PUBLIC SERVICE ENTERPRISE GROUP INC - 10-K Annual Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003,

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO .

Commission File Number	Registrants, State of Incorporation, Address, and Telephone Number	I.R.S. Employer Identification No.
001-09120	PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED (A New Jersey Corporation) 80 Park Plaza, P.O. Box 1171 Newark, New Jersey 07101-1171 973 430-7000 http://www.pseg.com	22-2625848
001-00973	PUBLIC SERVICE ELECTRIC AND GAS COMPANY (A New Jersey Corporation) 80 Park Plaza, P.O. Box 570 Newark, New Jersey 07101-0570 973 430-7000 http://www.pseg.com	22-1212800
000-49614	PSEG POWER LLC (A Delaware Limited Liability Company) 80 Park Plaza—T25 Newark, New Jersey 07102-4194 973 430-7000 http://www.pseg.com	22-3663480
000-32503	PSEG ENERGY HOLDINGS LLC (A New Jersey Limited Liability Company) 80 Park Plaza—T20 Newark, New Jersey 07102-4194 973 456-3581 http://www.pseg.com	42-1544079

Securities registered pursuant to Section 12(b) of the Act:

Registrant		Title of Each Class		Title of Each Class		Name of Each Exchange On Which Registered
Public Service Enterprise Group Incorporated		Common Stock without par value				New York Stock Exchange

Participating Equity Preference Securities (consisting of a Purchase Contract and a Preferred Trust Security) of PSEG Funding Trust I (Registrant) and registered on the New York Stock Exchange.

Trust Originated Preferred Securities (Guaranteed Preferred Beneficial Interest in PSEG’s Debentures), $25 par value at 8.75%, issued by PSEG Funding Trust II (Registrant) and registered on the New York Stock Exchange.

Registrant	Title of Each Class	Title of Each Class				Name of Each Exchange On Which Registered
Public Service Electric and Gas Company	Cumulative Preferred Stock $100 par value Series:	First and Refunding Mortgage Bonds:
				Series	Due
	4.08%	9¹/8	%	BB	2005
	4.18%	9¹/4	%	CC	2021
	4.30%	6¹/2	%	PP	2004	New York Stock Exchange
	5.05%	7	%	SS	2024
	5.28%	7³/8	%	TT	2014
		6³/4	%	UU	2006
		6³/4	%	VV	2016
		6¹/4	%	WW	2007
		6³/8	%	YY	2023
		8	%		2037
		5	%		2037

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Securities registered pursuant to Section 12(g) of the Act:

Registrant		Title of Class
Public Service Enterprise Group Incorporated		Floating Rate Capital Securities (Guaranteed Preferred Beneficial Interest in PSEG’s Debentures), $1,000 par value issued by Enterprise Capital Trust II (Registrant), LIBOR plus 1.22%.
		Trust Originated Preferred Securities (Guaranteed Preferred Beneficial Interest in PSEG’s Debentures), $25 par value at 7.44%, issued by Enterprise Capital Trust I (Registrant).
		Trust Originated Preferred Securities (Guaranteed Preferred Beneficial Interest in PSEG’s Debentures), $25 par value at 7.25%, issued by Enterprise Capital Trust III (Registrant).
Public Service Electric and Gas Company		6.92% Cumulative Preferred Stock $100 par value Medium-Term Notes, Series A Medium-Term Notes, Series B Medium-Term Notes, Series C
PSEG Power LLC		Limited Liability Company Membership Interest
PSEG Energy Holdings LLC		Limited Liability Company Membership Interest

The aggregate market value of the Common Stock of Public Service Enterprise Group Incorporated held by non-affiliates as of June 30, 2003 was $9,386,723,992 based upon the New York Stock Exchange Composite Transaction closing price.

The number of shares outstanding of Public Service Enterprise Group Incorporated’s sole class of Common Stock, as of the latest practicable date, was as follows:

Class		Outstanding at January 30, 2004
Common Stock, without par value		236,179,721

PSEG Power LLC and PSEG Energy Holdings LLC are wholly-owned subsidiaries of Public Service Enterprise Group Incorporated and meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are filing their respective Annual Reports on Form 10-K with the reduced disclosure format authorized by General Instruction I.

As of January 30, 2004, Public Service Electric and Gas Company had issued and outstanding 132,450,344 shares of Common Stock, without nominal or par value, all of which were privately held, beneficially and of record by Public Service Enterprise Group Incorporated.

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports) and (2) have been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether each registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Public Service Enterprise Group Incorporated	Yes x	No o
Public Service Electric and Gas Company	Yes o	No x
PSEG Power LLC	Yes o	No x
PSEG Energy Holdings	Yes o	No x

DOCUMENTS INCORPORATED BY REFERENCE

Part of Form 10-K of Public Service Enterprise Group Incorporated		Documents Incorporated by Reference
III		Portions of the definitive Proxy Statement for the Annual Meeting of Stockholders of Public Service Enterprise Group Incorporated to be held April 20, 2004, which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 10, 2004, as specified herein.

TABLE OF CONTENTS

			Page

FORWARD—LOOKING STATEMENTS			1

PART I

Item 1.	Business		3

	General		3

		Public Service Enterprise Group Incorporated	3

		Public Service Electric and Gas Company	4

		PSEG Power LLC	5

		PSEG Energy Holdings LLC	10

	Regulatory Issues		15

	Segment Information		23

	Environmental Matters		23

Item 2.	Properties		29

Item 3.	Legal Proceedings		40

Item 4.	Submission of Matters to a Vote of Security Holders		44

PART II

Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters		45

Item 6.	Selected Financial Data		45

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		47

	Overview of 2003 and Future Outlook		47

	Results of Operations		55

	Liquidity and Capital Resources		69

	Capital Requirements		80

	Off Balance Sheet Arrangements		82

	Critical Accounting Estimates		82

Item 7A.	Qualitative and Quantitative Disclosures About Market Risk		84

Item 8.	Financial Statements and Supplementary Data		94

	Independent Auditors’ Report		95

	Consolidated Financial Statements		99

	Notes to Consolidated Financial Statements		120

		Note 1. Organization and Summary of Significant Accounting Policies	120

		Note 2. Restatement of Financial Statements	127

		Note 3. Recent Accounting Standards	130

		Note 4. Adoption of SFAS 143	138

		Note 5. Discontinued Operations	140

		Note 6. Extraordinary Item	142

		Note 7. Change in Accounting Principle	142

		Note 8. Asset Impairments	142

		Note 9. Restructuring Charges	144

		Note 10. Regulatory Assets and Liabilities	145

		Note 11. Earnings Per Share	148

		Note 12. Long-Term Investments	149

		Note 13. Purchase Business Combinations/Asset Acquisitions	153

		Note 14. Schedule of Consolidated Capital Stock and Other Securities	154

		Note 15. Schedule of Consolidated Debt	155

		Note 16. Risk Management	161

		Note 17. Commitments and Contingent Liabilities	164

		Note 18. Nuclear Decommissioning Trust	176

			Page

		Note 19. Other Income and Deductions	177

		Note 20. Income Taxes	179

		Note 21. Pension, Other Postretirement Benefit (OPEB) and Savings Plans	183

		Note 22. Stock Options and Employee Stock Purchase Plan	187

		Note 23. Financial Information by Business Segments	189

		Note 24. Property, Plant and Equipment and Jointly Owned Facilities	193

		Note 25. Selected Quarterly Data (Unaudited)	195

		Note 26. Related-Party Transactions	197

		Note 27. Guarantees of Debt	200

Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure		202

Item 9A.	Controls and Procedures		203

PART III

Item 10.	Directors and Executive Officers of the Registrants		204

Item 11.	Executive Compensation		207

Item 12.	Security Ownership of Certain Beneficial Owners and Management		212

Item 13.	Certain Relationships and Related Transactions		214

Item 14.	Principal Accounting Fees and Services		214

PART IV

Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K		214

	Schedule II—Valuation and Qualifying Accounts		217

	Signatures		220

	Exhibit Index		224

FORWARD-LOOKING STATEMENTS

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,” “forecast,” “project,” variations of such words and similar expressions are intended to identify forward-looking statements. Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings LLC (Energy Holdings) 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 should not be construed as a complete list of factors that could effect forward-looking statements.

In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements discussed above, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

PSEG, PSE&G, Power and Energy Holdings

•

credit, commodity, interest rate, counterparty and other financial market risks;

•

liquidity and the ability to access capital and credit markets;

•

general economic conditions, including inflation;

•

regulatory issues that significantly impact operations;

•

ability to obtain adequate and timely rate relief;

•

changes to accounting standards or accounting principles generally accepted in the United States (U.S.), which may require adjustments to financial statements;

•

changes in tax laws and regulations;

•

energy obligations, available energy supply and trading risks;

•

adverse weather conditions that significantly impact operations;

•

changes in the electric industry including changes to power pools and their market structure, rules and regulations;

•

delays or cost escalations of construction and development;

•

changes in the number of market participants and the risk profiles of such participants;

•

regulation and availability of energy transmission facilities that impact the ability to deliver output or supply to customers;

•

changes in costs and expenses;

•

the impact of environmental regulation on operations;

•

changes in rates of return on overall debt and equity markets that could have an adverse impact on the value of pension assets and the Nuclear Decommissioning Trust Fund (NDT);

•

effectiveness of risk management and internal controls systems;

•

changes in corporate strategies;

•

changes in political conditions, recession, acts of war or terrorism;

•

insufficient insurance coverage;

•

involvement in lawsuits including liability claims and commercial disputes that could affect profits or the ability to sell and market products;

•

inability to attract and retain management and other key employees;

•

acquisitions, divestitures, mergers, restructurings or strategic initiatives that change PSEG’s, PSE&G’s, Power’s or Energy Holdings’ structure;

•

business combinations among competitors and major customers;

•

changes in distribution technology;

•

inability to service debt as a result of any of the aforementioned events;

Power and Energy Holdings

•

adverse changes in the marketplace for energy, capacity, natural gas, emissions credits, congestion credits and other commodity prices;

•

excess supply due to overbuild in the industry;

•

generation operating performance that may fall below projected levels;

•

substantial competition from well capitalized participants in the worldwide energy markets;

•

margin posting requirements;

•

competitive position could be adversely affected by actions involving competitors or major customers;

•

changes in generation and transmission technology may make existing power generation assets less competitive;

•

transmission upgrades could have an impact on energy and related prices;

•

extremes in energy and fuel price volatility could adversely affect revenues and cash flows;

Power

•

changes in regulation and security measures at nuclear facilities;

Energy Holdings

•

adverse international developments that negatively impact business;

•

changes in foreign currency exchange rates;

•

substandard operating performance or cash flow from investments could fall below projected levels, adversely impacting the ability to service debt; and

•

credit of lessees and their ability to adequately service lease rentals.

Consequently, all of the forward-looking statements made in this report are qualified by these cautionary statements and PSEG, PSE&G, Power and Energy Holdings cannot assure you that the results or developments anticipated by management will be realized, or even if realized, will have the expected consequences to, or effects on, PSEG, PSE&G, Power and Energy Holdings or their respective business prospects, financial condition or results of operations. Undue reliance should not be placed on these forward-looking statements in making any investment decision. Each of PSEG, PSE&G, Power and Energy Holdings expressly disclaims 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 PSEG’s, PSE&G’s, Power’s and Energy Holdings’ securities, PSEG, PSE&G, Power and Energy Holdings is 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 I

This combined Annual Report on Form 10-K is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings LLC (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each make representations only as to itself and its subsidiaries and makes no other representations whatsoever as to any other company.

ITEM 1. BUSINESS

GENERAL

PSEG, PSE&G, Power and Energy Holdings

PSEG was incorporated under the laws of the State of New Jersey in 1985 and has its principal executive offices located at 80 Park Plaza, Newark, New Jersey 07102. PSEG is an exempt public utility holding company under the Public Utility Holding Company Act of 1935 (PUHCA).

PSEG has four principal direct wholly-owned subsidiaries: PSE&G, Power, Energy Holdings and PSEG Services Corporation (Services). The following organization chart shows PSEG and its principal subsidiaries, as well as the principal operating subsidiaries of Power: PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear) and PSEG Energy Resources & Trade LLC (ER&T); and of Energy Holdings: PSEG Global LLC (Global) and PSEG Resources LLC (Resources):

PSEG

PSE&G

Power

Energy Holdings

Services

Fossil

Nuclear

ER&T

Global

Resources

The regulatory structure that has historically governed the electric and gas utility industries in the United States (U.S.) has changed dramatically in recent years. Deregulation is complete in New Jersey and is complete or underway in certain other states in the Northeast and across the U.S. Actions by state regulators, the Federal Energy Regulatory Commission (FERC) and the enforcement of the National Energy Policy Act of 1992 (Energy Policy Act) have afforded power marketers, merchant generators, Exempt Wholesale Generators (EWGs) and utilities the opportunity to compete actively in wholesale energy markets and have allowed consumers the right to choose their energy suppliers. The deregulation and restructuring of the nation’s energy markets, the unbundling of energy and related services, the diverse strategies within the industry related to holding, building, buying or selling generation capacity and consolidation within the industry had, and are likely to continue to have, a significant effect on PSEG and its subsidiaries, providing them with new opportunities and exposing them to new risks.

As energy markets have changed dramatically in recent years, PSEG and its subsidiaries have transitioned from a vertically integrated utility to an energy company with a diversified business mix. PSEG has realigned its organizational structure to address the competitive environment brought about by the deregulation of the electric generation industry and has evolved from primarily being a state regulated New Jersey utility to operating as a competitive energy company with operations primarily in the Northeastern U.S. and in other select markets. As the competitive portion of PSEG’s business has

grown, the resulting financial risks and rewards have become greater, causing financial requirements to change and increasing the volatility of earnings and cash flows.

PSEG’s objective is to reduce future volatility of earnings and cash flows principally by entering into longer-term contracts for material portions of its anticipated energy output and by reducing exposure to its international businesses by seeking to opportunistically monetize investments of Energy Holdings that may no longer have a strategic fit. PSEG also expects a gradual decline in earnings from Resources’ leveraged leasing business due to the maturation of its investment portfolio. The proceeds from Energy Holdings’ asset sales will be used, over time, to reduce debt and equity, to maintain credit requirements. As of December 31, 2003, Power, PSE&G, and Energy Holdings comprised approximately 27%, 46% and 27%, respectively, of PSEG’s consolidated assets and contributed approximately 53%, 28% and 19%, respectively, of PSEG’s Income from Continuing Operations for the year ended December 31, 2003. For additional information, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A)—Overview of 2003 and Future Outlook.

PSE&G

PSE&G is a New Jersey corporation, incorporated in 1924, and has principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. PSE&G is an operating public utility company engaged principally in the transmission and distribution of electric energy and gas service in New Jersey. PSE&G, pursuant to an order of the New Jersey Board of Public Utilities (BPU) issued under the provisions of the New Jersey Electric Discount and Energy Competition Act, (EDECA), transferred all of its electric generation facilities, plant, equipment and wholesale power trading contracts to Power and its subsidiaries in August 2000. Also, pursuant to a BPU order, PSE&G transferred its gas supply business, including its inventories and supply contracts, to Power in May 2002. PSE&G continues to own and operate its electric and gas transmission and distribution business. In addition, PSE&G Transition Funding LLC (Transition Funding), a bankruptcy-remote subsidiary of PSE&G, was formed in 1999 for the sole purpose of issuing $2.525 billion principal amount of transition bonds in connection with the securitization of $2.4 billion of PSE&G’s stranded costs approved for recovery by the BPU under EDECA.

PSE&G provides electric and gas service in areas of New Jersey in which approximately 5.5 million people, about 70% of the State’s population, reside. PSE&G’s electric and gas service area is a corridor of approximately 2,600 square miles running diagonally across New Jersey from Bergen County in the northeast to an area below the city of Camden in the southwest. The greater portion of this area is served with both electricity and gas, but some parts are served with electricity only and other parts with gas only. This heavily populated, commercialized and industrialized territory encompasses most of New Jersey’s largest municipalities, including its six largest cities—Newark, Jersey City, Paterson, Elizabeth, Trenton and Camden—in addition to approximately 300 suburban and rural communities. This service territory contains a diversified mix of commerce and industry, including major facilities of many nationally prominent corporations. PSE&G’s load requirements are almost evenly split among residential, commercial and industrial customers. PSE&G believes that it has all the franchises (including consents) necessary for its electric and gas distribution operations in the territory it serves. Such franchise rights are not exclusive.

PSE&G distributes electric energy and gas to end-use customers within its designated service territory. All electric and gas customers in New Jersey have the ability to choose an electric energy and/or gas supplier. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for electric and gas customers within its service territory. PSE&G earns no margin on the commodity portion of its electric and gas sales. PSE&G earns margins through the transmission and distribution of electricity and gas. PSE&G’s revenues for these services are based upon tariffs approved by the BPU and FERC. The demand for electric energy and gas by PSE&G’s customers is affected by customer conservation, economic conditions, weather and other factors not within PSE&G’s control.

New Jersey’s Electric Distribution Companies (EDCs), including PSE&G, began providing two types of basic generation service (BGS) service in August 2003. BGS-FP provides for smaller commercial and residential customers at seasonally-adjusted fixed prices for terms ranging from 10

months to three years. BGS-HEP provides supply for larger customers at hourly market prices for a term of 10 months or 12 months. BGS-FP and BGS-HEP represent approximately 84% and 16%, respectively, of PSE&G’s load. The BPU holds two concurrent auctions of New Jersey’s BGS each February to determine who will supply BGS to New Jersey’s EDCs. The total supply under auction was over 18,000 MWs. As a condition of qualification to participate in this auction, energy suppliers are required to agree to execute the BGS Master Service Agreement and provide required security within two days of BPU certification of auction results, in addition to satisfying BPU credit worthiness requirements.

PSE&G’s BGS-FP load is approximately 8,500 MW and starting in 2005, one-third of this load is expected to be auctioned off each year for a three-year term. The current pricing is as follows:

	Term Ending
	May 2004(a)	May 2005(b)	May 2006(a)	May 2007(b)
Term	10 months	12 months	34 months	36 months
Load (MW)	5,600	2,800	2,900	2,800
$ per Kilowatt-hour (kWh)	$ 0.05386	$ 0.05479	$ 0.05560	$ 0.05515

______________

(a)

Prices set in the February 2003 BGS auction.

(b)

Prices set in the February 2004 BGS auction.

Also, to meet the supply requirements of its gas customers, PSE&G has entered into a full requirements contract with Power under which Power will provide PSE&G with its gas supply through 2007. Power charges PSE&G for gas commodity costs which PSE&G recovers from its customers. Any difference between rates charged by Power under the basic gas supply service (BGSS) contract and rates charged to its customers are deferred and collected or refunded through adjustments in future rates.

Competitive Environment

The electric and gas transmission and distribution business has minimal risks from competitors. PSE&G’s transmission and distribution business is minimally impacted when customers choose alternate electric or gas suppliers since PSE&G earns its return by providing transmission and distribution service, not by supplying the commodity.

Customers

As of December 31, 2003, PSE&G provided service to approximately 2.0 million electric customers and approximately 1.6 million gas customers. PSE&G’s load requirements are almost evenly split among residential, commercial and industrial customers. In addition to its transmission and distribution business, PSE&G also offers appliance services and repairs to customers throughout its service territory.

Employee Relations

As of December 31, 2003, PSE&G had 6,309 employees. PSE&G has three-year collective bargaining agreements in place with four unions, representing 4,839 employees, which expire on April 30, 2005. PSE&G believes that it maintains satisfactory relationships with its employees.

Power

Power is a Delaware limited liability company, formed in 1999, and has its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. Power is a multi-regional, independent wholesale energy supply company that integrates its generating asset operations with its wholesale energy, fuel supply, energy trading and marketing and risk management function through three principal direct wholly-owned subsidiaries: Nuclear, which owns and operates nuclear generating stations, Fossil, which develops, owns and operates domestic fossil generating stations and ER&T, which markets the capacity

and production of Fossil’s and Nuclear’s stations and manages the commodity price risks and market risks related to generation.

As of December 31, 2003, Power’s generation portfolio consisted of approximately 13,751 MW of installed capacity which is diversified by fuel source and market segment. Power’s current construction projects are expected to increase capacity to approximately 16,000 MW through 2005, net of planned retirements. For additional information, see Item 2. Properties.

Through its operating subsidiaries, Power competes as an independent wholesale electric generating company, primarily in the Northeast. Most of Power’s generating assets are strategically located within the Pennsylvania, New Jersey, Maryland Interconnection (PJM), one of the nation’s largest and most developed energy markets. Power has extended its generation business into New York, Connecticut and the Midwest states. Power completed construction of the Waterford, Ohio plant, an 821 MW natural gas-fired, combined cycle plant, which began commercial operation in August 2003. In addition, Power has nearly completed construction of a 1,096 MW combined cycle plant in Lawrenceburg, Indiana, which is expected to achieve commercial operation in the first half of 2004. Additionally, the Albany, New York generating station is currently being replaced with a 763 MW combined cycle plant, the Bethlehem Energy Center, which is expected to be operational in the second quarter of 2005. The Linden, New Jersey generating station is currently being replaced with a 1,220 MW combined cycle gas fired plant, which is expected to be operational in 2005. Power extended into the New England Power Pool (NEPOOL) with the acquisition of two fossil fuel generating stations in Connecticut in late 2002; the Bridgeport Harbor facility, a 525 MW coal/oil fuel facility and the New Haven Harbor facility, a 455 MW oil/gas facility.

In the PJM market, the pricing of energy is based upon the locational marginal price (LMP) set through power providers’ bids. Due to transmission constraints, the LMP may be higher in congested areas during peak demand periods reflecting the bid prices of the higher cost units that are dispatched to supply demand and alleviate transmission constraints when coordination is sufficient to satisfy demand within PJM. This typically occurs in the eastern portion of the grid, where many of Power’s plants are located. These bids are currently capped at $1,000 per megawatt-hour (MWh). In the event that available generation within PJM is insufficient to satisfy demand, PJM may institute emergency purchases from adjoining regions for which there is no price cap.

