================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549 FORM 10-Q (Mark One) [ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2002 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. - ------------- ---------------------------------------------- ------------------ 001-09120 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED 22-2625848 (A New Jersey Corporation) 80 Park Plaza P.O. Box 1171 Newark, New Jersey 07101-1171 973-430-7000 http://www.pseg.com Indicate by check mark whether the registrant (1) has 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 registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No As of April 30, 2002, Public Service Enterprise Group Incorporated had outstanding 206,228,771 shares of its sole class of Common Stock, without par value. ================================================================================
================================================================================ PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED ================================================================================ TABLE OF CONTENTS PAGE ---- PART I. FINANCIAL INFORMATION - ----------------------------- Item 1. Financial Statements 1 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 27 Item 3. Qualitative and Quantitative Disclosures About Market Risk 40 PART II.OTHER INFORMATION - ------------------------- Item 1. Legal Proceedings 43 Item 4. Submission of Matters to Vote of Security Holders 44 Item 5. Other Information 45 Item 6. Exhibits and Reports on Form 8-K 47 Signature 48
================================================================================ PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED ================================================================================ PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS
<TABLE> <CAPTION> PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED CONSOLIDATED STATEMENTS OF INCOME (Millions of Dollars, except for Per Share Data) (Unaudited) For the Quarters Ended March 31, ----------------------------------------- 2002 2001 ------------------- ----------------- <S> <C> <C> OPERATING REVENUES Electric $ 1,072 $ 925 Gas Distribution 815 1,082 Trading 430 587 Other 198 225 ------------------- ----------------- Total Operating Revenues 2,515 2,819 ------------------- ----------------- OPERATING EXPENSES Electric Energy Costs 310 220 Gas Costs 527 787 Trading Costs 398 536 Operation and Maintenance 555 538 Depreciation and Amortization 137 108 Taxes Other Than Income Taxes 47 48 ------------------- ----------------- Total Operating Expenses 1,974 2,237 ------------------- ----------------- OPERATING INCOME 541 582 OTHER (LOSS) INCOME Foreign Currency Transaction Loss (52) -- Other Income and Deductions 14 13 ------------------- ----------------- Total Other (Loss) Income (38) 13 ------------------- ----------------- Interest Expense (195) (164) Preferred Securities Dividend Requirements and Premium on Redemption (14) (24) ------------------- ----------------- INCOME BEFORE INCOME TAXES, EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 294 407 Income Taxes (114) (153) ------------------- ----------------- INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 180 254 Extraordinary Loss on Early Retirement of Debt (net of tax) -- (2) Cumulative Effect of a Change in Accounting Principle (net of tax) -- 9 ------------------- ----------------- NET INCOME $ 180 $ 261 =================== ================= WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (000's) 206,340 208,390 =================== ================= EARNINGS PER SHARE (BASIC AND DILUTED): INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE $ 0.87 $ 1.22 Extraordinary Loss on Early Retirement of Debt (net of tax) -- (0.01) Cumulative Effect of a Change in Accounting Principle (net of tax) -- 0.04 ------------------- ----------------- NET INCOME $ 0.87 $ 1.25 =================== ================= DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 0.54 $ 0.54 =================== ================= See Notes to Consolidated Financial Statements. </TABLE>
<TABLE> <CAPTION> PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED CONSOLIDATED BALANCE SHEETS ASSETS (Millions of Dollars) (Unaudited) March 31, December 31, 2002 2001 -------------------- ------------------- <S> <C> <C> CURRENT ASSETS Cash and Cash Equivalents $ 175 $ 169 Accounts Receivable: Customer Accounts Receivable 958 824 Other Accounts Receivable 248 348 Allowance for Doubtful Accounts (43) (43) Unbilled Electric and Gas Revenues 221 291 Fuel 238 494 Materials and Supplies, net of valuation reserves - 2002, $2; 194 189 2001, $11 Prepayments 57 74 Energy Trading Contracts 324 454 Restricted Cash 13 12 Assets held for Sale 457 422 Notes Receivable 142 26 Other 34 25 -------------------- ------------------- Total Current Assets 3,018 3,285 -------------------- ------------------- PROPERTY, PLANT AND EQUIPMENT Generation 5,146 4,884 Transmission and Distribution 9,477 9,500 Other 507 502 -------------------- ------------------- Total 15,130 14,886 Accumulated Depreciation and Amortization (4,917) (4,822) -------------------- ------------------- Net Property, Plant and Equipment 10,213 10,064 -------------------- ------------------- NONCURRENT ASSETS Regulatory Assets 5,116 5,247 Long-Term Investments, net of accumulated amortization and Valuation allowances-- 2002, $31; 2001, $30 4,826 4,818 Nuclear Decommissioning Fund 815 817 Other Special Funds 308 222 Goodwill, net of accumulated amortization 621 649 Other 297 322 -------------------- ------------------- Total Noncurrent Assets 11,983 12,075 -------------------- ------------------- TOTAL ASSETS $ 25,214 $ 25,424 ==================== =================== See Notes to Consolidated Financial Statements. </TABLE>
<TABLE> <CAPTION> PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED CONSOLIDATED BALANCE SHEETS LIABILITIES AND CAPITALIZATION (Millions of Dollars) (Unaudited) March 31, December 31, 2002 2001 ------------------- ------------------- <S> <C> <C> CURRENT LIABILITIES Long-Term Debt Due Within One Year $ 1,385 $ 1,213 Commercial Paper and Loans 1,503 1,338 Accounts Payable 546 790 Energy Trading Contracts 310 602 Accrued Taxes 257 243 Other 529 535 ------------------- ------------------- Total Current Liabilities 4,530 4,721 ------------------- ------------------- NONCURRENT LIABILITIES Deferred Income Taxes and ITC 3,252 3,205 Nuclear Decommissioning 815 817 OPEB Costs 487 476 Regulatory Liabilities 344 373 Cost of Removal 145 146 Environmental 140 140 Other 405 348 ------------------- ------------------- Total Noncurrent Liabilities 5,588 5,505 ------------------- ------------------- COMMITMENTS AND CONTINGENT LIABILITIES -- -- ------------------- ------------------- CAPITALIZATION Long-Term Debt 6,288 6,437 Securitization Debt 2,321 2,351 Project Level, Non-Recourse Debt 1,569 1,513 ------------------- ------------------- Total Long-Term Debt 10,178 10,301 ------------------- ------------------- SUBSIDIARIES' PREFERRED SECURITIES Preferred Stock Without Mandatory Redemption 80 80 Guaranteed Preferred Beneficial Interest in Subordinated 680 680 Debentures ------------------- ------------------- Total Subsidiaries' Preferred Securities 760 760 ------------------- ------------------- COMMON STOCKHOLDERS' EQUITY Common Stock, issued: 2002-232,313,099 shares, 2001-231,957,608 shares 3,613 3,599 Treasury Stock, at cost: 2002 and 2001-- 26,118,590 shares (981) (981) Retained Earnings 1,881 1,809 Accumulated Other Comprehensive Loss (355) (290) ------------------- ------------------- Total Common Stockholders' Equity 4,158 4,137 ------------------- ------------------- Total Capitalization 15,096 15,198 ------------------- ------------------- TOTAL LIABILITIES AND CAPITALIZATION $ 25,214 $ 25,424 =================== =================== See Notes to Consolidated Financial Statements. </TABLE>
<TABLE> <CAPTION> PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions of Dollars) (Unaudited) For the Quarters Ended March 31, -------------------------------------- 2002 2001 ----------------- --------------- <S> <C> <C> Net income $ 180 $ 261 Adjustments to reconcile net income to net cash flows from operating activities: Depreciation and Amortization 137 108 Market Transition Charge (MTC) Overcollections 8 16 Amortization of Nuclear Fuel 24 27 AFDC and IDC (24) (12) Deferral of Gas Costs - net (86) (80) Provision for Deferred Income Taxes and ITC-- net 20 (15) Investment Distributions 3 86 Undistributed Earnings from Affiliates (14) (25) Net Losses on Investments 5 14 Change in Derivate Fair Value (10) (1) Leasing Activities 15 2 Proceeds from Sale of Capital Leases -- 1 Foreign Currency Transaction Loss 52 -- Gain on Withdrawal from Partnership Interests (7) (51) Proceeds from Withdrawal of Partnership Interests 50 7 Net Changes in Certain Current Assets and Liabilities: Accounts Receivable and Unbilled Revenues 36 42 Inventory-Fuel and Materials and Supplies 251 162 Prepayments 17 (5) Accounts Payable (244) (205) Accrued Taxes 14 181 Other Current Assets and Liabilities (9) 36 Other 88 (153) ----------------- --------------- Net Cash Provided By Operating Activities 463 438 ----------------- --------------- CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment, excluding IDC and AFDC (373) (356) Net Change in Long-Term Investments (49) (58) Other (121) -- ----------------- --------------- Net Cash Used in Investing Activities (543) (414) ----------------- --------------- CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Short-Term Debt 165 (2,332) Issuance of Long-Term Debt 73 3,088 Issuance of Common Stock 14 -- Redemption/Purchase of Long-Term Debt (24) (330) Redemption of Preferred Securities -- (240) Cash Dividends Paid on Common Stock (111) (112) Other (31) (2) ----------------- --------------- Net Cash Provided By Financing Activities 86 72 ----------------- --------------- Net Change in Cash and Cash Equivalents 6 96 Cash and Cash Equivalents at Beginning of Period 169 102 ----------------- --------------- Cash and Cash Equivalents at End of Period $ 175 $ 198 ================= =============== Income Taxes Paid $ 119 $ 8 Interest Paid $ 122 $ 108 See Notes to Consolidated Financial Statements. </TABLE>
================================================================================ PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED ================================================================================ NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 1. Organization and Basis of Presentation Organization Unless the context otherwise indicates, all references to "PSEG," "we," "us" or "our" herein means Public Service Enterprise Group Incorporated, an exempt public utility holding company which has four principal direct wholly-owned subsidiaries: Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power), PSEG Energy Holdings Inc. (Energy Holdings) and PSEG Services Corporation (Services). Basis of Presentation The financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). Certain information and note disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations. However, in the opinion of management, the disclosures are adequate to make the information presented not misleading. These consolidated financial statements and Notes to Consolidated Financial Statements (Notes) should be read in conjunction with the Notes contained in our 2001 Annual Report on Form 10-K. These Notes update and supplement matters discussed in our 2001 Annual Report on Form 10-K. The unaudited financial information furnished reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. The year-end consolidated balance sheets were derived from the audited consolidated financial statements included in our 2001 Annual Report on Form 10-K. Certain reclassifications of prior period data have been made to conform with the current presentation. Note 2. Accounting Matters On January 1, 2002 we adopted Statement of Financial Accounting Standard (SFAS) No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). Under SFAS 142, goodwill is considered a nonamortizable asset and is be subject to an annual review for impairment and an interim review when events or circumstances occur. The effect of no longer amortizing goodwill was not material to our financial position and statement of operations. The impact of adopting SFAS 142 is likely to be material to our financial position and statement of operations. We are required to complete our analysis of implementing SFAS No. 142 by June 30, 2002, and the related financial statement impact is required to be recorded by December 31, 2002. An impairment loss, as of the date of adoption, will be recognized as the cumulative effect of a change in accounting principle in the first interim period, if applicable. If certain events or changes in circumstance indicate that goodwill might be impaired before completion of the transitional goodwill impairment test, goodwill shall be tested for impairment and any impairment loss shall be recorded as a component of income from continuing operations. For additional information relating to potential asset impairments, see Note 4. Commitments and Contingent Liabilities. On January 1, 2002 we adopted SFAS No. 144, "Accounting for Impairment or Disposal of Long-Lived Assets" (SFAS 144). The impact of adopting SFAS 144 did not have an effect on our financial position and statement of operations. Under SFAS 144, long-lived assets to be disposed of are measured at the lower of carrying amount or fair value less costs 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. SFAS 144 also broadens the reporting of discontinued operations. A long-lived asset must be tested for impairment whenever events or changes in circumstances indicate that its carrying amount may be impaired. For additional information relating to potential asset impairments, see Note 4. Commitments and Contingent Liabilities.
================================================================================ PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED ================================================================================ NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). Under SFAS 143, the fair value of a liability for an asset retirement obligation should be recorded in the period in which it is created with an offsetting amount to an asset. 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. The impact of adopting SFAS 143 is likely to be material to our financial position and statement of operations. Note 3. Regulatory Assets and Liabilities At March 31, 2002 and December 31, 2001, respectively, we had deferred the following regulatory assets and liabilities on the Consolidated Balance Sheets: <TABLE> <CAPTION> March 31, December 31, 2002 2001 ----------------- ------------------- (Millions of Dollars) <S> <C> <C> Regulatory Assets Stranded Costs to be Recovered.............................. $4,059 $4,105 SFAS 109 Income Taxes....................................... 306 302 OPEB Costs.................................................. 207 212 Societal Benefits Charges (SBC)............................. -- 4 Environmental Costs......................................... 87 87 Unamortized Loss on Reacquired Debt and Debt Expense........ 90 92 Underrecovered Gas Costs.................................... 166 120 Unrealized Losses on Gas Contracts.......................... 22 137 Other....................................................... 179 188 ---------------- ------------------- Total Regulatory Assets............................... $5,116 $5,247 ================ =================== Regulatory Liabilities Excess Depreciation Reserve................................. $282 $319 Non-Utility Generation Transition Charge (NTC).............. 37 48 SBC......................................................... 18 -- Other....................................................... 7 6 ---------------- ------------------- Total Regulatory Liabilities.......................... $344 $373 ================ =================== </TABLE> Note 4. Commitments and Contingent Liabilities Guaranteed Obligations Power has guaranteed certain energy trading contracts of PSEG Energy Resources and Trading (ER&T), its subsidiary. Power has entered into guarantees having a maximum liability of $701 and $506 million as of March 31, 2002 and December 31, 2001, respectively. The amount of Power's exposure under these guarantees was $206 million and $153 million, as of March 31, 2002 and December 31, 2001, respectively. As of March 31, 2002, Power had issued letters of credit in the amount of approximately $122 million. These letters of credit are in support of our trading business and various contractual obligations.
