a reduction of depreciation expense pursuant to the Final Order. The remaining $319 million will be amortized through July 31, 2003. See Note 4. Regulatory Assets and Liabilities for further discussion of these and other regulatory issues. SFAS 133 - Accounting for Derivative Instruments and Hedging Activities SFAS 133 established accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires an entity to recognize the fair value of derivative instruments held as assets or liabilities on the balance sheet. In accordance with SFAS 133, the effective portion of the change in the fair value of a derivative instrument designated as a cash flow hedge is reported in other comprehensive income (OCI), net of tax, or as a Regulatory Asset (Liability). Amounts in accumulated OCI are ultimately recognized in earnings when the related hedged forecasted transaction occurs. The change in the fair value of the ineffective portion of the derivative instrument designated as a cash flow hedge is recorded in earnings. Derivative instruments that have not been designated as hedges are adjusted to fair value through earnings. We have entered into several derivative instruments, including interest rate swaps which have been designated as cash flow hedges. The fair value of the derivative instruments is determined by reference to quoted market prices, listed contracts, published quotations or quotations from counterparties. For additional information regarding Derivative Financial Instruments, See Note 7 Financial Instruments and Risk Management. Other Accounting Issues For additional information on our accounting policies and the implementation of recently issued accounting standards, see Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies and Note 2. Accounting Matters, respectively. FORWARD LOOKING STATEMENTS Except for the historical information contained herein, certain of the matters discussed in this report constitute "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management's beliefs as well as assumptions made by and information currently available to management. When used herein, the words "will", "anticipate", "intend", "estimate", "believe", "expect", "plan", "hypothetical", "potential", variations of such words and similar expressions are intended to identify forward-looking statements. We undertake no obligation to publicly update or revise any 27 PUBLIC SERVICE ELECTRIC AND GAS COMPANY forward-looking statements, whether as a result of new information, future events or otherwise. The following review of factors should not be construed as exhaustive or as any admission regarding the adequacy of our disclosures prior to the effective date of the Private Securities Litigation Reform Act of 1995. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following: o failure to obtain adequate and timely rate relief may have an adverse impact; o deregulation and the unbundling of energy supplies and services and the establishment of a competitive energy marketplace; o inability to raise capital on favorable terms to refinance existing indebtedness or to fund capital commitments; o changes in the economic and electricity and gas consumption growth rates; o environmental regulation may limit our operations; o insurance coverage may not be sufficient; and o recession, acts of war or terrorism could have an adverse impact. ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK Information relating to quantitative and qualitative disclosures about market risk is set forth under the caption "Qualitative and Quantitative Disclosures About Market Risk" in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. Such information is incorporated herein by reference. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 28 PUBLIC SERVICE ELECTRIC AND GAS COMPANY CONSOLIDATED STATEMENTS OF INCOME (Millions of Dollars)
For The Years Ended December 31, -------------------------------------------------- 2001 2000 1999 ------------- ------------- ------------- OPERATING REVENUES Electric Transmission and Distribution $ 1,481 $ 1,447 $ 561 Bundled - - 2,445 Power Supply 2,317 1,141 127 Generation - 1,110 948 Gas Distribution 2,293 2,140 1,717 Trading - 1,521 1,842 ------------- ------------- ------------- Total Operating Revenues 6,091 7,359 7,640 ------------- ------------- ------------- OPERATING EXPENSES Power Supply 2,317 1,141 127 Gas Costs 1,596 1,429 1,038 Generation - 331 781 Trading - 1,472 1,800 Operation and Maintenance 975 1,261 1,573 Depreciation and Amortization 384 291 529 Taxes Other Than Income Taxes 137 166 194 ------------- ------------- ------------- Total Operating Expenses 5,409 6,091 6,042 ------------- ------------- ------------- OPERATING INCOME 682 1,268 1,598 Other Income and Deductions 22 26 (2) Interest Expense-net (356) (254) (387) Preferred Securities Dividend Requirements (24) (46) (46) ------------- ------------- ------------- INCOME BEFORE INCOME TAXES AND EXTRAORDINARY ITEM 324 994 1,163 Income Taxes (89) (407) (510) ------------- ------------- ------------- INCOME BEFORE EXTRAORDINARY ITEM 235 587 653 Extraordinary Item (Net of Tax of $345) - - (804) ------------- ------------- ------------- NET INCOME (LOSS) 235 587 (151) Preferred Stock Dividend Requirement (5) (9) (9) ------------- ------------- ------------- EARNINGS (LOSS) AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED $ 230 $ 578 $ (160) ============= ============= =============
* Note: Bundled revenues were recorded based on the bundled rates in effect through July 31, 1999. Commencing with the unbundling of rates on August 1, 1999, revenues are disaggregated between Generation Revenue and Transmission and Distribution Revenue. See Notes to Consolidated Financial Statements. 29 PUBLIC SERVICE ELECTRIC AND GAS COMPANY CONSOLIDATED BALANCE SHEETS ASSETS (Millions of Dollars)
December 31, -------------------------------- 2001 2000 -------------- -------------- CURRENT ASSETS Cash and Cash Equivalents $ 102 $ 39 Accounts Receivable: Customer Accounts Receivable 556 614 Other Accounts Receivable 67 71 Allowance for Doubtful Accounts (38) (39) Unbilled Revenues 291 357 Fuel 415 372 Materials and Supplies 50 48 Prepayments 40 5 Energy Contracts 32 - Restricted Cash 13 1 Other 21 23 -------------- -------------- Total Current Assets 1,549 1,491 -------------- -------------- PROPERTY, PLANT AND EQUIPMENT Electric 5,501 5,302 Gas 3,284 3,177 Other 385 420 -------------- -------------- Total 9,170 8,899 Accumulated depreciation and amortization (3,329) (3,139) -------------- -------------- Net Property, Plant and Equipment 5,841 5,760 -------------- -------------- NONCURRENT ASSETS Regulatory Assets 5,220 4,995 Notes Receivable - Affiliated Companies - 2,786 Long-Term Investments 112 109 Other Special Funds 130 70 Other 84 56 -------------- -------------- Total Noncurrent Assets 5,546 8,016 -------------- -------------- TOTAL $ 12,936 $ 15,267 ============== ==============
See Notes to Consolidated Financial Statements. 30 PUBLIC SERVICE ELECTRIC AND GAS COMPANY CONSOLIDATED BALANCE SHEETS LIABILITIES AND CAPITALIZATION (Millions of Dollars)
December 31, ------------------------------------- 2001 2000 -------------- ------------------ CURRENT LIABILITIES Long-Term Debt Due Within One Year $ 668 $ 100 Commercial Paper and Loans - 1,543 Accounts Payable 642 748 Energy Contracts 169 - Other 280 253 -------------- ------------------ Total Current Liabilities 1,759 2,644 -------------- ------------------ NONCURRENT LIABILITIES Deferred Income Taxes and ITC 2,551 2,701 Regulatory Liabilities 373 470 OPEB Costs 466 441 Other 205 223 -------------- ------------------ Total Noncurrent Liabilities 3,595 3,835 -------------- ------------------ COMMITMENTS AND CONTINGENT LIABILITIES - - -------------- ------------------ CAPITALIZATION: LONG-TERM DEBT 4,977 3,590 -------------- ------------------ PREFERRED SECURITIES: Preferred Stock Without Mandatory Redemption 80 95 Preferred Stock With Mandatory Redemption - 75 Subsidiaries' Preferred Securities: Guaranteed Preferred Beneficial Interest in Subordinated Debentures 155 513 -------------- ------------------ Total Preferred Securities 235 683 -------------- ------------------ COMMON STOCKHOLDER'S EQUITY: Common Stock, issued; 132,450,344 shares 892 2,563 Contributed Capital - 594 Basis Adjustment 986 986 Retained Earnings 493 375 Accumulated Other Comprehensive Income (Loss) (1) (3) -------------- ------------------ Total Common Stockholder's Equity 2,370 4,515 -------------- ------------------ Total Capitalization 7,582 8,788 -------------- ------------------ TOTAL $ 12,936 $ 15,267 ============== ==================
See Notes to Consolidated Financial Statements. 31 PUBLIC SERVICE ELECTRIC AND GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions of Dollars)
For The Years Ended December 31, ------------------------------------------ 2001 2000 1999 ----------- ---------- ---------- CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $ 235 $ 587 $ (151) Adjustments to reconcile net income (loss) to net cash flows from operating activities: Extraordinary Loss - net of tax - - 804 Depreciation and Amortization 384 291 529 Amortization of Nuclear Fuel - 36 92 Recovery of Electric Energy and Gas Costs - net (86) 16 61 Excess Unsecuritized Stranded Costs 54 115 - Provision for Deferred Income Taxes and ITC - net (267) (12) (181) Net Changes in certain current assets and liabilities: Accounts Receivable and Unbilled Revenues 127 (298) (198) Inventory - Fuel and Materials and Supplies (45) (172) 10 Prepayments (35) 27 4 Accounts Payable (106) 294 68 Other Current Assets and Liabilities 152 39 25 Other (2) (26) 87 ----------- ---------- ---------- Net Cash Provided By Operating Activities 411 897 1,150 ----------- ---------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment, excluding AFDC (398) (401) (479) Contribution to Decommissioning Funds and Other Special Funds (94) (4) (70) Other (32) (15) (34) ----------- ---------- ---------- Net Cash Used In Investing Activities (524) (420) (583) ----------- ---------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Short-Term Debt (1,543) 68 625 Issuance of Long-Term Debt 2,525 590 - Redemption/Purchase of Long-Term Debt (570) (622) (423) Deferred Issuance Costs (192) - - Redemption of Preferred Stock (448) - - Return of Capital (2,265) - - Collection of Notes Receivable-Affiliated Company 2,786 - - Cash Dividends Paid on Common Stock (112) (638) (629) Preferred Stock Dividend Requirements (5) (9) (9) ----------- ---------- ---------- Net Cash Provided By (used In) Financing Activities 176 (611) (436) ----------- ---------- ---------- Net Change In Cash And Cash Equivalents 63 (134) 131 Cash And Cash Equivalents At Beginning Of Period 39 173 42 ----------- ---------- ---------- Cash And Cash Equivalents At End Of Period $ 102 $ 39 $ 173 =========== ========== ========== Income Taxes Paid $ 264 $ 593 $ 537 Interest Paid $ 455 $ 406 $ 409
See Notes to Consolidated Financial Statements. 32 PUBLIC SERVICE ELECTRIC AND GAS COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (Millions of Dollars)
Accumulated Contributed Other Common Capital from Basis Retained Comprehensive Stock PSEG Adjustment Earnings Loss Total ---------- ------------ ---------- -------- -------------- -------- Balance as of January 1, 1999 $ 2,563 $ 594 - $1,386 $ (3) $ 4,540 ---------- ------------ ---------- -------- -------------- -------- Net Loss - - - (151) - (151) Other Comprehensive Income, net of tax: - - - - - - -------- Comprehensive Loss - - - - - (151) -------- Cash Dividends on Common Stock - - - (629) - (629) Cash Dividends on Preferred Stock - - - (9) - (9) ---------- ------------ ---------- -------- -------------- -------- Balance as of December 31, 1999 2,563 594 - 597 (3) 3,751 ---------- ------------ ---------- -------- -------------- -------- Net Income - - - 587 - 587 Other Comprehensive Income, net of tax: - - - - - - -------- Comprehensive Income - - - - - 587 -------- Cash Dividends on Common Stock - - - (800) - (800) Cash Dividends on Preferred Stock - - - (9) - (9) Basis Adjustment - - 986 - - 986 ---------- ------------ ---------- -------- -------------- -------- Balance as of December 31, 2000 2,563 594 986 375 (3) 4,515 ---------- ------------ ---------- -------- -------------- -------- Net Income - - - 235 - 235 Other Comprehensive Income , net of tax: - - - - - - Pension Adjustments, net of tax $(1) - - - - 2 2 -------- Comprehensive Income - - - - - 237 -------- Cash Dividends on Common Stock - - - (112) - (112) Cash Dividends on Preferred Stock - - - (5) - (5) Return of Capital (1,671) (594) - - - (2,265) Basis Adjustment - - - - - - ---------- ------------ ---------- -------- -------------- -------- Balance as of December 31, 2001 $ 892 $ - $ 986 $ 493 $ (1) $ 2,370 ========== ============ ========== ======== ============== ========
See Notes to Consolidated Financial Statements. 33 PUBLIC SERVICE ELECTRIC AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies Organization Unless the context otherwise indicates, all references to "PSE&G," "we," "us" or "our" herein means Public Service Electric & Gas Company, a New Jersey corporation with its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. We are a wholly-owned subsidiary of Public Service Enterprise Group Incorporated (PSEG) and are an operating public utility providing electric and gas service in certain areas within the State of New Jersey. Following the transfer of our generation-related assets to PSEG Power LLC (Power) in August 2000, we continue to maintain our electric transmission and electric and gas distribution businesses. PSEG owns all of our common stock. Of the 150,000,000 authorized shares of common stock at December 31, 2001 and 2000, there were 132,450,344 shares outstanding. Basis of Presentation Effective August 1, 2000, our presentation of Electric Revenues and Power Supply Costs in our Consolidated Statements of Income has changed due to the transfer of our electric generating facilities and wholesale power contracts to Power. Effective with the transfer, we pay a fixed price for energy and capacity provided by Power under a contract to meet our basic generation service (BGS) obligation through July 31, 2002 and charge such costs to our BGS customers. As a result, we transferred the market risk related to our estimated electric commitments to Power. On February 4, 2002 the New Jersey Board of Public Utilities (BPU) held an auction to determine who will supply BGS to New Jersey Utilities for the one year period subsequent to July 31, 2002, which was approved on February 15, 2002. Through the auction, we successfully secured contracts with multiple suppliers for 100% of our expected peak load for the period. Effective August 1, 1999, the presentation of revenues in our Consolidated Statements of Income had changed due to the deregulation of the electric generation business by the BPU in its Energy Master Plan Proceedings. Effective with that date, electric rates charged to customers have been unbundled and the generation, transmission, distribution and other components of the total rate have become separate charges to our customers. Revenues earned prior to August 1, 1999 continue to be presented as Bundled Electric Revenues on our Consolidated Statements of Income as they were earned based upon bundled electric rates effective for that period. Summary of Significant Accounting Policies Consolidation The Consolidated Financial Statements include our accounts and those of PSE&G Transition Funding LLC (Transition Funding) and our other subsidiaries. We consolidate those entities in which we have a controlling interest. All significant intercompany accounts and transactions are eliminated in consolidation. Regulation We prepare our financial statements in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71 "Accounting for the Effects of Certain Types of Regulation" (SFAS 71). In general, SFAS 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (a regulatory asset) or the recognition of revenues (a regulatory liability) if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future rates. Accordingly, we have deferred certain costs and revenues, which will be 34 PUBLIC SERVICE ELECTRIC AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS amortized over various future periods. To the extent that collection of such costs or payment of liabilities is no longer probable as a result of changes in regulation and/or our competitive position, the associated regulatory asset or liability is charged or credited to income. Our transmission and distribution business continues to meet the requirements for application SFAS 71. Revenues and Fuel Costs Electric and gas revenues are recorded based on services rendered to