To reduce earnings and cash flow volatility, Power’s objective is to enter into load serving contracts, firm sales and trading positions sufficient to hedge at least 75% of its anticipated output over an 18-month to 24-month horizon. As a result of the conclusion of the BGS auction in February 2004, the contracts Power has entered into in Pennsylvania and Connecticut and other firm sales and trading positions, commitments have been entered into to achieve this objective. Power’s ability to increase the term of its forward sales is constrained by the multiple tranche structure of the BGS auction process in New Jersey. Due to the soft market conditions in the Midwest, Power expects only modest output from its Lawrenceburg and Waterford facilities in the near term. In addition to the BGS auction process in New Jersey, Power expects to take advantage of other opportunities elsewhere in its market region.

Under the New Jersey BGS contracts that began on August 1, 2003, Power is a direct supplier of certain large customers under hourly energy price contracts for a 10-month period. Power has also entered into contracts with third parties who are direct suppliers of New Jersey’s EDCs. Through these seasonally-adjusted fixed-price contracts, Power indirectly serves New Jersey’s smaller commercial and residential customers for 10-month and 34-month periods that began August 1, 2003.

In February 2004, the BPU approved the results of the BGS auction for New Jersey customers. The auction was for over 18,000 MWs and each bidder was limited to a third of each EDC’s total load. Power will be a direct supplier of New Jersey EDCs entering into seasonally-adjusted fixed-price contracts for 12-month and 36-month periods beginning June 1, 2004. Power believes that its obligations under these contracts are reasonably balanced by its available supply.

In addition to the electric generation business described above, a significant amount of Power’s revenues come from gas supply under the BGSS contract with PSE&G. Power also generates revenue from the sales of various commodity based instruments, such as capacity, ancillary services, emission credits and congestion credits, such as firm transmission rights (FTRs).

Fossil

Fossil has an ownership interest in twelve generating stations in New Jersey, one in New York, two in Connecticut, two in Pennsylvania and one in Ohio. Fossil also has an ownership interest in one hydroelectric pumped storage facility in New Jersey. For additional information, see Item 2. Properties—Power.

Fossil uses coal, natural gas and oil for electric generation. These fuels are purchased through various contracts and in the spot market and represent a significant portion of Power’s working capital requirements. Changes in the prices of these fuel sources can impact Power’s costs and working capital requirements. The majority of Power’s fossil generating stations obtain their fuel supply from within the U.S. In order to minimize emissions levels, the Connecticut generating facilities use a specific type of coal, which is obtained from Indonesia through a fixed-price supply contract through 2008 and fixed-price transportation contracts through 2004. Fossil does not anticipate any difficulties in obtaining adequate coal, natural gas and oil supplies for its facilities over the next several years. However, if the supply of coal from Indonesia or equivalent coal from other sources was not available for the Connecticut facilities, additional material capital expenditures could be required to modify the existing plants to enable their continued operation. For additional information, see Item 2. Properties—Power.

Nuclear

Nuclear has an ownership interest in five nuclear generating units and operates three of them: the Salem Nuclear Generating Station, Units 1 and 2 (Salem 1 and 2), each owned 57.41% by Nuclear and 42.59% by Exelon Generation LLC (Exelon), and the Hope Creek Nuclear Generating Station (Hope Creek), which is 100% owned by Nuclear. Exelon operates the Peach Bottom Atomic Power Station Units 2 and 3 (Peach Bottom 2 and 3), each of which is 50% owned by Nuclear. For additional information, see Item 2. Properties—Power.

Nuclear unit capacity and availability factors for 2003 were as follows:

Unit	Capacity Factor*			Availability Factor

Salem Unit 1		94.7	%		95.9	%
Salem Unit 2		84.5	%		84.0	%
Hope Creek		79.0	%		81.5	%
Peach Bottom Unit 2		95.1	%		96.2	%
Peach Bottom Unit 3		91.8	%		92.4	%
Combined Nuclear’s Share		87.7	%		88.6	%

______________

* Maximum Dependable Capacity (MDC) net.

The 2003 capacity factor was adversely affected by storm-related impacts in the third quarter. The combined capacity factor in 2002 was approximately 94%.

Nuclear has several long-term purchase contracts with uranium suppliers, converters, enrichers and fabricators to meet the currently projected fuel requirements for Salem and Hope Creek nuclear power plants. Nuclear has been advised by Exelon that it has similar purchase contracts to satisfy the annual fuel requirements for Peach Bottom. See Note 17. Commitments and Contingent Liabilities of the Notes to Consolidated Financial Statements (Notes).

ER&T

ER&T purchases virtually all of the capacity and energy produced by Fossil and Nuclear. In conjunction with these purchases, ER&T uses commodity and financial instruments designed to cover estimated commitments for BGS and other bilateral contract agreements. ER&T also markets electricity, capacity, ancillary services and natural gas products on a wholesale basis. ER&T is a fully

integrated wholesale energy marketing and trading organization that is active in the long-term and spot wholesale energy markets.

Electric Supply

Power’s generation capacity is sourced from a diverse mix of fuels comprised of approximately 41% gas, 25% nuclear, 18% coal, 14% oil and 2% pumped storage. Power’s fuel diversity mitigates risk associated with fuel price volatility and market demand cycles. The following table indicates the MWh output of Power’s generating stations by fuel type in 2003 and its estimated MWh output by fuel type for 2004.

Generation by Fuel Type	Actual 2003			Estimated 2004(A)
Nuclear:
New Jersey facilities		37	%		38	%
Pennsylvania facilities		20	%		19	%
Fossil:
Coal:
New Jersey facilities		11	%		12	%
Pennsylvania facilities		13	%		12	%
Connecticut facilities		6	%		5	%
Oil and Natural Gas:
New Jersey facilities		10	%		7	%
New York facilities		—			—
Connecticut facilities		2	%		3	%
Midwest facilities		—			3	%
Pumped Storage:		1	%		1	%
Total		100	%		100	%

______________

(A)

No assurances can be given that actual 2004 output by source will match estimates.

Approximately 87% of Power’s generation was from nuclear and coal facilities in 2003, which are typically the most cost effective fuel types on an operating cost basis. On a per-MWh basis, nuclear power is the most cost effective and therefore Power’s profitability is largely affected by the utilization and efficiency of its nuclear facilities. The nuclear facilities are considered “base load” and run continuously when not in shutdown. Older oil and gas fired facilities are typically the least cost effective of the fossil fuel burners. Accordingly, these plants are not usually run outside of peak periods of demand (Peak Load) when the cost of operation can be rationalized by the market price. The cost of coal and oil burning facilities, and new combined cycle gas facilities are between the two aforementioned facility types. These plants can be base load plants and/or load following plants.

Gas Supply

As described above, Power sells gas to PSE&G under the BGSS contract. About 40% of PSE&G’s peak daily gas requirements are provided through firm transportation, which is available every day of the year. The remainder comes from field storage, liquefied natural gas, seasonal purchases, contract peaking supply, propane and refinery and landfill gas. Power purchases gas for its gas operations directly from natural gas producers and marketers. These supplies are transported to New Jersey by four interstate pipeline suppliers.

Power has approximately 1.1 billion cubic-feet-per-day of firm transportation capacity under contract to meet the primary needs of the gas consumers of PSE&G and the needs of its generation fleet. In addition, Power supplements that supply with a total storage capacity of 81 billion cubic feet that provides a maximum of .94 billion cubic feet-per-day of gas during the winter season.

Power expects to meet the energy-related demands of its firm natural gas customers. However, the ability to maintain an adequate supply could be affected by several factors not within Power’s control, including curtailments of natural gas by its suppliers, the severity of the winter weather and the availability of feedstocks for the production of supplements to its natural gas supply. In addition, supply of all types of gas is affected by the nationwide availability of all sources of fuel for energy production.

Competitive Environment

Power’s competitors include merchant generators with or without trading capabilities, utilities that have generating capability or have formed generation and/or trading affiliates, aggregators, wholesale power marketers or combinations thereof. These participants compete with Power and one another buying and selling in wholesale power pools, entering into bilateral contracts and/or selling to aggregated retail customers. Power believes that its asset size and location, regional market knowledge and integrated functions allow it to compete effectively in its selected markets. However, actions by developers, including Power, to build new generating stations has led to an overbuild situation causing energy and capacity prices to decrease. Capacity prices in PJM have decreased to less than $10 per kW-year in 2003 from historical levels of more than $25 per kW-year in 2001. This overcapacity has decreased capacity revenues and has decreased margins from some of Power’s units.

In particular, the Midwest market is expected to have excess capacity due to recent additions, which will negatively impact the expected returns of Power’s Lawrenceburg and Waterford facilities. The drivers to reduce the excess capacity will be load growth, the retirement of certain plants, particularly older plants of competitors due to the weakened wholesale energy and capacity market and increased costs associated with higher levels of environmental compliance. Power anticipates that capacity prices in PJM will return to historical levels in the next several years and increase over the longer term.

Power’s businesses are also under competitive pressure due to technological advances in the power industry and increased efficiency in certain energy markets. It is possible that advances in technology, such as distributed generation, will reduce the cost of alternative methods of producing electricity to a level that is competitive with that of most central station electric production.

Additional state legislation has been introduced within the last few years to further encourage competition at the retail level (often referred to as customer choice or retail access). However, there is a risk of re-regulation if states decide to turn away from deregulation and allow regulated utilities to continue to own or reacquire and operate generating stations in a regulated and potentially uneconomical manner. This has already occurred in certain states in which Power does business. The lack of consistent rules in markets outside of PJM can negatively impact the competitiveness of Power’s plants, particularly its Lawrenceburg and Waterford facilities in the Midwest. Also, inconsistent environmental regulation, particularly those related to emissions regulations that are more stringent in the Northeast, have put some of Power’s plants at an economic disadvantage compared to its competitors in certain Midwest states.

Customers

As EWGs, Power’s subsidiaries do not directly serve retail customers. Power uses its generation facilities primarily for the production of electricity for sale at the wholesale level. Power’s customers consist mainly of wholesale buyers within the Super Region, primarily within PJM, but also in New York, Connecticut and the Midwest. As a result of the 2003 New Jersey BGS auction, Power entered into hourly energy price contracts to be a direct supplier of certain large customers through the BGS auction and entered into contracts with third parties who are direct suppliers of New Jersey’s EDCs. As a result of the 2004 New Jersey BGS auction, Power will be a direct supplier of New Jersey’s EDCs. In addition, Power extended into the New England Power Market by securing a three-year, full requirements contract with a Connecticut utility with an expected peak load of 1,150 MW, has entered into four year contracts totalling 500 MW with two Pennsylvania utilities and is considering entering into similar opportunities in other states.

Employee Relations

As of December 31, 2003, Power had 3,201 employees. Power has collective bargaining agreements with three union groups, which expire on October 31, 2004, April 30, 2005 and May 15, 2006, respectively. These agreements cover 1,557 employees (741 employees, or approximately 66% of the workforce for Fossil and 816 employees, or approximately 46% of the workforce for Nuclear). Power believes that it maintains satisfactory relationships with its employees.

Energy Holdings

Energy Holdings is a New Jersey limited liability company and is the successor to PSEG Energy Holdings Inc., which was originally incorporated in 1989. Energy Holdings’ principal executive offices are located at 80 Park Plaza, Newark, New Jersey 07102. Energy Holdings has two principal direct wholly-owned subsidiaries, which are also its segments; Global and Resources. By September 2003, Energy Holdings completed its planned sale of PSEG Energy Technologies Inc. (Energy Technologies), see Note 5. Discontinued Operations of the Notes.

Energy Holdings has pursued investment opportunities in the global energy markets, with Global focusing on the operating segments of the electric industries and Resources primarily making financial investments in these industries. Global and Resources have more than 100 financial and operating investments.

Energy Holdings’ portfolio is diversified by number, type and geographic location of investments. As of December 31, 2003, its assets were comprised of the following types:

	As of December 31, 2003
Leveraged Leases (mainly energy related)	40		%
International Electric Distribution Facilities	20		%
International Electric Generation Plants	23		%
Domestic Electric Generation Plants	6		%
Other (1)	6		%
Other Passive Financial Investments		5	%
Total		100	%

______________

(1)

Assets not allocated to a special project, including corporate receivables.

The characteristics of each of these investment types are described in more detail below.

Global

Global is an independent power producer and distributor, which develops, owns and operates electric generation, transmission and distribution facilities in selected domestic and international markets.

Global realized substantial growth prior to 2002, but has been faced with significant challenges as the electricity privatization model has become stressed. These challenges have included political, economic and social crisis in areas such as Argentina, Brazil, Venezuela and India. A series of disruptive events have slowed privatization in many countries and have adversely affected Global’s existing investments. In 2003, Global began to review its portfolio and to seek to opportunistically monetize investments that no longer have a strategic fit. Global has placed its near-term emphasis on maintaining adequate liquidity and improving profitability of currently held investments. Global has developed or acquired interests in electric generation and/or distribution facilities in the U.S., Brazil, Chile, China, India, Italy, Oman, Peru, Poland, Taiwan, Tunisia and Venezuela. Projects are being completed in China, Italy and South Korea. While Global still expects certain of its investments in Latin America to contribute significantly to its earnings in the future, adverse political and economic risks associated with

this region could have a material adverse impact on its remaining investments in the region. See Item 7. MD&A—Future Outlook for additional information.

Global has sought to minimize risk in the development and operation of its generation projects by selecting partners with complementary skills, structuring long-term power purchase contracts, arranging financing prior to the commencement of construction and contracting for adequate fuel supply. Historically, Global’s operating affiliates have entered into long-term power purchase contracts, thereby selling the electricity produced for the majority of the project life. However, two plants in China, Nantong (14 MW) and Tongzhou (12 MW), two in Texas, Guadalupe (500 MW) and Odessa (500 MW), and one plant in Poland, Skawina (590 MW), operate as merchant plants without long-term power purchase contracts. Global’s other plant in Poland, Elcho, may also become a merchant plant in the future due to the Polish government’s current intention to eliminate all existing long-term Power Purchase Agreements (PPAs). For further discussion of the oversupply of energy in the Texas power market and Global’s investment in Poland, see Item 7. MD&A—Future Outlook.

Global, to the extent practical, attempts to limit its financial exposure associated with each project and to mitigate development risk, foreign currency exposure, interest rate risk and operating risk, including exposure to fuel costs, through contracts. For a further discussion of these risks, see Item 7A. Qualitative and Quantitative Disclosures About Market Risk. In addition, project loan agreements are generally structured on a non-recourse basis. Further, Global generally structures project financing so that a default under one project’s loan agreement will have no effect on the loan agreements of other projects or Energy Holdings’ debt.

Fuel supply arrangements are designed to balance long-term supply needs with price considerations. Global’s project affiliates generally utilize a combination of long-term contracts and spot-market purchases. Global believes that there are adequate fuel supplies for the anticipated needs of its generating projects. Global also believes that transmission access and capacity are sufficient at this time for its generation projects.

Global has invested in four distribution companies which serve approximately 2.8 million customers in Brazil, Chile and Peru. Global is actively involved in managing the operations of these distribution companies in accordance with shareholder agreements and/or operating contracts. Rate-regulated distribution assets represented 39% of Global’s assets, or $1.5 billion, as of December 31, 2003.

As of December 31, 2003, Global’s assets, which include consolidated projects and those accounted for under the equity method, and share of project MW by region are as follows:

	As of December 31, 2003
	Amount		MW
	(Millions)
Generation:
North America	$	416	1,450
Latin America		344	277
Asia Pacific		181	1,063
Europe and Africa		846	883
India and the Middle East		322	260
Distribution:
Latin America		1,494	N/A
Other:
Other(1)		211	N/A
Total	$	3,814	3,933

______________

(1)

Assets not allocated to a specific project, including corporate receivables and deferred tax assets.

Resources

Resources invests in energy-related financial transactions and manages a diversified portfolio of assets, including leveraged leases, operating leases, leveraged buyout funds, limited partnerships and marketable securities. Since it was established in 1985, Resources has grown its portfolio to include more than 60 separate investments. Based on current market conditions and Energy Holdings’ intent to limit capital expenditures, it is unlikely that Resources will make significant additional investments in the near term.

Also, the Demand Side Management (DSM) business, previously managed by Energy Technologies, was transferred to Resources as of December 31, 2002. DSM revenues are earned principally from monthly payments received from utilities, which represent shared electricity savings from the installation of the energy efficient equipment. For further discussion of the transfer of DSM to Resources, see Note 26. Related-Party Transactions—Energy Holdings of the Notes.

The major components of Resources’ investment portfolio as a percent of its total assets as of December 31, 2003 were:

	As of December 31, 2003
	Amount		% of Resources’ Total Assets
	(Millions)
Leveraged Leases
Energy-Related
Foreign	$	1,278		39	%
Domestic		1,337		41
Real Estate—Domestic		176		5
Aircraft
Foreign		44		1
Domestic		59		2
Commuter Railcars—Foreign		87		3
Total Leveraged Leases		2,981		91
Limited Partnerships
Leveraged Buyout Funds		74		2
Other		20		1
Total Limited Partnerships		94		3
Marketable Securities		4		—
Other Investments		24		1
Owned Property		73		2
Current and Other Assets		101		3
Total Resources’ Assets	$	3,277		100	%

As of December 31, 2003, no single investment represented more than 7.5% of Resources’ total assets.

Leveraged Lease Investments

Resources maintains a portfolio that is designed to provide a fixed rate of return, predictable income and cash flow and depreciation and amortization deductions for federal income tax purposes. Income on leveraged leases is recognized by a method which produces a constant rate of return on the outstanding net investment in the lease, net of the related deferred tax liability, in the years in which the net investment is positive. Any gains or losses incurred as a result of a lease termination are recorded as Operating Revenues as these events occur in the ordinary course of business of managing the investment portfolio.

In a leveraged lease, the lessor acquires an asset by obtaining equity representing approximately 15% to 20% of the cost and incurring non-recourse lease debt for the balance. The lessor acquires economic and tax ownership of the asset and then leases it to the lessee for a period of time no greater than 80% of its remaining useful life. As the owner, the lessor is entitled to depreciate the asset under

applicable federal and state tax guidelines. In addition, the lessor receives income from lease payments made by the lessee during the term of the lease and from tax receipts associated with interest and depreciation deductions with respect to the leased property. The ability of Resources to realize these tax benefits are dependent on operating gains generated by its affiliates and allocated pursuant to PSEG’s consolidated tax sharing agreement. Lease rental payments are unconditional obligations of the lessee and are set at levels at least sufficient to service the non-recourse lease debt. The lessor is also entitled to any residual value associated with the leased asset at the end of the lease term. An evaluation of the after-tax cash flows to the lessor determines the return on the investment. Under accounting principles generally accepted in the U.S. (GAAP), the lease investment is recorded on a net basis and income is recognized as a constant return on the net unrecovered investment.

Resources has evaluated the lease investments it has made against specific risk factors. The assumed residual-value risk, if any, was analyzed and verified by third-parties at the time the investment was made. Credit risk was assessed and, if necessary, mitigated or eliminated through various structuring techniques, such as defeasance mechanisms and letters of credit. Resources has not taken currency risk in its cross-border lease investments. Transactions have been structured with rental payments denominated and payable in U.S. Dollars. Resources, as a passive lessor or investor, has not taken operating risk with respect to the assets it owns, so leases have been structured with the lessee having an absolute obligation to make rental payments whether or not the related assets operate. The assets subject to lease are an integral element in Resources’ overall security and collateral position. If such assets were to be impaired, the rate of return on a particular transaction could be affected. The operating characteristics and the business environment in which the assets operate are, therefore, important and must be understood and periodically evaluated. For this reason, Resources retains experts to conduct regular appraisals on the assets it owns and leases.

Resources’ ten largest lease investments as of December 31, 2003 were as follows:

Investment	Description	Gross Investment Balances as of December 31, 2003		% of Resources’ Total Assets
		(Millions)
Reliant Energy MidAtlantic Power LLC	Three generating stations (Keystone, Conemaugh and Shawville)		$ 239		7	%
Midwest Generation (MWG)	Collins Electric Generation Station		199		6
Dynegy Holdings Inc.	Two electric Generating stations (Danskammer and Roseton)		190		6
Seminole Electric Cooperative	Seminole Generation Station Unit #2		183		6
MWG (Guaranteed by Edison Mission Energy)	Two electric generating stations (Powerton and Joliet)		182		6
ENECO	Gas distribution network (Netherlands)		151		5
Merrill Creek	Merrill Creek Reservoir Project		132		4

(table continued on next page)

(table continued from previous page)

Investment	Description	Gross Investment Balances as of December 31, 2003		% of Resources’ Total Assets
		(Millions)
System Energy Resources	Nuclear generating station		131		4
ESG	Electric distribution system (Austria)		121		4
EZH	Electric generating station (Netherlands)		115			4
			$1,643			52	%

For further details on leases, including credit matters related to certain lessees, see Item 7A. Qualitative and Quantitative Disclosures About Market Risk—Credit Risk—Energy Holdings.

Energy Technologies

Energy Technologies was an energy management company whose primary objective was to construct, operate and maintain heating, ventilating and air conditioning (HVAC) systems for, and provide energy-related engineering, consulting and mechanical contracting services to, industrial and commercial customers in the Northeastern and Mid-Atlantic U.S. In the third quarter of 2003, Energy Holdings completed its planned sale of these HVAC/mechanical operating companies. For more details, see Note 5. Discontinued Operations of the Notes.

Other Subsidiaries

Enterprise Group Development Corporation (EGDC), a commercial real estate property management business, is conducting a controlled exit from the real estate business. EGDC directly owns a 100% interest in two parcels of land available for development located in New Jersey totaling $19 million. EGDC also owns an 80% general partnership interest in each of four partnerships which own and operate two buildings and land in New Jersey totaling $15 million. EGDC also owns a 100% interest in development land located in Maryland valued at $12 million. Together, the 100% wholly-owned land and the 80% general partnership interests represent 72% of the total assets of EGDC. Additionally, EGDC owns a 50% partnership interest in development land located in Virginia. Total assets of EGDC as of December 31, 2003 and 2002 were $86 million and $95 million, respectively.