================================================================================ PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED ================================================================================ NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued Energy Holdings or PSEG Global Inc. (Global), a subsidiary of Energy Holdings, have guaranteed certain obligations of Global's affiliates, including the successful completion, performance or other obligations related to certain of their projects, in an aggregate amount of approximately $188 million as of March 31, 2002. A substantial portion of such guarantees is eliminated upon successful completion, performance and/or refinancing of construction debt with non-recourse project debt. In the normal course of business, PSEG Energy Technologies Inc. (Energy Technologies), a subsidiary of Energy Holdings, secures construction obligations with performance bonds issued by insurance companies. In the event that Energy Technologies' tangible equity falls below $100 million, Energy Holdings would be required to provide additional support for the performance bonds. Tangible equity is defined as net equity less goodwill. As of March 31, 2002, Energy Technologies had tangible equity of $111 million and performance bonds outstanding of $130 million. The performance bonds are not included in the $188 million of guaranteed obligations of Energy Holdings, discussed above. Environmental 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. PSE&G, Power, and predecessor companies own or owned and/or operate 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 the compliance with these regulations will have a material adverse effect on our financial position, results of operations or net cash flows. PSE&G Manufactured Gas Plant Remediation Program PSE&G is currently working with the NJDEP under a program (Remediation Program) to assess, investigate and, if necessary, remediate environmental conditions at PSE&G's former manufactured gas plant (MGP) sites. To date, 38 sites have been identified. The Remediation Program is periodically reviewed and revised by PSE&G 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 at least $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. At March 31, 2002 and December 31, 2001, our estimated liability for remediation costs through 2004 aggregated $87 million. Expenditures beyond 2004 cannot be reasonably estimated. Passaic River Site The U.S. Environment Protection Agency (EPA) has determined that a six mile stretch of the Passaic River in Newark, New Jersey is a "facility" within the meaning of that term under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and that, to date, at least thirteen corporations, including PSE&G, may be potentially liable for performing required remedial actions to address potential environmental pollution at the Passaic River "facility." PSE&G, PSEG Fossil LLC (Fossil), a subsidiary of Power, and certain of their predecessors operated industrial facilities at properties within the Passaic River "facility," comprised of four former MGPs, one operating electric generating station and one former generating station. PSE&G's costs to clean up former MGPs are recoverable from its utility customers under the SBC. PSE&G has contracted to sell the former generating site to a third party that would be responsible for remediation costs. Regulatory approval by the state is pending. We cannot predict what action, if any, the EPA or any third party may take against PSE&G and Power with respect to these matters, or in such event, what costs PSE&G and Power may incur to address any such claims. However, such costs may be material. Prevention of Significant Deterioration (PSD)/New Source Review (NSR) In a response to a request by the EPA and the NJDEP under Section 114 of the Federal Clean Air Act (CAA) requiring information to assess whether projects completed since 1978 at the Hudson and Mercer coal burning units were implemented in accordance with applicable NSR regulations, we provided certain data in November 2000. In January 2002, we reached an agreement with the state and the federal government to resolve allegations of noncompliance with federal and state NSR regulations. Under that agreement, we will install advanced air pollution controls over 12 years that are expected to significantly reduce emissions of nitrogen oxides (NOx), sulfur dioxide (SO2), and carbon dioxide (CO2), particulate matter, and mercury from these units. The estimated cost of the program is $355 million and such costs, when incurred, will be capitalized as plant additions. We also paid a $1.4 million civil penalty, and will pay up to $6 million on supplemental environmental projects and up to $1.5 million if reductions in CO2 levels are not achieved. The EPA had also asserted that PSD requirements are applicable to Bergen 2, such that we were required to have obtained a permit before beginning actual on-site construction. We disputed that PSD/NSR requirements were applicable to Bergen 2. As a result of the agreement resolving the NSR allegations concerning Hudson and Mercer, the NJDEP issued an air permit for Bergen 2. The unit is expected to begin operating in June 2002. Power New Generation and Development Power is in the process of developing the Bethlehem Energy Center, a 750 MW combined-cycle power plant that will replace the 400 MW Albany (NY) Steam Station. Total costs for this project will be approximately $450 million with expenditures to date of approximately $59 million. Construction is expected to begin in the summer of 2002. The expected completion date is in June 2004, at which time the existing station will be retired. Power is constructing a 550 MW natural gas-fired, combined cycle electric generation plant at Bergen Generation Station at a cost of approximately $319 million with completion expected in June 2002. Total expenditures to date have been $299 million. Power is also constructing a 1,186 MW combined cycle generation plant in Linden, New Jersey. Costs are estimated at approximately $600 million with expenditures to date of approximately $282 million. Completion is expected in May 2003 at which time 445 MW of generating capacity will be retired. Power is also constructing through indirect, wholly-owned subsidiaries, two natural gas-fired combined cycle electric generation plants in Waterford, Ohio (850 MW) and Lawrenceburg, Indiana (1,150 MW) at an aggregate total cost of $1.2 billion. Total expenditures to date on these projects have been approximately $968 million. The required estimated equity investment in these projects is approximately $400 million, with the remainder being financed with non-recourse debt. As of March 31, 2002, approximately $168 million of equity has been invested in these projects. In connection with these projects, ER&T has entered into a five-year tolling agreement pursuant to which it is obligated to purchase the output of these facilities at stated prices. The agreement expires if current financing is repaid within five years. Additional equity investments may be required if the proceeds received from ER&T under this tolling agreement are not sufficient to cover the required payments under the bank financing. The Waterford project will not begin commercial operation as a single-cycle facility in June 2002 as originally scheduled. Both the Waterford and Lawrenceburg combined-cycle facilities are currently scheduled to achieve commercial operation in 2003. Power has commitments to purchase equipment and services, to meet its current plans to develop additional generating capacity. The aggregate amount due under these commitments is approximately $480 million, the majority of which are included in estimated costs for the projects discussed above. Energy Holdings California Investments In May 2001, GWF Energy LLC (GWF Energy), a 50/50 joint venture between Global and Harbinger GWF LLC, entered into a 10-year power purchase agreement (PPA) with the California Department of Water Resources (CDWR) to provide 340 MW of electric capacity to California from three new natural gas-fired peaking plants, Hanford, Henrietta and Tracy Peaking Plants. Total project cost is estimated at approximately $335 million. The Hanford Peaking Plant, a 90 MW facility, was completed and began operation in August 2001. The Henrietta Peaking Plant is currently under construction, with completion expected in July 2002, and the Tracy Peaking Plant, a 160 MW facility, is in the permitting process. Permitting for the Tracy Peaking project has been delayed significantly. The California Energy Commission is not expected to issue a permit allowing the start of construction before the end of June 2002. This date does not allow sufficient time to complete construction before the final Commercial Operations Date deadline of October 31, 2002 under the contract. On February 28, 2002, GWF Energy asserted a force majeure claim under the provisions of its contract for an appropriate extension of the deadline. On April 24, 2002, GWF Energy received notice from the CDWR rejecting GWF Energy's force majeure claim. Energy Holdings and Global are evaluating the appropriate course of action to protect its rights under the CDWR PPA. Global's permanent equity investment in these plants, including contingencies, is not expected to exceed $100 million after completion of project financing, which is currently expected to occur in late 2002 or in 2003. For a description of the loans to GWF Energy, see Note 10. Related-Party Transactions. On February 25, 2002 the Public Utilities Commission of the State of California and the State of California Electricity Oversight Board filed complaints with the Federal Energy Regulatory Commission (FERC) under Section 206 of the Federal Power Act against sellers, which pursuant to long-term FERC authorized contracts, provide power to the CDWR. GWF Energy is a named respondent in these proceedings. The complaints, which address over 40 transactions embodied in over 30 contracts with over 20 sellers, allege that, collectively, the specified long-term wholesale power contracts are priced at unjust and unreasonable levels and request FERC to abrogate the contracts to enable the State to obtain replacement contracts as necessary or in the alternative, to reform the contracts to provide for just and reasonable pricing, reduce the length of the contracts and strike from the contracts the specific non-price conditions found to be unjust and unreasonable. On April 25, 2002, FERC consolidated the two dockets and set the ten year PPA contract of GWF Energy and certain other respondents, including the ten year PPA contact for hearing "to determine whether the dysfunctional California spot markets adversely affected the long-term bilateral markets and, if so, whether modification of any individual contract at issue is warranted." FERC determined that the GWF contract, among others, was entitled to presumption of validity, requiring the CPUC to prove it was "against the public interest." FERC also strongly encouraged the parties to negotiate settlements and directed a settlement judge to be appointed to oversee such negotiations. GWF Energy has indicated to representatives of the State of California its willingness to enter into negotiations in an attempt to resolve differences between the parties. GWF Energy plans to attend FERC settlement conference discussions during the week of May 13, 2002. We cannot predict the outcome of this matter or its impact on future earnings or cash flows.
Dispute of Power Contracts-Tanir Bavi Global owns a 74% interest in Tanir Bavi Power Company Private Ltd. (Tanir Bavi), which owns and operates a 220 MW barge mounted, combined-cycle generating facility. The plant commenced combined-cycle commercial operation in November 2001. Power from the plant is being sold under a seven-year fixed price PPA with the Karnataka Power Transmission Company Limited (KPTCL), a State affiliated entity, formerly known as Karnataka Electricity Board. Tanir Bavi has been in dispute with KPTCL regarding the terms of payment specified in the PPA relating to the fixed portion of the tariff, which is approximately US $.04 per kilowatt-hour. The amount of the dispute is approximately half of this fixed amount. During the first quarter of 2002, KPTCL referred the dispute to the government of Karnataka, which directed KPTCL to accept Tanir Bavi's position. Prior to KPTCL's acceptance of such direction, however, the Karnataka Electricity Regulatory Commission (KERC) exercised jurisdiction over the matter and requested that KPTCL not comply with the requests of the government of Karnataka until KERC had reviewed the matter. A hearing was held in May 2002, at which KERC determined that the disputed amounts could not be paid until the parties complied with the dispute resolution process called for in the PPA. KERC did not rule on the merits regarding the arrearages but directed the parties on the process of the dispute. The dispute resolution process could take several months. Beginning in January 2002, approximately 50% of the disputed amounts were subject to a reserve established by Global. Beginning in the second quarter of 2002, Global began to reserve 100% of the disputed amount. As of March 31, 2002, the amount in dispute due from KPTCL was $22 million, net of reserves, of which our share was $16 million. We cannot predict the outcome due to the uncertainty of the dispute resolution process. If there was an unfavorable outcome in this matter, we would be required to recognize a loss of up to our share of the entire unrecovered and unreserved amount in dispute. In addition, an unfavorable outcome would adversely impact this project's future earnings and cash flows and could lead to an impairment of the existing $27 million of goodwill associated with this project. Potential Asset Impairments As previously disclosed, and as discussed below, we are currently evaluating the recoverability of our $585 million capital at risk in Argentina. In addition, as part of the implementation of SFAS 142, the goodwill associated with Rio Grande Energia (RGE), EDEERSA, Energy Technologies and Tanir Bavi is being evaluated for potential impairment. Under a worst-case scenario, if the results of these evaluations indicate a complete impairment, we would record an approximate $735 million (pre-tax and pre-minority interest), $473 million (after-tax and after minority interest) charge to earnings in 2002. This would amount to approximately $2.29 per share. The related, worst-case, charge to equity would be approximately $410 million due to the $63 million charge to OCI previously recorded in the first quarter. We expect to complete our evaluation of these issues during the second quarter of 2002. Argentine Economic Crisis As of March 31, 2002, Energy Holdings' aggregate investment exposure in Argentina was approximately $585 million, including $165 million of investment exposure for Empresa Distribuidora de Electricidad de Entre Rios S.A. (EDEERSA), and $420 million of investment exposure for assets under contract for sale. This investment exposure was reduced in the first quarter by a $47 million (pre-tax) charge related to the change in the functional currency at EDEERSA discussed further below. Goodwill related to Energy Holdings' investment in EDEERSA is approximately $63 million and is included in this investment exposure. Investments include a 90% owned distribution company, EDEERSA; and Energy Holdings' minority interests in three distribution companies, Empresa Distribuidora de Energia Norte S.A. (EDEN), Empresa Distribuidora de Energia Sur S.A. (EDES), and Empresa Distribuidora La Plata S.A. (EDELAP) and two generating companies, Central Termica San Nicolas power plant (CTSN), and Parana which are under contract for sale to certain subsidiaries of the AES Corporation (AES). The Argentine economy has been in a state of recession for approximately five years. Continued deficit spending in the 23 Argentine provinces, coupled with low growth and high unemployment, has precipitated an economic, political and social crisis. Toward the end of 2001, a liquidity crisis ensued causing the Argentine government to default on $141 billion of national debt. The economic crisis was fueled by political instability and social unrest as the new year began. The present Argentine federal government is in the process of developing an economic plan to avert a return to the economic instability and hyperinflationary economy of the 1980s. In early January 2002, the decade old convertibility formula that maintained the Argentine Peso at a 1:1 exchange rate with the US Dollar, was abandoned. In early February 2002, the Argentine Peso was no longer pegged to the US Dollar. In the first day of the free floating formula, the currency weakened to a rate of approximately 2 Pesos per 1 US Dollar. At the end of March 2002, the currency weakened further to a rate of approximately 2.90 Pesos per 1 US Dollar. As of April 30, 2002, the currency weakened further to a rate of approximately 2.96 Pesos per 1 US Dollar. In the Province of Entre Rios, where EDEERSA is located, the electricity law provided for a pass-through of devaluation to the end user customer. Customers' bills were to be first computed in US Dollars and then converted into Pesos for billing. This mechanism assured that devaluation would not impact the level of US Dollar revenues an electric distribution company received. However, in January 2002, the Argentine federal government implemented a new law that prohibits any foreign price or currency indexation and any US Dollar or other foreign currency adjustment clauses relating to public service tariffs, thus prohibiting the pass through of the costs of devaluation to customers. The provincial governments have been requested to adopt this provision. The provincial government of the Province of Entre Rios has recently adopted this provision as well as a law that requires public service companies within the Province, including EDEERSA, to accept payment for all billed services in a provincial promissory note, the "Federal". The terms of the "Federal" require principal payment at maturity in an equal amount of Argentine Pesos. However, the "Federal" is not freely convertible in the financial markets into Argentine Pesos or US Dollars. Approximately 75% of cash receipts generated from EDEERSA's operations are currently settled in "Federals." There are ongoing negotiations to remedy this situation, although no assurances can be given. While we continue to operate EDEERSA, there has been an adverse impact to its financial condition and cash flows due to its inability to pass through the costs of devaluation to customers and its receipt of an illiquid provincial currency. Energy Holdings is pursuing remedies on several fronts, including holding discussions with the Province and United States government officials, both individually and collectively with a coalition of international investors, and Energy Holdings is pursuing legal recourse under the Bilateral Investment Treaty between the United States and Argentina. Energy Holdings has been notified by lenders of the occurrence of events of default in certain of its subsidiaries non-recourse credit agreements related to Parana, EDEN, EDES, and EDELAP credit facilities. If Argentine conditions do not improve, Global's other Argentine properties may also default on non-recourse obligations in connection with other financings. Currently, we cannot predict the outcome of our ongoing negotiations with the lenders. The situation in Argentina is quite uncertain and highly volatile. While it is likely that some or all of our investment in Argentina is impaired, the continued lack of stability in the political and economic environment causes significant variability in the quantification of value. However, the continued passage of time without a credible solution and continuing instability diminishes the prospect of recovery. Other potential impacts of the Argentine economic, political and social crisis, include increased collection risk, further devaluation of the Peso, potential nationalization of assets, foreclosure of our assets by lenders and an inability to complete the pending sale of certain Argentine assets to certain subsidiaries of AES. Global anticipates that evolving economic and political events, ongoing discussions with regulators about tariff levels and discussions with lenders will occur that will enable a determination of value in the second quarter of 2002. Functional Currency - Argentine Operations As of December 31, 2001, the functional currency of EDEERSA was the US Dollar, as all revenues, most expenses and all financings were denominated in US Dollars or were linked to the US Dollar. As a US Dollar reporting entity, EDEERSA's monetary accounts denominated in Pesos, such as short-term receivables or payables, were re-measured into the US Dollar with a minimal impact to earnings. At December 31, 2001, Energy Holdings' 90% share of EDEERSA's US Dollar denominated debt was approximately $76 million. This debt is non-recourse to us and Energy Holdings. Due to the recent events described above, we changed the functional currency of EDEERSA's operations to the Argentine Peso, effective March 1, 2002. As a result, all monetary accounts denominated in US Dollars were re-measured to the Argentine Peso effective March 1, 2002, including the US Dollar denominated debt using the applicable exchange rate of 2.90 Pesos per 1 US Dollar. This resulted in a pre-tax loss of approximately $47 million after deductions for minority interest for the quarter ended March 31, 2002. In addition to this impact on our Consolidated Statements of Income, the recorded amount of Energy Holdings' net investment in EDEERSA decreased by approximately $100 million due to the translation adjustment as of March 31, 2002. Assets Held for Sale-Certain Argentine Projects On August 24, 2001, Global entered into a Stock Purchase Agreement to sell its minority interests in EDEN, EDES, EDELAP, CTSN and Parana, to certain subsidiaries of AES. The transaction is subject to regulatory approval and consent of lenders. On February 6, 2002, AES notified Global that it was terminating the Stock Purchase Agreement. In the Notice of Termination, AES alleged that a Political Risk Event, within the meaning of the Stock Purchase Agreement, had occurred, by virtue of certain decrees of the Government of Argentina, thereby giving AES the right to terminate the Stock Purchase Agreement. Global disagrees that a Political Risk Event as defined in the Stock Purchase Agreement, which is limited to expropriation of assets, has occurred and has so notified AES. In April 2002, Global filed a lawsuit in New York State Supreme Court for New York County against AES to enforce its rights under the Stock Purchase Agreement, which it will vigorously pursue. We cannot predict the ultimate outcome of this matter.