customers during each accounting period. We record unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period. Prior to August 1, 1999, fuel revenue and expense flowed through the Electric Levelized Energy Adjustment Clause (LEAC) mechanism. Variances in fuel revenues and expenses were subject to deferral accounting and had no direct effect on earnings. Under the LEAC and the Levelized Gas Adjustment Clause (L GAC), any LEAC and LGAC underrecoveries or overrecoveries, together with interest (in the case of net overrecoveries), are deferred and included in operations in the period in which they are reflected in rates. Pursuant to a BPU Order, the fuel component of the LEAC rate was frozen for 1997 and 1998 and we bore all risks associated with fuel prices. Following the transfer of generation-related assets and liabilities in August 2000, we no longer bear the risks and rewards of changes in nuclear and fossil generating fuel costs and replacement power costs. Power Supply Revenues and Costs Power Supply revenues since August 1, 2000 represent the Basic Generation Service (BGS) and Market Transition Charge (MTC) tariff rates charged by us to our customers who are not served by another supplier and Non-Utility Generation Transition Charge (NTC) rates charged by us to our customers to recover the above market costs related to energy purchased by us under various Non-Utility Generation (NUG) Contracts. Power Supply revenues in 2001 also include sales to Power of energy purchased under the NUG Contracts. These sales are made to Power at the Locational Marginal Price (LMP) in the Pennsylvania-New Jersey Maryland Power Pool (PJM) Market. For periods prior to the transfer of the generation business to Power in August 2000, Power Supply revenues include the sales of energy purchased under the NUG contracts at LMP. Any difference between the amounts we pay under the NUG Contracts and the amount we recover through the NTC and sales at LMP are deferred as a regulatory asset or liability. The BGS and MTC revenues are offset by a corresponding expense in Power Supply Costs for the amount paid to Power under our contract with Power pursuant to which Power delivers energy and capacity to us under our full requirements contract (BGS Contract). The costs of energy purchased under the NUG contracts are also included in Power Supply Costs. Cash and Cash Equivalents The December 31, 2001 and 2000 balances consist primarily of cash, working funds and highly liquid marketable securities (commercial paper and money market funds) with an original maturity of three months or less. Restricted Cash Transition Funding has deposited funds with a Trustee which are required to be used for payment of principal, interest and other expenses related to its transition bonds (see Note 3. Regulatory Issues and Accounting Impacts of Deregulation). Accordingly, these funds are classified as "Restricted Cash" on our Consolidated Balance Sheets. Fuel and Materials and Supplies Our fuel and materials and supplies are carried on the books at average cost in accordance with rate-based regulation. 35 PUBLIC SERVICE ELECTRIC AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Depreciation and Amortization We calculate depreciation under the straight-line method based on estimated average remaining lives of the several classes of depreciable property. These estimates are reviewed on a periodic basis and necessary adjustments are made as approved by the BPU. The depreciation rate stated in a percentage of original cost of depreciable property was 3.32% for 2001 and 3.52% for 2000 and 1999. We have certain regulatory assets and liabilities resulting from the use of a level of depreciation expense in the ratemaking process that differs from the amount that is recorded under GAAP for non-regulated companies. Unamortized Loss on Reacquired Debt and Debt Expense Bond issuance costs and associated premiums and discounts are generally amortized over the life of the debt issuance. In accordance with Federal Energy Regulatory Commission (FERC) regulations, our costs to reacquire debt are deferred and amortized over the remaining original life of the retired debt. When refinancing debt, the unamortized portion of the original debt issuance costs of the debt being retired must be amortized over the life of the replacement debt. Gains and losses on reacquired debt are deferred and amortized to interest expense over the period approved for ratemaking purposes. Allowance for Funds Used During Construction (AFDC) AFDC represents the cost of debt and equity funds used to finance the construction of utility facilities. The amount of AFDC capitalized is reported in the Consolidated Statements of Income as a reduction of interest charges for the borrowed funds component and as other income for the equity funds component (if any). The rates used for calculating AFDC in 2001, 2000 and 1999 were 6.71%, 6.45%, and 5.29%, respectively. In 2001, 2000 and 1999, AFDC amounted to $2 million, $1 million and $3 million, respectively. Income Taxes We file a consolidated Federal income tax return with PSEG and income taxes are allocated to us and each of PSEG's other subsidiaries based on the taxable income or loss of each respective subsidiary. Investment tax credits were deferred in prior years and are being amortized over the useful lives of the related property. Property, Plant and Equipment Our additions to property, plant and equipment and replacements that are either retirement units or property record units are capitalized at original cost. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts. At the time units of depreciable property are retired or otherwise disposed, the original cost less net salvage value is charged to accumulated depreciation. Commodity Contracts Effective January 1, 1999 through the transfer of the energy trading business to Power in August 2000, we utilized Emerging Issues Task Force (EITF) Issue 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98-10). EITF 98-10 requires that energy trading contracts not utilized to hedge price risk be marked to market with gains and losses included in current earnings. We engage in natural gas commodity forwards, futures, swaps and options purchases and sales with counterparties to manage exposure to natural gas price risk associated with fluctuations from factors such as weather, changes in demand and changes in supply. These 36 PUBLIC SERVICE ELECTRIC AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS instruments, in conjunction with physical gas supply contracts, are designed to cover estimated gas customer commitments. In accordance with SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities" as amended (SFAS 133), such energy contracts are recognized at fair value as derivative assets or liabilities on the balance sheet. These derivatives, when realized, are recoverable through the LGAC. Accordingly, the offset to the change in fair value of these derivatives is specified as a regulatory asset or liability. In July 2000, EITF 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent" (EITF 99-19), provided guidance on the issue of whether a company should report revenue based on the gross amount billed to the customer or the net amount retained. The guidance states that whether a company should recognize revenue based on the gross amount billed or the net retained requires significant judgment, which depends on the relevant facts and circumstances. Based on the analysis and interpretation of EITF 99-19, we report all of the energy trading revenues and energy trading-related costs on a gross basis for physical bilateral energy and capacity sales and purchases. We continue to report swaps, futures, option premiums, firm transmission rights, transmission congestion credits, and purchases and sales of emission allowances on a net basis. The prior year financial statements have been reclassified accordingly. For additional information regarding commodity-related contracts, See Note 7 - Financial Instruments and Risk Management. Capital Leases as Lessee The Consolidated Balance Sheets include assets and related obligations applicable to capital leases under which the entity is a lessee. Our capital leases primarily relate to our corporate headquarters. The total amortization of the leased assets and interest on the lease obligations equals the net minimum lease payments included in rent expense for capital leases. See Note 8. Commitments and Contingent Liabilities. Impairment of Long-Lived Assets We review long-lived assets for possible impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Upon deregulation, we evaluated the recoverability of our assets and recorded an extraordinary, non-cash charge to earnings. For the impact of the application of SFAS No. 121 "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of" (SFAS 121), see Note 3. Regulatory Issues and Accounting Impacts of Deregulation. Use of Estimates The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions regarding certain types of assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, upon settlement, actual results may differ from estimated amounts. Reclassifications Certain reclassifications of amounts reported in prior periods have been made to conform with the current presentation. Note 2. Accounting Matters In July 2001, the FASB issued SFAS No. 141, "Business Combinations" (SFAS 141). SFAS 141 was effective July 1, 2001 and requires that all business combinations on or after that date be accounted for under the purchase 37 PUBLIC SERVICE ELECTRIC AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS method. Upon implementation of this standard, there was no impact on our financial position or results of operations and we do not believe it will have a substantial effect on our strategy. Also, in July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). Under SFAS 142, goodwill is considered a nonamortizable asset and will be subject to an annual review for impairment and an interim review when required by events or circumstances. SFAS 142 is effective for all fiscal years beginning after December 15, 2001. We do not have any goodwill or other intangible assets on our balance sheet. Therefore, there will be no effect on our financial position or results of operations as a result of adopting this standard. Also in July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). Upon adoption of SFAS 143, the fair value of a liability for an asset retirement obligation is required to be recorded. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. SFAS 143 is effective for fiscal years beginning after June 15, 2002. We are currently evaluating the effect of this guidance and cannot predict the impact on our financial position or results of operations; however, such impact could be material. In August 2001, the FASB issued SFAS No. 144, "Accounting for Impairment or Disposal of Long-Lived Assets" (SFAS 144). Under SFAS 144, long-lived assets to be disposed of should be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continued operations or in discontinued operations. Discontinued operations will no longer be measured at net realizable value or include amounts for operating losses that have not yet occurred. The statement also broadens the reporting of discontinued operations. SFAS 144 is effective for fiscal years beginning after December 15, 2001. We are currently evaluating this guidance and do not believe that it will have a material impact on our financial position or results of operations. Note 3. Regulatory Issues and Accounting Impacts of Deregulation New Jersey Energy Master Plan Proceedings and Related Orders Following the enactment of the New Jersey Electric Discount and Energy Competition Act, the BPU rendered a Final Order relating to our rate unbundling, stranded costs and restructuring proceedings (Final Order). Pursuant to the Final Order, we transferred our electric generating facilities and wholesale power contracts to Power and its subsidiaries on August 21, 2000 in exchange for a promissory note in an amount equal to the purchase price. The generating assets were transferred at the price specified in the BPU order - $2.443 billion plus $343 million for other generation related assets and liabilities. Because the transfer was between affiliates, we recorded the sale at the net book value of the assets and liabilities rather than the transfer price. The difference between the total transfer price and the net book value of the generation-related assets and liabilities was recorded as an equity adjustment on Power's and our Consolidated Balance Sheets. These amounts are eliminated on PSEG's consolidated financial statements. Power paid the promissory note on January 31, 2001. Also in the Final Order, the BPU concluded that we should recover up to $2.94 billion (net of tax) of our generation-related stranded costs through securitization of $2.4 billion and an opportunity to recover up to $540 million (net of tax) of our unsecuritized generation-related stranded costs on a net present value basis. The $540 million is subject to recovery through a market transition charge (MTC). We remit the MTC revenues to Power as part of the BGS contract as provided for by the Final Order. In September 1999, the BPU issued its order approving our petition relating to the proposed securitization transaction (Finance Order) which authorized, among other things, the imposition of a non-bypassable transition 38 PUBLIC SERVICE ELECTRIC AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS bond charge (TBC) on our customers; the sale of our property right in such charge to a bankruptcy-remote financing entity; the issuance and sale of $2.525 billion of transition bonds by such entity as consideration for such property right, including an estimated $125 million of transaction costs; and our application of the transition bond proceeds to retire outstanding debt and/or equity. Transition Funding issued the transition bonds on January 31, 2001 and the TBC and a 2% rate reduction became effective on February 7, 2001 in accordance with the Final Order. An additional 2% rate reduction became effective on August 1, 2001 bringing the total rate reduction to 9% since August 1, 1999. These rate reductions and the TBC were funded through the MTC rate. On January 31, 2001, $2.525 billion of transition bonds (non-recourse asset backed securities) were issued by Transition Funding, in eight classes with maturities ranging from 1 year to 15 years. Also on January 31, 2001, we received payment from Power on the $2.786 billion promissory note used to finance the transfer of our generation business. The proceeds from these transactions were used to pay for certain debt issuance and related costs for securitization, retire a portion of our outstanding short-term debt, reduce our common equity, loan funds to PSEG and make various short-term investments. Extraordinary Charge and Other Accounting Impacts of Deregulation In April 1999, we determined that SFAS 71 was no longer applicable to the electric generation portion of our business in accordance with the requirements of EITF Issue 97-4, "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statements No. 71 and No. 101" (EITF 97-4). Accordingly, we recorded an extraordinary charge to earnings of $804 million (after tax), consisting primarily of the write-down of our nuclear and fossil generating stations in accordance with SFAS 121. As a result of this impairment analysis, the net book value of the generating stations was reduced by approximately $5.0 billion (pre-tax) or $3.1 billion (net of tax). This amount was offset by the creation of a $4.057 billion (pre-tax), or $2.4 billion (net of tax) regulatory asset, as provided for in the Final Order and Finance Order. In addition to the impairment of our electric generating stations, the extraordinary charge consisted of various accounting adjustments to reflect the absence of cost of service regulation in the electric generation portion of our business. The adjustments primarily related to materials and supplies, general plant items and liabilities for certain contractual and environmental obligations. In accordance with the Final Order, we also reclassified a $569 million excess depreciation reserve related to our electric distribution assets from Accumulated Depreciation to a Regulatory Liability. Such amount is being amortized in accordance with the terms of the Final Order over the period from January 1, 2000 to July 31, 2003. Note 4. Regulatory Assets and Liabilities At December 31, 2001 and 2000, respectively, we had deferred the following regulatory assets and liabilities on the Consolidated Balance Sheets:
December -------------------------- 2001 2000 ---------- ----------- (Millions of Dollars) Regulatory Assets ----------------- Stranded Costs To Be Recovered................................ $4,105 $4,057 SFAS 109 Income Taxes......................................... 302 285 OPEB Costs.................................................... 212 232 Societal Benefits Charges (SBC)............................... 4 135 Environmental Costs........................................... 87 13 Unamortized Loss on Reacquired Debt and Debt Expense.......... 92 104 Underrecovered Gas Costs...................................... 120 -- 39 PUBLIC SERVICE ELECTRIC AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December -------------------------- 2001 2000 ---------- ----------- (Millions of Dollars) Regulatory Assets ----------------- Unrealized Losses on Gas Contracts............................ 137 -- Non-Utility Generation Transition Charge (NTC)................ -- 7 Other......................................................... 161 162 ---------- ----------- Total Regulatory Assets................................. $5,220 $4,995 ========== =========== Regulatory Liabilities Excess Depreciation Reserve................................... $319 $444 Non-Utility Generation Transition Charge (NTC)................ 48 -- Overrecovered Gas Costs....................................... -- 26 Other......................................................... 6 -- ---------- ----------- Total Regulatory Liabilities............................ $373 $470 ========== ===========
Stranded Costs To Be Recovered: This reflects the deferred costs to be recovered by the securitization transition charge, which was authorized by the Final Order and Finance Order. SFAS 109 Income Taxes: This amount represents the portion of deferred income taxes that will be recovered through future rates, based upon established regulatory practices, which permit the recovery of current taxes. OPEB Costs: Includes costs associated with adoption of SFAS 106. "Employers' Accounting for Benefits Other Than Pensions which were deferred in accordance with EITF Issue 92-12, "Accounting for OPEB Costs by Rate Regulated Enterprises". Prior to the adoption of SFAS 106, post-retirement benefits costs were recognized on a cash basis. SFAS 106 required that these costs be accrued as the benefits were earned. Accordingly a liability and a regulatory asset were recorded for the total benefits earned at the implementation date. Beginning January 1, 1998, we commenced the amortization of this regulatory asset over 15 years. See Note 10. Pension, Other Postretirement Benefit and Savings Plans for additional information. Societal Benefits Charges (SBC): The SBC includes costs related to our electric distribution business as follows: 1) social programs which include the universal service fund; 2) nuclear plant decommissioning; 3) demand side management (DSM) programs; 4) manufactured gas plant remediation; 5) consumer education; 6) Under and overrecovered electric bad debt expenses; and 7) MTC overrecovery. Environmental Costs: Represents environmental investigation and remediation costs which are probable of recovery in future rates. Unamortized Loss on Reacquired Debt and Debt Expense: Represents bond issuance costs, premiums, discounts and losses on reacquired long-term debt. Underrecovered/Overrecovered Gas Costs: Represents gas costs in excess of or below the amount included in rates and probable of recovery in the future. Unrealized Losses on Gas Contracts: This represents the recoverable portion of unrealized losses associated with contracts used in the company's gas distribution business. Non-Utility Generation Transition Charge (NTC): This clause was established to account for above market costs related to non-utility generation contracts. The charge for the stranded NTC recovery was initially set at $183 million annually. Any NUG contract costs and/or buyouts are charged to the NTC. Proceeds from the sale of the energy and capacity purchased under these NUG contracts are also credited to this account. Other Regulatory Assets: Includes Decontamination and Decommissioning Costs, Plant and Regulatory Study Costs, Repair Allowance Tax Deficiencies and Interest, Property Abandonments, Oil and Gas Property Write-Down and recovery of costs related to Transition Funding's interest rate swap. 40 PUBLIC SERVICE ELECTRIC AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Excess Depreciation Reserve: As required by the BPU, we reduced our depreciation reserve for our electric distribution assets by $569 million and recorded such amount as a regulatory liability to be amortized over the period from January 1, 2000 to July 31, 2003. In 2000 and 2001, $125 million was amortized. The remaining $319 million will be amortized through July 1, 2003. Other Regulatory Liabilities: This includes the following: 1) Interest on amounts collected from customers that are used to fund incentives for choosing a third party gas supplier; 2) Interest on amounts collected early from customers relating to the Transitional Energy Facility Assessment tax; and 3) Amounts collected from customers in order for Transition Funding to obtain a AAA rating on its transition bonds. Note 5. Schedule of Consolidated Capital Stock and Other Securities
Outstanding Current Shares at Redemption December 31, Price Per December 31, December 31, 2001 Share 2001 2000 --------------- ------------ -------------- ---------------- (Millions of Dollars) PSE&G Preferred Securities PSE&G Cumulative Preferred Stock (A) without Mandatory Redemption (B) (C) $100 par value series 4.08%........................................... 146,221 103.00 $15 $15 4.18%........................................... 116,958 103.00 12 12 4.30%........................................... 149,478 102.75 15 15 5.05%........................................... 104,002 103.00 10 10 5.28%........................................... 117,864 103.00 12 12 6.92%........................................... 160,711 -- 16 16 $25 par value series 6.75%........................................... -- -- -- 15 ------------- ---------------- Total Preferred Stock without Mandatory Redemption $80 $95 ============= ================ With Mandatory Redemption (B) (C) $100 Par value series 5.97%........................................... -- -- $-- $75 ------------- ---------------- Total Preferred Stock with Mandatory Redemption... $-- $75 ============= ================ PSE&G Monthly Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures (B) (C) (D) 9.375%.......................................... -- -- $-- $150 8.00%........................................... 2,400,000 25.00 60 60 ------------- ---------------- Total Monthly Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures..... $60 $210 ============= ================ PSE&G Quarterly Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures (B) (C) (D) 8.625%.......................................... -- -- $-- $208 8.125%.......................................... 3,800,000 -- 95 95 ------------- ---------------- Total Quarterly Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures..... $95 $303 ============= ================
(A) At December 31, 2001, there were an aggregate of 6,704,766 aggregates of shares of $100 par value and 10,000,000 shares of $25 par value Cumulative Preferred Stock which were authorized and unissued and which, upon issuance, may or may not provide for mandatory sinking fund redemption. If dividends upon any shares of Preferred Stock are in arrears in an amount equal to the annual dividend thereon, voting rights for the election of a majority of our Board of Directors become operative and continue until all accumulated and unpaid dividends thereon have been paid, whereupon all such voting rights cease, subject to being revived from time to time. 41 PUBLIC SERVICE ELECTRIC AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (B) At December 31, 2001 and 2000, the annual dividend requirement and embedded dividend rate for our Preferred Stock without mandatory redemption was $10,127,383 and 5.03%, $10,886,758 and 5.18%, respectively, and for our Preferred Stock with mandatory redemption was $1,119,375 and 6.02%, $4,477,500 and 6.02%, respectively. At December 31, 2001 and 2000, the annual dividend requirement and embedded cost of the Monthly Income Preferred Securities (Guaranteed Preferred Beneficial Interest in our Subordinated Debentures) were $7,768,750 and 4.90%, $18,862,500 and 5.50% respectively. At December 31, 2001 and 2000, the annual dividend requirement of the Quarterly Income Preferred Securities (Guaranteed Preferred Beneficial Interest in our Subordinated Debentures) and our embedded costs were $16,439,584 and 4.97%, $ 25,658,750 and 5.18% respectively. (C) For information concerning fair value of financial instruments, see Note 7. Financial Instruments and Risk Management. (D) PSE&G Capital L.P., PSE&G Capital Trust I and PSE&G Capital Trust II were formed and are controlled by us for the purpose of issuing Monthly and Quarterly Income Preferred Securities (Monthly and Quarterly Guaranteed Preferred Beneficial Interest in our Subordinated Debentures). The proceeds were loaned to us and are evidenced by our Deferrable Interest Subordinated Debentures. If and for as long as payments on our Deferrable Interest Subordinated Debentures have been deferred, or we have defaulted on the indentures related thereto or its guarantees thereof, we may not pay any dividends on our common and preferred stock. The Subordinated Debentures and the indentures constitute our full and unconditional guarantee of the Preferred Securities issued by the partnership and the trusts. Note 6. Schedule of Consolidated Debt LONG-TERM
December 31, --------------------------------- Interest Rates Maturity 2001 2000 - ------------------------------------------------------ --------------------- -------------- --------------- (Millions of Dollars) PSE&G (excluding Transition Funding): - ------------------------------------- First and Refunding Mortgage Bonds (A): 7.875% 2001................ - 100 6.125% 2002................ 258 258 6.875%-8.875% 2003................ 300 300 6.50% 2004................ 286 286 9.125% 2005................ 125 125 6.75% 2006 ............... 147 147 6.25% 2007 ............... 113 113 Variable 2008-2012........... - 66 6.75%-7.375% 2013-2017........... 330 330 6.45%-9.25% 2018-2022........... 139 139 Variable 2018-2022........... - 14 5.20%-7.50% 2023-2027........... 434 434 5.45%-6.55% 2028-2032........... 499 499 Variable 2028-2032........... - 25 5.00%-8.00% 2033-2037........... 160 160 Medium-Term Notes: 7.19% 2002................ 290 290 42 PUBLIC SERVICE ELECTRIC AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 8.10%-8.16% 2008-2012........... 60 60 7.04% 2018-2022........... 9 9 7.15%-7.18% 2023-2027........... 39 39 -------------- --------------- Total First and Refunding Mortgage Bonds............................ 3,189 3,394 -------------- --------------- Unsecured Bonds-7.43% 2002............... - 300 Unsecured Bonds-Variable 2027............... - 19 -------------- --------------- Total Unsecured Bonds............................................... - 319 -------------- --------------- Principal Amount Outstanding (B)............................................. 3,189 3,713 Amounts Due Within One Year (C).............................................. (547) (100) Net Unamortized Discount..................................................... (16) (23) -------------- --------------- Total Long-Term Debt of PSE&G (excluding Transition Funding) (D)....................................................... $2,626 $3,590 ============== =============== December 31, --------------------------------- Interest Rates Maturity 2001 2000 - ------------------------------------------------------ --------------------- -------------- --------------- Transition Funding (Millions of Dollars) - ------------------ Securitization Bonds (E): 5.46%................................................ 2004................ $52 - 5.74%................................................ 2007................ 369 - 5.98%................................................ 2008................ 183 - LIBOR plus 0.30%..................................... 2011................ 496 - 6.45%................................................ 2013................ 328 - 6.61%................................................ 2015................ 454 - 6.75%................................................ 2016................ 220 - 6.89%................................................ 2017................ 370 - -------------- --------------- Principal Amount Outstanding (B)............................................. 2,472 - Amounts Due Within One Year (E).............................................. (121) - -------------- --------------- Total Long-Term Debt of Transition Funding............................ $2,351 - -------------- --------------- Total Long-Term Debt of PSE&G $4,977 $3,590 ============== ===============
(A) Our First and Refunding Mortgage (Mortgage), securing the Bonds, constitutes a direct first mortgage lien on substantially all of our property and franchises. (B) For information concerning fair value of financial instruments, see Note 7. Financial Instruments and Risk Management. (C) The aggregate principal amounts of mandatory requirements for sinking funds and maturities for each of the five years following December 31, 2001 are as follows:
Transition Year PSE&G Funding Total ---------- --------- ----------- ------- 2002..... $547 $-- $547 2003..... 300 -- 300 2004..... 286 52 338 2005..... 125 -- 125 2006..... 147 -- 147 --------- ----------- ------- $1,405 $52 $1,457 ========= =========== =======
43 PUBLIC SERVICE ELECTRIC AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (D) At December 31, 2001 and 2000, our annual interest requirement on long-term debt of PSE&G was $220 million and $256 million, of which $220 million and $233 million, respectively, was the requirement for Mortgage Bonds. The embedded interest cost on long-term debt on such dates was 7.46% and 7.30%, respectively. The embedded interest cost on long-term debt due within one year at December 31, 2001 was 6.76%. (E) On January 31, 2001, Transition Funding issued $2.525 billion of Bonds in eight classes with estimated final payment dates from one year to fifteen years. The net proceeds were remitted to us as consideration for the property right in the TBC. At December 31, 2001, Transition Funding's annual interest requirement on the securitization bonds was $148 million. The current portion of Transition Funding's debt is based on estimated payment dates, with final estimated payment dates at two years earlier than the final maturity dates for each respective class of Bonds. At December 31, 2001, Transition Funding's annual interest requirement on its bonds was $137 million. SHORT-TERM (Commercial Paper and Bank Loans)
2001 2000 1999 ----------- ----------- ---------- (Millions of Dollars) Principal amount outstanding at year end, primarily commercial paper..... $-- $1,543 $1,475 Weighted average interest rate for short-term debt at year end........... -- 7.29% 6.56%
In March 2001, we reduced the maximum size of our commercial paper program (Program) from $1.5 billion to $900 million. To provide back up liquidity for this program, we maintain $900 million in revolving credit facilities, each of which expire in June 2002. As of December 31, 2001, there were no borrowings outstanding under these facilities. In addition, we have an uncommitted line of credit with a bank. As of December 31, 2001, we had no borrowings against our uncommitted line of credit. Note 7. Financial Instruments and Risk Management Our operations are exposed to market risks from changes in commodity prices and interest rates that could affect our results of operations and financial conditions. We manage our exposure to these market risks through our regular operating and financing activities and, when deemed appropriate, hedge these risks through the use of derivative financial instruments. We use the term hedge to mean a strategy designed to manage risks of volatility in prices or rate movements on certain assets, liabilities or anticipated transactions and by creating a relationship in which gains or losses on derivative instruments are expected to counterbalance the losses or gains on the assets, liabilities or anticipated transactions exposed to such market risks. We use derivative instruments as risk management tools consistent with our business plans and prudent business practices and not for speculative purposes. Fair Value of Financial Instruments The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions at December 31, 2001 and December 31, 2000, respectively.