Competitive Environment

Energy Holdings and its subsidiaries continue to experience substantial competition, both in the U.S. and in international markets. In the U.S., an overbuild in generation has led to a large capacity surplus in several regions, including Texas. This has resulted in reduced operating margins for both independent power producers and utility generators.

In addition to the imbalance between supply and demand, regulatory initiatives are also a factor in the competitive environment. In California there has been numerous contract renegotiations between government entities and independent power producers. PPAs that were signed in 2000 and 2001, at the height of the California power crisis when market prices were at a peak, were renegotiated in 2002 and 2003, when power prices had dropped considerably. As a result of this decrease in revenues, profit margins have deteriorated, requiring increased focus on cost controls. The overbuild situation exists in Texas as well, coupled with a marketplace evolving from a rate-regulated structure to a competitive environment. Global anticipates that these matters in Texas will improve in the long-term, leading to higher capacity prices and increased utilization of its facilities.

Internationally, the recession in some regions has led to a softening of electric power demand. Regulators, driven by local politics and a desire to lower costs are reducing allowable rates of return. In addition, several countries, such as Poland and India, are seeking to renegotiate existing PPAs that they believe to be uncompetitive in the local energy market.

Customers

Global has ownership interests in four distribution companies which serve approximately 2.8 million customers and has developed or acquired interests in electric generation facilities which sell energy, capacity and ancillary services to numerous customers through PPAs, as well as into the wholesale market. For additional information, see Item 2. Properties—Energy Holdings.

Employee Relations

As of December 31, 2003, Energy Holdings had 103 employees. There was a significant decrease from the prior year due to the sale of Energy Technologies and its operating subsidiaries, which had approximately 1,900 employees. Energy Holdings believes that it maintains satisfactory relationships with its employees.

Services

Services is a New Jersey corporation with its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. Services provides management and administrative services to PSEG and its subsidiaries. These include accounting, legal, communications, human resources, information technology, treasury and financial, investor relations, stockholder services, real estate, insurance, risk management, tax, library and information services, security, corporate secretarial and certain planning, budgeting and forecasting services. Services charges PSEG and its subsidiaries for the cost of work performed and services provided pursuant to the terms and conditions of intercompany service agreements. As of December 31, 2003, Services had 1,019 employees, none of whom were unionized. Services believes that it maintains satisfactory relationships with its employees.

REGULATORY ISSUES

Federal Regulation

PSEG, PSE&G, Power and Energy Holdings

PUHCA

PSEG has claimed an exemption from regulation by the U.S. Securities and Exchange Commission (SEC) as a registered holding company under PUHCA, except for Section 9(a)(2) thereof, which relates to the acquisition of 5% or more of the voting securities of an electric or gas utility company. Fossil, Nuclear and certain subsidiaries of Energy Holdings with domestic operations are EWGs. In addition, several of Energy Holdings’ investments include foreign utility companies (FUCOs) under PUHCA and Qualifying Facilities (QFs) under the Public Utility Regulatory Policy Act (PURPA). If PSEG were no longer exempt under PUHCA, or if the subsidiaries’ investments failed to maintain their status as EWGs, FUCOs or QFs, PSEG and its subsidiaries would be subject to additional regulation by the SEC with respect to their financing and investing activities, including the amount and type of non-utility investments they would be permitted to make. PSEG does not believe, however, that this would have a material adverse effect on it and its subsidiaries.

FERC

FERC is an independent federal agency that regulates the transmission of electric energy and sale of electric energy at wholesale prices in interstate commerce pursuant to the Federal Power Act. FERC also regulates the transmission of, as well as certain wholesale sales of, natural gas pursuant to the Natural Gas Act. Several PSEG subsidiaries including PSE&G, Fossil, Nuclear, ER&T and certain

subsidiaries of Fossil and certain subsidiaries of Energy Holdings with domestic operations are public utilities subject to regulation by FERC. FERC’s regulation of public utilities is comprehensive and governs such matters such as rates, service, mergers, financings, affiliate transactions, market behaviors and reporting. FERC is also responsible under PURPA for administering PURPA’s requirements for QFs.

Regional Transmission Organization (RTO) and Transmission Order

Over the last several years, FERC has issued several orders in an effort to restructure the wholesale electricity and electric transmission industries. FERC is attempting to establish RTOs to conduct competitive wholesale electricity markets and to manage the regional transmission grid, including administration of open access tariffs for non-discriminatory use of the grid.

As FERC continues to move toward RTO development in other regions of the nation, RTO expansion and refinement continues to be the focus in the Northeast. In April 2002, PJM successfully implemented its “PJM West” expansion and integrated Allegheny Electric Systems into PJM. In December 2002, FERC granted full RTO status to PJM. In 2004, PJM is working toward integrating Commonwealth Edison Inc. (ComEd) and American Electric Power Company, Inc. (AEP) in stages to commence in the first half of 2004. Implementation of this effort would more than double the size of the current PJM region and would result in a market encompassing more than 153,000 MW of generation capacity and more than 128,000 MW of Peak Load. While this expansion was generally approved by FERC in 2003, actions by the states of Virginia and Kentucky may delay the prompt integration of AEP. The expansion of PJM to include ComEd and AEP is expected to have a positive impact on PSEG because it would likely expand market opportunities for Power’s Midwest plants.

On November 17, 2003, FERC ordered that the regional through-and-out-tariff (RTOR) charges for electric transmission service that crosses the border between PJM and the Midwest Independent System Operator Inc. (MISO) or PJM/MISO and the service territories of certain other designated midwestern utilities be eliminated as of April 1, 2004. Elimination of these rates would have the effect of reducing PSE&G’s transmission revenues. PSE&G, along with other impacted electric utilities, has filed a Petition for Review of this aspect of FERC’s order in the U.S. Court of Appeals for the District of Columbia Circuit. Also on November 17, 2003, FERC directed that PJM, MISO, and certain midwestern utilities implement a lost-revenue recovery mechanism called a Seams Elimination Cost Adjustment (SECA) as of April 1, 2004. The SECA is to be a tariff charge assessed on transmission customers in each of the respective regions, which would in turn be paid to the utilities in the other region to reimburse them for transmission revenues lost as a result of the elimination of the RTOR. ER&T is a transmission customer and would therefore likely incur additional costs as a result of the imposition of SECA charges. PSE&G, along with other impacted electric utilities, has filed a Request for Rehearing of this aspect of the order with the FERC. The outcome of these proceedings cannot be predicted.

In January 2003, FERC also proposed a new transmission pricing policy that, if adopted, would give rate incentives to transmission companies that engage in certain transactions, including transfer of control of facilities to a FERC-approved RTO, joining an RTO as part of an independent transmission company and constructing new transmission facilities pursuant to a regional plan. The ultimate outcome of this proposal and its effect on PSEG cannot be predicted.

Pursuant to a 2002 FERC order, PSE&G’s current transmission rate design is authorized through December 31, 2004. In 2004, PSE&G will be required to file for authorization of a rate design to become effective January 1, 2005. Within the context of that proceeding, FERC may examine PSE&G’s transmission revenue requirements and require PSE&G to adopt a formula rate design. PSE&G expects to be able to obtain reasonable rate treatment, however, the outcome of this proceeding cannot be predicted.

Generation and Trading

In July 2003, FERC issued its final rule on large generator interconnections, standardizing interconnection procedures and the terms and conditions for interconnection agreements for all generators over 20 MW. The rule retains FERC’s current pricing policy with respect to interconnection costs and permits generators to receive transmission credits for system upgrades. This final rule is expected to benefit Power and Energy Holdings.

As a prerequisite to the market-based rate authority held by PSE&G, ER&T and certain subsidiaries of Fossil and Energy Holdings, each company was required to demonstrate that it did not have market power in its respective wholesale markets. As a condition of these market-based rates, each of these companies is required to file on a triennial basis a market power update to demonstrate to FERC that it continues to meet the requirements necessary to have market-based rate authority. In 2003, PSE&G and ER&T each filed its analysis, which were found to be acceptable by FERC. In 2004, certain subsidiaries of Fossil and Energy Holdings will be required to submit their triennial market power analysis. Failure to meet these requirements can result in the revocation of market-based rate authority.

On June 26, 2003, FERC issued a final order that adds six new market behavioral rules to all market-based rate tariffs. These new conditions govern unit operation, market manipulation, communications with regulators and other entities, data reporting to publishers of electric or natural gas indices and record retention. Violation of these market behavioral rules could result in disgorgement of profits and potentially the revocation of market-based rates. PSEG believes that its subsidiaries are in compliance with these rules.

The existence and mitigation of potential market power continues to be a focus of the FERC and RTOs. FERC is attempting to achieve a level of market mitigation that will protect consumers while, at the same time, send appropriate price signals allowing generators to recover sufficient revenues needed to maintain existing generation and to construct new generation at appropriate levels. In PJM, where the vast majority of Power’s generation is located, the PJM market monitor is seeking to tighten existing mitigation while generation interests are insisting that the current level of mitigation is excessive. Over the long-term, PSEG supports robust competitive markets that act as natural mitigation and send appropriate energy price signals.

In 2004, FERC is expected to finalize the Supply Margin Assessment (SMA) screen or some variation of the SMA as its interim generation market power screen which is one element of the comprehensive approach that FERC utilizes in evaluating whether an applicant may have market-based rate authority. FERC has also indicated that in 2004 it will revisit its approach to evaluate the competitiveness of markets and its approach to granting market-based rate authority. Currently, the SMA is not applied to market participants in RTOs/ISOs with approved market monitoring units. FERC has indicated that it is currently reconsidering this exemption. The effect of the adoption of the SMA screen should be positive for PSEG, as it is expected to encourage more regions to join RTOs/ISOs and will place strict limits on the potential for companies outside of RTOs/ISOs to abuse market power. To the extent that FERC eliminates the RTO/ISO exemption, there could be negative implications for Power resulting from additional mitigation measures that could be imposed on Power by the RTOs.

FERC Affiliate Standards

FERC’s current objectives are to scrutinize the activities of regulated entities, particularly these entities’ affiliate relationships and behavior in the electric wholesale market. In November 2003, FERC issued Order 2004, effective June 1, 2004, in which it adopted new Standards of Conduct that will apply uniformly to both interstate natural gas pipelines and electric public utilities, commonly referred to as transmission providers. PSE&G expects to be in compliance with this order.

Old Dominion Electric Cooperative (ODEC)

See Note 17. Commitments and Contingent Liabilities of the Notes.

Grid Reliability.

FERC recently announced its intention to develop and begin enforcing mandatory reliability standards prior to the 2004 summer peak demand period. The potential promulgation of mandatory reliability standards by FERC is not expected to have significant impact on PSEG.

Power

Nuclear Regulatory Commission (NRC)

Nuclear’s operation of nuclear generating facilities is subject to continuous regulation by the NRC, an independent agency established to regulate nuclear activities to ensure protection of public health and safety, as well as the security and protection of the environment. Such regulation involves testing, evaluation and modification of all aspects of plant operation in light of NRC safety and environmental requirements. Continuous demonstrations to the NRC that plant operations meet requirements are also necessary. The NRC has the ultimate authority to determine whether any nuclear generating unit may operate.

Exelon has informed Power that the application for operating license extensions for Peach Bottom 2 and 3 was approved by the NRC on May 7, 2003. The 20-year license extensions expire in 2033 for Unit 2 and 2034 for Unit 3. The licenses for Salem 1, Salem 2 and Hope Creek expire in 2016, 2020 and 2026, respectively.

The NRC has issued orders to all nuclear power plants to implement compensatory security measures. Some of the requirements formalize a series of security measures that licensees had taken in response to advisories issued by the NRC in the aftermath of the September 11, 2001 terrorist attacks. Nuclear has evaluated these orders for the Salem, Peach Bottom and Hope Creek facilities and does not expect the cost of implementation of the additional NRC measures to be material.

In 2002, the NRC issued a bulletin requiring that all operators of pressurized water reactor (PWR) nuclear units submit certain information related to potential degradation of reactor vessel heads. In September 2002, Nuclear provided the requested information for Salem to the NRC. Bare metal visual inspections for Salem 1 and 2 were completed during 2002 and 2003, respectively, and no degradation of the reactor heads was observed. In 2003, the NRC issued an order to all operators of PWR units concerning reactor vessel head inspections. The order confirms the previous bulletin’s requirements and adds more intrusive and frequent future inspections, which apply to Salem 1 and 2. If repairs are determined to be necessary, it is estimated that the repair would extend an outage by approximately four weeks. Nuclear plans to replace Salem 1 and 2 reactor heads in 2005 as a preventive maintenance measure.

Also in 2003, the NRC issued a bulletin requiring that all operators of PWR nuclear units also perform inspections of the reactor vessel lower head, due to leakage observed at another nuclear unit not owned by Power. Bare metal visual examinations were completed during Salem 2’s October 2003 outage and no degradation was observed. Examinations of Salem 1’s reactor vessel lower head will be performed during its Spring 2004 outage. Nuclear’s Hope Creek nuclear unit and Peach Bottom 2 and 3 are unaffected by either of these bulletins as they are boiling water reactor nuclear units. Power cannot predict what other actions the NRC may take on this issue. For additional information regarding NRC regulation, see Environmental Matters.

On January 28, 2004, the NRC issued a letter requesting Power to conduct a review of its Salem and Hope Creek facilities to assess the workplace environment for raising and addressing safety issues. The NRC’s letter requires a response by February 28, 2004. Power has initiated an in-depth self-assessment of the work environment at both facilities and will appropriately respond to the NRC.

For additional information, see also Note 17. Commitments and Contingent Liabilities of the Notes.

Other Regulatory Matters

PSEG, PSE&G, Power and Energy Holdings

Environmental

PSEG and its subsidiaries are also subject to the rules and regulations relating to environmental issues by the U.S. Environmental Protection Agency (EPA), the U.S. Department of Transportation (DOT), the U.S. Department of Energy (DOE) and other regulators. For information on environmental regulation, see Environmental Matters.

PSE&G

Investment Tax Credits (ITC)

For a discussion of an Internal Revenue Service (IRS) proposal that could have a material impact on PSE&G’s treatment of ITCs, see Note 17. Commitments and Contingent Liabilities of the Notes.

State Regulation

PSEG, PSE&G, Power and Energy Holdings

The BPU is a regulatory authority that oversees the electric and natural gas distribution companies in New Jersey. PSE&G is subject to comprehensive regulation by the BPU including, among other matters, regulation of retail electric and gas distribution rates and service and the issuance and sale of securities. Power’s partial ownership of nuclear generating facilities in Pennsylvania, as well as PSE&G’s ownership of certain transmission facilities in Pennsylvania, are subject to regulation by the Pennsylvania Public Utility Commission (PPUC), which oversees the electric and natural gas industries in the Commonwealth of Pennsylvania. PSE&G and Power are also subject to rules and regulations of the New Jersey Department of Environmental Protection (NJDEP) and the New Jersey Department of Transportation (NJDOT).

PSEG is not subject to direct regulation by the BPU, except potentially with respect to certain transfers of control and reporting requirements. Certain subsidiaries of PSEG, Power and Energy Holdings with operations in New Jersey may be subject to some regulation by the BPU, with respect to energy supply (BGS and BGSS), certain asset sales, transfers of control, reporting requirements and affiliate standards.

Various Power subsidiaries and Energy Holdings’ subsidiaries are subject to some state regulation in individual states where they operate facilities, including New York, Connecticut, Indiana, Ohio, Texas, California, Hawaii, New Hampshire and Pennsylvania.

Focused Audit

The BPU previously conducted a Focused Audit of the impact of PSEG’s non-utility businesses (those operated by Energy Holdings at the time of the Focused Audit) on PSE&G. Among other things, the BPU ordered that PSEG not permit Energy Holdings’ investments to exceed 20% of PSEG’s consolidated assets without prior notice to the BPU. In the Final Decision and Order (Final Order) issued in 1999, relating to PSE&G’s rate unbundling, stranded costs and restructuring proceedings, the BPU noted that, due to significant changes in the industry and, in particular PSEG’s corporate structure as a result of the Final Order, modifications to or relief from the BPU’s Focused Audit order might be warranted. PSE&G has notified the BPU that PSEG eliminated PSEG Capital Corporation (PSEG Capital) debt at the end of the second quarter of 2003 and that it believes the Final Order otherwise supercedes the requirements of the Focused Audit.

On December 31, 2003, the BPU requested all utilities in New Jersey, including PSE&G, to provide certain information related to corporate governance. The BPU has informally indicated that it intends to propose rules to regulate utility holding company relationships in 2004. While PSEG, PSE&G and Energy Holdings believe that this issue will be satisfactorily resolved, no assurances can be given.

BPU Affiliate Standards

PSE&G is required to file a compliance plan every two years with the BPU to demonstrate its compliance with the New Jersey Competitive Service and Affiliate Standards. In 2002, the BPU issued orders adopting the Competitive Service Audit reports on New Jersey’s electric and gas utilities. The audit reports generally concluded that PSE&G was in compliance with the BPU’s affiliate standards. PSE&G filed its compliance plan in accordance with the BPU’s regulations. Also in 2002, the BPU commenced its next regular audit of the state’s electric and gas utilities’ competitive activities. On April 22, 2003, the BPU issued for public comment the report of its consultant on the competitive services audit. The report concluded that PSE&G had implemented the recommendations from the BPU’s original order and was operating in compliance with the standards, with limited exceptions which PSE&G expects to be able to resolve in the ordinary course of business. The report raised some potential concerns about the impact on PSE&G from affiliate operations and proposed that the BPU ask for a demonstration that adequate steps will be taken to assure a continuing ability of PSE&G to gain access to the capital markets. The BPU has not issued a final order on the 2002 audit. PSE&G expects to submit another compliance plan in 2004 to address these matters. PSE&G does not expect an adverse outcome to this matter.

The New Jersey Ratepayer Advocate (RPA) requested the BPU to conduct a discovery process and hearings regarding the competitive services reports. Discovery was received from the RPA and PSE&G filed comments concerning the conclusions raised in the report. In response, the RPA filed comments requesting a ruling by the BPU. The objectives of these audits are to assure that neither the utilities nor their related competitive business segments enjoy an unfair competitive advantage over their competitors and to assure that there is no form of cross-subsidization of competitive services by utility operators or affiliates with which they are associated. The audits will be guided by the BPU’s Affiliate Standards requirements.

PSE&G

Electric Base Rate Case

In July 2003, PSE&G received an order from the BPU approving a proposed settlement of its electric base rate case with certain modifications. For additional information, see Item 7. MD&A—Overview of 2003 and Future Outlook.

Deferral Proceeding

In August 2002, PSE&G filed a petition proposing changes to two components of its rates: the Societal Benefits Clause (SBC) and the Non-Utility Generation Transition Charge (NTC). The case was transferred to the Office of Administrative Law (OAL) and a settlement was reached during the second quarter of 2003. On July 9, 2003 the BPU approved the settlement of the Deferral Proceeding resulting in the annual reduction of rates by approximately $238 million through the SBC and NTC.

Deferral Audit

In September 2002, the BPU retained the services of two outside firms to conduct a review of New Jersey’s electric utilities’ deferred costs for compliance with BPU mandates. Audit work has been completed and a final draft report was filed with the BPU on December 16, 2002, with PSEG responding on December 30, 2002. Formal comments on the final report were incorporated in the Deferral Proceedings, discussed above.

In October 2003, a second phase of the review commenced concentrating on deferred SBC, NTC and Market Transition Charge (MTC) balances for the twelve months ended July 31, 2003. Audit work has been completed and a draft report is expected to be filed with the BPU during the first quarter 2004. The outcome cannot be determined at this time.

Gas Base Rate Case

In January 2002, the BPU issued an order approving a settlement of PSE&G’s Gas Base Rate Case under which PSE&G is receiving an additional $90 million of gas base rate revenues, approximately $8 million of which results from gas depreciation rate changes. This occurred simultaneously with PSE&G’s implementation of its previously approved Gas Cost Underrecovery Adjustment (GCUA) surcharge to recover the October 31, 2001 gas cost underrecovery balance of approximately $130 million over a three-year period with interest and with PSE&G’s reduction of its 2001-2003 Commodity Charges by approximately $140 million. As a result of the settlement, PSE&G agreed not to request another gas base rate increase that would take effect prior to September 1, 2004.

Residential Natural Gas Supply

In December 2002, the BPU approved a revised statewide BGSS Commodity filing procedure. An annual filing will be made each year by June 1 for rate relief expected by October 1. That rate relief may be supplemented by two potential self-implementing rate increases to the maximum of 5% of the residential customer’s bill on December 1st and February 1st. In addition, companies may self-implement rate decreases at any time. All increases will be reconciled in the annual filing. PSE&G has implemented the following BGSS-RSG rate changes since January 2002:

January 16, 2003	7.4	%	increase	(Final June 20, 2003)
March 1, 2003.	5.0	%	increase	(Self-implementing)
September 1, 2003	7.2	%	increase	(Provisional)
January 1, 2004	4.3	%	decrease	(Self-implementing)

New Jersey Interim Clean Energy Program

The New Jersey Clean Energy Program was initiated by the BPU in 1999 through EDECA. In December 2003, the BPU ordered PSE&G to deposit funds associated with the 2004 Interim Clean Energy Program with a BPU-selected fiscal agent. The agent will disburse the funds to cover the Clean Energy Program costs as directed by the BPU Office of Clean Energy. PSE&G’s financial responsibility for the 2004 Interim Program has been identified by the BPU at $65 million for 2004, plus $46 million for PSE&G’s share of a carryover liability for 2001-2002. As a result, PSE&G has established a regulatory asset and corresponding liability to recognize the impact of the BPU’s December 2003 decision and the full recovery of all payments as provided by the order.

Remediation Adjustment Clause (RAC) Filing

In June 2003, PSE&G filed its RAC petition with the BPU for recovery of approximately $35 million for remediation costs incurred at PSE&G’s former Manufactured Gas Plant (MGP) sites. The costs cover the period from August 1, 2001 through July 31, 2002. On July 11, 2003, the case was transferred to the OAL for hearings. The parties to the case entered into a Stipulation of Settlement on December 16, 2003 to recover the entire $35 million. The Stipulation was filed with the OAL. The OAL is expected to issue a decision and forward it to the BPU for a Final Decision and Order. It is anticipated that a Final Decision and Order will be approved during the first quarter of 2004.