As of March 31, 2002, we had approximately $19 million of interest and other receivables due from the AES Corporation as provided for in the transaction documents. In the first quarter of 2002, the Administrative Agent for the non-recourse project financing notified Global that Parana was in default and a $28 million equity commitment was accelerated by two weeks. Global made such payment in March 2002 and it is included in the $585 million of investment exposure in Argentina. Goodwill As of March 31, 2002, the carrying value of unamortized goodwill was $621 million, of which $451 million was recorded in connection with Global's acquisitions of Sociedad Austral de Electricidad S.A. (SAESA) and Empresa de Electricidad de los Andes S.A. (Electroandes) in Chile and Peru in August and December of 2001, respectively. For the year-ended December 31, 2001, the amortization expense related to goodwill was $3 million. As of March 31, 2002, our pro-rata share of goodwill included in equity method investees totaled $378 million. In accordance with generally accepted accounting principles, such goodwill is not consolidated on our balance sheet. Our share of the amortization expense related to such goodwill was $8 million for the year-ended December 31, 2001. However, this goodwill is subject to the same impairment testing under SFAS 142 at the local entities. We are in the process of finalizing our evaluation of the effect of adopting SFAS 142 on the recorded amount of goodwill at RGE, EDEERSA, Energy Technologies and Tanir Bavi. It is likely that the entire carrying value of the goodwill at EDEERSA and Energy Technologies is completely impaired, that the goodwill at RGE up to approximately half of the recorded carrying value could be impaired, and that the goodwill at Tanir Bavi could be impaired. The goodwill at EDEERSA is included in the $585 million of investment exposure associated with our assets in Argentina.
As of March 31, 2002, our unamortized goodwill and pro-rata share of goodwill in equity method investees was as follows: As of March 31, 2002 --------------------- (Millions of Dollars) Global EDEERSA ............................................... $ 63 SAESA ................................................. 315 Electroandes .......................................... 136 Tanir Bavi ............................................ 27 Chorzow ............................................... 6 ---- Total Global .................................... $547 ---- Energy Technologies ...................................... 53 Power .................................................... 21 ---- Total Consolidated Goodwill ................ $621 ---- Global RGE ................................................... $140 Chilquinta ............................................ 174 Luz del Sur ........................................... 39 Kalaeloa .............................................. 25 ---- Pro-Rata Share of Equity Investment Goodwill ........ $378 ---- Total Goodwill .................................. $999 ==== As of December 31, 2001 goodwill was $1.024 billion. As of March 31, 2002, goodwill was $999 million. The decrease of $25 million from year-end represents a purchase price adjustment with respect to our acquisition of Electroandes. Note 5. Financial Instruments, Energy Trading and Risk Management Our operations are exposed to market risks from changes in commodity prices, foreign currency exchange rates, interest rates and equity prices 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 for energy trading purposes.
Energy Trading Contracts We engage in physical and financial transactions in the electricity wholesale markets and execute an overall risk management strategy to mitigate the effects of adverse movements in the fuel and electricity markets. We actively trade energy, capacity, fixed transmission rights and emissions allowances in the spot, forward and futures markets primarily in Pennsylvania-New Jersey-Maryland Power Pool (PJM), but also throughout our target market, which we refer to as the Super Region, which extends from Maine to the Carolinas and the Atlantic Coast to Indiana. We are also involved in financial transactions that include swaps, options and futures in the electricity markets. Our energy trading contracts are recorded under Emerging Issues Task Force (EITF) 98-10. This requires energy trading contracts to be marked-to-market with the resulting realized and unrealized gains and losses included in current earnings. These contracts are recorded in our Energy Trading Segment. We also enter into certain other contracts for our generation business which are derivatives but do not qualify for hedge accounting under SFAS 133 nor are classified as energy trading contracts under EITF 98-10. Most of these contracts are option contracts on gas purchases for generation requirements, which do not qualify for hedge accounting and therefore the changes in fair market value of these derivative contracts are recorded in the income statement at the end of each reporting period in our generation segment. Energy Trading For our Energy Trading Segment for the quarters ended March 31, 2002 and 2001, we recorded net margins of $29.6 million and $48.8 million, respectively, as shown below: For the Quarter Ended March 31, --------------------------------- 2002 2001 -------------- --------------- Millions of Dollars Realized Gains....................... $ 1.1 $47.1 Unrealized Gains..................... 30.3 3.6 -------------- --------------- Gross Margin..................... $31.4 $50.7 ============== =============== Net Margin*...................... $29.6 $48.8 ============== =============== * Net Margin equals Gross Margin less broker fees and other trading related expenses of $1.8 million and $1.9 million, for the quarters March 31, 2002 and March 31, 2001, respectively.
Generation For our generation asset based business for the quarters ended March 31, 2002 and 2001, we recorded gross margins of $(4.5) million and $0.2 million, respectively, as shown below: For the Quarter Ended March 31, --------------------------------- 2002 2001 -------------- --------------- Millions of Dollars Realized (Losses)................ $(12.0) $-- Unrealized Gains................. 7.5 0.2 -------------- --------------- Gross Margin................. $(4.5) $0.2 ============== =============== As of March 31, 2002, the fair value of our energy contracts in trading and generation segments was $49.8 million, described below, more than 90% of which have terms of two years or less. <TABLE> <CAPTION> (Millions of Dollars) ------------------------------------------------------------- Energy Trading Generation Total ----------------- ------------------- ----------------- <S> <C> <C> <C> Fair Value December 31, 2001............. $9.7 $(11.6) $(1.9) Realized (Gains)/Losses.................. (1.1) 12.0 10.9 Unrealized Gains......................... 30.3 7.5 37.8 Fair Value of New Contracts.............. 3.0 -- 3.0 ----------------- ------------------- ----------------- Fair Value March 31, 2002................ $41.9 $7.9 $49.8 ================= =================== ================= </TABLE> The fair values as of March 31, 2002 and December 31, 2001 of financial instruments related to the energy commodities in our energy trading segment are summarized in the following table: <TABLE> <CAPTION> March 31, 2002 December 31, 2001 ----------------------------- -------------------------------- Notional Notional Fair Notional Notional Fair (mWh) (MMBTU) Value (mWh) (MMBTU) Value ------------------------------ ---------------------- --------- (Millions) (Millions) <S> <C> <C> <C> <C> <C> Futures and Options NYMEX. 14.0 12.0 $(1.5) -- 16.0 $(1.2) Physical forwards......... 53.0 48.0 $9.9 41.0 9.0 $(2.6) Options-- OTC............. 2.0 470.0 $16.7 8.0 717.0 $(18.7) Swaps..................... -- 1,151.0 $3.5 -- 1,047.0 $23.9 Emission Allowances....... -- -- $13.3 -- -- $8.3 </TABLE>
The fair values as of March 31, 2002 and December 31, 2001 of financial instruments related to the energy commodities in our generation segment are summarized in the following table: <TABLE> <CAPTION> March 31, 2002 December 31, 2001 ------------------------------ ------------------------------- Notional Notional Fair Notional Notional Fair (mWh) (MMBTU) Value (mWh) (MMBTU) Value ------------------------------ ------------------------------- (Millions) (Millions) <S> <C> <C> Futures and Options NYMEX. -- 1.0 $1.2 -- -- -- Physical forwards......... -- -- -- -- -- -- Options-- OTC............. -- 79.0 $5.4 -- 86.0 $(10.4) Swaps..................... -- 64.0 $1.3 -- 84.0 $(1.2) Emission Allowances....... -- -- -- -- -- -- </TABLE> We routinely enter into exchange traded futures and options transactions for electricity and natural gas as part of our energy trading operations. Generally, exchange-traded futures contracts require deposit of margin cash, the amount of which is subject to change based on market movement and in accordance with exchange rules. The amount of the margin deposits as of March 31, 2002 was approximately $4.9 million. Derivative Financial Instruments and Hedging Activities Commodity Contracts The availability and price of energy commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies and other events. To reduce price risk caused by market fluctuations, we enter into derivative contracts, including forwards, futures, swaps and options with approved counterparties, to hedge our anticipated demand. These contracts, in conjunction with owned electric generation capacity, are designed to cover estimated electric customer commitments. The BPU approved an auction to identify energy suppliers for the Basic Generation Service (BGS) beginning on August 1, 2002. Power did not participate directly in the auction but agreed to supply power to several of the direct bidders, securing contracts for a substantial portion of our generation capacity. On February 15, 2002 the BPU approved the BGS auction results. As a result of the BGS auction, Power has entered into BGS/Third Party Suppliers agreements with several counterparties who won bids to deliver energy, capacity, transmission and ancillary services to serve the native load of various New Jersey utilities at a fixed price. In order to hedge a portion of our forecasted BGS requirements, Power entered into forward purchase contracts, futures, options and swaps. Power has forecasted the energy delivery from our generating stations based on the forward price curve movement of energy. As a result, Power entered into swaps, options and futures transactions to hedge the price of gas to meet our gas purchases requirements for generation. These transactions qualify for hedge accounting treatment under SFAS 133. As of March 31, 2002, the fair value of these hedges was $11.1 million with offsetting charges to Other Comprehensive Income (OCI) of $6.5 million (after-tax). These hedges will mature in 2003. As of March 31, 2002, PSE&G had entered into 268 MMBTU of gas futures, options and swaps to hedge forecasted requirements. Also as of December 31, 2001, PSE&G had entered into 330 MMBTU of gas futures, options and swaps to hedge forecasted requirements. As of March 31, 2002 and December 31, 2001, the fair value of those instruments was $(22.0) and $(137.0) million, respectively, with a maximum term of approximately one year. PSE&G utilizes derivatives to hedge its gas purchasing activities which, when realized, are recoverable in rates through the Levelized Gas Adjustment Clause (LGAC). Accordingly, these commodity contracts are recognized at fair value as derivative assets or liabilities on the balance sheet and the offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability. We use a value-at-risk (VAR) model to assess the market risk of our commodity business. This model includes fixed price sales commitments, owned generation, native load requirements, physical contracts and financial derivative instruments. VAR represents the potential gains or losses for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. We estimated VAR across our commodity business using a model with historical volatilities and correlations. Our Board of Directors has established a VAR Threshold of $75 million and the Risk Management Committee (RMC) has established an internal VAR threshold of $50 million for Power. If the $50 million threshold was reached, the RMC would be notified and the portfolio would be closely monitored to reduce risk and potential adverse movements. The measured VAR using a variance/co-variance model with a 95% confidence level and assuming a one-week time horizon as of March 31, 2002 was approximately $22 million, compared to the December 31, 2001 level of $18 million which was calculated using various controls and conservative assumptions, such as a 50% success rate in the BGS Auction. This estimate, however, is not necessarily indicative of actual results, which may differ due to the fact that actual market rate fluctuations may differ from forecasted fluctuations and due to the fact that the portfolio of hedging instruments may change over the holding period and due to certain assumptions embedded in the calculation.