December 31, 2001 December 31, 2000 ------------------------- --------------------------- Carrying Fair Carrying Fair Amount Value Amount Value ------------ ----------- ------------ ----------- (Millions of Dollars) Long-Term Debt (A): PSE&G................................................. 3,173 3,290 3,453 3,690 Transition Funding.................................... 2,472 2,575 -- -- 44 PUBLIC SERVICE ELECTRIC AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2001 December 31, 2000 ------------------------- --------------------------- Carrying Fair Carrying Fair Amount Value Amount Value ------------ ----------- ------------ ----------- (Millions of Dollars) Preferred Securities Subject to Mandatory Redemption: PSE&G Cumulative Preferred Securities................. -- -- 75 60 Monthly Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures.................... 60 60 210 212 Quarterly Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures.................... 95 96 303 304
(A) Includes current maturities. At December 31, 2001, Transition Funding had an interest rate swap agreement outstanding with a notional amount of $497 million. For additional information regarding consolidated debt, see Note 6. Schedule of Consolidated Debt. For additional information regarding preferred securities, see Note 5. Schedule of Consolidated Capital Stock and Other Securities. Commodity-Related Instruments We use natural gas futures and swaps to reduce exposure to price fluctuations from factors such as weather, changes in demand and changes in supply to manage the price risk associated with gas supply to our customers. These instruments, in conjunction with physical gas supply contracts, are designed to cover estimated gas customer commitments. We have entered into 330 MMBTU of gas futures, swaps and options to hedge forecasted requirements. As of December 31, 2001, the fair value of those instruments was $(137) million with a maximum term of approximately one year. We utilize derivatives to hedge our gas purchasing activities which, when realized, are recoverable through our LGAC. Accordingly, the offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability. As a result of the gas contract transfer that is anticipated to take place in April 2002, our price risk relating to gas purchases will be transferred to Power. As a result, after that date, we will not be utilizing these derivative instruments in our gas distribution business. Through the BGS auction, we have contracted for our expected peak load of 9,600 MW. If our peak load should exceed this amount or one of our suppliers defaults on their contract, we may have to purchase power on the open market and use commodity contracts during periods of high demand. To the extent that the market prices exceed the auction contract price, the difference will be deferred and collected from our customers as provided in the BPU Order approving the auction process. Given the absence of a PJM price cap in situations involving emergency purchases and the potential for plant outages, extreme price movements can occur and could have a material impact on our financial condition and net cash flows. Interest Rates We are subject to the risk of fluctuating interest rates in the normal course of business. Our policy is to manage interest rate risk through the use of fixed rate debt, floating rate debt and interest rate swaps. As of December 31, 2001, a hypothetical 10% change in market interest rates would result in a $4 million change in annual interest costs related to our short-term and floating rate debt. Transition Funding has entered into an interest rate swap on its sole class of floating rate transition bonds. The notional amount of the interest rate swap is approximately $497 million. The interest rate swap is indexed to the three-month LIBOR rate. The fair value of the interest rate swap was approximately $(18) million as of December 31, 2001 and was recorded as a derivative liability, with an offsetting amount recorded as a regulatory asset on the Consolidated Balance Sheet. This amount will vary over time as a result of changes in market conditions. 45 PUBLIC SERVICE ELECTRIC AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 8. Commitments and Contingent Liabilities Hazardous Waste The New Jersey Department of Environmental Protection (NJDEP) regulations concerning site investigation and remediation require an ecological evaluation of potential injuries to natural resources in connection with a remedial investigation of contaminated sites. The NJDEP is presently working with industry to develop procedures for implementing these regulations. These regulations may substantially increase the costs of remedial investigations and remediations, where necessary, particularly at sites situated on surface water bodies. We and predecessor companies owned and/or operated certain facilities situated on surface water bodies, certain of which are currently the subject of remedial activities. The financial impact of these regulations on these projects is not currently estimable. We do not anticipate that compliance with these regulations will have a material adverse effect on our financial position, results of operations or net cash flows. Manufactured Gas Plant Remediation Program We are currently working with the NJDEP under a program (Remediation Program) to assess, investigate and, if necessary, remediate environmental conditions at our former manufactured gas plant sites. To date, 38 sites have been identified. The Remediation Program is periodically reviewed and revised by us based on regulatory requirements, experience with the Remediation Program and available remediation technologies. The long-term costs of the Remediation Program cannot be reasonably estimated, but experience to date indicates that approximately $20 million per year could be incurred over a period of about 30 years since inception of the program in 1988 and that the overall cost could be material. The costs for this remediation effort are recovered through the SBC. Net of insurance recoveries, costs incurred from January 1, 2001 through December 31, 2001 for the Remediation Program amounted to approximately $22.8 million. Net of insurance recoveries, total project costs incurred through December 31, 2001 for the Remediation Program amounted to approximately $164.6 million. In addition, at December 31, 2001, our estimated liability for remediation costs through 2004, excluding insurance recoveries, aggregated $87 million. Expenditures beyond 2004 cannot reasonably be estimated. Passaic River Site The United States Environmental Protection Agency (EPA) has determined that a six mile stretch of the Passaic River in the area of Newark, New Jersey is a "facility" within the meaning of that term under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 and that, to date, at least thirteen corporations, including us, may be potentially liable for performing required remedial actions to address potential environmental pollution at the Passaic River "facility." We and certain of our predecessors conducted industrial operations at properties within the Passaic River "facility." The operations include one operating electric generating station, one former generating station, and four former manufactured gas plant sites. We cannot predict what action, if any, the EPA or any third party may take against it with respect to these matters, or in such event, what costs it may incur to address any such claims. However, such costs may be material. 46 PUBLIC SERVICE ELECTRIC AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Minimum Lease Payments We lease administrative office space under various operating leases with future minimum lease payments of: (Millions of Dollars) 2002 $3 2003 3 2004 2 2005 2 2006 2 Thereafter 1 ----------- Total minimum lease payments....... $13 =========== We have entered into a capital lease for administrative office space. The total future minimum payments and present value of this capital lease as of December 31, 2001 are: (Millions of Dollars) 2002 $8 2003 8 2004 8 2005 8 2006 8 Thereafter 62 ----------- Total minimum lease payments........ 102 ----------- Less: Imputed Interest (42) ----------- Present Value of net minimum lease payments $60 =========== Note 9. Income Taxes A reconciliation of reported income tax expense with the amount computed by multiplying pretax income by the statutory Federal income tax rate of 35% is as follows:
2001 2000 1999 ----------- ------------ ---------- (Millions of Dollars) Net Income (Loss).......................................................... $235 $587 $(151) Extraordinary Item (Net of Tax of $345)............................... -- -- 804 ----------- ------------ ---------- Net Income before Extraordinary Item....................................... 235 587 653 ----------- ------------ ---------- Income Taxes: Federal - Current..................................................... 250 261 425 Deferred ................................................... (192) 50 (1) ITC......................................................... (2) (1) (11) ----------- ------------ ---------- Total Federal............................................ 56 310 413 ----------- ------------ ---------- State - Current....................................................... 42 150 109 Deferred...................................................... (9) (53) (12) ----------- ------------ ---------- Total State.............................................. 33 97 97 ----------- ------------ ---------- Total ........................................................... 89 407 510 ----------- ------------ ---------- Pretax income.............................................................. $324 $994 $1,163 =========== ============ ==========
PUBLIC SERVICE ELECTRIC AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Reconciliation between total income tax provisions and tax computed at the statutory tax rate on pretax income:
2001 2000 1999 ----------- -------------- ------------ (Millions of Dollars) Tax computed at the statutory rate......................................... $113 $348 $407 Increase (decrease) attributable to flow through of certain tax adjustments: Plant Related......................................................... (41) (15) 35 Amortization of investment tax credits................................ (2) (1) (11) New Jersey Corporate Business Tax..................................... 21 58 68 Other................................................................. (2) 17 11 ----------- -------------- ------------ Subtotal......................................................... (24) 59 103 ----------- -------------- ------------ Total income tax provisions...................................... $89 $407 $510 =========== ============== ============ Effective income tax rate.................................................. 27.5% 40.9% 43.9%
We provide deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities irrespective of the treatment for ratemaking purposes. Management believes that it is probable that the accumulated tax benefits that previously have been treated as a flow-through item to our customers will be recovered from utility customers in the future. Accordingly, an offsetting regulatory asset was established. As of December 31, 2001, we have a deferred tax liability and an offsetting regulatory asset of $302 million representing the tax costs expected to be recovered through future rates based upon established regulatory practices, which permit recovery of current taxes. This amount was determined using the enacted Federal income tax rate of 35% and State income tax rate of 9%. SFAS 109 The following is an analysis of deferred income taxes:
December 31, ------------------------------- 2001 2000 ------------- -------------- Deferred Income Taxes (Millions of Dollars) - --------------------- Assets: Current (net)................................................ $21 $23 Non-current: Unrecovered Investment Tax Credits......................... 19 20 New Jersey Corporate Business Tax.......................... 407 395 Other Post-Retirement Benefit Costs........................ 83 64 Market Transition Charge................................... 59 40 Total Non-current....................................... 568 519 ------------- -------------- Total Assets............................................ 589 542 ------------- -------------- Liabilities: Non-current: Plant Related Items........................................ 1,228 1,245 Securitization-EMP......................................... 1,594 1,657 Conservation Costs......................................... 24 124 Pension Costs.............................................. 70 55 Taxes Recoverable Through Future Rates (Net)............... 130 90 Other (Net)................................................ 17 (10) ------------- -------------- Total Non-current....................................... 3,063 3,161 ------------- -------------- Total Liabilities....................................... 3,063 3,161 ------------- -------------- Summary--Deferred Income Taxes Net Current Asset............................................ 21 23 Net Non-current Liability.................................... 2,495 2,642 ------------- -------------- Total................................................... $2,474 $2,619 ============= ==============
47 PUBLIC SERVICE ELECTRIC AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The balance of Federal income tax receivable from PSEG was $16 million and $12 million as of December 31, 2001 and December 31, 2000, respectively. Note 10. Pension, Other Postretirement Benefit and Savings Plans Our employees participate in non-contributory pension plans sponsored by PSEG and administered by PSEG Services Corporation. In addition, PSEG sponsors two defined contribution plans. Our represented employees are eligible for participation in the PSEG Employee Savings Plan (Savings Plan), while our non-represented employees are eligible for participation in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). These plans are 401(k) plans to which eligible employees may contribute up to 25% of their compensation. Employee contributions up to 7% for Savings Plan participants and up to 8% for Thrift Plan participants are matched with employer contributions of cash or PSEG common stock equal to 50% of such employee contributions. For periods prior to March 1, 2002, employer contributions related to participant contributions in excess of 5% and up to 7%, were made in shares of PSEG common stock for Savings Plan participants. For periods prior to March 1, 2002, employer contributions, related to participant contributions in excess of 6% and up to 8%, were made in shares of PSEG common stock for Thrift Plan participants. Beginning on March 1, 2002, and thereafter, all employer contributions will be made in cash to each plan. Pension costs amounted to $30 million and $17 million for the years ended December 31, 2001 and 2000, respectively. Thrift and Savings Plan matching costs amounted to approximately $12 million and $11 million for the years ended December 31, 2001 and 2000, respectively. SFAS No. 106, which requires that the expected cost of employees' postretirement health care and life insurance benefits, also referred to as other postretirement benefits (OPEB), be charged to income during the years in which employees render service. Such costs were deferred through December 31, 1997, pursuant to an order from the BPU. In concert with the discontinuance of SFAS 71, the portion of the resulting regulatory asset allocated to Power prior to the transfer of the electric generation assets remained with us as recovery of these previously incurred costs will be through our regulated transmission and distribution operations. OPEB costs amounted to $95 million and $109 million for the years ended December 31, 2001 and 2000, respectively. Note 11. Financial Information by Business Segments Basis of Organization The reportable segments were determined by Management in accordance with SFAS No. 131, "Disclosures About Segments of an Enterprise and Related Information" (SFAS 131). The separation of the electric segment data prior to August 1, 1999 into our Generation, Energy Resources and Trade and Transmission and Distribution segments was based on estimates and allocations. Generation This segment earns revenue through the sale of our energy and capacity. Effective with the transfer of our generation-related assets to Power in August 2000, we have no further operations in this segment. Trading This segment markets electricity, capacity, ancillary services and natural gas products on a wholesale basis throughout the Eastern and Midwestern United States. Effective with the transfer of our generation-related assets in August 2000, we have no further operations in this segment. 48 PUBLIC SERVICE ELECTRIC AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Transmission and Distribution (T&D) This segment represents our provision of regulated utility services. The electric transmission and electric and gas distribution segment of our business generates revenue from our tariffs under which we provide such services to residential, commercial and industrial customers in New Jersey. The rates charged for electric transmission are regulated by FERC while the rates charged for electric and gas distribution are regulated by the BPU. Revenues are also earned from a variety of other activities such as sundry sales, the appliance service business, wholesale transmission services and other miscellaneous services. Information related to the segments of our business is detailed below:
Consolidated Generation Trading T&D Total ------------- --------- --------- ------------- For the Year Ended December 31, 2001: - ------------------------------------- Total Operating Revenues............. $-- $-- $6,091 $6,091 Depreciation and Amortization........ -- -- 384 384 Interest Income...................... -- -- 21 21 Net Interest Charges................. -- -- 356 356 Operating Income Before Income -- -- 324 324 Taxes................................ Income Taxes......................... -- -- 89 89 Segment Net Income................... -- -- 235 235 Gross Additions to Long-Lived Assets. -- -- 398 398 As of December 31, 2001: - ------------------------------------- Total Assets......................... $-- $-- $12,936 $12,936 For the Year Ended December 31, 2000: Total Operating Revenues............. $1,110 $1,521 $4,728 $7,359 Depreciation and Amortization........ 77 -- 214 291 Interest Income...................... 1 -- 21 22 Net Interest Charges................. 46 -- 208 254 Operating Income Before Income 310 46 638 994 Taxes................................ Income Taxes......................... 128 19 260 407 Segment Net Income (Loss)............ 182 27 378 587 Gross Additions to Long-Lived Assets. -- -- 401 401 As of December 31, 2000: - ------------------------------------- Total Assets...................... $-- $-- $15,267 $15,267 For the Year Ended December 31, 1999: - ------------------------------------- Total Operating Revenues............. $2,602 $1,842 $3,196 $7,640 Depreciation and Amortization........ 224 -- 305 529 Interest Income...................... -- -- 12 12 Net Interest Charges................. 112 -- 275 387 Operating Income Before Income 768 39 356 1,163 Taxes................................ Income Taxes......................... 275 16 219 510 Segment Income before 493 23 137 653 Extraordinary Item................... Extraordinary Item (A)............... (3,204) -- 2,400 (804) Segment Net Income (Loss)............ (2,711) 23 2,537 (151) Gross Additions to Long-Lived Assets. 92 -- 387 479
(A) See Note 3. Regulatory Issues and Accounting Impact of Deregulation for discussion of the extraordinary charge recorded by the generation segment in 1999 and the related regulatory asset for securitization recorded by the T&D segment. 49 PUBLIC SERVICE ELECTRIC AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 12. Property, Plant and Equipment and Jointly Owned Facilities We have ownership interests in and are responsible for providing our share of the necessary financing for the following jointly owned facilities. All amounts reflect the share of our jointly owned projects and the corresponding direct expenses are included in the Statements of Income as operating expenses. Information related to our Property, Plant and Equipment is detailed below:
2001 2000 --------------- ----------------- Property, Plant and Equipment Electric Plant in Service: Transmission........................... $1,201 $1,183 Distribution........................... 4,254 4,056 --------------- ----------------- Total Electric Plant in Service... 5,455 5,239 --------------- ----------------- Construction Work in Progress............ 26 43 Plant Held for Future Use................ 20 20 --------------- ----------------- Total Electric Plant ............. 5,501 5,302 --------------- ----------------- Gas Plant in Service: Transmission........................... 74 69 Distribution........................... 3,121 2,978 Other.................................. 89 130 --------------- ----------------- Total Gas Plant in Service........ 3,284 3,177 --------------- ----------------- Other Plant in Service................... 385 420 --------------- ----------------- Total Property, Plant and Equipment $9,170 $8,899 =============== =================
Information related to Jointly Owned Facilities is detailed below:
Plant - December 31, 2001 Plant - December 31, 2000 ------------------------------------------------------------ Ownership Accumulated Accumulated Interest Plant Depreciation Plant Depreciation ------------- ------------------------------------------------------------ (Millions of Dollars) Transmission Facilities... Various $80 $30 $97 $33 Linden SNG Plant.......... 90.00% 5 4 16 15
50 PUBLIC SERVICE ELECTRIC AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 13. Selected Quarterly Data (Unaudited) The information shown below, in our opinion, includes all adjustments, consisting only of normal recurring accruals, necessary to a fair presentation of such amounts. Due to the seasonal nature of the utility business, quarterly amounts vary significantly during the year.