Universal Service Fund (USF)

In March 2003, the BPU approved the implementation of a permanent USF program. Amounts related to this program will be included in the SBC with deferred accounting treatment.

Foreign Regulation

Energy Holdings

Global

Global’s electric distribution facilities in Latin America are rate-regulated enterprises. Rates charged to customers are established by government authorities and are viewed by Global as currently sufficient to cover all operating costs and provide a return. Global can give no assurances that future rates will be established at levels sufficient to cover such costs, provide a return on its investments or generate adequate cash flow to pay principal and interest on its debt or to enable it to comply with the terms of its debt agreements.

Brazil

Rio Grande Energia S.A. (RGE) is regulated by Agencia Nacional de Energia Eletrica (ANEEL), the national regulatory authority. ANEEL’s functions include granting and supervising electric utility concessions, approving electricity tariffs, issuing regulations and auditing distribution systems’ performance. The rate setting process for Brazilian distribution companies has two components: an annual adjustment for which RGE applies every April and which is embedded in the concession contract and a rate case revision, which was conducted in 2003 and will be repeated again every fifth year. In April 2003, ANEEL approved a 36.07% tariff increase for RGE. Thirty-one percent of this increase became effective on April 16, 2003, with the balance effective in 2004. This rate increase is sufficient to maintain the current level of goodwill recorded at RGE.

In April 2004, RGE will apply for the annual rate case adjustment. Based on 2003 annual inflation and the 5% increase postponed since 2003, Global expects that RGE should be granted an 18% tariff increase.

In October 2003, the Brazilian Congress passed a law requesting the electric distribution companies (including RGE) to provide service connections to new low voltage customers without charging any fee for such connections. The law requires that the companies must develop a plan to connect every residential house that currently has no electricity service within the next five years. Although RGE should be compensated under the law for the costs of this program, implementation of this program may increase RGE’s capital expenditure budget.

Chile

Distribution companies in Chile, including Chilquinta Energia S.A. (Chilquinta) and Sociedad Austral de Electricidad S.A. (SAESA), are subject to rate regulation by the Comision Nacional de Energia (CNE), a national governmental regulatory authority. The Chilean regulatory framework has been in existence since 1982, with rates set every four years based on a model company. The tariff which distribution companies charge to regulated customers consists of two components: the actual cost of energy purchased plus an additional amount to compensate for the value added in distribution (DVA tariff). The DVA tariff considers allowed losses incurred in the distribution of electricity, administrative costs of providing service to customers, costs of maintaining and operating the distribution systems and an annual return on investment of 6% to 14%, based on the replacement cost of distribution assets. Changes in electricity distribution companies’ cost of energy are passed through to customers, with no impact on the distributors’ margins (equal to the DVA tariff). Therefore, distributors, including SAESA and Chilquinta, should not be affected by changes in the generation sector which affect prices.

The most recent tariff adjustments for SAESA and Chilquinta occurred in 2000. The next rate case is scheduled for 2004. The DVA tariff index provides for monthly adjustments based on variations in certain economic indicators whenever the component costs increase by more than 3% over prior levels. This index provides inflation adjustments and indirect partial devaluation protection. The CNE concluded a profitability review of Chilean distribution companies in January 2002, with no resulting adverse effects to SAESA or Chilquinta’s tariff rates. The CNE is in the process of conducting its

annual profitability reviews, similar to the one completed in 2002, which may result in material adverse effects on tariffs for SAESA and/or Chilquinta.

Peru

Distribution companies in Peru, including Global’s facility, Luz del Sur S.A.A. (LDS), are subject to rate regulation by a national government regulatory authority. The Peruvian rate setting mechanism was established in 1992 and is similar to the Chilean system described above, except that rates of return are between 8% and 16%. Rates are set every four years. LDS’s latest rate case was completed in 2001. The next regularly scheduled rate setting for LDS is in 2005

SEGMENT INFORMATION

Financial information with respect to the business segments of PSEG, PSE&G, Power and Energy Holdings is set forth in Note 23. Financial Information by Business Segments of the Notes.

ENVIRONMENTAL MATTERS

PSEG, PSE&G, Power and Energy Holdings

Federal, regional, state and local authorities regulate the environmental impacts of PSEG’s operations within the U.S. Laws and regulations particular to the region, country, or locality where these operations are located govern environmental impacts associated with PSEG’s operations in foreign countries. For both domestic and foreign operations, areas of regulation may include air quality, water quality, site remediation, land use, waste disposal, aesthetics, impact on global climate and other matters.

To the extent that environmental requirements are more stringent and compliance more costly in certain states where PSEG operates compared to other states that are part of the same market, such rules may impact its ability to compete within that market. Due to evolving environmental regulations, it is difficult to project expected costs of compliance and its impact on competition. For additional information related to environmental matters, see Item 3. Legal Proceedings.

PSEG, Power and Energy Holdings

Air Pollution Control

The Federal Clean Air Act (CAA) and its implementing regulations require controls of emissions from sources of air pollution and also impose record keeping, reporting and permit requirements. Facilities in the U.S. that Power and Energy Holdings operate or in which they have an ownership interest are subject to these Federal requirements, as well as requirements established under state and local air pollution laws applicable where those facilities are located. Except as noted below, capital costs of complying with air pollution control requirements through 2005 are included in Power’s estimate of construction expenditures in Item 7. MD&A—Capital Requirements.

Prevention of Significant Deterioration (PSD)/New Source Review (NSR)

For a discussion of PSD/NSR, see Note 17. Commitments and Contingent Liabilities of the Notes.

Sulfur Dioxide (SO2 )/Nitrogen Oxide (NOx )

To reduce emissions of SO2 the CAA sets a cap on total SO2 emissions from affected units and allocates SO2 allowances (each allowance authorizes the emission of one ton of SO2) to those units. Generation units with emissions greater than their allocations can obtain allowances from sources that have excess allowances. Similarly, to reduce emissions of NOx, Northeastern states and the District of Columbia have set a cap on total emissions of NOx from affected units and allocated NOx allowances (with each allowance authorizing the emission of one ton of NOx) to those units. The NOxcap applies from May through September of each year. The NOx allowances can be bought and sold through a

regional trading program. To comply with the SO2 and NOx requirements, affected units may choose one or more strategies, including installing air pollution control technologies, changing or limiting operations, changing fuels or obtaining additional allowances. At this time, Power does not expect to incur material expenditures to continue complying with the SO2 program. Beginning in 2003, the NOx cap was reduced in New Jersey, New York, Pennsylvania, Connecticut and other Northeastern states, which is expected to materially increase the cost of complying with the NOx program in those states. The extent of the increase across the region will depend upon a number of factors that may increase or decrease total NOx emissions from affected units, thus increasing or decreasing demand for a fixed supply of allowances. Power has been implementing measures to reduce NOx emissions at several of its units, which should reduce the impact of any further increases to the costs of allowances. For additional information regarding the costs of these allowances, see Item 7. MD&A—Future Outlook.

The EPA has issued regulations (commonly known as the NOx State Implementation Plan (SIP) Call) requiring the 22 states in the eastern half of the U.S. and the District of Columbia to reduce and cap NOx emissions from power plant and industrial sources. This cap applies from May through September of each year. Although the EPA has delayed the implementation until May 31, 2004, the NOx reduction requirements are consistent with requirements already in place in New Jersey, New York, Connecticut and Pennsylvania, and therefore are not likely to have an additional impact on or change the capacity available from Power’s existing facilities. Beginning May 31, 2004, new facilities that Power has developed in Ohio and is developing in Indiana will be subject to rules that those states have promulgated to comply with the NOx SIP Call. Because the rules in Ohio and Indiana both set aside allowances for allocation to new sources, Power does not anticipate any material adverse effects from complying with this program in these states.

In 1997, the EPA adopted a new air quality standard for fine particulate matter and a revised air quality standard for ozone. In 2002, the EPA announced that it would move forward with the process for identifying and designating areas of the U.S. that fail to meet the revised federal health standard for ozone or the new federal health standard for fine particulates. Designation of these areas is expected in 2004, with states expected to develop regulatory measures necessary to achieve and maintain the health standards. States may require reductions in NOx and SO2 to attain these standards. Additional NOx and SO2 reductions also may be required to satisfy requirements of an EPA rule protecting visibility in many of the nation’s scenic areas, including some areas near Power’s facilities. Power cannot at this time determine whether any costs it may incur to comply with these standards would be material.

In December 2003, the EPA announced its intent to propose an Interstate Air Quality Rule (IAQR) that would identify 29 states and the District of Columbia as contributing significantly to the levels of fine particulates and/or 8-hour ozone in downwind states. New Jersey, New York, Pennsylvania and Connecticut are among the states EPA lists in the proposed IAQR. Based on state obligations to address interstate transport of pollutants under the CAA, the EPA is proposing a two-phased emission reduction program for SO2 and NOx, with Phase 1 beginning in 2010 and Phase 2 beginning in 2015. The EPA is recommending that the program be implemented through a cap-and-trade program, although states are not required to proceed in this manner. The EPA has stated its intent to finalize the IAQR during 2004. States would have to submit plans to the EPA for complying with the rule within 18 months of publication of the notice of final rulemaking. Power cannot at this time determine whether any costs it may incur to comply with these standards would be material.

Carbon Dioxide (CO2) Emissions

When effective, it is expected that the Kyoto Protocol will require material reductions of CO2 and certain other greenhouse gases between 2008 and 2012. Although the U.S. has indicated that it does not intend to ratify the treaty, Energy Holdings’ assets in Europe will be affected by implementation of the Kyoto Protocol, although the specific impacts will depend upon the regulations adopted by the European Union (EU) and nations looking to accede to the EU, such as Poland. The outcome of this rulemaking and its impact upon Energy Holdings cannot be predicted.

In 2002, Power announced a voluntary agreement that calls for a goal of reducing the annual average CO2 emission rate of its fossil fuel fired electric generating units by 15% below the 1990 average annual CO2 emission rate of its New Jersey fossil fuel fired electric generating units by

December 31, 2005. Fossil also made a $1.5 million payment to the NJDEP to assist in the development of landfill gas projects and is required to make an additional payment equal to $1 per ton of CO2 emitted greater than the 15% goal, up to $1.5 million, if that reduction is not achieved.

PSEG joined the EPA Climate Leaders Program as a charter member in February 2002. On January 13, 2004, PSEG announced a voluntary goal to cut its domestic CO2 emissions rate 18% from 2000 levels by January 1, 2009. The establishment of this target reaffirms PSEG’s participation in the EPA Climate Leaders Program.

There continues to be a debate within the U.S. over the direction of domestic climate change policy. Several states, primarily in the Northeastern U.S., are considering state-specific or regional legislation initiatives to stimulate CO2 emission reductions in the electric power industry. For example, New York initiated the Regional Greenhouse Gas Initiative (RGGI) in April 2003. Currently, nine Northeastern states are participating in discussions intended to lead to a regional program to cap CO2 emissions from the electric power sector in the region. The outcome of this initiative cannot be determined at this time, however, adoption of stringent CO2 emission reduction requirements in the Northeast could materially impact Power’s operations in the Northeast.

Other Air Pollutants

The CAA directed the EPA to study potential public health impacts of hazardous air pollutants (HAP) emitted from electric utility steam generating units. In December 2000, the EPA announced its intent to regulate HAP emissions from coal-fired and oil-fired steam units and to develop Maximum Achievable Control Technology (MACT) standards for these units. The EPA proposed the MACT standards in December 2003 and expects to promulgate a final rule by December 2004, with compliance to be required by December 2007. PSEG is evaluating the potential impact of these proposed standards.

The EPA announced in December 2003 its intent to propose alternative rules for addressing emissions of mercury from electric generating sources. The first alternative proposes to regulate mercury through the establishment of a MACT standard applicable on a unit-by-unit basis or through a cap and trade program. The MACT standard would establish mercury emission limits for all new and existing units and reduce nationwide mercury emissions by approximately 29% by December 2007. The second option requires the EPA to rescind its December 2000 announcement to regulate mercury as a HAP through a MACT standard and to regulate mercury through a cap and trade program to be implemented by changes to the states’ individual SIPs that establish decreasing emission caps in 2010 and 2018. As part of the December 15, 2003 proposal, the EPA is also proposing to set nickel MACT emission limits for oil-fired electric steam generating units.

Connecticut has already adopted standards for the reduction of emissions of mercury from coal-fired electric generating units and New Jersey has proposed similar regulations. On January 5, 2004, the NJDEP issued draft regulations that would restrict emissions of mercury from coal fueled power plants. The draft rule recognizes multi-pollutant reduction agreements reached between NJDEP and private parties. Power has reached an agreement with the NJDEP in the level of mercury emissions from its coal plants as a result of a consent that resolved issues of PSD and NSR at the Hudson, Mercer and Bergen facilities. These regulations are expected to be finalized during 2004. The impact on Power’s operations of Federal or state regulation of these emissions is still unknown.

Water Pollution Control

The Federal Water Pollution Control Act (FWPCA) prohibits the discharge of pollutants to waters of the U.S. from point sources, except pursuant to a National Pollutant Discharge Elimination System (NPDES) permit issued by the EPA or by a state under a federally authorized state program. The FWPCA authorizes the imposition of technology-based and water quality-based effluent limits to regulate the discharge of pollutants into surface waters and ground waters. The EPA has delegated authority to a number of state agencies, including the NJDEP, to administer the NPDES program through state acts. The New Jersey Water Pollution Control Act (NJWPCA) authorizes the NJDEP to implement regulations and to administer the NPDES program with EPA oversight, and to issue and enforce New Jersey Pollutant Discharge Elimination System (NJPDES) permits. Power and Energy

Holdings also have ownership interests in domestic facilities in other jurisdictions that have their own laws and implement regulations to regulate discharges to their surface waters and ground waters that directly regulate Power’s or Energy Holdings’ facilities in these jurisdictions.

The EPA is conducting a rulemaking under 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 Power currently has under construction or in development is subject to the Phase I rule. A decision issued in February 2004, by the U.S. Court of Appeals for the Second Circuit in the litigation challenging Phase I of the rule struck down that rule’s provision allowing for the use of restoration measures to the specified performance standard and upheld EPA’s consideration of numbers of organisms killed or injured in cooling water systems in determining whether the system has caused an adverse environmental impact. These two determinations, if applied to Phase II of the rulemaking, could have a material impact on Power’s ability to renew its NPDES permits at its larger once-through cooled plants without significant upgrades to their existing intake structures and cooling systems.

The EPA signed the Phase II rules covering large existing power plants on February 16, 2004. The regulations provide the following five alternative methods by which a facility can demonstrate that it complies with the requirement for best technology available for minimizing adverse environmental impacts associated with cooling water intake structures: (1) reduce flow commensurate with a closed-cycle system or reduce intake velocity; (2) meet applicable performance standards for reduction of entrainment and impingement through the use of the existing design, construction, operational or restoration measures; (3) meet applicable performance standards through a combination of existing and proposed design, construction, operational or restoration measures; (4) installation of a design and construction technology specified by the regulation or pre-approved by the agency; and (5) a site-specific determination that the cost to the facility to meet the performance standards is “significantly greater” than either (a) the costs that EPA estimated for that type of facility or (b) the environmental benefits of complying with the performance standards. Although the rule applies to all of Power’s electric generating units that use surface waters for once-through cooling purposes, the impact of the rule to Power and the rule’s ability to withstand anticipated legal challenges cannot be determined at this time. If application of the Phase II rules requires the retrofitting of cooling water intake structures at Power’s existing facilities, additional material capital expenditures could be required to modify the existing plants to enable their continued operations.

PSE&G and Power

Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and New Jersey Spill Compensation and Control Act (Spill Act)

CERCLA and the Spill Act authorize Federal and state trustees for natural resources to assess damages against persons who have discharged a hazardous substance, causing an injury to natural resources. Pursuant to the Spill Act, the NJDEP requires persons conducting remediation to characterize injuries to natural resources and to address those injuries through restoration or damages. In 2003, the NJDEP issued a policy directive memorializing its efforts to recover natural resource damages and its intent to continue to pursue the recovery of natural resource damages. The NJDEP also issued guidance to assist parties in calculating their natural resource damage liability for settlement purposes, but has stated that those calculations are applicable only for those parties that volunteer to settle a claim for natural resource damages before a claim is asserted by the NJDEP. PSE&G and Power cannot assess the magnitude of the potential impact of this regulatory change. The financial impact of this development is not currently estimable, however, these costs could be material.

Because of the nature of PSE&G’s and Power’s respective businesses, including the production and delivery of electricity, the distribution of gas and, formerly, the manufacture of gas, various by-products and substances are or were produced or handled that contain constituents classified by Federal and state authorities as hazardous. For discussions of these hazardous substance issues and a discussion of potential liability for remedial action regarding the Passaic River, see Note 17. Commitments and

Contingent Liabilities of the Notes. For a discussion of remediation/clean-up actions involving PSE&G and Power, see Item 3. Legal Proceedings.

Hazardous Waste

The NJDEP adopted regulations concerning site investigation and remediation that require an ecological evaluation of potential damages to natural resources in connection with an environmental investigation of contaminated sites. See Note 17. Commitments and Contingent Liabilities of the Notes for further discussion of this issue.

Uranium Enrichment Decontamination and Decommissioning Fund

In accordance with the Energy Policy Act (EPAct), domestic entities that own nuclear generating stations are required to pay into a decontamination and decommissioning fund, based on their past purchases of U.S. government enrichment services. Since these amounts are being collected from PSE&G’s customers over a period of 15 years, this obligation remained with PSE&G following the generation asset transfer to Power in 2000. PSE&G’s obligation for the nuclear generating stations in which it had an interest was $80 million (adjusted for inflation). As of December 31, 2003, PSE&G had paid $63 million, resulting in a balance due of $17 million. As of December 31, 2003, Power also had a balance due of approximately $4 million, which related to interests in certain nuclear units it purchased. This amount is payable to the DOE in annual installments through October 2006.

Power

Permit Renewals

In June 2001, the NJDEP issued a renewed NJPDES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water system.

The consultant hired by NJDEP to review the NJPDES permit renewal application for Power’s Hudson station recommended that the Hudson station be retrofitted to operate with closed cycle cooling to address alleged adverse impacts associated with the thermal discharge and intake structure. Power proposed certain modifications to the intake structure and resubmitted these modifications to the NJDEP in 1998. In the second quarter of 2003, Power received a NJDES permit for its Hudson generating station, that required the modification to the intake structures that Power had proposed, but did not require Power to retrofit the station to operate with closed cycle cooling.

The NJDEP has advised Power that it is reviewing a NJPDES permit renewal application for the Mercer station and, in connection with that renewal, will be reexamining the effects of the Mercer station’s cooling water system pursuant to FWPCA. Power has submitted to the NJDEP a renewal application that proposes certain modifications to the cooling water system.

Power cannot predict the timing and/or outcome of the review of the application for the Mercer generation station. An unfavorable outcome could have a material adverse effect on Power’s financial position, results of operations and net cash flows. Capital costs of complying with water pollution control requirements are included in Power’s estimate of construction expenditures in Item 7. MD&A—Capital Requirements.

Nuclear Fuel Disposal

For a discussion of nuclear fuel disposal, see Note 17. Commitments and Contingencies of the Notes.

Low Level Radioactive Waste (LLRW)

As a by-product of their operations, nuclear generation units produce LLRW. Such wastes include paper, plastics, protective clothing, water purification materials and other materials. LLRW materials are accumulated on site and disposed of at licensed permanent disposal facilities. New Jersey, Connecticut and South Carolina have formed the Atlantic Compact, which gives New Jersey nuclear

generators, including Power, continued access to the Barnwell LLRW disposal facility which is owned by South Carolina. Power believes that the Atlantic Compact will provide for adequate LLRW disposal for Salem and Hope Creek through the end of their current licenses, although no assurances can be given. Both Power and Exelon have on-site LLRW storage facilities for Salem, Hope Creek and Peach Bottom, which have the capacity for at least five years of temporary storage for each facility.

PSE&G

Spill Prevention Control and Countermeasure (SPCC)

In 1998, PSE&G evaluated SPCC Plan compliance at all of its substations and identified certain deficiencies. The necessary upgrades are being made and the costs of these upgrades are not expected to be material over the next several years. In July 2002, the EPA amended its SPCC regulations to, among other things, confirm the regulations’ applicability to oil-filled electrical equipment.

MGP

For information regarding PSE&G’s MGP, see Note 17. Commitments and Contingent Liabilities of the Notes.

ITEM 2.

PROPERTIES

PSEG

PSEG does not own any property. All property is owned by its subsidiaries.

Services leases substantially all of a 25-story office tower for PSEG’s corporate headquarters at 80 Park Plaza, Newark, New Jersey, together with an adjoining three-story building.

PSE&G

PSE&G’s First and Refunding Mortgage (Mortgage), securing the bonds issued thereunder, constitutes a direct first mortgage lien on substantially all of PSE&G’s property.

PSE&G’s electric lines and gas mains are located over or under public highways, streets, alleys or lands, except where they are located over or under property owned by PSE&G or occupied by it under easements or other rights. These easements and other rights are deemed by PSE&G to be adequate for the purposes for which they are being used.

PSE&G believes that it maintains adequate insurance coverage against loss or damage to its principal properties, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost.

Electric Transmission and Distribution Properties

As of December 31, 2003, PSE&G’s transmission and distribution system included approximately 21,361 circuit miles, of which approximately 7,294 circuit miles were underground, and approximately 786,980 poles, of which approximately 536,236 poles were jointly owned. Approximately 99% of this property is located in New Jersey.

In addition, as of December 31, 2003, PSE&G owned five electric distribution headquarters and four subheadquarters in four operating divisions, all located in New Jersey.