Interest Rates We, PSE&G, Power and Energy Holdings 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, interest rate swaps and interest rate lock agreements. As of March 31, 2002, a hypothetical 10% change in market interest rates would result in a $3 million, $5 million and $1 million change in annual interest costs related to short-term and floating rate debt at PSEG, PSE&G and Energy Holdings, respectively. The following table shows details of the interest rate swaps at PSEG, PSE&G, Power and Energy Holdings and their associated values that are still open at March 31, 2002: <TABLE> <CAPTION> - -------------------------------------- -------- ---------- ---------- ------------ ---------- -------------- ---------- Accumulated Total Fair Other Project Notional Pay Receive Market Comprehensive Maturity Underlying Securities Percent Amount Rate Rate Value Income Date (A) (B) - -------------------------------------- ------- ---------- ---------- ------------ ---------- -------------- ---------- (Millions of dollars, where applicable) <S> <C> <C> <C> <C> <C> <C> <C> PSEG: Enterprise Capital Trust II 100% $150.0 5.98% 3-month $(2.6) $1.5 2008 Securities LIBOR PSE&G: Transition Funding Bonds (Class 100% $497.0 6.29% 3-month (10.6) -- 2011 A-4) LIBOR Power: Construction Loan - Waterford 100% $177.5 4.16% 3-month 3.6 (2.1) 2005 LIBOR Energy Holdings: Construction Loan - Tunisia 60% $56.8 6.96% 6-month (3.6) 1.4 2009 (US$) LIBOR Construction Loan - Tunisia 60% $62.9 5.19% 6-month (0.7) 0.3 2009 (EURO) EURIBOR* Construction Loan - Poland 55% $108.2 8.40% 6-month (28.0) 9.5 2010 (US$) LIBOR Construction Loan - Poland 55% $47.4 13.23% 6-month (22.2) 7.4 2010 (PLN) WIBOR** Construction Loan - Oman 81% $70.3 6.27% 6-month (1.2) 1.0 2018 LIBOR Construction Loan - Kalaeloa 50% $55.4 6.60% 3-month (1.4) 0.9 2007 LIBOR Construction Loan - Guadalupe 50% $125.1 6.57% 3-month (3.3) 2.1 2004 LIBOR Construction Loan - Odessa 50% $136.6 7.39% 3-month (5.0) 3.3 2004 LIBOR ---------- ---------- --------- Total Energy Holdings $662.7 $(65.4) $25.9 ---------- ---------- --------- Total PSEG $1,487.2 $(75.0) $25.3 ========== ========== ========= <FN> * EURIBOR - EURO Area Inter-Bank Offered Rate ** WIBOR - Warsaw Inter-Bank Offered Rate (A) Represents 100% of Derivative Instrument. (B) Net of Tax and Minority Interest. </FN> </TABLE> We expect to reclass approximately $24.5 million of open losses on interest rate swaps from OCI to earnings during the next twelve months. As of March 31, 2002, there was a $25.3 million balance remaining in the Accumulated Other Comprehensive Loss account, as indicated in the table above.
Equity Securities PSEG Resources Inc. (Resources), a wholly- owned subsidiary of Energy Holdings has investments in equity securities and limited partnerships. Resources carries its investments in equity securities at their approximate fair value as of the reporting date. Consequently, the carrying value of these investments is affected by changes in the fair value of the underlying securities. Fair value is determined by adjusting the market value of the securities for liquidity and market volatility factors, where appropriate. The aggregate fair values of such investments, which had quoted market prices at March 31, 2002 and December 31, 2001 were $28 million and $34 million, respectively. The potential change in fair value resulting from a hypothetical 10% change in quoted market prices of these investments amounted to $2 million as of March 31, 2002. Foreign Currencies We conduct our business on a multinational basis in a wide variety of foreign currencies. Our objective for foreign currency risk management policy is to preserve the economic value of cash flows in currencies other than the US Dollar. Our policy is to hedge significant probable future cash flows identified as subject to significant foreign currency variability. In addition, we typically hedge a portion of our exposure resulting from identified anticipated cash flows, providing the flexibility to deal with the variability of longer-term forecasts as well as changing market conditions, in which the cost of hedging may be excessive relative to the level of risk involved. Our foreign currency hedging activities to date include hedges of US Dollar debt arrangements in operating companies that conduct business in currencies other than the US Dollar. As of March 31, 2002, Global and Resources had international assets of approximately $3.5 billion and $1.4 billion, respectively. Resources' international investments are primarily leveraged leases of assets located in Austria, Australia, Belgium, China, Germany, the Netherlands, United Kingdom, and New Zealand with associated revenues denominated in U.S. Dollars and therefore, not subject to foreign currency risk. Global's international investments are primarily in projects that presently or upon completion are expected to generate or distribute electricity in Argentina, Brazil, Chile, China, India, Italy, Oman, Peru, Poland, Taiwan, Tunisia and Venezuela. Investing in foreign countries involves certain additional risks. Economic conditions that result in higher comparative rates of inflation in foreign countries are likely to result in declining values in such countries' currencies. As currencies fluctuate against the $US, there is a corresponding change in Global's investment value in terms of the $US. Such change is reflected as an increase or decrease in the investment value and OCI, a separate component of Stockholder's Equity. As of March 31, 2002, net foreign currency devaluations have reduced the reported amount of our total Stockholder's Equity by $320 million, of which $159 million, $84 million and $63 million were caused by the devaluation of the Brazilian Real, Chilean Peso and Argentine Peso, respectively. Global holds a 60% ownership interest in Carthage Power Company (CPC), a Tunisian generation facility under construction. The Power Purchase Agreement (PPA), signed in 1999, contains an embedded derivative that indexes a portion of the fixed Tunisian Dinar payments to US Dollar exchange rates. The indexation portion of the PPA is considered an embedded derivative and has been recognized and valued separately as a derivative instrument. As the Dinar depreciates/appreciates in relation to the US Dollar, the derivative increases/decreases in value equal to the discounted present value of additional units of foreign currency (measured in US Dollars) over the life of the PPA. This increased/decreased value is reported on the balance sheet as an asset/liability. To the extent that such indexation is provided to hedge foreign currency debt exposure, the offsetting amount is recorded in OCI. Amounts will be reclassified from OCI to Earnings over the life of the debt beginning on the date of commercial operation of the project, expected to occur in the second quarter of 2002. To the extent such indexation is provided to hedge an equity return in US Dollars, the offsetting amount is recorded in Earnings. As of March 31, 2002, we had a derivative asset of $40 million recorded on the balance sheet related to the indexation of the PPA. During the first quarter of 2002, a gain of $4 million, net of tax and minority interests, was recorded to earnings as a result of a net increase in the value of the derivative. Global holds a 32% ownership interest in a Brazilian distribution company, RGE, whose debt is denominated in US Dollars. As of March 31, 2002, Global's pro-rata share of such debt was approximately $60 million. In order to hedge the risk of fluctuations in the exchange rate between the two currencies associated with the debt principal payments due in 2002, RGE entered into three forward exchange contracts to purchase US Dollars for Brazilian Reais in December 2001. Global's share of the notional value of these contracts, which expire in the same months as the respective principal payments are due, is approximately $12 million. As of March 31, 2002, Global's share of the derivative liability associated with these contracts was $2 million and the change in fair value for the three months ended March 31, 2002 was negligible to our Consolidated Statement of Income. Additionally, in order to hedge the risk of fluctuations in the exchange rate between the two currencies associated with the principal payments due in 2003 through 2005, RGE entered into nine cross currency interest rate swaps in January 2002. The instruments convert the fixed US Dollar principal payments to Brazilian Real-denominated obligations with a variable CDI-based (the Brazilian inter-bank offered rate) interest rate. As a result, RGE has hedged its foreign currency exposure but is still at risk for variability in the Brazilian CDI interest rate during the terms of the instruments. Global's share of the notional values of these instruments is approximately $49 million. The fair market value of the instruments as of March 31, 2002, and the change in the fair market values of these instruments for the three months ended March 31, 2002 were both approximately $1 million. The fluctuations in the fair value of the interest rate components of these cross currency swaps were recorded directly to the Consolidated Statements of Income. Through its 50% joint venture, Meiya Power Company, Global holds a 17.5% ownership interest in a Taiwanese generation project under construction where the construction contractor's fees, payable in installments through July 2003, are payable in Euros. To manage the risk of foreign exchange rate fluctuations associated with these payments, the project entered into a series of forward exchange contracts to purchase Euros in exchange for Taiwanese Dollars. As of March 31, 2002, Global's share of the fair value and aggregate notional value of these forward exchange contracts was an asset of less than $1 million and $16 million, respectively. These forward exchange contracts were designated as hedges for accounting purposes and were recorded to OCI, resulting in a change to OCI of less than $1 million, Global's share after-tax for the quarter ended March 31, 2002. During 2001, Global purchased approximately 100% of a Chilean distribution company. In order to hedge final Chilean Peso denominated payments required to be made on the acquisition, Global entered into a forward exchange contract to purchase Chilean Pesos for US Dollars. Upon settlement of the transaction, Global recognized an after-tax loss of $1 million. Furthermore, as a requirement to obtain certain debt financing necessary to fund the acquisition, and in order to hedge against fluctuations in the US Dollar to Chilean Peso foreign exchange rates, Global entered into two forward contracts with notional values of $75 million each to exchange Chilean Pesos for US Dollars. These transactions expire in October 2002 and are considered hedges for accounting purposes. As of March 31, 2002, the derivative liability value of $15 million has been recorded to OCI, net of taxes. Credit Risk Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We have established credit policies that we believe significantly minimize credit risk. These policies include an evaluation of potential counterparties' financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which may allow for the netting of positive and negative exposures associated with a single counterparty. As a result of the BGS auction, Power has contracted to provide generating capacity to the direct suppliers of New Jersey electric utilities, including PSE&G, commencing August 1, 2002. These bilateral contracts are subject to credit risk. This credit risk relates to the ability of counterparties to meet their payment obligations for the power delivered under each BGS contract. This risk is substantially higher than the risk associated with potential nonpayment by PSE&G under the BGS contract expiring July 31, 2002. Any failure to collect these payments under the new BGS contracts could have a material impact on our results of operations, cash flows, and financial position. Note 6. Income Taxes Our effective income tax rate is as follows: Quarter Ended March 31, -------------- 2002 2001 ------ ------ Federal tax provision at statutory rate ........................ 35.0% 35.0% New Jersey Corporate Business Tax, net of Federal benefit ...... 5.9% 5.9% Other-- net .................................................... (2.1)% (3.3)% ------- ------ Effective Income Tax Rate ................................. 38.8% 37.6% ======= ======
Note 7. Financial Information by Business Segments Information related to the segments of our business is detailed below: <TABLE> <CAPTION> Generation Energy Global Energy Other Consolidated (A) Trading PSE&G Resources (B) Technologies (C) Total ------------ ---------- --------- ------------ ---------- --------------- ------- ------------- (Millions of Dollars) <S> <C> <C> <C> <C> <C> <C> <C> <C> For the For the Quarter Ended March 31, 2002: - ------------------------------------ Total Operating Revenues............ $625 $430 $1,659 $53 $137 $101 $(490) $2,515 Operating Income.................... $198 $30 $210 $49 $63 $(5) $(4) $541 Segment Earnings (Loss)............. $102 $18 $67 $14 $(10) $(3) $(8) $180 Segment Earnings (Loss) Excluding Argentina Charge.................... $102 $18 $67 $14 $21 $(3) $(8) $211 As of March 31, 2002: - ------------------------------------ Total Assets........................ $4,888 $557 $12,689 $3,091 $4,122 $286 $(419) $25,214 For the Quarter Ended March 31, 2001: - ------------------------------------- Total Operating Revenues............ $561 $587 $1,952 $33 $89 $102 $(505) $2,819 Operating Income.................... $187 $49 $247 $29 $78 $5 $(13) 582 Income Before Extraordinary Item and Cumulative Effect of a Change in Accounting Principle............. $72 $49 $109 $3 $48 $(3) $(24) $254 Extraordinary Loss on Early Retirement of Debt.................. -- -- -- -- $(2) -- -- $(2) Cumulative Effect of a Change in Accounting Principle................ -- -- -- -- $9 -- -- $9 Segment Earnings (Loss)............. $73 $29 $109 $3 $55 $(3) $(5) $261 As of December 31, 2001: - ------------------------------------- Total Assets........................ $4,707 $790 $12,936 $3,026 $4,074 $290 $(399) $25,424 </TABLE> Includes approximately $460 million and $463 million charges for the quarters ended March 31, 2002 and 2001, respectively, to PSE&G related to the BGS Contract which commenced in August 2000, following the generation-related asset transfer to Power. Such amounts are eliminated in consolidation. (A) For a discussion of the charge relating to Argentina, see Note 4. Commitments and Contingent Liabilities. (B) Our other activities include amounts applicable to PSEG (parent corporation), Energy Holdings (parent corporation), Enterprise Group Development Company (EGDC), and intercompany eliminations, primarily relating to intercompany transactions between Power and PSE&G. The net losses primarily relate to financing and certain administrative and general costs at the parent corporations. Geographic information for us is disclosed below. The foreign assets and operations noted below were made solely through Energy Holdings. <TABLE> <CAPTION> Revenues (1) Identifiable Assets ------------------------ ----------------------------------- Quarter Ended March 31, March 31, December 31, ------------------------ -------------- ----------------- 2002 2001 2002 2001 ---------- ---------- -------------- ----------------- (Millions of Dollars) (Millions of Dollars) <S> <C> <C> <C> <C> United States......................... $2,360 $2,768 $20,326 $20,660 Foreign Countries (2)................. 155 51 4,888 4,764 ---------- ---------- -------------- ----------------- Total........................... $2,515 $2,819 $25,214 $25,424 ---------- ---------- -------------- ----------------- </TABLE> <TABLE> <CAPTION> <S> <C> <C> Assets in foreign countries include: Netherlands..................................................... $921 $911 Chile........................................................... 917 880 Argentina....................................................... 636 737 Peru............................................................ 547 520 India........................................................... 315 288 Brazil.......................................................... 302 282 Tunisia......................................................... 268 245 Other........................................................... 982 901 -------------- ----------------- Total..................................................... $4,888 $4,764 ============== ================= <FN> (1) Revenues are attributed to countries based on the locations of the investments. Global's revenue includes its share of the net income from joint ventures recorded under the equity method of accounting. (2) Total assets are net of foreign currency translation adjustment of $(393) million (pre-tax and minority interest) as of March 31, 2002 and $(283) million (pre-tax and minority interest) as of December 31, 2001. </FN> </TABLE>
The table below reflects our investment exposure in Latin American countries: Investment Exposure ---------------------- March 31, December 31, 2002 2002 --------- ------------ (Millions of Dollars) Argentina ................................................ $585 $632 Brazil ................................................... 476 467 Chile .................................................... 528 542 Peru ..................................................... 425 387 Venezuela ................................................ 52 53 The investment exposure consists of invested equity plus equity commitment guarantees. The investments in these Latin American countries are Global's. Note 8. Comprehensive Income Comprehensive Income, Net of Tax: <TABLE> <CAPTION> Quarter Ended March 31, -------------- 2002 2001 ----- ----- (Millions of Dollars) <S> <C> <C> Net income ............................................................. $ 180 $ 261 Foreign currency translation (A) ....................................... (62) (2) Change in Fair Value of Derivative Instruments (B) ..................... (9) (5) Cumulative effect of a change in accounting principle (net of tax of $8) ................................................ -- (15) Reclassification adjustments for net amounts included in Net Income, net of tax $6 and minority interest $3 .................... 8 -- Current Period Change in the Fair Value of Financial Instruments ....... (1) -- Pension Adjustments, net of tax ........................................ (1) -- ----- ----- Comprehensive Income ................................................... $ 115 $ 239 ===== ===== <FN> (A) Net of tax of $38 million and $0.2 million for the quarters March 31, 2002 and 2001, respectively. (B) Net of tax of $(4) million and $2 million for the quarters March 31, 2002 and 2001, respectively. </FN> </TABLE>