Calendar Quarter Ended ---------------------------------------------------------------------------------------- March 31, June 30, September 30, December 31, --------------------- --------------------- --------------------- ---------------------- 2001 2000 2001 2000 2001 2000 2001 2000 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------- (Millions of Dollars) Operating Revenues........... $1,952 $2,265 $1,311 $1,992 $1,395 $1,466 $1,433 $1,636 Operating Income............. 247 522 150 361 160 214 125 171 Net Income................... 112 250 32 152 65 99 27 86 Earnings Available to PSEG... 109 248 31 150 65 97 26 84
Note 14. Related-Party Transactions In August 2000, we transferred our electric generating assets to Power in exchange for a $2.786 billion Promissory Note. Interest on the Promissory Note was payable at an annual rate of 14.23%, which represented our weighted average cost of capital. For the period from January 1, 2001 to January 31, 2001, we recorded interest income of approximately $34 million relating to the Promissory Note. Power repaid the Promissory Note on January 31, 2001. In addition, on January 31, 2001, we loaned $1.084 billion to PSEG at 14.23% per annum and recorded interest income of approximately $33 million relating to the loan in 2001. PSEG repaid the loan on April 16, 2001. We also returned $2.265 billion of capital to PSEG on January 31, 2001 utilizing proceeds from the $2.525 billion securitization transaction and the generation asset transfer, as required by the Final Order, as part of the recapitalization. (See Note 3. Regulatory Issues and Accounting Impacts of Deregulation). Effective with the transfer of the electric generation business, Power charges us for MTC and the energy and capacity provided to meet our BGS requirements. For the years ended December 31, 2001 and 2000, we were charged by Power approximately $2 billion and $0.8 billion for MTC and BGS. As of December 31, 2001 and 2000, our payable to Power relating to these costs was approximately $158 million and $159 million. For the years ended December 31, 2001 and 2000, we sold energy and capacity to Power at the market price of approximately $158 million and $78 million, which we purchased under various NUG contracts at costs above market prices. As of December 31, 2001 and 2000, our receivable related to these purchases was approximately $7 million and $17 million. As a result of the Final Order, we have established an NTC to recover the above market costs related to these NUG contracts. The difference between our costs and recovery of costs through the NTC and sales to Power, which are priced at the locational marginal price (LMP) set by the PJM ISO for energy and at wholesale market prices for capacity, is deferred as a regulatory asset. PSEG Services Corporation provides and bills administrative services to us on a monthly basis. Our costs related to such service amounted to approximately $385 million for the year ended December 31, 2001. As of December 31, 2001 our related party payable related to these costs was approximately $37 million. PUBLIC SERVICE ELECTRIC AND GAS COMPANY FINANCIAL STATEMENT RESPONSIBILITY Our management is responsible for the preparation, integrity and objectivity of our consolidated financial statements and related notes. The consolidated financial statements and related notes are prepared in accordance with generally accepted accounting principles. The financial statements reflect estimates based upon the judgment of management where appropriate. Management believes that the consolidated financial statements and related notes present fairly our financial position and results of operations. Information in other parts of this Annual Report is also the responsibility of management and is consistent with these consolidated financial statements and related notes. The firm of Deloitte & Touche LLP, independent auditors, is engaged to audit our consolidated financial statements and related notes and issue a report thereon. Deloitte & Touche's audit is conducted in accordance with generally accepted auditing standards. Management has made available to Deloitte & Touche all the corporation's financial records and related data, as well as the minutes of directors' meetings. Furthermore, management believes that all representations made to Deloitte & Touche during its audit were valid and appropriate. Management has established and maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded, and that transactions are executed in accordance with management's authorization and recorded properly for the prevention and detection of fraudulent financial reporting, so as to maintain the integrity and reliability of the financial statements. The system is designed to permit preparation of consolidated financial statements and related notes in accordance with generally accepted accounting principles. The concept of reasonable assurance recognizes that the costs of a system of internal accounting controls should not exceed the related benefits. Management believes the effectiveness of this system is enhanced by an ongoing program of continuous and selective training of employees. In addition, management has communicated to all employees its policies on business conduct, safeguarding assets and internal controls. The Internal Auditing Department of PSEG Services conducts audits and appraisals of accounting and other operations and evaluates the effectiveness of cost and other controls and, where appropriate, recommends to management improvements thereto. Management has considered the internal auditors' and Deloitte & Touche's recommendations concerning the corporation's system of internal accounting controls and has taken actions that are cost-effective in the circumstances to respond appropriately to these recommendations. Management believes that, as of December 31, 2001, the corporation's system of internal accounting controls was adequate to accomplish the objectives discussed herein. The Board of Directors carries out its responsibility of financial overview through the Audit Committee of PSEG, which presently consists of six directors who are not our employees of or employees of any of our affiliates. The PSEG Audit Committee meets periodically with management as well as with representatives of the internal auditors and Deloitte & Touche. The Audit Committee reviews the work of each to ensure that their respective responsibilities are being carried out and discusses related matters. Both the internal auditors and Deloitte & Touche, periodically meet alone with the Audit Committee and have free access to the Audit Committee and its individual members at all times. E. JAMES FERLAND ROBERT E. BUSCH Chairman of the Board and Senior Vice President - Finance Chief Executive Officer and Chief Financial Officer PATRICIA A. RADO Vice President and Controller (Chief Accounting Officer) February 15, 2002 51 PUBLIC SERVICE ELECTRIC AND GAS COMPANY INDEPENDENT AUDITORS' REPORT To the Board of Directors of Public Service Electric and Gas Company: We have audited the consolidated balance sheets of Public Service Electric and Gas Company and its subsidiaries (the "Company") as of December 31, 2001 and 2000, and the related consolidated statements of income, common stockholder's equity and cash flows for each of the three years in the period ended December 31, 2001. Our audits also included the consolidated financial statement schedule listed in the Index in Item 14(B)(a). These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and the consolidated financial statement schedule based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein. We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheets of the Company as of December 31, 1999, 1998, and 1997, and the related consolidated statements of income, common stockholder's equity and cash flows for the years ended December 31, 1998 and 1997 (none of which are presented herein), and we expressed unqualified opinions on those consolidated financial statements. In our opinion, the information set forth in the Selected Financial Data for each of the five years in the period ended December 31, 2001, presented in Item 6, is fairly stated in all material respects, in relation to the consolidated financial statements from which it has been derived. DELOITTE & TOUCHE LLP Parsippany, New Jersey February 15, 2002 52 PUBLIC SERVICE ELECTRIC AND GAS COMPANY ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS Directors Below is shown as to each present director information recording each director's period of service as a director of PSE&G, age as of April 16, 2002, present committee memberships, business experience during the last five years and other present directorships. E. JAMES FERLAND has been a director since 1986. Age 60. and has been Chairman of the Board, President and Chief Executive Officer of PSEG since July 1986, Chairman of the Board and Chief Executive Officer of PSE&G since July 1986, Chairman of the Board and Chief Executive Officer of Energy Holdings since June 1989, Chairman of the Board and Chief Executive Officer of Power since June 1999 and Chairman of the Board and Chief Executive Officer of Services since November 1999. Director of Foster Wheeler Ltd. ALBERT R. GAMPER, JR. has been a director since December 2000. Age 59. Director of PSEG. Has been President and Chief Executive Officer of the CIT Group, Inc., Livingston, New Jersey (commercial finance company), since February 2002. Was President and Chief Executive Officer of Tyco Capital Corporation from June 2001 to February 2002. Was Chairman of the Board, President and Chief Executive Officer of the CIT Group, Inc., from January 2000 to June 2001. Was President and Chief Executive Officer of the CIT Group, Inc. from December 1989 to December 1999. During 2001, Albert R. Gamper, Jr. was late in filing a Form 3 in accordance with the requirements of Section 16(a) of the Securities and Exchange Act of 1934, as amended, to report any ownership of PSE&G Preferred Stock, upon election as a Director. At the time of his election as a Director, Mr. Gamper did not own any Preferred Stock. CONRAD K. HARPER has been a director since May 1997. Age 61. Director of PSEG. Has been a partner in the law firm of Simpson Thacher & Bartlett, New York, New York since October 1996 and from 1974 to May 1993. Was Legal Adviser, U.S. Department of State from May 1993 to June 1996. Director of New York Life Insurance Company. MARILYN M. PFALTZ has been a director since 1980. Age 69. Director of PSEG. Has been a partner of P and R Associates, Summit, New Jersey (communications specialists), since 1968. Director of AAA National Association, AAA Investment Company, AAA Life Re Ltd. and Beacon Trust Company. 53 PUBLIC SERVICE ELECTRIC AND GAS COMPANY Executive Officers The following table sets forth certain information concerning the executive officers of PSE&G.
============================================================================================================================ AGE EFFECTIVE DATE FIRST ELECTED NAME DECEMBER 31, 2001 OFFICE TO PRESENT POSITION ============================================================================================================================ E. James Ferland 59 Chairman of the Board and Chief July 1986 to present Executive Officer (PSE&G) ---------------------------------------------------------------------------------------------------------------------------- R. Edwin Selover 56 Senior Vice President and General January 1988 to present Counsel (PSE&G) ---------------------------------------------------------------------------------------------------------------------------- Alfred C. Koeppe 55 President and Chief Operating February 2000 to present Officer (PSE&G) Senior Vice President--Corporate October 1996 to February 2000 Services and External Affairs (PSE&G) Senior Vice President--External October 1995 to October 1996 Affairs (PSE&G) ---------------------------------------------------------------------------------------------------------------------------- Robert E. Busch 55 Senior Vice President and March 1998 to present Chief Financial Officer (PSE&G) ---------------------------------------------------------------------------------------------------------------------------- Patricia A. Rado 59 Vice President and Controller April 1993 to present (PSE&G) ----------------------------------------------------------------------------------------------------------------------------
ITEM 11. EXECUTIVE COMPENSATION Information regarding the compensation of the Chief Executive Officer and the four most highly compensated executive officers of PSE&G as of December 31, 2001 is set forth below. Amounts shown were paid or awarded for all services rendered to PSEG and its subsidiaries and affiliates including PSE&G.
=================================================================================================================== Long Term Compensation ----------------------------------- Annual Compensation Awards Payouts -------------------------------------------------------------- Bonus/Annual LTIP All Other Incentive Restricted Options Payouts Compensation Name and Principal Position Year Salary $ Award ($)(1) Stock ($) (#) (2) ($) (3) ($) (4) ------------------------------------------------------------------------------------------------------------------- E. James Ferland 2001 962,525 1,023,000 2,248,000(5) 350,000 400,800 51,152 Chairman of the Board and Chief 2000 890,000 1,001,300 0 300,000 361,440 59,037 Executive Officer 1999 815,000 733,500 0 215,000 304,720 29,292 ------------------------------------------------------------------------------------------------------------------- R. Edwin Selover 2001 367,852 225,000 0 70,000 100,200 6,867 Senior Vice President and 2000 325,000 170,600 0 40,000 81,324 17,280 General Counsel 1999 310,000 162,800 0 35,000 65,632 12,828 ------------------------------------------------------------------------------------------------------------------- Alfred C. Koeppe 2001 358,654 270,000 0 75,000 100,200 6,803 President and Chief Operating 2000 340,000 255,000 0 310,000 90,360 6,805 Officer 1999 290,000 152,300 0 75,000 75,008 6,404 ------------------------------------------------------------------------------------------------------------------- Robert E. Busch 2001 335,482 262,500 0 315,000 60,120 6,803 Senior Vice President and 2000 300,000 157,500 0 40,000 0 6,805 Chief Financial Officer 1999 275,000 144,400 0 26,500 0 6,402 ------------------------------------------------------------------------------------------------------------------- Patricia A. Rado 2001 209,835 94,500 0 25,000 24,048 6,449 Vice President and Controller 2000 200,000 90,000 0 15,000 18,072 7,289 1999 192,000 72,000 0 15,000 18,072 6,609 -------------------------------------------------------------------------------------------------------------------
54 PUBLIC SERVICE ELECTRIC AND GAS COMPANY (1) Amount awarded in 2001 was earned under the Restated and Amended Management Incentive Compensation Plan and in 2000 and 1999 was earned under the Management Incentive Compensation Plan and determined and paid in the following year based on individual performance and financial and operating performance of PSEG and us, including comparison to other companies. (2) All grants of options to purchase shares of PSEG Common Stock were non-qualified options made under the 1989 Long-Term Incentive Plan (1989 LTIP) or the 2001 Long-Term Incentive Plan (2001 LTIP). All options granted were non-tandem. Non-tandem grants are made without performance units and dividend equivalents. (3) Amount paid in proportion to options exercised, if any, based on value of previously granted performance units and dividend equivalents under the 1989 LTIP, each as measured during three-year period ending the year prior to the year in which payment is made. Under the 1989 LTIP, tandem grants are made with an equal number of performance units and dividend equivalents which may provide cash payments, dependent upon future financial performance of PSEG in comparison to other companies and dividend payments by PSEG, to assist recipients in exercising options granted. The tandem grant is made at the beginning of a three-year performance period and cash payment of the value of such performance units and dividend equivalents is made following such period in proportion to the options, if any, exercised at such time. (4) Includes employer contribution to the Thrift and Tax-Deferred Savings Plan:
======================================================================================================== Ferland Selover Koeppe Busch Rado -------------------------------------------------------------------------------------------------------- Year ($) ($) ($) ($) ($) -------------------------------------------------------------------------------------------------------- 2001 5,102 5,104 6,803 6,803 6,449 -------------------------------------------------------------------------------------------------------- 2000 5,102 4,747 6,805 6,805 6,422 -------------------------------------------------------------------------------------------------------- 1999 4,801 4,802 6,404 6,402 6,390 ========================================================================================================
In addition, 2001, 2000 and 1999 amounts include for Mr. Ferland, $46,050, $53,935, and $24,491; for Mr. Selover $1,763, $12,533, and $8,026; and for Mrs. Rado $0, $867, and $219, respectively, representing earnings credited on compensation deferred under PSE&G's Deferred Compensation Plan in excess of 120% of the applicable Federal long-term interest rate as prescribed under Section 1274(d) of the Internal Revenue Code. Prior to January 1, 2000, under our Deferred Compensation Plan, interest is paid at prime rate plus 1/2%, adjusted quarterly. Effective January 1, 2000, the Plan was amended to permit participants to select from among four additional investment options for compensation that is deferred. (5) Value as of original grant date, based on the closing price of $40.80 on the New York Stock Exchange on November 20, 2001, with respect to an award to Mr. Ferland of 60,000 shares of restricted stock, of which 30,000 shares vest in 2006 and 30,000 shares vest in 2007. Dividends on the entire grant are paid in cash from the date of award.