Gas Distribution Properties

As of December 31, 2003, the daily gas capacity of PSE&G’s 100%-owned peaking facilities (the maximum daily gas delivery available during the three peak winter months) consisted of liquid petroleum air gas (LPG) and liquefied natural gas (LNG) and aggregated 2,973,000 therms (approximately 2,886,000 cubic feet on an equivalent basis of 1,030 Btu/cubic foot) as shown in the following table:

Plant	Location	Daily Capacity (Therms)

Burlington LNG	Burlington, NJ		773,000
Camden LPG	Camden, NJ		280,000
Central LPG	Edison Twp., NJ		960,000
Harrison LPG	Harrison, NJ		960,000
Total			2,973,000

As of December 31, 2003, PSE&G owned and operated approximately 16,932 miles of gas mains, owned 12 gas distribution headquarters and two subheadquarters, all in two operating regions located in New Jersey and owned one meter shop in New Jersey serving all such areas. In addition, PSE&G operated 61 natural gas metering or regulating stations, all located in New Jersey, of which 28 were located on land owned by customers or natural gas pipeline suppliers and were operated under lease, easement or other similar arrangement. In some instances, the pipeline companies owned portions of the metering and regulating facilities.

Office Buildings and Facilities

PSE&G rents office space from Services as its headquarters in Newark, New Jersey. PSE&G also leases office space at various locations throughout New Jersey for district offices and offices for various corporate groups and services. PSE&G also owns various other sites for training, testing, parking, records storage, research, repair and maintenance, warehouse facilities and for other purposes related to its business.

In addition to the facilities discussed above, as of December 31, 2003, PSE&G owned 41 switching stations in New Jersey with an aggregate installed capacity of 21,079 megavolt-amperes and 241 substations with an aggregate installed capacity of 7,584 megavolt-amperes. In addition, four substations in New Jersey having an aggregate installed capacity of 122 megavolt-amperes were operated on leased property.

Power

Power rents office space from Services as its headquarters in Newark, New Jersey. Other leased properties include office, warehouse, classroom and storage space, primarily in New Jersey, used for system maintenance, procurement and materials management staff, training and storage.

Through a subsidiary, Power owns a 57.41% interest in approximately 12,000 acres of restored wetlands and conservation facilities in the Delaware River Estuary that was formed to acquire and own lands and other conservation facilities required to satisfy the condition of the NJPDES permit issued for Salem. Power also owns several other facilities, including the on-site Nuclear Administration and Processing Center buildings.

Power has a 13.91% ownership interest in the 650-acre Merrill Creek Reservoir in Warren County, New Jersey and approximately 200 acres of land surrounding the reservoir. The reservoir was constructed to store water for release to the Delaware River during periods of low flow. Merrill Creek is jointly owned by seven companies that have generation facilities along the Delaware River or its tributaries and use the river water in their operations. Power owned the Maplewood Test Services in Maplewood, New Jersey and owns the Central Maintenance Shop at Sewaren, New Jersey. The Maplewood Test Services in Maplewood, New Jersey was transferred to Services at book value in January 2004.

Power believes that it maintains adequate insurance coverage against loss or damage to its plants and properties, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost. For a discussion of nuclear insurance, see Note 17. Commitments and Contingent Liabilities of the Notes.

As of December 31, 2003, Power's share of installed generating capacity was 13,751 MW, as shown in the following table:

OPERATING POWER PLANTS

Name	Location		Total Capacity (MW)		% Owned			Owned Capacity (MW)		Principal Fuels Used	Mission
Steam:
Hudson		NJ		991		100	%		991	Coal/Gas	Load Following
Mercer		NJ		648		100	%		648	Coal/Gas	Load Following
Sewaren		NJ		453		100	%		453	Gas/Oil	Load Following
Linden(F)		NJ		430		100	%		430	Oil	Load Following
Keystone(A)(B)		PA		1,700		23	%		388	Coal	Base Load
Conemaugh(A)(B)		PA		1,700		23	%		382	Coal	Base Load
Kearny		NJ		300		100	%		300	Oil	Load Following
Albany(F)		NY		376		100	%		376	Gas/Oil	Load Following
Bridgeport Harbor		CT		525		100	%		525	Coal/Oil	Base Load
New Haven Harbor		CT		455		100	%		455	Oil/Gas	Load Following
Total Steam				7,578					4,948
Nuclear:
Hope Creek		NJ		1,049		100	%		1,049	Nuclear	Base Load
Salem 1 & 2(A)		NJ		2,236		57	%		1,284	Nuclear	Base Load
Peach Bottom 2 & 3(A)(C)		PA		2,224		50	%		1,112	Nuclear	Base Load
Total Nuclear				5,509					3,445
Combined Cycle:
Bergen		NJ		1,221		100	%		1,221	Gas/Oil	Load Following
Burlington(F)		NJ		245		100	%		245	Gas/Oil	Load Following
Waterford		OH		821		100	%		821	Gas	Load Following
Total Combined Cycle				2,287					2,287

Combustion Turbine:
Essex		NJ		617		100	%		617	Gas/Oil	Peaking
Edison		NJ		504		100	%		504	Gas/Oil	Peaking
Kearny		NJ		443		100	%		443	Gas/Oil	Peaking
Burlington		NJ		557		100	%		557	Gas/Oil	Peaking
Linden		NJ		324		100	%		324	Gas/Oil	Peaking
Mercer		NJ		129		100	%		129	Oil	Peaking
Sewaren		NJ		129		100	%		129	Oil	Peaking
Bayonne		NJ		42		100	%		42	Oil	Peaking
Bergen		NJ		21		100	%		21	Gas	Peaking
National Park		NJ		21		100	%		21	Oil	Peaking
Kearny		NJ		21		100	%		21	Gas	Peaking
Linden(F)		NJ		21		100	%		21	Gas/Oil	Peaking
Salem(A)		NJ		38		57	%		22	Oil	Peaking
Bridgeport Harbor		CT		15		100	%		15	Oil	Peaking
Total Combustion Turbine				2,882					2,866

Internal Combustion:
Conemaugh(A)(B)		PA		11		23	%		2	Oil	Peaking
Keystone(A)(B)		PA		11		23	%		3	Oil	Peaking
Total Internal Combustion				22					5

Pumped Storage:
Yards Creek(A)(D)(E)		NJ		400		50	%		200		Peaking
Total Operating Generation Plants				18,678					13,751

______________

(A)

Power’s share of jointly owned facility

(B)

Operated by Reliant Energy

(C)

Operated by Exelon

(D)

Operated by Jersey Central Power & Light Company

(E)

Excludes energy for pumping and synchronous condensers

(F)

These assets are scheduled for retirement within the next five years, partially dependent upon new generation going into service discussed below. The 245 MW Burlington 10 unit was retired in early 2004.

As of December 31, 2003, Power had 3,268 MW of generating capacity in construction or advanced development, as shown in the following table:

POWER PLANTS IN CONSTRUCTION OR ADVANCED DEVELOPMENT

Name	Location	Total Capacity (MW)		% Owned	Owned Capacity (MW)		Principal Fuels Used	Scheduled In Service Date
Combined Cycle:
Bethlehem	NY		763	100%		763	Gas	2005
Lawrenceburg	IN		1,096	100%		1,096	Gas	2004
Linden	NJ		1,220	100%		1,220	Gas	2005
Total Construction			3,079			3,079
Nuclear Uprates:	NJ/PA		233	Various		189	Nuclear	2004-2008
Total Advanced Development			233			189

Projected Capacity (2004-2008)	Total Owned Capacity (MW)
Total Owned Operating Generating Plants		13,751
Under Construction		3,079
Advanced Development		189
Less: Planned Retirements		(1,072	)
Projected Capacity		15,947

Energy Holdings

Energy Holdings rents office space from Services as its headquarters in Newark, New Jersey. Energy Holdings’ subsidiaries also lease office space at various locations throughout the world to support business activities.

Energy Holdings believes that it maintains adequate insurance coverage for properties in which its subsidiaries have an equity interest, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost.

Global has invested in the following generation facilities, which are in operation or under construction as of December 31, 2003:

OPERATING POWER PLANTS

Name	Location	Total Capacity (MW)		% Owned	Owned Capacity (MW)		Principal Fuels Used
United States
Texas Independent Energy, L.P. (TIE)
Guadalupe	TX		1,000	50%		500	Natural gas
Odessa	TX		1,000	50%		500	Natural gas
Total TIE			2,000			1,000
Kalaeloa	HI		180	50%		90	Oil
GWF
Bay Area I	CA		21	50%		10	Petroleum coke
Bay Area II	CA		21	50%		10	Petroleum coke
Bay Area III	CA		21	50%		10	Petroleum coke
Bay Area IV	CA		21	50%		10	Petroleum coke
Bay Area V	CA		21	50%		10	Petroleum coke
Hanford	CA		27	50%		14	Petroleum coke
Tracy	CA		21	35%		7	Biomass
Total GWF			153			71
GWF Energy
Hanford—Peaker Plant	CA		95	75%		71	Natural gas
Henrietta—Peaker Plant	CA		97	75%		73	Natural gas
Tracy—Peaker Plant	CA		171	75%		128	Natural gas
Total GWF Energy			363			272
SEGS III	CA		30	9%		3	Solar
Bridgewater	NH		16	40%		6	Biomass
Conemaugh	PA		15	50%		8	Hydro
Total United States:			2,757			1,450
International
MPC
Jingyuan—Units 5 & 6	China		600	15%		90	Coal
Tongzhou	China		30	40%		12	Coal
Nantong	China		30	46%		14	Coal
Jinqiao (Thermal Energy)	China		N/A	30%		N/A	Coal/Oil
Zuojiang—Units 1, 2 & 3	China		72	30%		22	Hydro
Fushi—Units 1, 2 & 3	China		54	35%		19	Hydro
Shanghai BFG	China		50	33%		16	Blast furnace gas
Haian (Thermal Energy)	China		N/A	100%		N/A	Coal
Huangshi Unit I	China		100	25%		25	Coal
Hexie	China		98	50%		49	Natural gas
Mianyang—Units 1	China		15	38%		6	Hydro
Qujing—Phases II—Unit 3	China		900	19%		167	Coal
Kuo Kuang	Taiwan		465	18%		84	Natural gas
Total MPC			2,414			504
PPN	India		330	20%		66	Naphtha/Natural gas
Prisma
Crotone	Italy		20	25%		5	Biomass
Bando D’Argenta I	Italy		30	50%		15	Biomass
Strongoli	Italy		40	25%		10	Biomass
Total Prisma			90			30
Electroandes	Peru		183	100%		183	Hydro
Skawina CHP	Poland		590	63%		372	Coal
Elcho	Poland		220	90%		198	Coal
Turboven
Maracay	Venezuela		60	50%		30	Natural gas
Cagua	Venezuela		60	50%		30	Natural gas
Total Turboven			120			60
TGM	Venezuela		40	9%		4	Natural gas
Rades	Tunisia		471	60%		283	Natural gas
Salalah	Oman		240	81%		194	Natural gas
SAESA Group	Chile		30	100%		30
Total International:			4,728			1,924
Total Operating Power Plants:			7,485			3,374

Global has invested in the following generation facilities which are under construction as of December 31, 2003:

POWER PLANTS IN CONSTRUCTION

Name	Location	Total Capacity (MW)		% Owned	Owned Capacity (MW)		Principal Fuels Used	Scheduled In Service Date
International
MPC
Haian—Phase II	China		30	50%		15	Coal	2005
Huangshi Phase II	China		660	25%		165	Coal	2006
Mianyang—Units 2 & 3	China		30	38%		11	Hydro	2004
Nantong Phase II	China		15	46%		7	Coal	2004
Qujing—Phases II—Unit 4	China		300	18%		55	Coal	2004
Yulchon	South Korea		612	50%		306	Natural Gas	2005
Total Construction:			1,647			559
TOTAL GENERATION FACILITIES:			9,132			3,933

Domestic Generation In Operation

TIE

Global and its partner, TECO Energy Inc. (Teco), own and operate two electric generation facilities in Guadalupe County in south central Texas (Guadalupe) and Odessa in western Texas (Odessa) through TIE, a 50/50 joint venture. In January 2003, Panda Energy International, Inc. (Panda) indirectly transferred 50% of its interest in TIE to Teco. In September 2003, Panda indirectly transferred its remaining interest in TIE to Teco.

Approximately 31% of the Guadalupe plant’s total capacity for 2004 has been sold via bilateral power purchase agreements. Guadalupe and Odessa continue to enter into forward contracts on an ongoing basis. Approximately 32% of the Odessa plant’s total capacity for 2004 has been sold via bilateral power purchase agreements. To access the spot market more effectively, in 2003 TIE entered into an asset management agreement. Any remaining uncommitted output is sold in the Texas spot market. For a discussion of the Texas power market, see Item 3. Legal Proceedings and Item 7. MD&A—Future Outlook.

Kalaeloa

Global’s partner in Kalaeloa is a power fund managed by Harbert Power Corporation (Harbert). All of the electricity generated by the Kalaeloa power plant is sold to the Hawaiian Electric Company, Inc. under a power purchase contract expiring in May 2016, Under a steam purchase and sale agreement expiring in May 2016, the Kalaeloa power plant supplies steam to the adjacent Tesoro refinery. The primary fuel of low sulfur waxy residue fuel oil is provided from the adjacent Tesoro refinery under a long-term all requirements contract. The refinery is interconnected to the power plant by a pipeline and preconditions the fuel oil prior to delivery. Back-up fuel supply is provided by the electric generation off-taker, Hawaiian Electric Company, Inc.

GWF Power Systems LP (GWF) and Hanford LP (Hanford)

Global and Harbert each own 50% of the GWF plants. Power purchase contracts for the plants’ net output are in place with Pacific Gas and Electric Company (PG&E) ending in 2020 and 2021. GWF acquires the petroleum coke used to fuel its plants through contracts with two local oil refineries with price and minimum volumes being negotiated annually. Three of the five GWF plants have been modified to burn a wider variety of petroleum coke products to mitigate fuel supply and pricing risk.

Global and Harbert each own 50% of Hanford. A power purchase contract for the plant’s net output is in place with PG&E ending in August 2011. Hanford acquires its delayed petroleum coke from the Bakersfield Refinery, which is scheduled to be closed in October 2004. Hanford is testing quality and firing characteristics of alternate sourced delayed petroleum coke to be in position to transition to new fuel suppliers.

Hanford, Henrietta and Tracy Peaker Plants

GWF Energy LLC (GWF Energy), which is jointly owned by Global and Harbinger GWF LLC (Harbinger), an affiliate of Harbert, owns and operates three peaker plants in California, including the Tracy Peaker Plant, a 171 MW facility that completed construction and achieved commercial operation in the second quarter of 2003. The output of these plants are sold under GWF Energy’s power purchase agreement with the California Department of Water Resources (DWR) with maturities in 2011 and 2012. As of December 31, 2003, Global’s ownership interest in this project was 74.9%. See Note 17. Commitments and Contingent Liabilities of the Notes for a reduction of Global’s ownership percentage to 60%. DWR has the right to schedule energy and/or reserve capacity from each unit of the three plants for a maximum of 2,000 hours each year. Energy and capacity not scheduled by the DWR is available for sale by GWF Energy. GWF Energy’s gas-fired power plants obtain their natural gas from the spot market on a non-firm basis. Natural gas fuel is purchased from the spot market with DWR taking the price and availability risk.

For further information, see Note 17. Commitments and Contingent Liabilities of the Notes.

International Generation in Operation

China and Taiwan

Meiya Power Company Limited (MPC)

Global’s activities in China and surrounding countries are conducted through MPC, a joint venture with the Asian Infrastructure Fund (AIF) and Hydro Quebec International (HQI).

MPC is focused on developing, acquiring, owning and operating electric and thermal heat generation facilities in China, South Korea and Taiwan. MPC seeks to structure long-term power purchase contracts with its customers and to incorporate take-or-pay and minimum take provisions to support debt service and a specified equity return. Pricing terms for energy from its facilities generally include a base price and indexed adjustments to compensate for changes in inflation, foreign currency exchange rates up to the minimum equity return and laws affecting taxes, fees and required reserves. The following seven electric generation plants operate in this long term power purchase contract environment: Fushi, Zhoujiang, Shanghai BFG, Huangshi Phase II, and Jingyuan in China; Kuo Kuang in Taiwan (except no currency exchange rate indication in tariff), and Yulchon in South Korea (except no currency exchange indication in tariff). For cogeneration facilities, instead of selling the electricity through long-term power purchase contracts, MPC sells its output through the regulatory tariff based on the general pricing principles set out in the Chinese Electric Power Law which allows the generator to recover its cost and a reasonable return. As part of the regulatory tariff process, priority dispatch is given to cogenerations plant when the annually determined production quota is fixed in accordance with a pre-determined formula which essentially determines the amount of electricity to be sold by reference to the amount of steam generated by the cogeneration facilities. The two cogeneration plants in Tongzhou and Nantong operate under this system. Haian Phase II and Nantong Phase II under construction will also operate under this system when the respective cogeneration facilities are completed. Four (4) additional electric generation plants will operate on the regulatory tariff based on the general pricing principles set out in the Chinese Electric Power Law as described above. Each of these four plants will receive an annually determined production quota fixed in accordance with the rules and regulations. The four power plants under this system are: Huangshi Phase I, Mianyang, Hexie, and Quijing. MPC’s projects, either under construction or in operation, have obtained all the required approvals to enable issuance of a business license in their respective localities.

Through MPC, Global owns a 17.5% indirect interest in a gas-fired combined-cycle electric generation facility in Kuo Kuang, Taiwan. MPC has a 35% interest in Kuo Kuang and partners with two local Taiwanese companies, Chinese Petroleum Corporation and CTCI Corporation. Kuo Kuang has entered into a 25-year power purchase contract for the sale of 100% of its electric output to Taiwan Power Company, the national utility. The power purchase contract payments consist of a fixed capacity charge to cover debt and equity return, as well as fixed and variable charges to cover fuel, operations and maintenance costs.

India

PPN Power Generating Company Limited (PPN)

Global owns a 20% interest in PPN located in Tamil Nadu, India. Global’s partners include Marubeni Corporation, with a 26% interest, El Paso Energy Corporation, with a 26% interest and the Apollo Infrastructure Company Ltd., with a 28% interest. PPN has entered into a PPA for the sale of 100% of the output to the State Electricity Board of Tamil Nadu (TNEB) for 30 years, with an agreement to take-or-pay equal to a plant load factor (PLF) of at least 68.5%. TNEB has not made full payment to PPN for the purchase of energy under the contract. For a discussion of the TNEB’s failure to meet its obligations under this PPA, see Item 7. MD&A.

Oman

Salalah

In March 2001, Global, through Dhofar Power Company (DPCO), signed a 20-year concession with the government of Oman to privatize the electric system of Salalah. A consortium led by Global (81% ownership) and several major Omani investment groups owns DPCO. The project achieved commercial operation in May 2003.

Peru

Empresa de Electricidad de los Andes S.A. (Electroandes)

Electroandes’ main assets include four hydroelectric facilities with a combined installed capacity of 183 MW and 437 miles of transmission lines located in the central Andean region east of Lima. In addition, Electroandes has expansion projects on existing stations totaling 35 MW and a temporary concession to develop two greenfield hydroelectric facilities totaling 130 MW. The concession expires in March 2005 but is expected to be renewed at that time. In 2003, 93% of Electroandes revenues were obtained through power purchase agreements with mining companies in the region expiring between 2005 and 2007.

Venezuela

Turboven

The facilities in Cagua and Maracay are owned and operated by Turboven, an entity which is jointly owned by Global and Corporacion Industrial de Energia (CIE). To date, power purchase contracts have been entered into for the sale of approximately 40% of the output of Maracay and Cagua, to various industrial customers expiring between 2004 and 2011. The power purchase contracts are structured to provide energy only with minimum take provisions. Fuel costs are passed through directly to customers and the energy tariffs are calculated in U.S. Dollars and paid in local currency.

Turbogeneradores de Maracay (TGM)

Global, with a 9% indirect interest, is in partnership with CIE, to own TGM. TGM sells all of the energy produced under contract to Manufacturas del Papel (MANPA), a paper manufacturing concern located in Maracay. MANPA and CIE have common controlling shareholders.

Poland

Elektrocieplownia Chorzow Sp. Z o.o. (Elcho)

Global has 90% ownership in Elcho, a company which has developed a combined thermal energy and power generation plant located in the city of Chorzow, Poland that began operation in the fourth quarter of 2003. Elcho also owns an older smaller combined heat and power plant, which will be retired some time in the near future. Elcho has a 20-year power purchase agreement with Polskie Sieci Elektroenergetyczne SA (PSE), the Polish government power grid company. For additional information related to Elcho, see Item 7. MD&A—Overview and Future Outlook.

Skawina CHP Plant (Skawina)

During 2002, Global acquired a 50% interest in Skawina, a combined thermal energy and power generation plant in Poland. In accordance with the original agreement, Global increased its equity interest in Skawina to approximately 63% in August 2003. Additionally, the agreement obligates Global to offer to purchase an additional 12% from Skawina’s employees in 2004, increasing Global’s suppliers’ potential ownership interest to approximately 75%. Skawina supplies electricity to several electric distribution companies and heat mainly to the city of Krakow, under one-year contracts consistent with current practice in Poland.

Tunisia

Rades

Global and its partner Marubeni Corporation own 60% and 40%, respectively, of the Carthage Power facility in Rades, Tunisia for which Global is the operator. For additional information relating to the pending sale of this plant, see Note 5. Discontinued Operations of the Notes.

Power Plants Under Construction

China

Haian Phase II

Through MPC, Global owns a 50% indirect interest in Haian Meiya Cogeneration Co., Ltd., a 30 MW coal-fired cogeneration plant under construction in Jiangsu Province with the first phase consisting of existing 2 x 20 tons per hour coal-fired temporary boilers and 6 km of steam pipeline. The expansion is scheduled for full commercial operations in June 2005. The electric power will be purchased by the state-owned Jiangsu Electric Power Company with annual purchase quantity being established based on steam load of the customers from the nearby economic zones. The total cost of the project is expected to be $34 million and is provided by non-recourse debt funds arranged by Agricultural Bank of China and equity funds from MPC.

Huangshi Phase II

Through MPC, Global owns a 24.5% indirect interest in Hubei Xisaishan Power Generating Company, a 660 MW pulverized coal-fired plant under construction in Hubei Province. Unit 1 is scheduled for commercial operations in December 2004 and Unit 2 is scheduled for June 2005. The electric power will be purchased by the state-owned Hubei Electric Power Company under a 20-year long-term power purchase contract. The total cost of the project is expected to be $382 million and is provided by non-recourse debt funds from the China Development Bank and equity funds from MPC.