Note 9. Property, Plant and Equipment Information related to Property, Plant and Equipment of PSEG and its subsidiaries is detailed below: <TABLE> <CAPTION> March 31, December 31, 2001 2002 ------- ------- (Millions of Dollars) <S> <C> <C> Property, Plant and Equipment: Generation: Fossil Production (A) ....................................................... $ 2,225 $ 2,233 Nuclear Production .......................................................... 181 154 Nuclear Fuel in Service ..................................................... 561 486 Construction Work in Progress (A) ........................................... 2,172 2,004 Other ....................................................................... 7 7 ------- ------- Total Generation ....................................................... 5,146 4,884 ------- ------- Transmission and Distribution: Electric Transmission (A) ................................................... 1,638 1,685 Electric Distribution ....................................................... 4,291 4,254 Gas Transmission ............................................................ 75 74 Gas Distribution ............................................................ 3,146 3,121 Construction Work in Progress (A) ........................................... 13 54 Plant Held for Future Use ................................................... 20 20 Other ....................................................................... 294 292 ------- ------- Total Transmission and Distribution .................................... 9,477 9,500 ------- ------- Other .......................................................................... 507 502 ------- ------- Total ................................................................. $15,130 $14,886 ======= ======= <FN> (A) These items include the following amounts which relate to our Global segment: </FN> </TABLE> March 31, December 31, 2002 2001 --------- ----------- (Millions of Dollars) Generation: ......................................... Fossil Production .............................. $ 315 $ 335 Construction Work in Progress .................. 366 317 ------ ------ Total Generation .......................... $ 681 $ 652 ------ ------ Transmission and Distribution: Electric Transmission .......................... $ 417 $ 484 Construction Work in Progress .................. 3 28 ------ ------ Total Transmission and Distribution ....... 420 512 ------ ------ Total .................................... $1,101 $1,164 ====== ======
================================================================================ PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED ================================================================================ NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Concluded Note 10. Related Party Transactions Loans to TIE In April 1999, Global and its partner, Panda Energy International, Inc., established Texas Independent Energy, L.P. (TIE), a 50/50 joint venture, to develop, construct, own, and operate electric generation facilities in Texas. As of March 31, 2002, Global's investments in the TIE partnership include $76 million of loans that earn interest at an annual rate of 12% that are scheduled to be repaid over the next 10 years. Loans to GWF Energy In May 2001, GWF Energy, a 50/50 joint venture between Global and Harbinger GWF LLC, entered into a 10-year PPA with the CDWR to provide 340 MW of electric capacity to California from three new natural gas-fired peaking plants that GWF Energy expects to build and operate in California. Total project cost is estimated at approximately $335 million. The first plant, a 90 MW facility, was completed and began operation in August 2001. The second plant is currently under construction, with completion expected in July 2002, and the third plant is in the permitting process. Global's permanent equity investment in these plants, including contingencies, is not expected to exceed $100 million after completion of project financing, which is currently expected to occur in late 2002 or in 2003. Pending completion of project financing, Global has provided GWF Energy approximately $98 million of secured loans to finance the purchase of turbines. The turbine loans bear interest at rates ranging from 12% to 15% per annum and are payable in installments beginning May 31, 2002, with final maturity no later than December 31, 2002. Global has also provided GWF Energy $27 million of working capital loans that bear interest at 20% per annum and are convertible into equity at Global's option on various dates expiring in May 2002. For a further discussion of this issue matter, see Note 4. Commitments and Contingent Liabilities.
================================================================================ PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED ================================================================================ ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Overview of the Quarter Ended March 31, 2002 and Future Outlook Net Income for the quarter ended March 31, 2002 was $180 million or $0.87 per share of common stock, based on 206 million average shares outstanding. These results include a charge of $31 million (after-tax), or $0.15 cents per share, due to a first-quarter change in the functional currency of an investment in Argentina resulting from the economic crisis there. Results excluding the charge would have been $211 million or $1.02 per share. We continue to expect earnings for the year to meet our previous guidance of $3.90 to $4.10 per share, excluding any accounting charges associated with the Argentine crisis or the adoption of a new accounting standard on goodwill discussed below. These charges are not expected to affect our long-term annual EPS growth target of 7%. The $0.15 per share non-cash charge recorded in the first quarter was related to a change in the functional currency of EDEERSA, a distribution company in which Global has a 90% interest, from the U.S. dollar to the Argentine Peso. The Argentine Peso has lost significant value this year due to the ongoing turmoil in Argentina and, because of the change in functional currency, approximately $76 million of non-recourse, U.S. dollar-denominated debt was marked to the Argentine Peso. This charge of $47 million (pre-tax), $31 million (after-tax), reduces our previously disclosed exposure in Argentina from $632 million to $585 million. See Note 4. Commitments and Contingent Liabilities for further discussion of the Argentine economic crisis, our investment exposure, potential goodwill impairments and certain other contingencies. We are currently evaluating the recoverability of our capital at risk in Argentina. In addition, as part of the implementation of SFAS 142, the goodwill associated with RGE, EDEERSA, Energy Technologies and Tanir Bavi is being evaluated for potential impairment. Under a worst-case scenario, if the results of these evaluations indicate a complete impairment of all such assets, we would record an approximate $735 million (pre-tax and pre-minority interest), $473 million (after-tax and after minority interest) charge to earnings in 2002. This would amount to approximately $2.29 per share. The related, worst-case, charge to equity would be approximately $410 million due to the $63 million charge to OCI previously recorded in the first quarter. We expect to complete our evaluation of those issues the second quarter of 2002. While Global realized substantial growth in 2001, significant challenges began developing during the fourth quarter of 2001 and into 2002. These challenges include the Argentine economic crisis, the soft power market in Texas and the worldwide economic downturn. As a result, Global has refocused its strategy from one of accelerated growth to one that places emphasis on increasing the efficiency and returns of its existing assets. Power is expected to be a major factor in achieving our goals for the year. Power's successful participation as an indirect supplier of energy to New Jersey's utilities, including PSE&G, involved in New Jersey's recent basic generation service (BGS) auction is expected to have a meaningful effect on our earnings, particularly in the second half of the year and should more than offset the lack of an earnings contribution from Argentina. Power surpassed its objective of securing contracts on more than 75% of its capacity with suppliers that won the right to serve New Jersey's utilities for a one-year period beginning August 1. At the same time, PSE&G was able to secure all of its power supply for the one-year period at competitive prices. Following are the significant changes in or additions to information reported in our 2001 Annual Report on Form 10-K affecting the consolidated financial condition and the results of operations of us and our subsidiaries. This discussion refers to our Consolidated Financial Statements (Statements) and related Notes to Consolidated Financial Statements (Notes) and should be read in conjunction with such Statements and Notes.
Results of Operations <TABLE> <CAPTION> Earnings (Losses) ------------------------------- For the Quarter Ended March 31, ------------------------------- 2002 2001 ------------ ------------ (Millions of Dollars) <S> <C> <C> Generation............................................ $102 $73 Energy Trading........................................ 18 29 PSE&G................................................. 67 109 Resources ............................................ 14 3 Global (A)............................................ (10) 55 Energy Technologies................................... (3) (3) Other (B)............................................. (8) (5) ------------ ------------ Total PSEG (A)................................... $180 $261 ------------ ------------ Total PSEG Excluding Argentina Charge......... $211 $261 ============ ============ </TABLE> <TABLE> <CAPTION> Contribution to Earnings Per Share (Basic and Diluted) For the Quarter Ended March 31, ------------ ----- ------------ 2002 2001 ------------ ------------ <S> <C> <C> Generation.......................................... $0.49 $0.35 Energy Trading...................................... 0.09 0.14 PSE&G............................................... 0.32 0.52 Resources........................................... 0.07 0.02 Global (A).......................................... (0.05) 0.27 Energy Technologies................................. (0.02) (0.02) Other (B)........................................... (0.03) (0.03) ------------ ------------ Total PSEG (A)................................. $0.87 $1.25 ------------ ------------ Total PSEG Excluding Argentina Charge........ $1.02 $1.25 ============ ============ <FN> (A) Includes a charge $47 million pre-tax, $31 million after-tax or $0.15 per share related to the change in the functional currency of the $US to the Argentine Peso. (B) Other activities include amounts applicable to PSEG (parent corporation) and Energy Holdings. Losses primarily result from after-tax effect of interest on certain financing transactions and certain other administrative and general expenses at parent companies. </FN> </TABLE> Basic and diluted earnings per share of our common stock (Common Stock) were $0.87 for the quarter ended March 31, 2002, representing a decrease of $0.38 or a 30.4% from the comparable 2001 period. The results include a charge of $31 million or $0.15 per share due to a first-quarter change in the functional currency of an investment in Argentina resulting from the economic crisis there. Results excluding the charge would have been $211 million or $1.02 per share. Power's contribution to earnings per share of Common Stock for the quarter ended March 31, 2002 increased $0.09 or 18% from the comparable 2001 period. The increase was due primarily to higher generation revenues and lower fuel costs. PSE&G's earnings per share of Common Stock for the quarter ended March 31, 2002 decreased $0.20 or 39% for the quarter ended March 31, 2002 from the comparable 2001 period primarily due to unusually warm winter weather. Energy Holdings' contribution to earnings per share of Common Stock for the quarter ended March 31, 2002 decreased $0.27 from the comparable 2001 period, primarily due to the $0.15 charge due to the change in the functional currency of an Argentine investment noted above, and the absence of a $0.19 benefit to Global related to its withdrawal from an interest in the Eagle Point Cogeneration Partnership in the first quarter of 2001. In December 2000, Global withdrew from its interest in Eagle Point in exchange for a series of payments through 2005, expected to total up to $290 million. Such payments will be made in each year until 2005, provided certain operating contingencies are met. With respect to Eagle Point, Global expects to record a total of $46 million in the second and third quarters of 2002, as operating contingencies for the facility are expected to be met. For the Quarter Ended March 31, 2002 compared to the Quarter Ended March 31, 2001 Operating Revenues Electric Electric revenues increased $147 million or 16% for the quarter ended March 31, 2002 from the comparable period in 2001 primarily due to the inclusion of $92 million of revenues related to various majority-owned acquisitions and plants going into operation at our Global segment in the second quarter of 2001. Generation segment revenues increased $64 million or 11% for the quarter ended March 31, 2002 from the comparable period in 2001 primarily due to an increase of $65 million in Interchange/Spot Market Sales due to additional generation and favorable prices. Also, a $25 million increase in BGS revenue for the quarter contributed to the increase. This resulted from customers returning to PSE&G in 2001 from Third Party Suppliers (TPS) as wholesale market prices exceeded fixed BGS rates. At March 31, 2002, TPS were serving less than 0.5% of the customer load traditionally served by PSE&G as compared to the March 31, 2001 level of 8%. These increases were partially offset by a net $28 million decrease in Market Transition Charge (MTC) revenues remitted to Power from PSE&G relating to the two 2% rate reductions that occurred in February and August 2001 and a decrease in our PSE&G segment revenues of $10 million or 3% due to the effects of warmer weather. Gas Distribution Gas distribution revenues decreased $267 million or 25% for the quarter ended March 31, 2002 from the comparable period in 2001 due to the unusually warm winter and decreased commodity rates that became effective in January 2002, partially offset by increased gas base rates. For the quarter ended March 31, 2002, we experienced an 18% decrease in degree days, as compared to the first quarter 2001. Trading Trading revenues decreased $157 million or 27% for the quarter ended March 31, 2002 from the comparable period in 2001 due to lower trading volumes in the first quarter of 2001 (see corresponding decrease in trading costs). Despite lower trading volumes for the quarter, we expect to meet our full year trading margin goals. Other Other revenues decreased $27 million or 12% for the quarter ended March 31, 2002 from the comparable period in 2001 due primarily to a $43 million gain recorded in connection with Global's withdrawal and sale from its interest in the Eagle Point Cogeneration Partnership. Global expects to recover much of this shortfall with scheduled payments later this year. This decrease was partially offset by Resources' higher leveraged lease income of $10 million, as compared to the first quarter of 2001, and Resources' lower net investment losses of $10 million, as compared to the first quarter of 2001. Operating Expenses Electric Energy Costs Electric Energy Costs increased $90 million or 41% for the quarter ended March 31, 2002 from the comparable 2001 period primarily due to the inclusion of $45 million of expenses related to various majority-owned acquisitions and plants going into operation at our Global segment in the second and third quarters of 2001. The increased load served under the BGS contract due to the additional retail customers returning to PSE&G in 2001 also contributed to the increase. This increase was partially offset by the lower cost of fuel, particularly natural gas and the continued strong performance of our nuclear generating plants. Gas Costs Gas Costs decreased $260 million or 33% for the quarter ended March 31, 2002 from the comparable 2001 period primarily due to lower demand as a result of the warmer weather and decreased commodity rates that became effective in January of 2002. Trading Costs Trading Costs decreased $138 million or 26% for the quarter ended March 31, 2002 from the comparable 2001 period primarily due to lower trading volumes (see corresponding decreases in trading revenues). Operations and Maintenance Operations and Maintenance expense increased $17 million or 3% primarily due to higher operating costs associated with new projects going into service at our Global segment. Depreciation and Amortization Depreciation and Amortization expense increased $29 million or 27% for the quarter ended March 31, 2002 from the comparable 2001 period. The increase was primarily due to a full periods recognition of amortization of the regulatory asset recorded for PSE&G's stranded costs beginning in February 2001 and the increase in gas depreciation expense recorded in accordance with PSE&G's increased gas base rates. Interest Expense Interest Expense increased $31 million or 19% for the quarter ended March 31, 2002 from the comparable 2001 period primarily due to increased long-term debt used to finance several investments made in 2001. Liquidity and Capital Resources The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions of our three direct operating subsidiaries, PSE&G, Power and Energy Holdings.