========================================================================================================== OPTION GRANTS IN LAST FISCAL YEAR (2001) ========================================================================================================== Number of % of Total Securities Options Underlying Granted to Exercise or Grant Date Options Employees in Base Price Expiration Present Value Name Granted Fiscal Year ($/Sh) Date ($) (3) ---------------------------------------------------------------------------------------------------------- E. James Ferland 350,000(1) 12.4 40.78 12/18/11 2,205,000 ---------------------------------------------------------------------------------------------------------- R. Edwin Selover 70,000 2.5 40.78 12/18/11 441,000 ---------------------------------------------------------------------------------------------------------- Alfred C. Koeppe 75,000(1) 2.6 40.78 12/18/11 472,500 ---------------------------------------------------------------------------------------------------------- Robert E. Busch 65,000(1) 2.3 40.78 12/18/11 409,500 250,000(2) 8.8 46.23 4/24/11 1,880,000 ---------------------------------------------------------------------------------------------------------- Patricia A. Rado 25,000 0.9 40.78 12/18/11 157,500 ==========================================================================================================
55 PUBLIC SERVICE ELECTRIC AND GAS COMPANY (1) Granted under LTIP with exercisability commencing December 18, 2002, December 18, 2003 and December 18, 2004, respectively, with respect to one-third of the options at each such date. (2) Granted under 1989 LTIP not in tandem with performance units and dividend equivalents, with exercisability commencing April 24, 2002, April 24, 2003, April 24, 2004, April 24, 2005 and April 24, 2006, respectively, with respect to one-fifth of the options at each such date. (3) Determined using the Black-Scholes model, incorporating the following material assumptions and adjustments: (a) exercise prices of $40.78 and $46.23, equal to the fair market value of the underlying PSEG Common Stock on the respective dates of grant; (b) an option term of ten years on all grants; (c) interest rates of 5.02% and 5.14% that represent the interest rates on U.S. Treasury securities on the respective dates of grant with a maturity date corresponding to that of the option terms; (d) volatility of 26.07% and 25.30% calculated using daily PSEG Common Stock prices for the one-year period prior to the respective grant dates; (e) dividend yields of 5.30% and 4.67% and (f) reductions of approximately 7.38% and 11.38% to reflect the probability of forfeiture due to termination prior to vesting, and approximately 8.70% and 9.78% to reflect the probability of a shortened option term due to termination of employment prior to the option expiration dates. Actual values which may be realized, if any, upon any exercise of such options, will be based on the market price of PSEG Common Stock at the time of any such exercise and thus are dependent upon future performance of PSEG Common Stock. There is no assurance that any such value realized will be at or near the value estimated by the Black-Scholes model utilized.
================================================================================================================== AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR (2001) AND FISCAL YEAR END OPTION VALUES (12/31/01) ------------------------------------------------------------------------------------------------------------------ Value of Unexercised Number of Unexercised In-the-Money Options Options at FY-End (#) (1) At FY-End ($) (3) ------------------------------------------------------------- ------------------------------------------------------------- Shares Acquired Value on Exercise Realized Exercisable Unexercisable Exercisable Unexercisable Name (#)(1) ($)(2) (#) (#) ($) (3) ($) (3) ------------------------------------------------------------------------------------------------------------------ E. James Ferland 10,000 122,875 493,333 621,667 2,993,689 1,143,161 ------------------------------------------------------------------------------------------------------------------ R. Edwin Selover 2,500 29,419 71,667 108,333 409,726 204,461 ------------------------------------------------------------------------------------------------------------------ Alfred C. Koeppe 2,500 29,344 155,000 340,000 651,463 332,375 ------------------------------------------------------------------------------------------------------------------ Robert E. Busch 1,500 10,575 45,000 350,000 194,249 167,189 ------------------------------------------------------------------------------------------------------------------ Patricia A. Rado 600 6,838 23,000 40,000 113,670 80,575 ==================================================================================================================
(1) Does not reflect any options granted and/or exercised after year-end (12/31/01). The net effect of any such grants and exercises is reflected in the table appearing under Security Ownership of Directors, Management and Certain Beneficial Owners. (2) Represents difference between exercise price and market price of PSEG Common Stock on date of exercise. (3) Represents difference between market price of PSEG Common Stock and the respective exercise prices of the options at fiscal year end (12/31/01). Such amounts may not necessarily be realized. Actual values which may be realized, if any, upon any exercise of such options will be based on the market price of PSEG Common Stock at the time of any such exercise and thus are dependent upon future performance of PSEG Common Stock. Employment Contracts and Arrangements PSEG has entered into an employment agreement dated as of June 16, 1998 and amended as of November 20, 2001 (Agreement) with Mr. Ferland covering his employment as Chief Executive Officer through March 31, 2007. Under the Agreement, Mr. Ferland has agreed not to retire prior to March 31, 2002, but may retire thereafter. The Agreement provides that Mr. Ferland will be re-nominated for election as a Director during his employment under the Agreement. The Agreement provides that Mr. Ferland's base salary, target annual incentive bonus and long term incentive bonus will be determined based on compensation practices for CEO's of similar companies and that his annual salary will not be reduced during the term of the Agreement. The Agreement also provided for an award to him of 150,000 shares of restricted PSEG Stock as of June 16, 1998 and 60,000 shares of restricted PSEG Common 56 PUBLIC SERVICE ELECTRIC AND GAS COMPANY Stock as of November 20, 2001, of which 60,000 shares vest in 2002; 20,000 shares vest in 2003; 30,000 shares vest in 2004; 40,000 shares vest in 2005; 30,000 shares vest in 2006; and 30,000 shares vest in 2007. Any non-vested shares are forfeited upon his retirement unless the Board of Directors, in its discretion, determines to waive the forfeiture. The Agreement provides for the granting of 22 years of pension credit for Mr. Ferland's prior service, which was awarded at the time of his initial employment. The Agreement further provides that if Mr. Ferland is terminated without "Cause" or resigns for "Good Reason" (as those terms are defined in the Agreement) during the term of the Agreement, the entire restricted stock award immediately vests, he will be paid a benefit of two times base salary and target bonus and his welfare benefits will be continued for two years unless he is sooner employed. In the event such a termination occurs after a "Change in Control" (also as defined in the Agreement), the payment to Mr. Ferland becomes three times the sum of salary and target bonus, continuation of welfare benefits for three years unless sooner reemployed, payment of the net present value providing three years additional service under PSEG's retirement plans, and a gross-up for excise taxes on any termination payments due under the Internal Revenue Code. The Agreement provides that Mr. Ferland is prohibited from competing with or recruiting employees from PSEG or its subsidiaries of affiliates for two years after termination of employment. Violation of these provisions requires a forfeiture of a portion of the restricted stock grant and certain other benefits. We have entered into an employment agreement with Mr. Koeppe dated as of October 17, 2000 and Mr. Busch dated as of April 24, 2001, covering the respective employment of each in the position listed in the Summary Compensation Table through October 16, 2005 for Mr. Koeppe and April 24, 2006 for Mr. Busch. The agreements are essentially identical and provide that the base salary, target annual incentive bonus and long-term incentive bonus will be determined based on compensation practices of similar companies and that their annual salary will not be reduced during the term of the Agreement, and annually awards to Mr. Koeppe 50,000 options on PSEG Common Stock from 2001 through 2005 which vest each October 17 and expire on October 17, 2010 and annually awards to Mr. Busch 50,000 options on PSEG Common Stock from 2002 through 2006 which vest each April 24 and expire on April 24, 2011. The Agreements further provide that if the individual is terminated without "Cause" or resigns for "Good Reason" (as those terms are defined in each Agreement) during the term of the Agreement, the entire option award becomes vested, the individual will be paid a benefit of two times base salary and target bonus, and his welfare benefits will be continued for two years unless he is sooner employed. In the event such a termination occurs after a "Charge in Control" (also as defined in the Agreement), the payment to the individual becomes three times the sum of salary and target bonus, continuation of welfare benefits for three years unless sooner reemployed, payment of the net present value of providing three years additional service under our retirement plans, and a gross-up for excise taxes on any termination payments due under the Internal Revenue Code. The Agreements provide that the individual is prohibited for one year from competing with and for two years from recruiting employees from, PSEG or its subsidiaries or affiliates, after termination of employment. Violation of these provisions requires a forfeiture of certain benefits. The agreement for Messrs. Busch and Koeppe also provide for the grant of additional years of credited service for retirement purposes in light of allied work experience of fifteen years and twenty-five years, respectively. Compensation Committee Interlocks and Insider Participation We do not have a compensation committee. Decisions regarding compensation of our executive officers are made by the Organization and Compensation Committee of PSEG. Hence, during 2001 the PSE&G Board of Directors did not have, and no officer, employee or former officer of us participated in any deliberations of such Board, concerning executive officer compensation. Compensation of Directors and Certain Business Relationships During 2001, a director who was not an officer of PSEG or its subsidiaries and affiliates, including us, was paid an annual retainer of $30,000 and a fee of $1,500 for attendance at any Board or Committee meeting, inspection trip, conference or other similar activity relating to PSEG or us. Fifty percent of the annual retainer is paid in PSEG Common Stock. No additional retainer is paid for service as a director of PSE&G. Each Committee Chair receives an additional annual retainer of $3,000. 57 PUBLIC SERVICE ELECTRIC AND GAS COMPANY PSEG also maintains a Stock Plan for Outside Directors pursuant to which directors who are not employees of PSEG or its subsidiaries receive 600 shares of restricted stock for each year of service as a director. Such shares held by each non-employee director are included in the table in Item 12 below under the heading Security Ownership of Certain Beneficial Owners and Management. The restrictions on the stock granted under the Stock Plan for Outside Directors provide that the shares are subject to forfeiture if the director leaves service at any time prior to the Annual Meeting of Stockholders following his or her 70th birthday. This restriction would be deemed to have been satisfied if the director's service were terminated after a "Change in Control" as defined in the Plan or if the director were to die in office. PSEG also has the ability to waive this restriction for good cause shown. Restricted stock may not be sold or otherwise transferred prior to the lapse of the restrictions. Dividends on shares held subject to restrictions are paid directly to the director, and the director has the right to vote the shares. Compensation Pursuant to Pension Plans The table below illustrates annual retirement benefits for executive officers expressed in terms of single life annuities based on the average final compensation and service shown and retirement at age 65. A person's annual retirement benefit is based upon a percentage that is equal to years of credited service plus 30, but not more than 75%, times average final compensation at the earlier of retirement, attainment of age 65 or death. These amounts are reduced by Social Security benefits and certain retirement benefits from other employers. Pensions in the form of joint and survivor annuities are also available. ================================================================================ PENSION PLAN TABLE - -------------------------------------------------------------------------------- Length of Service Average Final ----------------------------------------------------------------- Compensation 30 Years 35 Years 40 Years 45 Years - -------------- ----------------- --------------- ---------------- -------------- $400,000 $240,000 $260,000 $280,000 $300,000 500,000 300,000 325,000 350,000 375,000 600,000 360,000 390,000 420,000 450,000 700,000 420,000 455,000 490,000 525,000 800,000 480,000 520,000 560,000 600,000 900,000 540,000 585,000 630,000 675,000 1,000,000 600,000 650,000 700,000 750,000 1,100,000 660,000 715,000 770,000 825,000 1,200,000 720,000 780,000 840,000 900,000 1,300,000 780,000 845,000 910,000 975,000 1,400,000 840,000 910,000 980,000 1,050,000 1,500,000 900,000 975,000 1,050,000 1,125,000 ================================================================================ Average final compensation, for purposes of retirement benefits of executive officers, is generally equivalent to the average of the aggregate of the salary and bonus amounts reported in the Summary Compensation Table above under 'Annual Compensation' for the five years preceding retirement, not to exceed 150% of the average annual salary for such five year period. Messrs. Ferland, Selover, Koeppe, Busch and Mrs. Rado will have accrued approximately 48, 43, 46, 34, and 29 years of credited service, respectively, as of age 65. 58 PUBLIC SERVICE ELECTRIC AND GAS COMPANY ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT All of PSE&G's 132,450,344 outstanding shares of Common Stock are owned beneficially and of record by PSE&G's parent, PSEG, 80 Park Plaza, P.O. Box 1171, Newark, New Jersey. The following table sets forth beneficial ownership of PSEG Common Stock, including options, by the directors and executive officers named below as of February 22, 2002. None of these amounts exceed 1% of the PSEG Common Stock outstanding at such date. No director or executive officer owns any of our Preferred Stock of any class.