Mianyang—Units 2 and 3

Through MPC, Global owns a 37.5% indirect interest in Meiyang Sanjiang Meiya Hydropower Company Limited, a 45 MW hydro plant under construction in Sichuan Province with the first 15 MW Unit achieving operations in December 2003. Unit 2 is scheduled for commercial operations in June 2004 and Unit 3 is scheduled for August 2004. The electric power will be purchased by the state-owned Sichuan Provincial Electric Power Company with annual purchase quantity being established based on expected provisional electric demand. The total cost of the project is expected to

be $30 million and is provided by non-recourse debt funds arranged by Shenzhen development Bank Loan and equity funds from MPC.

Nantong Phase II

Through MPC, Global owns a 50% indirect interest in Nantong Meiya Cogeneration Co., Ltd., a 30 MW operating coal-fired cogeneration plant which has under construction a 130 tons per hour coal-fired boiler and 15 MW unit expansion in Jiangsu Province. The expansion unit is scheduled for commercial operations in June 2005. The electric power will be purchased by the state-owned Jiangsu Electric Power Company with annual purchase quantity being established based on steam load of the customers in the Nantong Economic and Technology Development Zone. The total cost of the project is expected to be $13 million.

Quijing Phase II—Unit 4

Through MPC, Global owns a 18.5% indirect interest in SDIC Quijing Power Generation Co., Ltd., which consists of a 600 MW coal-fired units in operation and a 300 MW coal-fired unit in operations and a 300 MW unit under construction in Yunnan Province. The unit under construction is scheduled for commercial operations in June 2004. The electric power will be purchased by the state-owned Yunnan Power Company with annual purchase quantity being established based on Yunnan provincial demand and exports to Guangdong Province through the direct current interconnection tie line. The total cost of the project is expected to be $248 million and is provided by non-recourse debt funds by China Development Bank, Bank of China and China Construction Bank, and equity funds from MPC.

South Korea

Yulchon

Through MPC, Global owns a 50% indirect interest in Yulchon Generation Company, 612 MW gas-fired combined-cycle plant under construction in South Korea. Open cycle operation of the plant is scheduled for mid-2004, with conversion to combined-cycle operation scheduled for July 2004, which is scheduled to be completed by July 2005. The electric power will be purchased by state-owned Korea Electric Power Company under a 20-year long-term power purchase contract. The total cost of the project is expected to be $301 million and is provided by non-recourse debt funds arranged by Korean Development Bank and equity funds from MPC.

Electric Distribution Facilities

Global has invested in the following major distribution facilities:

Name	Location	Number of Customers	Global’s Ownership Interest
RGE	Brazil	1,050,000	33%
Chilquinta	Chile	496,000	50%
SAESA	Chile	543,000	100%
LDS	Peru	732,000	44%
Total		2,821,000

As part of the Oman concession, Global also operates a small distribution facility serving approximately 26,000 customers.

Brazil

RGE

Together with VBC Energia, a consortium of Brazilian companies formed to invest in electric privatization and Previ, the largest pension fund in Brazil, Global acquired a 33% interest in RGE in 1997. Global is the named operator for the system. A shareholders’ agreement establishes corporate governance, voting rights and key financial provisions. Global has veto rights over certain actions, including approval of the annual budget and financing plan, appointment of executive officers, significant investments or acquisitions, sale or encumbrance of assets, establishment of guarantees,

amendment of the by-laws of the company and dividend policies. Day-to-day operations are the responsibility of RGE, subject to partnership oversight. During 2001, VBC Energia and Previ transferred their shares to Companhia Paulista de Forcae Luz (CPFL), an electric distribution company in which each of VBC Energia and Previ have majority interest.

RGE operates under a territorial concession agreement ending in 2027. The concession is non-exclusive in that the distribution system must provide large consumers the right to choose another provider of energy or to self-generate. Global does not believe this represents a substantial threat to the profitability of the distribution system in Brazil since the tariff structure provides the distribution system the opportunity to recover all costs associated with distribution service plus a return. RGE secures its energy supply through contractual agreements expiring between 2007 and 2020. RGE will also purchase 20% of its energy requirements through 2013 under the terms of contracts, which are denominated in U.S. Dollars.

For additional information related to RGE, see Note 2. Restatement of Financial Statements and Item 1. Business—Regulatory Issues and Item 7. MD&A—Future Outlook.

Chile and Peru

Chilquinta and LDS

Global together with its partner, Sempra Energy (Sempra), own 99.99% of the shares of Chilquinta, an energy distribution company with numerous energy holdings, based in Valparaiso, Chile. Global’s interest is 50% of this aggregate. In addition, Global and Sempra own 87.9% of LDS, an electric distribution company located in Lima, Peru which owns several smaller companies. Global’s interest is 50% of this aggregate. As part of the Chilquinta and LDS investments, Global/Sempra also own Tecnored and Tecsur, located in Chile and Peru, respectively. These companies provide procurement and contracting services to Chilquinta, LDS, and others.

As equal partners, Global and Sempra share in the management of Chilquinta and LDS; however, Sempra has assumed lead operational responsibilities at Chilquinta, while Global has assumed lead operational responsibilities at LDS. The shareholders’ agreement provides for important veto rights over major partnership decisions including dividend policy, budget approvals, management appointments and indebtedness.

In 2003, Chilquinta generated approximately $143 million in gross revenues. Chilquinta operates under a non-exclusive perpetual franchise within Chile’s Region V which is located just north and west of Santiago. Global believes that direct competition for distribution customers would be uneconomical for potential competitors. LDS operates under an exclusive, perpetual franchise in the southern portion of the city of Lima and in an area just south of the city along the coast serving a population of approximately 3.2 million. In 2003, LDS generated gross revenues of approximately $327 million. Both Chilquinta and LDS purchase energy for distribution from generators in their respective markets on a contract basis.

For a discussion of the regulatory environment in Chile and Peru, see Item 1. Business—Regulatory Issues.

SAESA

In 2001, Global purchased a 99.9% equity interest in SAESA and its subsidiaries. The SAESA group of companies consists of four distribution companies and one transmission company that provide electric service to 390 cities and towns over 900 miles in southern Chile. Additionally, Global owns approximately 14% of Empresa Electrica de la Frontera S.A. (Frontel), not already owned by SAESA, to bring Global’s total interest in Frontel to 95.5%.

Through its affiliated company Sistema de Transmission del Sur S.A. (STS), SAESA provides transmission services to electrical generation facilities that have power purchase arrangements with distributors in Regions VIII, IX and X and has current capacity of 673 MVA.

SAESA also owns a 50% interest in an Argentine distribution company, Empresa de Energia Rio Negro S.A. (EDERSA), which provides generation, transmission and distribution services to 66

communities serving 660,000 customers in the Province of Rio Negro, which is located close to Argentina’s principal oil and gas reserves. SAESA and its Chilean affiliates are organized and administered according to a centralized administrative structure designed to maximize operational synergies. In Argentina, EDERSA has its own independent administrative structure. For additional information related to SAESA, see Item 1. Business—Regulatory Issues.

Argentina

Empresa Distribuidora La Plata S.A. (EDELAP)

In 2003, the shares formerly held by Global in EDELAP were transferred to The AES Corporation (AES). In connection with that transfer, certain contingent obligations Global had with respect to the project loans relating to EDELAP have been terminated by consent of the lenders.

AES Parana Project

In 2003, the shares held by Global in the AES Parana companies were transferred to AES. In connection with the transfer, all contingent obligations Global had with respect to the project loans relating to the AES Parana project, have been terminated by consent of the lenders.

Empresa Distribuidora de Electricidad Norte (EDEN) and Empresa Distribuidora de Electricidad Sur (EDES)

In December 2003, the shares held by Global in EDEN and in EDES were transferred to AES.

ITEM 3. LEGAL PROCEEDINGS

PSE&G

On November 15, 2001, Consolidated Edison, Inc. (Con Edison) filed a complaint against PSE&G with the 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. An initial decision issued by an ALJ in April 2002 upheld PSE&G’s claim that the contracts do not require the provision of “firm” transmission service to Con Edison but also accepted Con Edison’s contentions that PSE&G was obligated to provide service to Con Edison utilizing all the facilities comprising its electrical system including generation facilities and that PSE&G was financially responsible for “out-of-merit,” i.e., above-market, generation costs needed to effectuate the desired power flows. On December 9, 2002, FERC issued a decision modifying the Initial Decision by finding that only 600 MW of the total 1,000 MW power transfers is required to be supported by out-of-merit generation. FERC also made a number of other findings, on a preliminary basis, including favorable findings to PSE&G that power transfers should be measured on a “net” basis that considers the impacts of third party transactions and that PSE&G’s obligations should be reduced to the extent that Con Edison has impaired PSE&G’s ability to perform under the contracts. FERC remanded a number of issues to the ALJ for additional hearings, mainly related to the development of protocols to implement the findings of the December 9, 2002 order. In addition, issues related to Phase II of the complaint involving the past administration of the contracts and a claim that PSE&G improperly benefited from the purchase of hedging contracts in New York, is also pending before the ALJ. The ALJ issued an Initial Decision on the Phase II issues on June 11, 2003. That decision, which was largely favorable to PSE&G, is currently pending FERC review on exceptions by Con Edison. The FERC also denied rehearing of its December 9, 2002 over issues on Phase II on December 22, 2003. Docket No. EL02-23-000. Con Edison filed an appeal of the December 22, 2003 order with the U.S. Court of Appeals for the District of Columbia Circuit on January 8, 2004. The nature and cost of any remedy, which is expected to be prospective only, cannot be predicted, but could be material.

Power

Hudson and Mercer Generation Stations

During 1997 and 1998, approximately 150,000 tons of fly ash generated by the Hudson and Mercer generating stations was taken by an ash marketer, with whom Power then worked, and sold to the owner and operator of a clay mine. The 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 the NJDEP. Upon discovery of this use, Power 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. Power expects that the NJDEP will likely require a clay cap and other engineering controls to ensure that the ash is isolated from the environment if it is left in place. The cost of resolving this matter will depend upon the results of the negotiations with the NJDEP and the property owner. Although the precise extent of liability is not currently estimable, it is not expected to be material.

Kearny Generation Station

A preliminary review of possible mercury contamination at the Kearny station concluded that additional study and investigations are required. A Remedial Investigation (RI) was conducted and a report was submitted to the NJDEP in 1997. This report is currently under technical review. The RI Report found that the mercury at the site is stable and immobile and should be addressed at the time the Kearny station is retired.

Energy Holdings

Texas

The Public Utility Commission of Texas (PUCT) instituted an anti-trust investigation with regard to the price spikes in the Electric Reliability Council of Texas (ERCOT) balancing energy and ancillary services market that occurred during the February 24-26, 2003 extreme weather conditions, including whether any market manipulation occurred and whether any existing protocols need to be revised. On those days, during several trading periods, prices in the ERCOT balancing energy market cleared near the $1,000 per MWh ERCOT price cap. As part of the PUCT investigation, TIE, along with the other market participants, were requested to provide certain information to the PUCT relating to its bids from its two generation projects during this period. TIE supplied all the requested information and, while Energy Holdings believes such information demonstrates that TIE’s bidding activities were consistent with ERCOT protocols, Energy Holdings is unable to predict what action, if any, the PUCT may take.

The PUCT issued an order in May 2003 directing ERCOT to implement certain changes to the Balancing Energy Service (BES) market operated by ERCOT to mitigate the affects of potential future price spikes. These changes have been implemented. Energy Holdings believes that the new protocols will have minimal financial impact on the TIE projects.

On July 7, 2003, Texas Commercial Energy LLC (TCE) filed suit against power generators, qualified scheduling entities and affiliated retail electric providers as well as the ERCOT in its function as the independent system operator for the Texas energy market. The action filed in the U.S. District Court for the Southern District of Texas alleges price-fixing, predatory pricing and certain common law claims. APX, a named defendant, acted as agent and submitted bids on behalf of TIE as well as several other generators in the ERCOT balancing energy market. APX has submitted a demand for indemnification from TIE. On February 3, 2004, TCE amended its complaint and named TIE and others as additional defendants. TIE believes it has valid defenses to these claims and will vigorously assert them.

RGE

ANEEL—RGE Merger Matter

On June 29, 1998, RGE’s parent, DOC3 Participacoes, S.A. (DOC3), was merged into RGE. In connection with the merger, the shareholders of DOC3 became direct shareholders in RGE

(Downstream Merger). Upon the merger, RGE assumed all of DOC3’s liabilities and the shareholders were issued shareholder loans and preferred shares in RGE. The preferred shares were to bear a fixed interest rate of 13% per annum. The Brazilian electricity sector regulator, ANEEL, has taken the position that the Downstream Merger of DOC3 into RGE was inappropriate because it was not expressly approved by ANEEL. RGE believes that ANEEL’s prior approval of the transaction was not required because it did not involve a change in the control of RGE. The matter has been under discussion for some time. Global cannot predict the ultimate outcome of this matter.

See information on the following proceedings at the pages indicated for PSEG and each of PSE&G, Power and Energy Holdings as noted:

(1)

Page 16. (PSE&G) FERC proceeding related to MISO and PJM. Joint Filing of New PJM Companies and PJM Interconnection, L.L.C. to expand PJM, The New PJM Companies, et al., Docket No. ER03-262-000, December 11, 2002.

(2)

Page 17. (PSEG, PSE&G, Power and Energy Holdings) FERC proceeding related to PJM Restructuring, FERC Order dated June 26, 2003 seeking comments on proposed revisions to market-based rate tariffs and authorizations, Investigation of Terms and Conditions of Public Utility Market-Based Rate Authorizations, 103 FERC ¶ 61,349.

(3)

Pages 18 and 165. (Power) Protest filed on October 27, 1997 and refiled on January 24, 2003 by Old Dominion Electric Cooperative (ODEC) at FERC against Power, Docket Nos. EL98-6-001 and EL03-45-000.

(4)

Page 20. (PSEG, PSE&G, Power and Energy Holdings) Affiliate Standards audit at the BPU beginning July, 2002.

(5)

Page 20. (PSE&G) PSE&G’s Electric Base Rate Case filed with the BPU on May 24, 2002, OAL No. PUC5744-02; Docket No. ERO2050303.

(6)

Page 20. (PSE&G) Deferral Proceeding filed with the BPU on August 28, 2002 and Deferral Audit beginning on October 2, 2002 at the BPU.

(7)

Page 21. (PSE&G) PSE&G’s Gas Base Rate proceeding filed on May 25, 2001, Docket Nos. GR01050328 and GR01050297.

(8)

Page 21. (PSE&G) PSE&G’s Basic Gas Supply Service (BGSS) Commodity filing with the BPU on May 30, 2003, Docket No. EO03050394

(9)

Page 21. (PSE&G) BPU Order dated December 23, 2003, Docket No. EO02120955 relating to the New Jersey Interim Clean Energy Program.

(10)

Pages 22 and 52. (Energy Holdings) Global’s rate case in Brazil for Rio Grande Energia S.A. (RGE) with Agencia Nacional de Energia Eletrica (ANEEL).

(11)

Page 35. (Energy Holdings) Complaint filed on February 25, 2002 with the FERC 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.

(12)

Pages 40 and 143. (Energy Holdings) AES termination of the Stock Purchase Agreement, relating to the sale of certain Argentine assets. Filed in New York State Supreme Court for New York County on 4/23/02 (Docket No. 60155/2002) PSEG Global, et al vs. The AES Corporation, et al.

(13)

Page 167. (PSE&G) Investigation Directive of NJDEP dated September 19, 2003 and additional investigation Notice dated September 15, 2003 by the EPA regarding the Passaic River site. Docket No. EX93060255.

(14)

Page 168. (PSE&G) PSE&G’s MGP Remediation Program instituted by NJDEP’s Coal Gasification Facility Sites letter dated March 25, 1988.

(15)

Page 170. (Energy Holdings) Complaint filed by Harbinger with the Circuit Court of Shelby, Co., Alabama on February 19, 2003 addressing ownership interest in GWF. Harbinger GWF LLC, et al. v. PSEG California Corp., et al, Civil Action No. CV-2003-201.

(16)

Page 171. (Power) Filing of Complaint by Nuclear against the DOE on September 26, 2001 in the US Court of Federal Claims, Docket No. 01-551C seeking damages caused by the DOE’s failure to take possession of spent nuclear fuel. The Complaint was amended to include PSE&G interests as a prior owner in interest.

(17)

Page 171. (Power) SWU Enrichment Litigation. Nuclear filed Complaint on October 11, 2001 with the U.S. Court of Federal Claims (Arizona Public Service v. United States, CFC 01-592C) seeking relief from past overcharges by the DOE for uranium enrichment services seeking relief in excess of $28M; The APS case is stayed pending conclusion of an appeal with the U.S. Court of Appeals for the Federal Circuit taken on June 27, 2003 (Florida P&L v. US, Docket No. 03-5127.

(18)

Page 173. (PSE&G) Purported class action law suit against PSE&G demanding the utility move or shield gas meters located in allegedly dangerous locations, Docket No. GO03080640.

(19)

Page 174. (Energy Holdings) Peru’s Internal Revenue Agency’s (SUNAT) claim for past due taxes at Luz de Sur (LDS), Resolution No. 0150150000030, dated July 10, 2003.

PSE&G and Power

In addition, see the following environmental related matters involving governmental authorities. Based on current information, PSE&G and Power do not expect expenditures for any such site, individually or all such current sites in the aggregate, to have a material effect on their respective financial condition, results of operations and net cash flows.

(1) Claim made in 1985 by U.S. Department of the Interior under CERCLA with respect to the Pennsylvania Avenue and Fountain Avenue municipal landfills in Brooklyn, New York, for damages to natural resources. The U.S. Government alleges damages of approximately $200 million. To PSE&G’s knowledge there has been no action on this matter since 1988.

(2) Duane Marine Salvage Corporation Superfund Site is in Perth Amboy, Middlesex County, New Jersey. The EPA had named PSE&G as one of several potentially responsible parties (PRPs) through a series of administrative orders between December 1984 and March 1985. Following work performed by the PRPs, the EPA declared on May 20, 1987 that all of its administrative orders had been satisfied. The NJDEP, however, named PSE&G as a PRP and issued its own directive dated October 21, 1987. Remediation is currently ongoing.

(3) Various Spill Act directives were issued by NJDEP to PRPs, including PSE&G with respect to the PJP Landfill in Jersey City, Hudson County, New Jersey, ordering payment of costs associated with operating and maintenance expenses, interim remedial measures and a Remedial Investigation and Feasibility Study (RI/FS) in excess of $25 million. The directives also sought reimbursement of NJDEP’s past and future oversight costs and the costs of any future remedial action.

(4) Claim by the EPA, Region III, under CERCLA with respect to a Cottman Avenue Superfund Site, a former non-ferrous scrap reclamation facility located in Philadelphia, Pennsylvania, owned and formerly operated by Metal Bank of America, Inc. PSE&G, other utilities and other companies are

alleged to be liable for contamination at the site and PSE&G has been named as a PRP. A Final Remedial Design Report was submitted to the EPA in September of 2002. This document presents the design details that will implement the EPA selected remediation remedy. The costs of remedy implementation are estimated to range from $14 million to $24 million. PSE&G’s share of the remedy implementation costs are estimated between $4 million and $8 million. The remedy itself and responsibility for the costs of its implementation are the subject of litigation currently venued in the U.S. District Court for the Eastern District of Pennsylvania entitled United States of America, et. al., v. Union Corporation, et. al., Civil Action No. 80-1589.

(5) The Klockner Road site is located in Hamilton Township, Mercer County, New Jersey, and occupies approximately two acres on PSE&G’s Trenton Switching Station property. PSE&G has entered into a memorandum of agreement (MOA) with the NJDEP for the Klockner Road site pursuant to which PSE&G will conduct an RI/FS and remedial action, if warranted, of the site. Preliminary investigations indicated the potential presence of soil and groundwater contamination at the site.

(6) The NJDEP assumed control of a former petroleum products blending and mixing operation and waste oil recycling facility in Elizabeth, Union County, New Jersey (Borne Chemical Co. site) and issued various directives to a number of entities including PSE&G requiring performance of various remedial actions. PSE&G’s nexus to the site is based upon the shipment of certain waste oils to the site for recycling. PSE&G and certain of the other entities named in NJDEP directives are members of a PRP group that have been working together to satisfy NJDEP requirements including: funding of the site security program;containerized waste removal; and a site remedial investigation program.

(7) The New York State Department of Environmental Conservation (NYSDEC) has named PSE&G as one of many PRPs for contamination existing at the former Quanta Resources Site in Long Island City, New York. Waste oil storage, processing, management and disposal activities were conducted at the site from approximately 1960 to 1981. It is believed that waste oil from PSE&G’s facilities were taken to the Quanta Resources Site. NYSDEC has requested that the PRPs reimburse the state for the costs NYSDEC has expended at the site and to conduct an investigation and remediation of the site. Power, PSE&G and the other PRPs have executed an Order on Consent with NYSDEC for the investigation of the site and have entered an agreement among the PRPs for the sharing of the associated costs.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

PSEG— None.
PSE&G— None.
Power— None.
Energy Holdings— None.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

PSEG

PSEG’s Common Stock is listed on the New York Stock Exchange, Inc. As of December 31, 2003, there were 110,373 holders of record.

The following table indicates the high and low sale prices for PSEG’s Common Stock and dividends paid for the periods indicated:

Common Stock	High	Low	Dividend Per Share
2003:
First Quarter	$37.25	$32.09	$0.54
Second Quarter	$44.50	$36.45	$0.54
Third Quarter	$43.78	$39.77	$0.54
Fourth Quarter	$44.20	$39.40	$0.54
2002:
First Quarter	$46.80	$40.46	$0.54
Second Quarter	$47.25	$41.30	$0.54
Third Quarter	$43.50	$28.00	$0.54
Fourth Quarter	$32.38	$20.00	$0.54

In January 2004, PSEG’s Board of Directors approved a one-cent increase in the quarterly common stock dividend, from $0.54 to $0.55 per share for the first quarter of 2004. This quarterly increase reflects an indicated annual dividend rate of $2.20 per share. For additional information concerning the increase in dividend payments, dividend history, policy and potential preferred voting rights, restrictions on payment and common stock repurchase programs, see Item 7. MD&A—Future Outlook and Liquidity and Capital Resources and Note 14. Schedule of Consolidated Capital Stock and Other Securities of the Notes.