Financing Methodology Our capital requirements and those of our subsidiaries are met through liquidity provided by internally generated cash flow and external financings. PSEG, Power and Energy Holdings from time to time make equity contributions to their respective direct and indirect subsidiaries to provide for part of their capital and cash requirements, generally relating to long-term investments. At times, we utilize inter-company dividends and inter-company loans to satisfy various subsidiary needs and efficiently manage our and our subsidiaries' short-term cash needs. Any excess funds are invested in accordance with guidelines adopted by our Board of Directors. External funding to meet our needs and the needs of PSE&G, the majority of the requirements of Power and a substantial portion of the requirements of Energy Holdings, is comprised of corporate finance transactions. The debt incurred is the direct obligation of those respective entities. Some of the proceeds of these debt transactions are used by the respective obligor to make equity investments in its subsidiaries. Depending on the particular company, external financing may consist of public and private capital market debt and equity transactions, bank revolving credit and term loan facilities, commercial paper and/or project financings. 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. The availability and cost of external capital could be affected by each subsidiary's performance as well as by the performance of their respective subsidiaries and affiliates. This could include the degree of structural or regulatory separation between us and our subsidiaries and between PSE&G and its non-utility affiliates and the potential impact of affiliate ratings on consolidated and unconsolidated 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. Financing for Global's projects and investments is generally provided by non-recourse project financing transactions. These consist of loans from banks and other lenders that are typically secured by project and special purpose subsidiary assets and/or cash flows. Two of Power's projects currently under construction have similar financing. Non-recourse transactions generally impose no obligation on the parent-level investor to repay any debt incurred by the project borrower. However, in some cases, certain obligations relating to the investment being financed, including additional equity commitments, are guaranteed by Global, Energy Holdings, and/or Power. Further, the consequences of permitting a project-level default include loss of any invested equity by the parent. Debt Covenants, Cross Default Provisions, Material Adverse Changes, and Ratings Triggers Our credit agreements and those of our subsidiaries and the debt indentures of Power and Energy Holdings contain cross-default provisions under which a default by us or by specified subsidiaries involving specified levels of indebtedness in other agreements would result in a default and the potential acceleration of payment under such indentures and credit agreements. For example, a default with respect to specified indebtedness in an aggregate amount of $50 million for us, $50 million for Power, $50 million for PSE&G or $5 million for Energy Holdings, including relevant equity contribution obligations in subsidiaries' non-recourse transactions, would cause a cross-default in our or certain of our subsidiaries' credit agreements or indentures. If such a default were to occur, lenders, or the debt holders under any of our or our subsidiaries' indentures, could determine that debt payment obligations may be accelerated as a result of a cross-default. A declaration of cross-default 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. In addition, our credit agreements and those of our subsidiaries generally contain provisions under which the lenders could refuse to advance loans in the event of a material adverse change in the borrower's, and as may be relevant, our, Energy Holdings', Power's or PSE&G's business or financial condition. In the event that we or the lenders in any of our or our subsidiaries' credit agreements determine that a material adverse change has occurred, loan funds may not be advanced. Some of these credit agreements also contain maximum debt to equity ratios, minimum cash flow tests and other restrictive covenants and conditions to borrowing. Compliance with applicable financial covenants will depend upon our future financial position and the level of earnings and cash flow, as to which no assurances can be given. As part of our financial planning forecast, we perform stress tests on our financial covenants. These tests include a consideration of the impacts of potential asset impairments, foreign currency fluctuations and other items. Our current analysis and projections indicate that, even in a worst-case scenario with respect to our investments in Argentina and considering other potential events, we should still be able to meet our financial covenants. Our debt indentures and credit agreements and those of our subsidiaries 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 and/or our subsidiaries may be subject to increased interest costs on certain bank debt. Also, in connection with its energy trading business, Power must meet certain credit quality standards as are required by counterparties. If Power loses its investment grade credit rating, ER&T would have to provide credit support (letters of credit or cash), which would significantly impact the energy trading business. These same contracts provide reciprocal benefits to Power. Providing this credit support would increase our costs of doing business and limit our ability to successfully conduct our energy trading operations. In addition, our counterparties may require us to meet margin or other security requirements which may include cash payments. Global and Energy Holdings may have to provide collateral for certain of their equity commitments if Energy Holdings' ratings should fall below investment grade. Regulatory Restrictions Capital resources and investment requirements could be affected by the outcome of proceedings by the BPU pursuant to the Energy Competition Act and the requirements of the 1992 Focused Audit conducted by the BPU, of the impact of our non-utility businesses, owned by Energy Holdings, on PSE&G. As a result of the Focused Audit, the BPU ordered that, among other things: (1) We will not permit Energy Holdings' investments to exceed 20% of our consolidated assets without prior notice to the BPU; (2) PSE&G's Board of Directors would provide an annual certification that the business and financing plans of Energy Holdings will not adversely affect PSE&G; (3) We will (a) limit debt supported by the minimum net worth maintenance agreement between us 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 PSE&G 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. PSE&G has notified the BPU that PSEG will eliminate PSEG Capital debt by the end of the second quarter of 2003 and that it believes that the Final Order otherwise supercedes the requirements of the Focused Audit. The BPU is expected to address the matter later this year. While we believe that this issue will be satisfactorily resolved, no assurances can be given. In addition, if we were no longer to be exempt under the Public Utility Holding Company Act of 1935 (PUHCA), we and our subsidiaries would be subject to additional regulation by the SEC with respect to financing and investing activities, including the amount and type of non-utility investments. 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 and our subsidiaries will be required to refinance maturing debt, incur additional debt and provide equity 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. Short Term Liquidity We and our subsidiaries have revolving credit facilities to provide liquidity for our $850 million commercial paper program and PSE&G's $550 million commercial paper program and for various funding purposes. We are in the process of increasing our commercial paper program to $1 billion and have already increased our available credit facilities accordingly. We also have bilateral agreements available at PSEG, PSE&G and Energy Holdings. The following table summarizes the various revolving credit facilities of PSEG, PSE&G and Energy Holdings as of March 31, 2002. Power has no such credit facilities and relies on PSEG for its short-term financing needs. <TABLE> <CAPTION> Expiration Total Primary Company Date Facility Purpose - ------------------------------------ ------------------- ------------------- ------------------- (Millions of Dollars) <S> <C> <C> PSEG: 364-day Credit Facility March 2003 $620 CP Support 364-day Bilateral Facility March 2003 100 CP Support 5-year Credit Facility March 2005 280 CP Support 5-year Credit Facility December 2002 150 Funding Uncommitted Bilateral Agreement N/A ** Funding PSE&G: 364-day Credit Facility June 2002* 275 CP Support 5-year Credit Facility June 2002* 275 CP Support Uncommitted Bilateral Agreement N/A ** Funding Energy Holdings: 364-day Credit Facility May 2003 200 Funding 5-year Credit Facility May 2004 495 Funding Uncommitted Bilateral Agreement N/A ** Funding * Expected to be extended in the second quarter of 2002. ** Availability varies based on market conditions. </TABLE> As of March 31, 2002, our consolidated total short-term debt outstanding was $1.503 billion, including $689 million of commercial paper at PSEG, $284 million of non-recourse short-term financing at Global and $258 million and $272 million outstanding under credit facilities and through the uncommitted bilateral agreement at PSEG and Energy Holdings, respectively. In addition, we have a total of $1.385 billion of long-term debt due within one year, comprised of $274 million at PSEG, $823 million at PSE&G and $288 million at Energy Holdlings. In the ordinary course of business, we and our subsidiaries have financial commitments for debt maturities and general corporate purposes. On April 16, 2002 PSEG filed a shelf registration statement on Form S-3 for the issuance of $1.5 billion of various debt and equity securities. The registration statement is currently under review by the Staff of the Securities and Exchange Commission (SEC). In the near term, while we anticipate that our commitments could be in excess of our current short-term funding capacity and internally-generated cash flow, we expect to meet these commitments through a variety of short-term borrowings incremental to our existing commercial paper programs, credit facilities and bilateral credit agreements. It is expected that any such incremental, short-term borrowings would be refinanced through the issuance of more permanent financing by PSEG. PSEG As of December 31, 2001, we had repurchased approximately 26.5 million shares of Common Stock, at a cost of approximately $997 million since 1998. For the year-ended December 31, 2001, we had repurchased approximately 2.3 million shares of Common Stock, at a cost of approximately $92 million. The repurchased shares have primarily been held as treasury stock with the balance used for general corporate purposes. No shares have been repurchased subsequent to December 2001. In addition, since December 31, 2001 we have issued 355,491 shares under our Dividend Reinvestment and Stock Purchase Plan (DRASPP). Dividend payments on Common Stock for the quarter ended March 31, 2002 were $0.54 per share and totaled approximately $111 million. Our dividend rate has remained constant since 1992 in order to retain additional capital for reinvestment and to reduce the payout ratio as earnings grow. Although we presently believe we will have adequate earnings and cash flow in the future from our subsidiaries to maintain common stock dividends at the current level, earnings and cash flows required to support the dividend will become more volatile as our business continues to change from one that was principally regulated to one that is principally competitive. Future dividends declared will necessarily be dependent upon our future earnings, cash flows, financial requirements, alternate investment opportunities and other factors. We would consider raising the dividend if our payout ratio declined to 50% and could be sustained at that level. We have issued Deferrable Interest Subordinated Debentures in connection with the issuance of tax deductible preferred securities. If payments on these Deferrable Interest Subordinated Debentures are deferred, in accordance with their terms, we may not pay any dividends on its common stock until such payments become current. Currently, there has been no deferral or default. Financial covenants contained in our credit facilities include the ratio of debt (excluding non-recourse project financings and securitization debt and including commercial paper and loans, certain letters of credit and similar instruments) to total capitalization. At the end of any quarterly financial period such ratio shall not be more than 0.70 to 1. As of March 31, 2002, the ratio of debt to capitalization was 0.64 to 1. As noted above, PSEG has filed a registration statement with the SEC which is currently under review and has not yet become effective. PSE&G Under its Mortgage, PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements and/or retired Mortgage Bonds provided that its ratio of earnings to fixed charges calculated in accordance with its Mortgage is at least 2:1. At March 31, 2002, PSE&G's Mortgage coverage ratio was 3:1. As of March 31, 2002, the Mortgage would permit up to approximately $1 billion aggregate principal amount of new Mortgage Bonds to be issued against previous additions and improvements. PSE&G will need to obtain BPU authorization to issue any financing necessary for its capital program, including refunding of maturing debt and opportunistic refinancing. PSE&G has authorization from the BPU to issue $1 billion of long-term debt through December 31, 2003 for the refunding of maturing debt and opportunistic refinancing of debt. In December 2001, PSE&G 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. Since 1986, PSE&G has made regular cash payments to us in the form of dividends on outstanding shares of PSE&G's common stock. PSE&G paid common stock dividends of $150 million and $112 million to us for the quarters ended March 31, 2002 and 2001, respectively. PSE&G has 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, PSE&G may not pay any dividends on its common or preferred stock until such default is cured. Currently, there has been no deferral or default. Power Power's short-term financing needs will be met using our commercial paper program or lines of credit discussed above. Energy Holdings As of March 31, 2002, Energy Holdings had two separate senior revolving credit facilities with a syndicate of banks as discussed in the table above. The five-year facility permits up to $250 million of letters of credit to be issued of which $14 million are outstanding as of March 31, 2002. Financial covenants contained in these facilities include the ratio of cash flow available for debt service (CFADS) to fixed charges. At the end of any quarterly financial period such ratio shall not be less than 1.50x for the 12-month period then ending. As a condition of borrowing, the pro-forma CFADS to fixed charges ratio shall not be less than 1.75x as of the quarterly financial period ending immediately following the first anniversary of each borrowing or letter of credit issuance. CFADS includes, but is not limited to, operating cash before interest and taxes, pre-tax cash distributions from all asset liquidations and equity capital contributions from us to the extent not used to fund investing activity. In addition, the ratio of consolidated recourse indebtedness to recourse capitalization, as at the end of any quarterly financial period, shall not be greater than 0.60 to 1.00. This ratio is calculated by dividing the total recourse indebtedness of Energy Holdings by the total recourse capitalization. This ratio excludes the debt of PSEG Capital, which is supported by us. As of March 31, 2002, the latest 12 months CFADS coverage ratio was 5.2 and the ratio of recourse indebtedness to recourse capitalization was .43 to 1. PSEG Capital has a $650 million MTN program which provides for the private placement of MTNs. This MTN program is supported by a minimum net worth maintenance agreement between PSEG Capital and us which provides, among other things, that we (1) maintain its ownership, directly or indirectly, of all outstanding common stock of PSEG Capital, (2) cause PSEG Capital to have at all times a positive tangible net worth of at least $100,000 and (3) make sufficient contributions of liquid assets to PSEG Capital in order to permit it to pay its debt obligations. We will eliminate our support of PSEG Capital debt by the second quarter of 2003, as required by the Focused Audit. At March 31, 2002 and December 31, 2001, total debt outstanding under the MTN program was $480 million and $480 million, respectively maturing from 2002 to 2003. Capital Requirements Power's capital needs will be dictated by its strategy to continue to develop as a profitable, growth-oriented supplier in the wholesale power market. PSE&G's construction expenditures are primarily to maintain the safety and reliability of its electric and gas transmission and distribution facilities. We plan to continue the growth of Resources. Global has refocused its strategy, from one of accelerated growth to one that places emphasis on increasing the efficiency and returns of its existing assets. We are evaluating the future prospects and opportunities of Energy Technologies' business. For the quarter ended March 31, 2002, we made net plant additions of $373 million, excluding Allowance for Funds Used During Construction (AFDC) and capitalized interest. The majority of these additions, $216 million, primarily related to Power for developing the Lawrenceburg, Indiana and the Waterford, Ohio sites and adding capacity to the Bergen and Linden stations in New Jersey. In addition, PSE&G had net plant additions of $80 million related to improvements in its transmission and distribution system, gas system and common facilities. Also, Energy Holdings' subsidiaries made investments totaling approximately $77 million for the quarter ended March 31, 2002. These investments included investments by Resources and additional investments in existing domestic and international facilities at Global. The $373 million of net plant additions and $77 million of investments were included in our forecasted expenditures for the year.