===================================================================================== Amount and Nature of Name Beneficial Ownership - ------------------------------------------------------------------------------------- E. James Ferland.............................................. 1,410,442 (1) R. Edwin Selover.............................................. 194,591 (2) Alfred R. Koeppe.............................................. 504,608 (3) Robert E. Busch............................................... 396,709 (4) Patricia A. Rado.............................................. 71,480 (5) Albert R. Gamper, Jr.......................................... 2,443 (6) Conrad K. Harper.............................................. 3,922 (7) Marilyn M. Pfaltz............................................. 12,179 (8) All directors and executive officers as a group (8 persons)... 2,596,374 =====================================================================================
(1) Includes the equivalent of 13,395 shares held under PSEG Thrift and Tax-Deferred Savings Plan. Includes options to purchase 1,115,000 shares, 493,333 of which are currently exercisable. Includes 210,000 shares of restricted stock, which vest as described in the Summary Compensation Table Note 5. (2) Includes options to purchase 180,000 shares, 71,667 of which are currently exercisable. (3) Includes the equivalent of 2,508 shares held under the PSE&G Thrift and Tax-Deferred Savings Plan. Includes options to purchase 495,000 shares, 155,000 of which are currently exercisable. (4) Includes the equivalent of 153 shares held under PSEG Thrift and Tax-Deferred Savings Plan. Includes options to purchase 395,000 shares, 45,000 of which are currently exercisable. (5) Includes the equivalent of 5,806 shares held under PSEG Thrift and Tax-Deferred Savings Plan. Includes options to purchase 63,000 shares, 23,000 of which are currently exercisable. (6) Includes 600 shares of restricted stock awarded pursuant to the Stock Plan for Outside Directors described below. (7) Includes 2,400 shares of restricted stock awarded pursuant to the Stock Plan for Outside Directors described below. (8) Includes 5,755 shares of restricted stock awarded pursuant to the Stock Plan for Outside Directors described below. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS None. 59 PUBLIC SERVICE ELECTRIC AND GAS COMPANY PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (A) Financial Statements: a. PSE&G Consolidated Statements of Income for the years ended December 31, 2001, 2000 and 1999 on page 29. PSE&G Consolidated Balance Sheets for the years ended December 31, 2001 and 2000 on pages 30 and 31. PSE&G Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000 and 1999 on page 32. PSE&G Statements of Common Stockholder's Equity for the years ended December 31, 2001, 2000 and 1999 on page 33. PSE&G Notes to Consolidated Financial Statements on pages 34 through 51. (B) The following documents are filed as a part of this report: a. PSE&G Financial Statement Schedules: Schedule II--Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2001 (page 61). Schedules other than those listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the consolidated financial statements or notes thereto. The following exhibits are filed herewith: (1) PSE&G: Exhibit 12: Computation of Ratios of Earnings to Fixed Charges Exhibit 12(a): Computation of Ratios of Earnings to Fixed Charges Plus Preferred Stock Dividend Requirements Exhibit 23: Independent Auditors' Consent (See Exhibit Index on pages 63 through 70.) (C) There were no reports on Form 8-K filed during the last quarter of 2001 and the 2002 period covered by this report under Item 5. 60 PUBLIC SERVICE ELECTRIC AND GAS COMPANY SCHEDULE II PUBLIC SERVICE ELECTRIC AND GAS COMPANY Schedule II -- Valuation and Qualifying Accounts Years Ended December 31, 2001 -- December 31, 1999
Column B Column C Column D Column E ------------- ---------------------------- --------------- ------------- Additions ---------------------------- Balance at Charged to Charged to Balance at beginning of cost and other Deductions- end of accounts- Description Period expenses describe describe Period - ------------------------------------------- ------------- ---------------------------- --------------- ------------- (Millions of Dollars) 2001: Allowance for Doubtful Accounts.......... $39 $45 $-- $46(A) $38 2000: Allowance for Doubtful Accounts.......... $35 $45 $-- $41(A) $39 Materials and Supplies Valuation Reserve. 11 -- -- 11(D) -- 1999: Allowance for Doubtful Accounts.......... $34 $40 $-- $39(A) $35 Discount on Property Abandonments........ 1 -- -- 1(B) -- Materials and Supplies Valuation Reserve. 12 41 -- 42(C) 11 (A) Accounts Receivable/Investments written off. (B) Amortization of discount to income. (C) Inventory written off. (D) Transferred to Power.
61 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.
Public Service Electric and Gas Company By E. JAMES FERLAND ----------------------------------------- E. James Ferland Chairman of the Board and Chief Executive Officer Date: March 7, 2002 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. Signature Title Date E. JAMES FERLAND Chairman of the Board and Chief March 7, 2002 - ----------------------------------------------- E. James Ferland Executive Officer and Director (Principal Executive Officer) ALFRED C. KOEPPE President and Chief Operating Officer March 7, 2002 - ----------------------------------------------- Alfred C. Koeppe ROBERT E. BUSCH Senior Vice President - Finance and Chief March 7, 2002 - ----------------------------------------------- Robert E. Busch Financial Officer (Principal Financial Officer) PATRICIA A. RADO Vice President and Controller March 7, 2002 - ----------------------------------------------- Patricia A. Rado (Principal Accounting Officer) ALBERT R. GAMPER, JR. Director March 7, 2002 - ----------------------------------------------- Albert R. Gamper, Jr. CONRAD K. HARPER Director March 7, 2002 - ----------------------------------------------- Conrad K. Harper MARILYN M. PFALTZ Director March 7, 2002 - ----------------------------------------------- Marilyn M. Pfaltz
62 EXHIBIT INDEX Certain Exhibits previously filed with the Commission and the appropriate securities exchanges are indicated as set forth below. Such Exhibits are not being refiled, but are included because inclusion is desirable for convenient reference. (a) Filed by PSE&G with Form 8-A under the Securities Exchange Act of 1934, on the respective dates indicated, File No. 001-00973. (b) Filed by PSE&G with Form 8-K under the Securities Exchange Act of 1934, on the respective dates indicated, File No. 001-00973. (c) Filed by PSE&G with Form 10-K under the Securities Exchange Act of 1934, on the respective dates indicated, File No. 001-00973. (d) Filed by PSE&G with Form 10-Q under the Securities Exchange Act of 1934, on the respective dates indicated, File No. 001-00973. (e) Filed by PSEG with Form 10-K under the Securities Exchange Act of 1934, on the respective dates indicated, File No. 001-09120. (f) Filed with registration statement of PSE&G under the Securities Exchange Act of 1934, File No. 1-973, effective July 1, 1935, relating to the registration of various issues of securities. (g) Filed with registration statement of PSE&G under the Securities Act of 1933, No. 2-4995, effective May 20, 1942, relating to the issuance of $15,000,000 First and Refunding Mortgage Bonds, 3% Series due 1972. (h) Filed with registration statement of PSE&G under the Securities Act of 1933, No. 2-7568, effective July 1, 1948, relating to the proposed issuance of 200,000 shares of Cumulative Preferred Stock. (i) Filed with registration statement of PSE&G under the Securities Act of 1933, No. 2-8381, effective April 18, 1950, relating to the issuance of $26,000,000 First and Refunding Mortgage Bonds, 2 3/4% Series due 1980. (j) Filed with registration statement of PSE&G under the Securities Act of 1933, No. 2-12906, effective December 4, 1956, relating to the issuance of 1,000,000 shares of Common Stock. (k) Filed with registration statement of PSE&G under the Securities Act of 1933, No. 2-59675, effective September 1, 1977, relating to the issuance of $60,000,000 First and Refunding Mortgage Bonds, 8 1/8% Series I due 2007. (l) Filed with registration statement of PSE&G under the Securities Act of 1933, No. 2-60925, effective March 30, 1978, relating to the issuance of 750,000 shares of Common Stock through an Employee Stock Purchase Plan. (m) Filed with registration statement of PSE&G under the Securities Act of 1933, No. 2-65521, effective October 10, 1979, relating to the issuance of 3,000,000 shares of Common Stock. (n) Filed with registration statement of PSE&G under the Securities Act of 1933, No. 2-74018, filed on June 16, 1982, relating to the Thrift Plan of PSE&G. (o) Filed with registration statement of Public Service Enterprise Group Incorporated under the Securities Act of 1933, No. 33-2935 filed January 28, 1986, relating to PSE&G's plan to form a holding company as part of a corporate restructuring. (p) Filed with registration statement of PSE&G under the Securities Act of 1933, No. 33-13209 filed April 9, 1987, relating to the registration of $575,000,000 First and Refunding Mortgage Bonds pursuant to Rule 415. (q) Filed with registration statement of PSE&G under the Securities Act of 1933, No. 333-76020, effective February 12, 2002, relating to the registration of $1,000,000,000 of Senior Debt Securities. 63 PUBLIC SERVICE ELECTRIC AND GAS COMPANY
PSE&G - ---------------------------------------------------- Exhibit Number - ---------------------------------------------------- This Previous Filing --------------------------------------- Filing Commission Exchanges ------ ---------- --------- 3a(1) (b) 3a (b) 3a Restated Certificate of Incorporation of PSE&G 8/28/86 8/29/86 3a(2) (c) 3a(2) (c) 3a(2) Certificate of Amendment of Certificate of Restated 4/10/87 Certificate of Incorporation of PSE&G filed February 18, 1987 with the State of New Jersey adopting limitations of liability provisions in accordance with an amendment to New Jersey Business Corporation Act 3a(3) (a) 3(a)3 (a) 3(a)3 Certificate of Amendment of Restated Certificate of 2/3/94 2/14/94 Incorporation of PSE&G filed June 17, 1992 with the State of New Jersey, establishing the 7.44% Cumulative Preferred Stock ($100 Par) as a series of the Preferred Stock 3a(4) (a) 3(a)4 (a) 3(a)4 Certificate of Amendment of Restated Certificate of 2/3/94 2/14/94 Incorporation of PSE&G filed March 11, 1993 with the State of New Jersey, establishing the 5.97% Cumulative Preferred Stock ($100 Par) as a series of Preferred Stock 3a(5) (a) 3(a)5 (a) 3(a)5 Certificate of Amendment of Restated Certificate of 2/3/94 2/14/94 Incorporation of PSE&G filed January 27, 1995 with the State of New Jersey, establishing the 6.92% Cumulative Preferred Stock ($100 Par) and the 6.75% Cumulative Preferred Stock -- $25 Par as series of Preferred Stock 3b(1) (d) (d) Copy of By-Laws of PSE&G 8/8/00 8/8/00 4a(1) (f) B-1 (c) 4b(1) Indenture between PSE&G and Fidelity Union Trust 2/18/81 Company, (now First Union National Bank, National Association), as Trustee, dated August 1, 1924, securing First and Refunding Mortgage Bond Indentures between PSE&G and First Fidelity Bank, National Association, as Trustee, supplemental to Exhibit 4a(1), dated as follows: 4a(2) (i) 7(1a) (c) 4b(2) April 1, 1927 2/18/81 4a(3) (k) 2b(3) (c) 4b(3) June 1, 1937 2/18/81 64 PSE&G - ---------------------------------------------------- Exhibit Number - ---------------------------------------------------- This Previous Filing --------------------------------------- Filing Commission Exchanges ------ ---------- --------- 4a(4) (k) 2b(4) (c) 4b(4) July 1, 1937 2/18/81 4a(5) (k) 2b(5) (c) 4b(5) December 19, 1939 2/18/81 4a(6) (g) B-10 (c) 4b(6) March 1, 1942 2/18/81 4a(7) (k) 2b(7) (c) 4b(7) June 1, 1949 2/18/81 4a(8) (k) 2b(8) (c) 4b(8) May 1, 1950 2/18/81 4a(9) (k) 2b(9) (c) 4b(9) October 1, 1953 2/18/81 4a(10) (k) 2b(10) (c) 4b(10) May 1, 1954 2/18/81 4a(11) (j) 4b(16) (c) 4b(11) November 1, 1956 2/18/81 4a(12) (k) 2b(12) (c) 4b(12) September 1, 1957 2/18/81 4a(13) (k) 2b(13) (c) 4b(13) August 1, 1958 2/18/81 4a(14) (k) 2b(14) (c) 4b(14) June 1, 1959 2/18/81 4a(15) (k) 2b(15) (c) 4b(15) September 1, 1960 2/18/81 4a(16) (k) 2b(16) (c) 4b(16) August 1, 1962 2/18/81 4a(17) (k) 2b(17) (c) 4b(17) June 1, 1963 2/18/81 4a(18) (k) 2b(18) (c) 4b(18) September 1, 1964 2/18/81 4a(19) (k) 2b(19) (c) 4b(19) September 1, 1965 2/18/81 4a(20) (k) 2b(20) (c) 4b(20) June 1, 1967 2/18/81 4a(21) (k) 2b(21) (c) 4b(21) June 1, 1968 2/18/81 4a(22) (k) 2b(22) (c) 4b(22) April 1, 1969 2/18/81 4a(23) (k) 2b(23) (c) 4b(23) March 1, 1970 2/18/81
65