PSE&G

All of the common stock of PSE&G is owned by PSEG. For additional information regarding PSE&G’s ability to continue to pay dividends, see Item 7. MD&A—Future Outlook.

Power

All of Power’s outstanding limited liability company membership interests are owned by PSEG. For additional information regarding Power’s ability to pay dividends, see Item 7. MD&A—Future Outlook.

Energy Holdings

All of Energy Holdings’ outstanding limited liability company membership interests are owned by PSEG. For additional information regarding Energy Holdings’ ability to pay dividends, see Item 7. MD&A—Future Outlook.

ITEM 6. SELECTED FINANCIAL DATA

PSEG

The information presented below should be read in conjunction with the Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) and the Consolidated Financial Statements and Notes to Consolidated Financial Statements (Notes).

	For the Years Ended December 31,
	2003		2002(A)			2001(A)		2000(A)		1999(A)
			(Millions, where applicable)
Operating Revenues	$	11,116	$	8,216		$	6,883	$	6,521	$	6,339
Income from Continuing Operations	$	852	$	405	(B)	$	766	$	782	$	694
Net Income (Loss)	$	1,160	$	235		$	764	$	770	$	(123	)
Earnings per Share:
Income from Continuing Operations:
Basic	$	3.73	$	1.94	(B)	$	3.68	$	3.64	$	3.15
Diluted	$	3.72	$	1.94	(B)	$	3.68	$	3.64	$	3.15
Net Income (Loss):
Basic	$	5.08	$	1.13	(B)	$	3.67	$	3.58	$	(0.56	)
Diluted	$	5.07	$	1.13	(B)	$	3.67	$	3.58	$	(0.56	)
Dividends Declared per Share	$	2.16	$	2.16		$	2.16	$	2.16	$	2.16
As of December 31:
Total Assets	$	28,055	$	26,135		$	25,568		21,531		19,388
Long-Term Obligations(C)	$	12,997	$	12,292		$	10,814	$	5,869	$	5,154
Preferred Stock With Mandatory Redemption	$	—	$	—		$	—	$	75	$	75

______________

(A)

Results reflect the restatement to correct foreign currency translation/transaction errors related to an equity method investment made by Energy Holdings in RGE and other minor items at Energy Holdings. The restatement reduced Net Income by $10 million, $6 million and $42 million in 2002, 2001 and 1999, respectively. The restatement reduced Earnings per Share by $0.04, $0.03 and $0.19 in 2002, 2001 and 1999, respectively. The restatement increased Net Income and Earnings per Share by $6 million and $0.03, respectively, in 2000. See Note 2. Restatement of Financial Statements of the Notes for further discussion.

(B)

2002 results include after-tax charges of $368 million, or $1.76 per share, related to losses from Energy Holdings’ Argentine investments. See Item 7. MD&A—Results of Operations and Note 8. Asset Impairments of the Notes for further discussion.

(C)

Includes capital lease obligations. The increase in Long-Term Obligations is related to the $2.5 billion securitization transaction in 2001. In addition, this includes debt in all years 2002—1999 due to the implementation of FASB Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities (VIE).” See Note 3. Recent Accounting Standards of the Notes.

PSE&G

The information presented below should be read in conjunction with the MD&A, the Consolidated Financial Statements and the Notes.

	For the Years Ended December 31,
	2003		2002		2001		2000		1999
					(Millions)
Operating Revenues	$	6,740	$	5,919	$	6,091	$	5,887	$	5,840
Income Before Extraordinary Item	$	247	$	205	$	235	$	587	$	653
Net Income (Loss)	$	229	$	205	$	235	$	587	$	(151	)
As of December 31:
Total Assets	$	13,136	$	12,841	$	13,299	$	15,626	$	15,058
Long-Term Obligations(A)	$	5,129	$	5,050	$	5,180	$	4,163	$	3,678
Preferred Stock With Mandatory Redemption	$	—	$	—	$	—	$	75	$	75

______________

(A)

Includes capital lease obligations. The increase in Long-Term Obligations is related to the $2.5 billion securitization transaction in 2001. In addition, this includes debt in years 2002—1999 due to the implementation of FIN 46. For additional information, see Note 3. Recent Accounting Standards of the Notes.

Power

Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

Energy Holdings

Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A)

This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power), and PSEG Energy Holdings LLC (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each make representations only as to itself and make no other representations whatsoever as to any other company.

As discussed in Note 2. Restatement of Financial Statements of the Notes to Consolidated Financial Statements (Notes), the Consolidated Financial Statements of PSEG and Energy Holdings have been restated. The following discussion gives effect to this restatement.

OVERVIEW OF 2003 AND FUTURE OUTLOOK

Overview

PSEG

PSEG’s business consists of four reportable segments, which are PSE&G, Power and the two direct subsidiaries of Energy Holdings: PSEG Global LLC (Global) and PSEG Resources LLC (Resources). The following is a discussion of the markets in which PSEG and its subsidiaries compete, the corporate strategy for the conduct of PSEG’s businesses within these markets and significant events that have occurred during 2003. PSEG’s results of operations are primarily comprised of the results of operations of its operating subsidiaries, PSE&G, Power and Energy Holdings. For a more detailed discussion of PSEG’s results of operations, see the applicable results of operations discussion for each respective subsidiary registrant.

As energy markets have changed dramatically in recent years, PSEG and its subsidiaries have transitioned from a vertically integrated utility to an energy company with a diversified business mix. PSEG has realigned its organizational structure to address the competitive environment brought about by the deregulation of the electric generation industry and has evolved from primarily being a state regulated New Jersey utility to operating as a competitive energy company with operations primarily in the Northeastern United States (U.S.) and in other select markets. As the competitive portion of PSEG’s business has grown, the resulting financial risks and rewards have become greater, causing financial requirements to change and increasing the volatility of earnings and cash flows.

PSEG’s objective is to reduce future volatility of earnings and cash flows by entering into longer-term contracts for substantial portions of its anticipated energy output and reducing exposure to its international businesses by seeking to opportunistically monetize investments of Energy Holdings that may no longer have a strategic fit. PSEG also expects a gradual decline in earnings from Resources’ leveraged leasing business due to the maturation of its investment portfolio. The proceeds from Energy Holdings’ asset sales will be used, over time, to reduce debt and equity, to maintain credit requirements.

During 2003, PSEG continued to take steps to strengthen its balance sheet, capital structure and enhance its credit quality. Total equity increased by more than $1.6 billion and PSEG’s debt ratio, as measured by its lending covenants, decreased from 62% as of December 31, 2002 to 57% as of December 31, 2003. This equity increase included $667 million of retained earnings, approximately $439 million of common stock issued, through a combination of a public offering in October 2003 and under its employee stock purchase and dividend reinvestment plans during the year, and an increase of $538 million in Other Comprehensive Income (OCI) due primarily to the effects of pension related activity and the favorable change in foreign currency exchange rates. The equity increase related to the pension

plan was due to PSEG fully recapturing the unfavorable 2002 year-end pension adjustment of $292 million charged to OCI as its pension fund earned a return of almost 25% during 2003 coupled with approximately $210 million of contributions. Furthermore, the adoption of Statement of Financial Accounting Standard No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143), resulted in an after-tax benefit to Net Income of $370 million due primarily to the re-measurement of nuclear decommissioning obligations. For further information regarding SFAS 143 see Note 3. Recent Accounting Standards and Note 4. Adoption of SFAS 143 of the Notes.

PSEG also took steps to reduce business risk at each of the operating companies. The PSE&G electric rate case was completed in July 2003 with annual rate relief of approximately $160 million, effective August 1, 2003, providing the opportunity to earn an acceptable return. As allowed for in the order issued in the case by the New Jersey Board of Public Utilities (BPU), PSE&G expects to file for an additional $64 million annual increase in electric distribution rates to be effective on January 1, 2006, subject to BPU approval, including a review of PSE&G’s earnings and other relevant financial information. An unfavorable outcome could have a material adverse affect on PSEG’s and PSE&G’s earnings and cash flows. In the February 2003 New Jersey Basic Generation Service (BGS) auction process, Power secured contracts for a material portion of its anticipated output as an indirect supplier of New Jersey electric utility customers. In addition, Power entered into long-term fixed price contracts with certain companies in other states, including Connecticut and Pennsylvania. At Energy Holdings, PSEG has continued to limit future investments to existing contractual commitments, primarily those needed to complete the development of generating plants currently under construction. In addition, Global announced the sale of its investment in a generating facility in Rades, Tunisia. Energy Holdings also executed a project refinancing, resulting in a return of capital of $137 million in 2003. In addition, PSEG revised its credit agreements to eliminate all cross defaults to Energy Holdings’ debt.

PSE&G

PSE&G operates as an electric and gas public utility, or Electric Distribution Company (EDC), in New Jersey under cost-based regulation by the BPU for its distribution operations and by the Federal Energy Regulatory Commission (FERC) for its electric transmission operations. As such, the earnings of PSE&G are largely determined by the regulation of its rates by those agencies.

In July 2003, PSE&G received an order from the BPU in its electric base rate case, which provided for the following:

•

PSE&G received an annual increase in electric distribution rates of approximately $160 million commencing August 1, 2003.

•

PSE&G reduced electric distribution depreciation rates from 3.52% to 2.49%, effective August 1, 2003, which is expected to reduce Depreciation and Amortization Expense by approximately $40 million per year.

•

PSE&G recorded a regulatory liability in the second quarter of 2003 by reducing its depreciation reserve for its electric distribution assets by $155 million and will amortize this liability from August 1, 2003 through December 31, 2005. The $64 million annual amortization of this liability results in a reduction of Depreciation and Amortization expense. Subsequent to the amortization of this reserve, the BPU’s order allows PSE&G to file for an additional $64 million annual increase in electric distribution rates effective January 1, 2006, subject to BPU approval, including a review of PSE&G’s earnings and other relevant financial information.

•

PSE&G is refunding approximately $238 million to ratepayers from August 1, 2003 through December 31, 2005, through an adjustment of rates, which include certain overrecovered amounts related to the order PSE&G received from the BPU in 1999 relating to its rate unbundling, stranded costs and restructuring proceedings. These amounts also include a $30 million, pre-tax, refund related to amounts previously collected through rates for nuclear decommissioning, which was accounted for as an Extraordinary Item as discussed further in Note 6. Extraordinary Item of the Notes. Also, PSE&G has begun to refund through rates an $18 million, pre-tax, amount for Market Transition Charge (MTC) overcollections which was recorded during the second quarter of 2003 as a reduction to Operating Revenues and a $4

million, pre-tax, reduction in interest capitalized on various deferred balances, which was recorded as a charge to Interest Expense.

•

PSE&G began to recover deferred tax expenses associated with Repair Allowances and deferred Restructuring Costs over a ten-year period commencing August 1, 2003.

Power

Power is an electric generation and wholesale energy marketing and trading company that is focused on a generation market extending from Maine to the Carolinas and the Atlantic Coast to Indiana (Super Region). Power seeks to balance its generating capacity, fuel requirements and supply obligations through integrated energy marketing and trading, enhance its ability to produce low cost energy through efficient nuclear operations and pursue modest growth in its target market based on market conditions.

As a result of the first New Jersey BGS Auction, Power entered into energy supply contracts for the period August 1, 2002 through July 31, 2003. In February 2003, Power secured contracts for energy and capacity as an indirect supplier in New Jersey’s BGS Auction process by entering into contracts with third parties who are direct suppliers of New Jersey’s EDCs. Power also entered into hourly energy price contracts to be a supplier of certain large customers through the BGS auction for a ten-month period beginning August 1, 2003 and expiring May 30, 2004. Through these seasonally-adjusted fixed-price contracts, Power is indirectly serving New Jersey’s smaller commercial and residential customers for ten-month and 34-month periods that began August 1, 2003 and expires on May 30, 2004 and May 30, 2006, respectively. Also in 2003, Power entered into a three-year contract to supply energy to a New England utility. Power believes that its obligations under these contracts are reasonably balanced by its available supply. As discussed further under Future Outlook—Power, Power has entered into commitments to achieve its objective to sufficiently hedge at least 75% of its anticipated output over an 18-month to 24-month horizon.

Energy Holdings

Energy Holdings, through Global, has invested in, owns and operates generation and distribution facilities in select international and U.S. markets. The generation plants sell power under long-term agreements, as well as on a merchant basis, while the distribution companies are rate-regulated enterprises. Through Resources, Energy Holdings invests in energy-related financial transactions, including leveraged leases, which are designed to produce predictable earnings.

In 2003, Energy Holdings continued to experience a challenging environment in its foreign investments as it refocused its strategy from one of accelerated growth to one that places emphasis on increasing the efficiency and returns of its existing assets. As part of this change in strategy, Energy Holdings limited its capital spending during 2003 to existing contractual commitments. Also in 2003, Global began to review its portfolio and is seeking to opportunistically monetize investments which may no longer have a strategic fit. In keeping with this strategy, Global committed to a plan to sell its investment in Carthage Power Company (CPC), a generating facility in Rades, Tunisia in December 2003. See Note 5. Discontinued Operations of the Notes for further discussion. Due to credit concerns with respect to certain lessees, Resources has shifted its focus from new investments to maintaining its current investment portfolio. See Item 7A. Qualitative and Quantitative Disclosures About Market Risk—Credit Risk.

Future Outlook

PSEG

PSEG develops a long-range growth target by building business plans and financial forecasts for each major business (PSE&G, Power, Global and Resources). These plans and forecasts incorporate specific, rather than generic, capital expenditures. Key factors which may influence the performance of each business, such as fuel costs and forward power prices, are also incorporated. Sensitivity analyses are performed on the key variables that drive the businesses’ financial results in order to understand the impact of these assumptions on PSEG’s projections. Once plans are in place, PSEG management

monitors actual results and key variables and updates financial projections to reflect changes in the energy markets, the economy and regional and global conditions. Management believes this monitoring and forecasting process enables it to alter operating and investment plans as conditions change.

Looking ahead, the business plan for 2004 has been adjusted and financial objectives have been aligned with significant changes to both earnings growth and dividend policy. As a result of industry growth prospects moderating in recent years, PSEG has lowered its targeted earnings per share growth rate. Over the next five years PSEG has targeted a 4%–6% range for its earnings per share growth rate. This target is dependent upon various assumptions, including an increase in capacity prices which is not expected to occur until the later part of the planning period. As a result, a substantial portion of the earnings growth occurs in the later years of the planning period. PSEG has reaffirmed earnings guidance for 2004 of $3.60 to $3.80 per share from continuing operations and expects to continue to generate stable earnings in the near-term even given current historically low capacity prices. PSEG foresees a return to reasonable growth in the future as capacity prices are expected to improve in the latter part of the planning period. However, given the volatility of the power sector and the uncertainty of investment opportunities, it has become more difficult to accurately predict future results.

In addition to factors affecting near-term earnings and the long-term growth rate referenced above, the results of the annual New Jersey BGS auction will continue to have a significant impact on future results. In the future, each annual New Jersey BGS auction is expected to have less of a dramatic impact on Power’s results as less volume will be bid annually and as Power continually explores opportunities to enter into medium-term and long-term contracts in the Super Region to provide power to other states, such as Connecticut and Maryland, which have issued requests to suppliers to provide energy through bilateral agreements.

Although earnings growth has moderated, PSEG expects sufficient future operating cash flows to fund investments and meet dividend requirements. Over the next five years, PSEG expects to be in an excess cash position and may employ this excess cash to reduce debt over the near term, invest in its businesses, and increase dividends or repurchase stock over the long-term. At PSE&G, while rate relief is expected to improve earnings and cash flows in 2004, future growth is expected to be moderate and capital expenditures are expected to remain stable at levels needed to continue safe and reliable operations. PSEG will look to Power to provide incremental cash flows and begin to provide dividends to PSEG after the conclusion of its construction program in 2005. Energy Holdings will continue to curtail new investments, focus on cash flow contribution and opportunistically monetize certain of Global’s assets.

Dividend payments on common stock for the year ended December 31, 2003 were $2.16 per share and totaled approximately $493 million. PSEG’s payout ratio, based on Income from Continuing Operations, was 58% in 2003. In January 2004, PSEG’s Board of Directors approved an increase in the quarterly dividend by $0.01 per share, from $0.54 to $0.55 for the first quarter of 2004, indicative of an annual dividend rate of $2.20 per share. PSEG will continue to evaluate its dividend payments and, if appropriate, will adjust its dividend payout in future years.

PSE&G

In 2004 and beyond, PSE&G’s success will be dependent, in part, on its ability to maintain a reasonable rate of return, realize a $64 million electric distribution rate increase in 2006, continue cost containment initiatives, maintain system reliability and safety levels and continue to recover the regulatory assets it has deferred and the investments it plans to make in its electric and gas transmission and distribution systems. PSE&G is required to file a transmission rate case with FERC by the end of 2004, which could impact its transmission rates beginning January 1, 2005. The risks from this business generally relate to the treatment of the various rate and other issues by the state and federal regulatory agencies, specifically BPU and FERC.

For 2004, a full year effect of the electric rate case is expected to have a significant impact on results compared to 2003. PSE&G expects stable earnings and cash flows in the future. PSE&G has minimal risks relating to commodity price volatility as this risk is largely borne by customers and/or commodity suppliers in the competitive markets.

Power

Power’s success as an energy provider will depend, in part, on its ability to meet its obligations under its full requirements contracts efficiently and profitably. Over the next few years, earnings are expected to be pressured due to a generating capacity overbuild affecting the U.S. merchant power sector. Also, Power will no longer benefit from MTC revenues which had contributed approximately $111 million in 2003, the final year of the transition period. Power expects to largely offset the loss of these revenues by achieving increased output from its large base of low-cost nuclear and fossil generating stations compared to 2003 and increased margins from the management of its generation portfolio and supply obligations.

Power expects to meet its obligations through a combination of generation and energy purchases managed by PSEG Energy Resources & Trade LLC (ER&T). Power also enters into trading positions related to its generation assets and supply obligations. To the extent Power does not hedge its costs, Power will be subject to the risk of price fluctuations that could affect its future results including variability in costs, such as changes in the expected price of energy and capacity that Power sells into the market, increases in the price of energy purchased to meet its supply obligations or the amount of excess energy sold into the market, the cost of fuel to generate electricity, the cost of emission credits and congestion credits that are used by Power to transmit electricity and other factors. In addition, Power is subject to the risk of substandard operating performance of its generating units. To the extent there are unplanned outages at Power’s generating facilities, changes in environmental or nuclear regulations or other factors that impact the production by such units or the ability to generate and transmit electricity in a cost effective manner, it may cost Power more to acquire or produce electricity. Changes in the rules and regulation of these markets by FERC, particularly changes in the rules in the power pools in which Power conducts business and ability to maintain market-based rates, could adversely impact Power’s results. These risks can be exacerbated by, among other things, changes in demand in electricity usage, such as those caused by extreme weather or economic conditions.

Power is currently constructing projects that are expected to increase capacity from approximately 13,700 MW to approximately 16,000 MW, net of planned retirements. In response to low energy and capacity prices, Power shifted its emphasis away from new plant construction and has adjusted certain of its generating station construction schedules to better align with anticipated market prices. The near-term environment is challenging largely because current capacity levels in the Pennsylvania, New Jersey, and Maryland Interconnection (PJM) and the Midwest are significantly in excess of the reserves required to maintain reliability by the respective Independent System Operator (ISO). Power anticipates this situation will ease in the latter part of its five-year planning horizon and improve thereafter. Such reductions in excess capacity assumes load growth and the expected retirement of certain plants, primarily older plants of competitors due to increased Operation and Maintenance costs, increased costs associated with higher levels of environmental compliance and a lack of return on investment associated with major capital upgrade requirements because of the weak market conditions.

In addition, Power’s earnings projections assume that it will continue to optimize the value of its portfolio of generating assets and supply obligations through its energy trading operations. This will depend, in part, on Power’s, as well as its counterparties’, ability to maintain sufficient creditworthiness and to display a willingness to participate in energy trading activities. Changes in the mechanisms of conducting trading activity could positively or negatively affect trading volumes and liquidity in these energy trading markets compared to the assumptions of these factors embedded in Power’s business plans. Energy trading provides the opportunity for greater returns, but it also has more risk than the

generation business and can be adversely impacted by fluctuating energy market prices and other factors. Power utilizes what it believes to be a conservative risk management strategy to minimize exposure to market and credit risk. As a result of these variables, Power cannot predict the impact of these potential future changes on its forecasted results of operations, financial position or net cash flows; however, such impact could be material.

Energy Holdings

Global

In 2003, Global refocused its strategy from one of accelerated growth to one that places emphasis on increasing the efficiency and returns of its existing assets. Global limited its spending to existing contractual commitments and is reviewing its portfolio and, over time, will seek to opportunistically monetize investments that may no longer have a strategic fit.

Energy Holdings’ success will depend, in part, on its ability to mitigate risks presented by its international strategy. The economic and political conditions in certain countries where Global has investments present risks that may be different than those found in the U.S. including: renegotiation or nullification of existing contracts, changes in law or tax policy, interruption of business, nationalization, expropriation, war and other factors. Operations in foreign countries also present risks associated with currency exchange and convertibility, inflation and repatriation of earnings. In some countries in which Global has interests, economic and monetary conditions and other factors could affect its ability to convert its cash distributions to U.S. Dollars or other freely convertible currencies. Furthermore, the central bank of any such country may have the authority to suspend, restrict or otherwise impose conditions on foreign exchange transactions or to limit distributions to foreign investors. Although Global generally seeks to structure power purchase contracts and other project revenue agreements to provide for payments to be made in, or indexed to, U.S. Dollars or a currency freely convertible into U.S. Dollars, its ability to do so in all cases may be limited.