Accounting Matters For a discussion of SFAS 142, SFAS 143 and SFAS 144, see Note 2. Accounting Matters and Note 4. Commitments and Contingent Liabilities. 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 PSE&G, our regulated transmission and distribution business; Emerging Issues Task Force (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98-10) and EITF 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent" (EITF 99-19), for our Energy Trading business; SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended (SFAS 133), to account for our various hedging transactions; SFAS 52, "Foreign Currency Translation" and its impacts on Global's foreign investments; and SFAS 142 and SFAS 144 and their potential impacts on our various investments. Accounting for the Effects of Regulation PSE&G prepares its financial statements in accordance with the provisions of SFAS No. 71, which differs in certain respects from the application of 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 utility 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, PSE&G has 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 PSE&G's 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. Two of these items 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 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, PSE&G's 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 probable. In order to properly recognize the recovery of the allowed unsecuritized stranded costs over the transition period, PSE&G recorded a regulatory liability and Power recorded a charge to net income of $88 million, pre-tax, or $52 million, after tax, in the third quarter of 2000 for the cumulative amount of estimated collections in excess of the allowed unsecuritized stranded costs from August 1, 1999 through September 30, 2000. PSE&G 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 March 31, 2002, this deferred amount was $177 million and is aggregated with the Societal Benefits Clause. After deferrals, pre-tax MTC revenues recognized were $220 million in 1999, $239 million in 2000, and $196 million in 2001. In 2002 and 2003, we expect to record approximately $90 million and $121 million, respectively. The amortization of the Excess Depreciation Reserve is another significant regulatory liability affecting our earnings. As required by the BPU, PSE&G reduced its depreciation reserve for its 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. Through March 31, 2002, $287 million had been amortized and recorded as a reduction of depreciation expense pursuant to the Final Order, of which $37 million relates to 2002. The remaining $282 million will be amortized through July 31, 2003. See Note 3. Regulatory Assets and Liabilities of Notes for further discussion of these and other regulatory issues. Accounting, Valuation and Presentation of Our Energy Trading Business Accounting - We account for our energy trading business in accordance with the provisions of EITF 98-10, which requires that energy trading contracts be marked to market with gains and losses included in current earnings. Valuation - Since the majority of our energy trading contracts have terms of less than two years, valuations for these contracts are readily obtainable from the market exchanges, such as PJM, and over the counter quotations. The valuations also include a credit reserve and a liquidity reserve, which is determined using financial quotation systems, monthly bid-ask prices and spread percentages. We have consistently applied this valuation methodology for each reporting period presented. The fair values of these contracts and a more detailed discussion of credit risk are reflected in Note 5. Financial Instruments, Energy Trading and Risk Management. Presentation - 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 report swaps, futures, option premiums, firm transmission rights, transmission congestion credits, and purchases and sales of emission allowances on a net basis. One of the primary drivers of our determination that these contracts should be presented on a gross basis was that we retain counterparty risk. 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 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 hedges of anticipated electric and gas purchases, interest rate swaps and foreign currency hedges 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. In the absence thereof, we utilize mathematical models based on current and historical data. The fair value of most of our derivatives is determined based upon quoted market prices. Therefore, the effect on earnings of valuations from our models is minimal. For additional information regarding Derivative Financial Instruments, See Note 5 - Financial Instruments Energy Trading and Risk Management - Derivative Instruments and Hedging Activities of Notes. SFAS 52 - Foreign Currency Translation Our financial statements are prepared using the $US Dollar as the reporting currency. In accordance with SFAS 52 "Foreign Currency Translation", foreign operations whose functional currency is deemed to be the local (foreign) currency, asset and liability accounts are translated into $US Dollars at current exchange rates and revenues and expenses are translated at average exchange rates prevailing during the period. Translation gains and losses (net of applicable deferred taxes) are not included in determining net income but are reported in other comprehensive income. Gains and losses on transactions denominated in a currency other than the functional currency are included in the results of operations as incurred. The determination of an entity's functional currency requires management's judgment. It is based on an assessment of the primary currency in which transactions in the local environment are conducted, and whether the local currency can be relied upon as a stable currency in which to conduct business. As economic and business conditions change, we are required to reassess the economic environment and determine the appropriate functional currency. The impact of foreign currency accounting has had and could continue to have a material adverse impact on our financial condition, results of operation and net cash flows. See Note 4. Commitments and Contingent Liabilities for a discussion of the change in functional currency of EDEERSA from the $US Dollar to the Argentine Peso. Accounting for the Effects of Goodwill Our 2002 earnings will likely be materially impacted by the application of SFAS 142. This new standard, effective in January 2002, requires the amount of any goodwill impairment to be disclosed in the second quarter and recorded by the fourth quarter of 2002, applied retroactively to the first quarter. The basic difference between previous accounting guidance and this new standard is that a discounted cash flow test must be performed to test goodwill for impairment under the new standard, compared to an undiscounted cash flow test required under the old standard. The new test must be completed using data as of January 1, 2002. Any amounts impaired using data as of that date will be recorded as a "Cumulative Effect of an Accounting Change". Any amounts impaired under the new test using data after that date will be recorded above the line in Operating Expenses. The discounted cash flow tests require broad assumptions and significant judgment to be exercised by management. This includes projections of future energy prices, customer demand, operating costs, rate relief from regulators, customer growth and many other items. While we believe that our assumptions are reasonable, actual results will likely differ from our projections. As of March 31, 2002, the carrying value of unamortized goodwill was $621 million, of which $451 million was recorded in connection with Global's acquisitions of Sociedad Austral de Electricidad S.A. (SAESA) and Empresa de Electricidad de los Andes S.A. (Electroandes) in Chile and Peru in August and December of 2001, respectively. For the year-ended December 31, 2001, the amortization expense related to goodwill was $3 million. As of March 31, 2002, our pro-rata share of goodwill included in equity method investees totaled $378 million. In accordance with generally accepted accounting principles, such goodwill is not consolidated on our balance sheet. Our share of the amortization expense related to such goodwill was $8 million for the year-ended December 31, 2001. However, this goodwill is subject to the same impairment testing under SFAS 142 at the local entities. We are in the process of finalizing our evaluation of the effect of adopting SFAS 142 on the recorded amount of goodwill at RGE, EDEERSA, Energy Technologies and Tanir Bavi. It is likely that the entire carrying value of the goodwill at EDEERSA and Energy Technologies is completely impaired, that the goodwill at RGE up to approximately half of the recorded carrying value could be impaired, and that the goodwill at Tanir Bavi could be impaired. The goodwill at EDEERSA is included in the $585 million of investment exposure associated with our assets in Argentina.
As of March 31, 2002, our unamortized goodwill and pro-rata share of goodwill in equity method investees was as follows: As of March 31, 2002 -------------------- (Millions of Dollars) Global EDEERSA ......................................... $ 63 SAESA ........................................... 315 Electroandes .................................... 136 Tanir Bavi ...................................... 27 Chorzow ......................................... 6 ---- Total Global .............................. $547 ---- Energy Technologies ................................ 53 Power .............................................. 21 ---- Total On Balance Sheet ............... $621 ---- Global RGE ............................................. $140 Chilquinta ...................................... 174 Luz del Sur ..................................... 39 Kalaeloa ........................................ 25 ---- Pro-Rata Share of Equity Investment Goodwill .. $378 ---- Total Goodwill ............................ $999 ==== As of December 31, 2001 goodwill was $1.024 billion. As of March 31, 2002, we had goodwill of $999 million. The decrease of $25 million from year-end represents a purchase price adjustment with respect to our acquisition of Electroandes. Accounting for Long-Lived Assets On January 1, 2002 we adopted SFAS No. 144, "Accounting for Impairment or Disposal of Long-Lived Assets" (SFAS 144). The impact of adopting SFAS 144 did not have an effect on our financial position and statement of operations. Under SFAS 144, long-lived assets to be disposed of are measured at the lower of carrying amount or fair value less costs 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. SFAS 144 also broadens the reporting of discontinued operations. A long-lived asset must be tested for impairment whenever events or changes in circumstances indicate that its carrying amount may be impaired. As previously disclosed, we have approximately $585 million of investment exposure in Argentina. Due to the economic, political and social crisis in Argentina, our investments there are faced with considerable fiscal and cash flow uncertainties. As a result of these events, an impairment test of these investments is required. However, due to the vast uncertainty related to the situation in Argentina, reasonable assumptions related to the environment in Argentina cannot be easily made. As the situation continues to evolve, we will be able to develop assumptions related to the environment in Argentina and these investments and will complete our impairment test. In addition to impairment testing for the Argentine investments, an impairment test for Energy Technologies is also being done as negative operating cash flow of certain parts of that entity indicate a potential impairment. These tests are required whenever events or circumstances indicate an impairment may exist. Examples of potential events which could require an impairment test are when power prices become depressed for a prolonged period in a market, when a foreign currency significantly devalues, or when an investment generates negative operating cash flows. Any potential impairments of these investments are recorded above the line. For additional information relating to potential asset impairments, see Note 4. Commitments and Contingent Liabilities. ITEM 3. 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 foreign currency exchange rates, commodity prices, equity security prices, and interest rates as discussed in the notes to the financial statements. Our policy is to use derivatives to manage risk consistent with our business plans and prudent practices. We have a Risk Management Committee comprised of executive officers which utilizes an independent risk oversight function to ensure compliance with corporate policies and prudent risk management practices. Commodity Contracts The availability and price of energy commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies and other events. To reduce price risk caused by market fluctuations, we enter into derivative contracts, including forwards, futures, swaps and options with approved counterparties, to hedge our anticipated demand. These contracts, in conjunction with owned electric generation capacity, are designed to cover estimated electric customer commitments. We use a value-at-risk (VAR) model to assess the market risk of our commodity business. This model includes fixed price sales commitments, owned generation, native load requirements, physical contracts and financial derivative instruments. VAR represents the potential gains or losses for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. PSEG estimates VAR across its commodity business using a model with historical volatilities and correlations. Our Board of Directors has established a VAR Threshold of $75 million and the Risk Management Committee (RMC) has established an internal VAR threshold of $50 million for Power. If the $50 million threshold was reached, the RMC would be notified and the portfolio would be closely monitored to reduce risk and potential adverse movements. The measured VAR using a variance/co-variance model with a 95% confidence level and assuming a one-week time horizon as of March 31, 2002 was approximately $22 million, compared to the December 31, 2001 level of $18 million which was calculated using various controls and conservative assumptions, such as a 50% success rate in the BGS Auction. This estimate, however, is not necessarily indicative of actual results, which may differ due to the fact that actual market rate fluctuations may differ from forecasted fluctuations and due to the fact that the portfolio of hedging instruments may change over the holding period and due to certain assumptions embedded in the calculation. Credit Risk Counterparties expose us to credit losses in the event of non-performance or non-payment. We have a credit management process which is used to assess, monitor and mitigate counterparty exposure for us and our subsidiaries. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on our and our subsidiaries' financial condition, results of operations or net cash flows. Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We have established credit policies that we believe significantly minimize credit risk. These policies include an evaluation of potential counterparties' financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which may allow for the netting of positive and negative exposures associated with a single counterparty. As a result of the BGS auction, Power has contracted to provide generating capacity to the direct suppliers of New Jersey's electric utilities, including PSE&G, commencing August 1, 2002. These bilateral contracts are subject to credit risk. This credit risk relates to the ability of counterparties to meet their payment obligations for the power delivered under each BGS contract. This risk is substantially higher than the risk associated with potential nonpayment by PSE&G under the BGS contract expiring July 31, 2002 since PSE&G is a rate-regulated entity. Any failure to collect these payments under the new BGS contracts could have a material impact on our results of operations, cash flows, and financial position. Foreign Operations As of March 31, 2002, Global and Resources had approximately $3.5 billion and $1.4 billion, respectively, of international assets. As of March 31, 2002, foreign assets represented 19% of our consolidated assets and the revenues related to those foreign assets contributed 6% to consolidated revenues for the quarter ended March 31, 2002. For discussion of foreign currency risk and potential asset impairments related to our investments in Argentina, see Note 5. Financial Instruments Energy Trading and Risk Management, Note 4. Commitments and Contingent Liabilities. Resources' international investments are primarily leveraged leases of assets located in Austria, Australia, Belgium, China, Germany, the Netherlands, United Kingdom, and New Zealand with associated revenues denominated in U.S. Dollars and therefore, not subject to foreign currency risk. Global's international investments are primarily in projects that are presently or upon completion are expected to generate or distribute electricity in Argentina, Brazil, Chile, China, India, Italy, Peru, Poland, Tunisia and Venezuela. Investing in foreign countries involves certain additional risks. Economic conditions that result in higher comparative rates of inflation in foreign countries are likely to result in declining values in such countries' currencies. As currencies fluctuate against the $US, there is a corresponding change in Global's investment value in terms of the $US. Such change is reflected as an increase or decrease in the investment value and Other Comprehensive Income, a separate component of Stockholder's Equity. As of March 31, 2002, net foreign currency devaluations have reduced the reported amount of our total Stockholder's Equity by $320 million, of which $159 million, $84 million and $63 million were caused by the devaluation of the Brazilian Real, Chilean Peso and Argentine Peso, 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 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 because a portion of our business is conducted outside the United States, adverse international developments could negatively impact our business; o credit, commodity, and financial market risks may have an adverse impact; o energy obligations, available supply and trading risks may have an adverse impact; o the electric industry is undergoing substantial change; o generation operating performance may fall below projected levels; o ability to obtain adequate and timely rate relief; o we and our subsidiaries are subject to substantial competition from well capitalized participants in the worldwide energy markets; o our ability to service debt could be limited; o power transmission facilities may impact our ability to deliver our output to customers; o government regulation affects many of our operations; o environmental regulation significantly impacts our operations; o we are subject to more stringent environmental regulation than many of our competitors; o insurance coverage may not be sufficient; o acquisition, construction and development may not be successful; and o recession, acts of war or terrorism could have an adverse impact. Consequently, all of the forward-looking statements made in this report are qualified by these cautionary statements and we cannot assure you that the results or developments anticipated by us will be realized, or even if realized, will have the expected consequences to or effects on us or our business prospects, financial condition or results of operations. You should not place undue reliance on these forward-looking statements in making any investment decision. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to these forward-looking statements to reflect events or circumstances that occur or arise or are anticipated to occur or arise after the date hereof. In making any investment decision regarding our securities, we are not making, and you should not infer, any representation about the likely existence of any particular future set of facts or circumstances. The forward-looking statements contained in this report are intended to qualify for the safe harbor provisions of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.