PSE&G - ---------------------------------------------------- Exhibit Number - ---------------------------------------------------- This Previous Filing --------------------------------------- Filing Commission Exchanges ------ ---------- --------- 4a(24) (k) 2b(24) (c) 4b(24) May 15, 1971 2/18/81 4a(25) (k) 2b(25) (c) 4b(25) November 15, 1971 2/18/81 4a(26) (k) 2b(26) (c) 4b(26) April 1, 1972 2/18/81 4a(27) (a) 2 (c) 4b(27) March 1, 1974 3/29/74 2/18/81 4a(28) (a) 2 (c) 4b(28) October 1, 1974 10/11/74 2/18/81 4a(29) (a) 2 (c) 4b(29) April 1, 1976 4/6/76 2/18/81 4a(30) (a) 2 (c) 4b(30) September 1, 1976 9/16/76 2/18/81 4a(31) (k) 2b(31) (c) 4b(31) October 1, 1976 2/18/81 4a(32) (a) 2 (c) 4b(32) June 1, 1977 6/29/77 2/18/81 4a(33) (l) 2b(33) (c) 4b(33) September 1, 1977 2/18/81 4a(34) (a) 2 (c) 4b(34) November 1, 1978 11/21/78 2/18/81 4a(35) (a) 2 (c) 4b(35) July 1, 1979 7/25/79 2/18/81 4a(36) (m) 2d(36) (c) 4b(36) September 1, 1979 (No. 1) 2/18/81 4a(37) (m) 2d(37) (c) 4b(37) September 1, 1979 (No. 2) 2/18/81 4a(38) (a) 2 (c) 4b(38) November 1, 1979 12/3/79 2/18/81 4a(39) (a) 2 (c) 4b(39) June 1, 1980 6/10/80 2/18/81 4a(40) (a) 2 (a) 2 August 1, 1981 8/19/81 8/19/81 4a(41) (b) 4e (b) 4e April 1, 1982 4/29/82 5/5/82 4a(42) (a) 2 (a) 2 September 1, 1982 9/17/82 9/20/82 4a(43) (a) 2 (a) 2 December 1, 1982 12/21/82 12/21/82 4a(44) (d) 4(ii) (d) 4(ii) June 1, 1983 7/26/83 7/27/83
66
PSE&G - ---------------------------------------------------- Exhibit Number - ---------------------------------------------------- This Previous Filing --------------------------------------- Filing Commission Exchanges ------ ---------- --------- 4a(45) (a) 4 (a) 4 August 1, 1983 8/19/83 8/19/83 4a(46) (d) 4(ii) (d) 4(ii) July 1, 1984 8/14/84 8/17/84 4a(47) (d) 4(ii) (d) 4(ii) September 1, 1984 11/2/84 11/9/84 4a(48) (b) 4(ii) (b) 4(ii) November 1, 1984 (No. 1) 1/4/85 1/9/85 4a(49) (b) 4(ii) (b) 4(ii) November 1, 1984 (No. 2) 1/4/85 1/9/85 4a(50) (a) 2 (a) 2 July 1, 1985 8/2/85 8/2/85 4a(51) (c) 4a(51) (c) 4a(51) January 1, 1986 2/11/86 2/11/86 4a(52) (a) 2 (a) 2 March 1, 1986 3/28/86 3/28/86 4a(53) (a) 2(a) (a) 2(a) April 1, 1986 (No. 1) 5/1/86 5/1/86 4a(54) (a) 2(b) (a) 2(b) April 1, 1986 (No. 2) 5/1/86 5/1/86 4a(55) (p) 4a(55) (p) 4a(55) March 1, 1987 4/9/87 4/9/87 4a(56) (a) 4 (a) 4 July 1, 1987 (No. 1) 8/17/87 8/17/87 4a(57) (d) 4 (d) 4 July 1, 1987 (No. 2) 11/13/87 11/20/87 4a(58) (a) 4 (a) 4 May 1, 1988 5/17/88 5/18/88 4a(59) (a) 4 (a) 4 September 1, 1988 9/27/88 9/28/88 4a(60) (a) 4 (a) 4 July 1, 1989 7/25/89 7/26/89 4a(61) (a) 4 (a) 4 July 1, 1990 (No. 1) 7/25/90 7/26/90 4a(62) (a) 4 (a) 4 July 1, 1990 (No. 2) 7/25/90 7/26/90 4a(63) (a) 4 (a) 4 June 1, 1991 (No. 1) 7/1/91 7/2/91 4a(64) (a) 4 (a) 4 June 1, 1991 (No. 2) 7/1/91 7/2/91 4a(65) (a) 4 (a) 4 November 1, 1991 (No. 1) 12/2/91 12/3/91
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PSE&G - ---------------------------------------------------- Exhibit Number - ---------------------------------------------------- This Previous Filing --------------------------------------- Filing Commission Exchanges ------ ---------- --------- 4a(66) (a) 4 (a) 4 November 1, 1991 (No. 2) 12/2/91 12/3/91 4a(67) (a) 4 (a) 4 November 1, 1991 (No. 3) 12/2/91 12/3/91 4a(68) (a) 4 (a) 4 February 1, 1992 (No. 1) 2/27/92 2/28/92 4a(69) (a) 4 (a) 4 February 1, 1992 (No. 2) 2/27/92 2/28/92 4a(70) (a) 4 (a) 4 June 1, 1992 (No. 1) 6/17/92 6/11/92 4a(71) (a) 4 (a) 4 June 1, 1992 (No. 2) 6/17/92 6/11/92 4a(72) (a) 4 (a) 4 June 1, 1992 (No. 3) 6/17/92 6/11/92 4a(73) (a) 4 (a) 4 January 1, 1993 (No. 1) 2/2/93 2/2/93 4a(74) (a) 4 (a) 4 January 1, 1993 (No. 2) 2/2/93 2/2/93 4a(75) (a) 4 (a) 4 March 1, 1993 3/17/93 3/18/93 4a(76) (b) 4 (a) 4 May 1, 1993 5/27/93 5/28/93 4a(77) (a) 4 (a) 4 May 1, 1993 (No. 2) 5/25/93 5/25/93 4a(78) (a) 4 (a) 4 May 1, 1993 (No. 3) 5/25/93 5/25/93 4a(79) (b) 4 (b) 4 July 1, 1993 12/1/93 12/1/93 4a(80) (a) 4 (a) 4 August 1, 1993 8/3/93 8/3/93 4a(81) (b) 4 (b) 4 September 1, 1993 12/1/93 12/1/93 4a(82) (a) 4 (a) 4 September 1, 1993 (No. 2) 12/1/93 12/1/93 4a(84) (a) 4 (a) 4 February 1, 1994 2/3/94 2/14/94 4a(85) (a) 4 (a) 4 March 1, 1994 (No. 1) 3/15/94 3/16/94 4a(86) (a) 4 (a) 4 March 1, 1994 (No. 2) 3/15/94 3/16/94 4a(87) (d) 4 (d) 4 May 1, 1994 11/8/94 12/2/94
68
PSE&G - ---------------------------------------------------- Exhibit Number - ---------------------------------------------------- This Previous Filing --------------------------------------- Filing Commission Exchanges ------ ---------- --------- 4a(88) (d) 4 (d) 4 June 1, 1994 11/8/94 12/2/94 4a(89) (d) 4 (d) 4 August 1, 1994 11/8/94 12/2/94 4a(90) (d) 4 (d) 4 October 1, 1994 (No. 1) 11/8/94 12/2/94 4a(91) (d) 4 (d) 4 October 1, 1994 (No. 2) 11/8/94 12/2/94 4a(92) (a) 4 (a) 4 January 1, 1996 (No.1) 1/26/96 1/26/96 4a(93) (a) 4 (a) 4 January 1, 1996 (No. 2) 1/26/96 1/26/96 4a(94) (c) 4 December 1, 1996 2/26/97 4a(95) (a) 4 (a) 4 June 1, 1997 6/17/97 6/17/97 4a(96) (a) 4 (a) 4 May 1, 1998 5/15/98 5/15/98 4b (b) 4 (b) 4 Indenture of Trust between PSE&G and Chase 12/1/93 12/1/93 Manhattan Bank (National Association), as Trustee, providing for Secured Medium-Term Notes dated July 1, 1993 4c(1) (b) (c) Indenture between PSE&G and First Fidelity Bank, 2/23/95 2/23/95 National Association (now known as First Union National Bank), as Trustee, dated November 1, 1994, providing for Deferrable Interest Subordinated Debentures in Series 4c(2) (a) 4b(5) (a) 4b(5) Supplemental Indenture between PSE&G and First Fidelity Bank, National Association (now known as (d) 4d(2) (d) 4d(2) First Union National Bank), as Trustee, dated 5/13/98 5/13/98 September 1, 1995 providing for Deferrable Interest Subordinated Debentures, Series B (relating to Monthly Preferred Securities) 4d(1) (d) 4e(1) (d) 4e(1) Indenture between PSE&G and First Union National 5/13/98 5/13/98 Bank, as Trustee, dated June 1, 1996 providing for Deferrable Interest Subordinated Debentures in Series (relating to Quarterly Preferred Securities) 4d(2) (d) 4e(2) (d) 4e(2) Supplemental Indenture between PSE&G and First Union 5/13/98 5/13/98 National Bank, as Trustee, dated February 1, 1997 providing for Deferrable Interest Subordinated Debentures, Series B (relating to Quarterly Preferred Securities) 4e (q) 4-6 (q) 4-6 Indenture dated as of December 1, 2000 between Public 2/12/02 2/12/02 Service Electric and Gas Company and First Union National Bank, as Trustee, providing for Senior Debt Securities. Senior Note Indenture
69
PSE&G - ---------------------------------------------------- Exhibit Number - ---------------------------------------------------- This Previous Filing --------------------------------------- Filing Commission Exchanges ------ ---------- --------- 10a(1) (c) 10a(1) (c) 10a(1) Directors' Deferred Compensation Plan 2/25/00 2/25/00 10a(2) (c) 10a(2) (c) 10a(2) Deferred Compensation Plan for Certain Employees 2/25/00 2/25/00 10a(3) (c) 10a(3) (c) 10a(3) Limited Supplemental Benefits Plan for Certain Employees 2/25/00 2/25/00 10a(4) (c) 10a(4) (c) 10a(4) Mid Career Hire Supplemental Retirement Plan 2/25/00 2/25/00 10a(5) (c) 10a(5) (c) 10a(5) Retirement Income Reinstatement Plan 2/25/00 2/25/00 10a(6) (c) 10a(6) (c) 10a(6) 1989 Long-Term Incentive Plan 2/22/99 2/22/99 10a(7) (c) 10a(7) (c) 10a(7) 2001 Long-Term Incentive Plan 3/5/01 3/5/01 10a(8) (c) 10a(8) 10a(8) Restated and Amended Management Incentive Compensation Plan 3/5/01 3/5/01 10a(9) (d) 10 (d) 10 Employment Agreement with E. James Ferland, dated 8/14/98 8/14/98 June 16, 1998 10a(10) (c) 10a(13) (c) 10a(13) Letter Agreement with Patricia A. Rado dated 2/26/94 3/9/94 March 24, 1993 10a(11) (d) 10a(21) (d) Employment Agreement with Alfred C. Koeppe dated 11/13/00 October 17, 2000 11 Inapplicable 12(a) Computation of Ratios of Earnings to Fixed Charges 12(b) Computation of Ratios of Earnings to Fixed Charges Plus Preferred Stock Dividend Requirements 13 Inapplicable 16 Inapplicable 19 Inapplicable 21 Inapplicable 23 Independent Auditors' Consent
EX-99.12(A) 3 file002.txt COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES EXHIBIT 12 (a) PUBLIC SERVICE ELECTRIC AND GAS COMPANY COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
Years Ended December 31, ----------- ------------ ----------- ------------ --------- 1997 1998 1999 2000 2001 ----------- ------------ ----------- ------------ --------- Earnings as Defined in Regulation S-K (A): Net Income (B) $528 $602 $653 $587 $235 Income Taxes (C) 256 404 510 407 89 Fixed Charges 450 446 450 463 392 ----------- ------------ ----------- ------------ --------- Earnings $1,234 $1,452 $1,613 $1,457 $716 =========== ============ =========== ============ ========= Fixed Charges as Defined in Regulation S-K(D): Total Interest Expense $395 $390 $394 $407 $358 Interest Factor in Rentals 11 11 10 10 10 Subsidiaries' Preferred Securities Dividend Requirements 44 45 46 46 24 ----------- ------------ ----------- ------------ --------- Total Fixed Charges $450 $446 $450 $463 $392 =========== ============ =========== ============ ========= Ratio of Earnings to Fixed Charges 2.74 3.27 3.58 3.15 1.83 =========== ============ =========== ============ =========
Notes: (A) The term "earnings" shall be defined as pre-tax income from continuing operations. Add to pre-tax income the amount of fixed charges adjusted to exclude (a) the amount of any interest capitalized during the period and (b) the actual amount of any preferred stock dividend requirements of majority-owned subsidiaries which were included in such fixed charges amount but not deducted in the determination of pre-tax income. (B) Excludes extraordinary item recorded in 1999. (C) Includes State income taxes and Federal income taxes for other income and excludes taxes applicable to extraordinary item recorded in 1999. (D) Fixed Charges represent (a) interest, whether expensed or capitalized, (b) amortization of debt discount, premium and expense, (c) an estimate of interest implicit in rentals, and (d) Preferred Securities Dividend Requirements of subsidiaries. EX-99.12(B) 4 file003.txt COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES EXHIBIT 12 (b) PUBLIC SERVICE ELECTRIC AND GAS COMPANY COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS
Years Ended December 31, ----------- ----------- ----------- ----------- ----------- 1997 1998 1999 2000 2001 ----------- ----------- ----------- ----------- ----------- Earnings as Defined in Regulation S-K (A): Net Income (B) $528 $602 $653 $587 $235 Income Taxes (C) 256 404 510 407 89 Fixed Charges 450 446 450 463 392 ----------- ----------- ----------- ----------- ----------- Earnings $1,234 $1,452 $1,613 $1,457 $716 =========== =========== =========== =========== =========== Fixed Charges as Defined in Regulation S-K(D): Total Interest Expense $395 $390 $394 $407 $358 Interest Factor in Rentals 11 11 10 10 10 Subsidiaries' Preferred Securities Dividend Requirements 44 45 46 46 24 Preferred Stock Dividends 12 9 9 9 5 Adjustment to Preferred Stock Dividends to state on a pre-income tax basis 6 6 7 7 3 ----------- ----------- ----------- ----------- ----------- Total Fixed Charges $468 $461 $466 $479 $400 =========== =========== =========== =========== =========== Ratio of Earnings to Fixed Charges 2.64 3.15 3.46 3.04 1.79 =========== =========== =========== =========== ===========
Notes: (A) The term "earnings" shall be defined as pre-tax income from continuing operations. Add to pre-tax income the amount of fixed charges adjusted to exclude (a) the amount of any interest capitalized during the period and (b) the actual amount of any preferred stock dividend requirements of majority-owned subsidiaries which were included in such fixed charges amount but not deducted in the determination of pre-tax income. (B) Excludes extraordinary item recorded in 1999. (C) Includes State income taxes and Federal income taxes for other income and excludes taxes applicable to extraordinary item recorded in 1999. (D) Fixed Charges represent (a) interest, whether expensed or capitalized, (b) amortization of debt discount, premium and expense, (c) an estimate of interest implicit in rentals, and (d) preferred securities dividend requirements of subsidiaries and preferred stock dividends, increased to reflect the pre-tax earnings requirement for Public Service Electric and Gas Company. EX-23 5 file004.txt INDEPENDENT AUDITORS' CONSENT EXHIBIT 23 PUBLIC SERVICE ELECTRIC AND GAS COMPANY INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Nos. 33-50199, 33-51309, 333-02763, 333-44991 and 333-76020 of Public Service Electric and Gas Company on Form S-3 of our report dated February 15, 2002, appearing in this Annual Report on Form 10-K of Public Service Electric and Gas Company for the year ended December 31, 2001. DELOITTE & TOUCHE LLP Parsippany, New Jersey March 7, 2002 -----END PRIVACY-ENHANCED MESSAGE-----