PART II. OTHER INFORMATION -------------------------- ITEM 1. LEGAL PROCEEDINGS Certain information reported under Item 3 of Part I of Public Service Enterprise Group Incorporated's (PSEG) 2001 Annual Report on Form 10-K is updated below. New Matter. On November 15, 2001, Consolidated Edison, Inc. (Con Edison) filed a complaint against PSE&G at the Federal Energy Regulatory Commission (FERC) pursuant to Section 206 of the Federal Power Act asserting that PSE&G had breached agreements covering 1,000 MW of transmission by curtailing service and failing to maintain sufficient system capacity to satisfy all of its service obligations. PSE&G denied the allegations set forth in the complaint. While finding that Con Edison's presentation of evidence failed to demonstrate several of the allegations, on April 26, 2002, FERC found sufficient reason to set the complaint for hearing. The hearing will be conducted on an expedited basis, with an Initial Decision to be issued by the end of May and a FERC order by the end of June. If Con Edison is successful, PSE&G could be required to provide future transmission services with uneconomic generation resources at a substantial cost to PSE&G. PSE&G believes it has complied with the terms of the Agreement and will vigorously defend its position. The nature and cost of any remedy, which is expected to be prospective only, cannot be predicted. Docket No. EL02-23-000. New Matter. Pages 11-13. AES termination of the Stock Purchase Agreement, relating to the sale of certain Argentine assets. New York State Supreme Court for New York County (Docket No. 60155/2002) PSEG Global, et al vs. The AES Corporation, et al. In addition, see information on the following proceedings at the pages indicated: (1) Form 10-K, Pages 26 and 27. See Page 45. DOE not taking possession of spent nuclear fuel, Docket No. 01-551C. (2) Form 10-K Page 100. See Page 8. PSE&G's MGP Remediation Program. (3) Form 10-K Page 100. See Page 8-9. Investigation and additional investigation by the EPA regarding the Passaic River site. Docket No. EX93060255. (4) Form 10-K Page 102. See Page 10. Complaint filed with the Federal Energy Regulatory Commission addressing contract terms of certain Sellers of Energy and Capacity under Long-Term Contracts with the California Department of Water Resources. Public Utilities Commission of the State of California v. Sellers of Long Term Contracts to the California Department of Water Resources FERC Docket No. EL02-60-000. California Electricity Oversight Board v. Sellers of Energy and Capacity Under Long-Term Contracts with the California Department of Water Resources FERC Docket No. EL02-62-000.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS PSEG's Annual Meeting of Stockholders was held on April 16, 2002. Proxies for the meeting were solicited pursuant to Regulation 14A under the Securities Act of 1934. There was no solicitation of proxies in opposition to management's nominees as listed in the proxy statement and all of management's nominees were elected to the Board of Directors. Details of the voting are provided below: <TABLE> <CAPTION> ========================================================================================= Votes For Votes Withheld - ------------------------------------------------------- --------------- ----------------- <S> <C> <C> Proposal 1: Election of Directors - ------------------------------------------------------ --------------- ------------------ Class II - Term expiring in 2004 175,787,329 3,560,131 William V. Hickey - ------------------------------------------------------ --------------- ------------------ Class III - Terms expiring in 2005 Raymond V. Gilmartin 176,711,184 2,636,276 Conrad K. Harper 174,596,036 4,751,424 Shirley Ann Jackson 175,334,212 4,013,248 ========================================================================================= </TABLE> Directors Whose Terms Continue Beyond the 2002 Annual Meeting: - ------------------------------------------------------------- Class II - Terms expiring in 2004 Albert R. Gamper, Jr. Richard J. Swift - -------------------------------------------------------------- Class I - Terms expiring in 2003 Ernest H. Drew E. James Ferland <TABLE> <CAPTION> ======================================================================================================================= Votes Broker Votes For Against Abstentions Non-Votes - ------------------------------------------------------ -------------- ------------------ ---------------- ------------- <S> <C> <C> <C> <C> Proposal 2: Approval of the 2001 Long-Term Incentive Plan 112,810,574 35,625,968 3,204,947 27,726,516 - ------------------------------------------------------ -------------- ------------------ ---------------- ------------- Proposal 3: Approval of Restated and Amended Management Incentive Compensation Plan 150,807,910 24,894,914 3,640,166 -- - ------------------------------------------------------ -------------- ------------------ ---------------- ------------- Proposal 4: Ratification of Appointment of Deloitte & Touche LLP as Independent Auditors 170,924,041 6,660,938 1,756,074 -- - ------------------------------------------------------ -------------- ------------------ ---------------- ------------- Proposal 5: Shareholder Proposal 12,605,865 134,101,764 4,906,401 27,726,516 ======================================================================================================================= </TABLE>
ITEM 5. OTHER INFORMATION Certain information reported under PSEG's 2001 Annual Report to the SEC is updated below. References are to the related pages on the Form 10-K as printed and distributed. Gas Contract Transfer Form 10-K, page 16. On August 11, 2000, PSE&G filed a gas merchant restructuring plan with the BPU. The BPU approved an amended stipulation, which authorized the transfer of PSE&G's gas supply business, including its interstate capacity, storage and gas supply contracts to ER&T which will, under a requirements contract, provide gas supply to PSE&G to serve its Basic Gas Supply Service (BGSS) customers. The transfer took place on May 1, 2002. On May 1, 2002 the Ratepayer Advocate requested rehearing by the BPU of its decision, but did not seek a stay. The gas contract transfer is expected to reduce volatility in PSE&G's cash flows; however, ER&T will bear the increased commodity risk. 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, PSE&G will pay ER&T for gas provided to PSE&G for its gas distribution customers. Industrial and commercial BGSS customers will be priced under PSE&G's 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. Nuclear Regulatory Commission (NRC) Form 10-K, page 18. A pressurized water reactor nuclear unit (PWR) not owned by us was recently identified with a degradation of the reactor vessel head, which forms part of the pressure boundary for the reactor coolant system. In March 2002, the NRC issued a bulletin 2002-01, requiring that all operators of PWR units submit information concerning: (i) the integrity of the reactor coolant pressure boundary, (ii) inspections that have been and will be undertaken to satisfy applicable regulatory requirements, and (iii) the basis for concluding that plants satisfy applicable regulatory requirements related to the structural integrity of the reactor coolant pressure boundary. In April, we provided the requested information for Salem Nuclear Generation Station (Salem). The response included an assessment that primary water stress corrosion cracking of the control rod drive mechanism nozzles at Salem Units 1 and 2 is unlikely in the near term, and our assurance that both Salem Units 1 and 2 are in compliance with applicable regulatory requirements. A visual inspection of the Salem Unit 2 reactor head has been completed during the current refueling outage, and no evidence of reactor vessel head degradation was found. A similar inspection was performed at Salem Unit 1 in 2001, which also found no evidence of degradation. Our Hope Creek nuclear unit and our interests in the Peach Bottom units 2 and 3 are unaffected as they are Boiling Water Reactor nuclear units. We cannot predict what other actions the NRC may take on this issue. Nuclear Fuel Disposal Form 10-K, page 26. Under the NWPA, the DOE was required to begin taking possession of all spent nuclear fuel generated by our nuclear units for disposal by no later than 1998. DOE construction of a permanent disposal facility has not begun and DOE has announced that it does not expect a facility to be available earlier than 2010. In February 2002, President Bush announced that Yucca Mountain in Nevada would be the permanent disposal facility for nuclear wastes. On April 8, 2002, the Governor of Nevada submitted his veto to the siting decision. On May 8, 2002, the U.S. House of Representatives approved a resolution to override the veto. The issue now awaits a vote by the U.S. Senate, which is expected in early July. No assurances can be given regarding the final outcome of this matter.
Employee Relations Form 10-K, page 20. As previously disclosed, PSE&G has collective bargaining arrangements with the Utility Co-Workers Association, (UWUA) covering approximately 1,400 employees primarily in the customer operations area. This contract expired on April 30, 2002, and was extended through May 6, 2002. A tentative agreement was reached on May 7, 2002, and is subject to a ratification vote by union membership. Water Pollution Control Form 10-K, page 23. The EPA is conducting a rulemaking under Federal Water Pollution Control Act (FWPCA) Section 316(b), which requires that cooling water intake structures reflect the best technology available (BTA) for minimizing "adverse environmental impact". Phase I of the rule became effective on January 17, 2002. None of the projects that we currently have under construction or in development is subject to the Phase I rule. EPA published for public comment on April 9, 2002 proposed draft Phase II rules covering large existing power plants, and is expected to issue final rules by August 28, 2003. The draft regulations propose to regulate existing power plants that have a design intake flow of 50 Million Gallons per Day or greater and use at least 25% of the water for cooling purposes. The draft regulations propose to establish three means of demonstrating that a facility has BTA at an intake; two of which would be linked to demonstrating compliance with specific performance criteria and the third requiring a determination by the permitting authority that a case-by-case demonstration would be warranted. The proposed uniform performance standards are applicable to subsets of facilities based on waterbody type and capacity utilization rate. The content of the final Phase II rules cannot be predicted at this time, although it is reasonable to expect that the rule will apply to all of our steam electric and combined cycle units that use surface waters for cooling purposes. If the Phase II rules require retrofitting of cooling water intake structures at our existing facilities, meeting the specific or performance criteria, identified as an option under the draft rule, the cost of complying with the rules would be material. New Matter Approximately 150,000 tons of fly ash generated by Hudson and Mercer Generating Stations was taken by the ash marketer we then employed and sold to the owner and operator of a clay mine in Monroe Township, New Jersey. During the Fall of 1997 through the Fall of 1998, the owner and operator of the clay mine used the fly ash as fill material to return the mine site to grade, without obtaining the necessary approvals from NJDEP. Upon discovery of this use of the material, we terminated the services of this ash marketer and initiated discussions with NJDEP for the appropriate regulatory approvals to allow this material to remain at the site. NJDEP likely will require a clay cap and other engineering controls to ensure that the ash is isolated from the environment if the ash is left in place. Our negotiations with NJDEP and the property owner are continuing. Our cost of resolving this matter will depend upon the results of our negotiations with NJDEP and the property owner. Although the precise extent of liability is not currently estimable, it is not expected to be material.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (A) A listing of exhibits being filed with this document is as follows: Exhibit Number Document -------------- -------- 12 Computation of Ratios of Earnings to Fixed Charges (B) Reports on Form 8-K: Date of Report Items Reported -------------- -------------- January 25, 2002 Items 5 and 7 February 7, 2002 Item 5 April 16, 2002 Items 5 and 7
================================================================================ PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED ================================================================================ SIGNATURE Pursuant to the requirements 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 ENTERPRISE GROUP INCORPORATED (Registrant) By: Patricia A. Rado -------------------------------------------- Patricia A. Rado Vice President and Controller (Principal Accounting Officer) Date: May 15, 2002