Global continues to face challenges with respect to certain of its investments as discussed below:

Brazil

The Brazilian economy is in a period of slowed growth that has resulted from the high public and private sector debt levels, as well as increased interest rates used by the Central Bank of Brazil to control rising inflation and to support the value of the Brazilian Real. In 2003, a new government administration assumed office that is attempting to reduce the effect of currency devaluations and wholesale prices on final consumer prices for electricity. Additionally, the new administration’s energy industry policy is to eliminate future privatizations of state-owned energy companies and increase federal government control and coordination of energy industry policies previously controlled by state and regional entities.

In April 2003, the Brazilian regulatory authority approved a 36.07% tariff increase for Rio Grande Energia S.A. (RGE). The majority of this increase became effective on April 16, 2003 while a portion of this increase will become effective in 2004. The result of this rate case was in line with management’s recent expectations. Unfavorable developments relating to potential changes in the regulatory structure and/or greater exertion of price controls by the Brazilian government could have a materially adverse impact on Global’s ability to earn a reasonable return on its investment in RGE and could materially impact its ability to recover its investment balance, including a potential impairment. Other risk factors that could affect future revenues and cash flows from Global’s investment in RGE are continued high interest rate levels, currency devaluation, extended recession and slow economic growth.

India

PPN Power Generating Company Limited’s (PPN) output is sold under a long-term Power Purchase Agreement (PPA) with the Tamil Nadu Electricity Board (TNEB) which sells the power to retail end-user customers. Beginning in April 2003, TNEB has not made full payment to PPN for the purchase of energy under the PPA. The past due receivable at PPN as of December 31, 2003 was approximately $95 million, of which Global’s share is approximately $8 million, net of a $10 million reserve. If TNEB continues to fail to make required payments under the PPA, PPN may have further

liquidity problems. The TNEB has agreed to pay approximately $30 million of the $95 million owed and negotiations have begun regarding the remaining $65 million. An adverse outcome to such negotiations could potentially result in an impairment of this investment, which could be material to PSEG’s and Global’s’ respective results of operations. As of December 31, 2003, Global’s total investment exposure in PPN was approximately $41 million.

Poland

Elektrocieplownia Chorzow Sp. Z o.o. (Elcho) has a 20-year PPA with the Polish government’s power grid company. The Polish government has embarked on a process with the intention of terminating all of the more than 30 long-term PPAs it has with energy suppliers. The Polish government has expressed its intention to compensate each entity whose contract is terminated with monies raised by the government by securitizing a charge that will be passed on to ratepayers. The Polish government informally proposed compensation for the termination of the PPA that Global does not believe to be adequate. Global is in discussions with the Polish government in order to ensure that, if the PPA is terminated, it is financially neutral to Elcho. Inadequate compensation could lead to lower future revenues and earnings and could have a material adverse impact on Global’s financial position.

Texas

As of December 31, 2003, Global had $240 million invested in two gas-fired combined-cycle electric generating facilities in Texas. Texas Independent Energy (TIE) continues to experience energy pricing pressures in the overbuilt Texas power market. To mitigate the risks associated with the spot market, in 2003 TIE entered into an asset management agreement to enhance its forward trading capabilities. In addition to forward trades, TIE has also entered into new PPAs for approximately 31% of the capacity of the plants for 2004 with an agreement to renew for 2005. As a result, the margins earned by TIE in 2003 have covered its fixed costs, bringing TIE to a break-even position in 2003 compared to a loss in 2002. Although project cash flows have improved, weakness in the Texas power market continues to put pressure on TIE’s ability to meet financial covenants in its loan documents. Global expects the current depressed level of energy prices in Texas to continue through the 2005-2006 time frame when market prices are expected to increase, as older less efficient plants in the Texas power market are expected to be retired and the demand for electricity is expected to increase. Global cannot predict the impact of these potential future changes on its forecasted results of operations, financial position or net cash flows; however, such impact could be material.

Venezuela

As of December 31, 2003, Global had approximately $50 million invested in its generation facilities in Venezuela which was fully funded by equity. Venezuela continues to undergo a period of significant political instability, as participation in prolonged work stoppages and violent street protests have caused a drastic reduction in economic activity. Following its 45% decline against the U.S. Dollar in 2002, the Venezuelan currency, the Bolivar, weakened further in 2003. Earnings and cash flows are expected to be affected by the prospects of reduced economic activity and increased exchange rate volatility. Although PPAs are indexed to the U.S. Dollar, the sharp decline in economic activity and in the exchange rate make the local sales price of energy supplies less attractive to local manufacturers. Revenues have already declined and are expected to remain below previous levels due to weakening demand.

Resources

Based on current market conditions and Energy Holdings’ intent to limit capital expenditures, it is unlikely that Resources will make significant additional investments in the near-term. As a result, Resources’ earnings and cash flows are expected to decrease in the future as the investment portfolio matures. Resources faces risks with regard to the creditworthiness of its counterparties, specifically, certain lessees that collectively comprise a substantial portion of Resources’ investment portfolio as discussed further below. Resources also faces risks related to potential changes in the current tax treatment of its investments in leveraged leases. The manifestation of either of these risks could cause a materially adverse effect on Resources’ strategy and its forecasted results of operations, financial position and net cash flows.

Resources has credit risk related to its investments in leveraged leases, totaling $1.4 billion, which is net of deferred taxes of $1.6 billion, as of December 31, 2003. These investments are largely concentrated in the energy industry and have some exposure to the airline industry. As of December 31, 2003, 65% of counterparties in the lease portfolio were rated investment grade by both S&P and Moody’s. As a result of recent actions of the rating agencies due to concerns over forward energy prices, the credit of some of the lessees was downgraded. Specifically, the lessees in the following transactions were downgraded below investment grade during 2002 by these rating agencies. Resources’ investment in such transactions was approximately $412 million, net of deferred taxes of $398 million as of December 31, 2003.

Resources is the lessor of the Keystone, Conemaugh and Shawville generating facilities located in the PJM West market in Pennsylvania to Reliant Energy Mid Atlantic Power Holdings LLC (REMA), an indirect wholly-owned subsidiary of Reliant Resources Incorporated (RRI). Resources’ investment in the REMA transaction was $117 million, net of deferred taxes of $122 million as of December 31, 2003. Resources expects $17 million of earnings from these leases in 2004.

Resources is the lessor of the Danskammer generation facility in New York to Dynegy Danskammer LLC (Danskammer) and the Roseton generation facility to Dynegy Roseton LLC (Roseton). Both Danskammer and Roseton are indirect subsidiaries of Dynegy Holdings Inc. (DHI). The lease obligations are guaranteed by DHI which is currently rated B by S&P and Caa2 by Moody’s. Resources’ investment in Danskammer and Roseton was $122 million, net of deferred taxes of $68 million as of December 31, 2003. Resources expects $17 million of earnings from these leases in 2004.

Resources is the lessor/equity participant of the Collins facility, as well as the Powerton and Joliet stations to Midwest Generation LLC (Midwest), an indirect subsidiary of Edison Mission Energy (EME). Edison Mission Midwest Holdings (EMM Holdings) is also an indirect subsidiary of EME. Resources’ investment in the Collins facility and the Powerton and Joliet facilities were $101 million and $72 million, respectively, net of deferred taxes of $98 million and $110 million, respectively. Resources expects $8 million and $6 million of earnings from the Powerton and Joliet facilities, respectively, in 2004.

Resources is the lessor of various aircraft to several domestic airlines. Resources leases a Boeing B767 aircraft to United Airlines (UAL). In December 2002, UAL filed for Chapter 11 bankruptcy protection. UAL has stated that it intends to retain its B767 aircraft to use in place of other aircraft. UAL has an additional debt obligation of $53 million associated with this aircraft. Resources will work constructively with UAL to keep the leveraged lease in place. The gross invested balance of this investment as of December 31, 2003 was $21 million. As accounted for under SFAS 13, Resources does not expect earnings from these leases in 2004.

As of December 31, 2003, lease payments on these facilities were current. If the collection of rental payments could not be reasonably assured, Resources would stop accruing earnings on these investments in accordance with SFAS 13, “Accounting for Leases”. If that occurred, Resources would need to review the investments for impairment and, if necessary, reduce them to net realizable value. In the event of a default, Resources would exercise its rights and attempt to seek recovery of its investment. The results of such efforts may not be known for a period of time. Under a worst case scenario, if a foreclosure were to occur, Resources would record a pre-tax write-off up to its gross investment in these facilities. Also, in the event of a potential foreclosure, the net tax benefits generated by Resources’ portfolio of investments could be materially reduced in the period in which gains associated with the potential forgiveness of debt at these projects occurs. The amount and timing of any potential reduction in net tax benefits is dependent upon a number of factors including, but not limited to, the time of a potential foreclosure, the amount of lease debt outstanding, any cash trapped at the projects and negotiations during such potential foreclosure process. The potential loss of earnings, impairment and/or tax payments could have a material impact to PSEG’s and Energy Holdings’ financial position, results of operations and net cash flows. As of December 31, 2003, Resources determined that the collectibility of the minimum lease payments under its leveraged lease investments is still reasonably probable and therefore continues to account for these investments as leveraged leases.

For further discussion of these leveraged leases, see Item 7A. Qualitative and Quantitative Discussion of Market Risk—Credit Risk—Resources.

RESULTS OF OPERATIONS

Net Income for the year ended December 31, 2003 was $1.2 billion or $5.07 per share of common stock, diluted, based on approximately 229 million average shares outstanding. For the year ended December 31, 2002, Net Income was $235 million or $1.13 per share of common stock, diluted, including certain after-tax charges of $538 million or $2.57 per share. The charges relate to the abandoned Argentine investments and losses from operations of those assets, discontinued operations of Energy Technologies Inc. (Energy Technologies) and Tanir Bavi Power Company Private Ltd. (Tanir Bavi), a generating facility in India, and goodwill impairment charges.

	Earnings (Losses)
	Years Ended December 31,
	2003			2002			2001
	(Millions)
PSE&G	$	247		$	205		$	235
Power		474			468			394
Energy Holdings:
Global(A)		121			(297	)		106
Resources		72			84			77
Other(B)		(4	)		(7	)		(4	)
Total Energy Holdings(A)		189			(220	)		179
Other(C)		(58	)		(48	)		(42	)
PSEG Income from Continuing Operations		852			405			766
Loss from Discontinued Operations, including Loss on Disposal(D)		(44	)		(49	)		(12	)
Extraordinary Item(E)		(18	)		—			—
Cumulative Effect of a Change in Accounting Principle(F)		370			(121	)		10
PSEG Net Income(A)	$	1,160		$	235		$	764

	Contribution to Earnings Per Share (Diluted)
	Years Ended December 31,
	2003			2002			2001
	(Millions)
PSE&G	$	1.08		$	0.98		$	1.13
Power		2.07			2.24			1.90
Energy Holdings:
Global(A)		0.53			(1.42	)		0.51
Resources		0.31			0.40			0.37
Other(B)		(0.02	)		(0.04	)		(0.02	)
Total Energy Holdings(A)		0.82			(1.06	)		0.86
Other(C)		(0.25	)		(0.22	)		(0.21	)
PSEG Income from Continuing Operations		3.72			1.94			3.68
Loss from Discontinued Operations, including Loss on Disposal(D)		(0.19	)		(0.23	)		(0.06	)
Extraordinary Item(E)		(0.08	)		—			—
Cumulative Effect of a Change in Accounting Principle(F)		1.62			(0.58	)		0.05
PSEG Net Income(A)	$	5.07		$	1.13		$	3.67

______________

(A)

Includes after-tax write-down and losses related to Argentine investments of $368 million or $1.76 for the year ended December 31, 2002.

(footnotes continued on next page)

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(B)

Other activities include non-segment amounts of Energy Holdings, Energy Technologies, Enterprise Group Development Corporation (EGDC) and intercompany eliminations. Specific amounts include interest on certain financing transactions and certain other administrative and general expenses at Energy Holdings.

(C)

Other activities include non-segment amounts of PSEG (parent company) and intercompany eliminations. Specific amounts include preferred securities dividends requirements for PSE&G and Energy Holdings, interest on certain financing transactions and certain other administrative and general expenses at PSEG (parent company).

(D)

Includes Discontinued Operations of Energy Technologies in 2003 and 2002, CPC in 2003 and 2002, and Tanir Bavi in 2002. See Note 5. Discontinued Operations of the Notes.

(E)

Relates to charge recorded in the second quarter of 2003 from PSE&G’s Electric Base Rate Case. See Note 6. Extraordinary Item of the Notes.

(F)

Relates to the adoption of SFAS 143 in 2003 and the adoption of SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142) in 2002. See Note 3. Recent Accounting Standards and Note 4. Adoption of SFAS 143 of the Notes.

The $447 million increase in Income from Continuing Operations for the year ended December 31, 2003, as compared to the same period in 2002, was primarily due to higher earnings from Energy Holdings due to the absence of the $368 million after-tax losses at Energy Holdings’ Argentine investments recorded in 2002. In addition, PSE&G improved earnings due to increased electric base rates, seasonality differences in pricing that are a component of those rates, favorable weather effects and lower interest costs. In addition, Power had slightly higher earnings primarily related to the benefits resulting from the operation of the two generating facilities in Connecticut that were acquired in December 2002, higher margins driven by an increase in volume as a result of the BGS contracts that went into effect in August 2002 and realized gains in its Nuclear Decommissioning Trust (NDT) portfolio, partially offset by the effects of storm-related weather and higher Operation and Maintenance expense. Also contributing to Energy Holdings’ increase in earnings were improved results from Global. The growth in Income from Continuing Operations did not result in higher per share amounts due to dilution caused mainly by the common stock issuance in the fourth quarter of 2003.

Included in PSEG’s 2003 Net Income was an after-tax benefit of $370 million related to the adoption of SFAS 143 during the first quarter of 2003. This benefit was due mainly to the required remeasurement of Power’s nuclear decommissioning obligations. Conversely, in 2002, PSEG adopted SFAS 142 and incurred an after-tax charge of $121 million related to goodwill impairments at certain of Energy Holdings’ investments. Also contributing to the changes in Net Income was a decrease in Energy Holdings’ Loss from Discontinued Operations, including Loss or Disposal of $5 million, after-tax, for the year ended December 31, 2003, as compared to the same period in 2002, and an $18 million, after-tax, extraordinary charge recorded at PSE&G in the second quarter of 2003 related to the outcome of its electric base rate case, discussed above in PSE&G’s Overview.

Excluding the charges discussed above, earnings for the year ended December 31, 2002 were largely consistent with 2001. This is primarily due to higher margins at Power due to its successful participation as an indirect supplier of energy to New Jersey’s utilities resulting from the 2002 BGS auction. The BGS contracts which went into effect on August 1, 2002 had a meaningful effect on PSEG’s earnings, particularly during the fourth quarter when Power served its contractual obligations with low cost energy during the colder months. PSE&G also improved earnings, due to stronger margins from gas rate relief and favorable weather as compared to the prior year and a reduction in operating expenses during 2002. These positive factors were offset by higher interest costs at PSEG and its subsidiaries, the absence of certain tax benefits realized by PSE&G in 2001 and comparatively lower contributions from investments at Energy Holdings, particularly the loss of earnings from Energy Holdings’ Argentine investments, continued weakness in the Texas power markets and a lower gain from Eagle Point Cogeneration Partnership (EPCP) transactions.

PSEG

Operating Revenues

For the year ended December 31, 2003, Operating Revenues increased by $2.9 billion or 35%, as compared to the same period in 2002, primarily due to the $1.1 billion of consolidation effects related to the BGS changes discussed below. Also contributing to the increase was an approximate $860 million increase in revenues from Power mainly related to contract volume increases under the load contracts which commenced on August 1, 2002 and increased revenues from two generation facilities in Connecticut acquired in 2002, an $821 million increase in PSE&G’s Operating Revenues due primarily to increased prices and sales volumes for gas and a $116 million increase in Energy Holdings’ Operating Revenues relating to higher revenues from Global’s generation projects and a higher partnership withdrawal payment from EPCP.

A portion of the increase in Operating Revenues for the year ended December 31, 2003, as compared to the same periods in 2002, was due to Power’s electric revenues no longer required to be eliminated in consolidation by PSEG subsequent to July 2002. Under the BGS contracts that terminated on July 31, 2002, Power sold energy directly to PSE&G, which in turn sold this energy to its customers. These revenues were properly recognized on each company’s stand-alone financial statements and were eliminated when preparing PSEG’s Consolidated Financial Statements. For the BGS contract period beginning August 1, 2002, Power entered into contracts with third parties who were direct suppliers of New Jersey’s EDCs and PSE&G purchased the energy for its customers’ needs from such third party suppliers. Due to this change in the BGS model, with the exception of a small portion of energy sold under the new contracts effective August 1, 2003, as discussed below, these revenues were no longer intercompany revenues and, therefore, were not eliminated in consolidation. For the year ended December 31, 2003, PSEG’s elimination related to the combined intercompany BGS and MTC revenues, decreased for that period by approximately $1.0 billion as compared to the prior year due primarily to this change. Also related to this change in the BGS model, PSE&G, in August 2002, began selling energy purchased under non-utility generation (NUG) contracts, which Power had previously paid PSE&G for at market prices, to the PJM, with the capacity purchased under these contracts being provided to the BGS suppliers on a pro-rata basis. As a result, for the year ended December 31, 2003, PSEG’s revenues related to NUG contracts increased by approximately $78 million.

For the year ended December 31, 2002, Operating Revenues increased by $1.3 billion or 19%, as compared to the same period in 2001, due primarily to Power’s BGS or commodity revenues subsequent to July 2002 not being eliminated in consolidation by PSEG. For the year ended December 31, 2002, PSEG’s elimination related to intercompany BGS and MTC revenues decreased by approximately $798 million as compared to 2001 due to this change. In addition, for the year ended December 31, 2002, PSEG’s revenues related to NUG contracts increased by approximately $82 million.

The remaining increase was due primarily to a $516 million increase from Power primarily related to the new BGS related revenues from third party wholesale electric suppliers which went into effect August 1, 2002 and revenues from off-system gas sales, partially offset by lower MTC revenues and lower net trading revenues as discussed further under the Power segment discussion. Also contributing to the increase was a $155 million increase at Energy Holdings driven by higher electric revenues at Global, relating to acquisitions and projects going into operation, and higher leveraged lease income at Resources, as discussed below under Energy Holdings’ segment discussion. These increases were partially offset by a $172 million decrease in revenues from PSE&G primarily due to a decrease in gas distribution revenues resulting in part from an average cost reduction of more than 10% in the cost of gas, in addition to other items discussed below under the PSE&G segment discussion.

Operating Expenses

Energy Costs

For the year ended December 31, 2003, as compared to the same period in 2002, Energy Costs increased approximately $2.7 billion or 72% due primarily to the fact that PSE&G no longer purchases

electric energy directly from Power, as discussed above in Operating Revenues. Amounts attributable to this change totaled approximately $1.1 billion between the year ended December 31, 2003 and 2002. Also contributing to the increase were an approximate $831 million net increase in gas costs, a $624 million increase at Power primarily related to increased power purchases and third-party wholesale electric supply contracts, discussed further below under Power, a $79 million increase in electric energy costs at PSE&G discussed further below under PSE&G and a $37 million increase at Energy Holdings, relating to projects at Global, discussed further below under Energy Holdings.

For the year ended December 31, 2002, as compared to the prior year, Energy Costs increased approximately $1 billion or 38% due primarily to the fact that PSE&G no longer purchased electric energy directly from Power, as discussed above in Operating Revenues, but rather from third party wholesalers. In 2001, and through July 31, 2002, PSE&G incurred energy costs related to electric energy transactions between it and Power. Accordingly, these costs were eliminated when preparing PSEG’s consolidated financial statements. Amounts attributable to this change totaled $880 million between the years ended December 31, 2002 and 2001.

The remaining increase was due to a $352 million increase at Power primarily related to increased energy purchases and third party wholesale electric supplier contracts, discussed further below in Power, and a $63 million increase at Energy Holdings, relating to acquisitions and projects going into operation at Global, discussed further below in Energy Holdings. These increases were partially offset by a $229 million decrease at PSE&G due primarily to decreased gas costs which resulted from lower demand, discussed further below in PSE&G.

Operation and Maintenance

For the year ended December 31, 2003, Operation and Maintenance expense increased $221 million or 12%, as compared to the year ended December 31, 2002, due to a $141 million increase at Power primarily due to the acquisition of the generating facilities in Connecticut in December 2002, higher accretion expense associated with the nuclear decommissioning liabilities, higher pension costs, higher nuclear refueling outage costs and higher real estate taxes, a $68 million increase at PSE&G due primarily to higher labor and fringe benefit costs, higher Demand Side Management (DSM) amortization, higher bad debt expense and storm-related costs, discussed further below under PSE&G. In addition, Operation and Maintenance expense increased at Energy Holdings by $8 million, due mainly to costs associated with projects at Global, as discussed further below under Energy Holdings.

For the year ended December 31, 2002, Operation and Maintenance expense increased $55 million or 3%, as compared to 2001 due to an increase of $35 million at Power primarily caused by scheduled outages at certain electric generating stations, and an increase at Energy Holdings of $46 million, primarily due to costs associated with acquisitions and projects going into operation. This increase was partially offset by a $14 million decrease at PSE&G primarily due to decreased labor and professional service costs, partially offset by higher DSM amortization, and a decrease in other charges of $12 million at PSEG.

Depreciation and Amortization

For the year ended December 31, 2003, Depreciation and Amortization decreased by $38 million or 7%, as compared to the same period in 2002. The decrease was primarily due to a $37 million decrease at PSE&G, as discussed further below.

For the year ended December 31, 2002, Depreciation and Amortization increased $70 million or 14%, as compared to 2001, primarily due to increases of $39 million at PSE&G, mainly due to a full period’s recognition of amortization of the regulatory asset related to stranded costs for securitization, $13 million at Power, primarily due to increases from Bergen 2 being placed into service in 2002 and a 2001 reversal of cost of removal reserves, and $13 million at Energy Holdings, primarily related to costs associated with acquisitions and projects going into operation.

Taxes Other Than Income Taxes

Taxes Other Than Income Taxes is comprised of the Transitional Energy Facility Assessment (TEFA) tax at PSE&G. Taxes Other Than Income Taxes increased $5 million or 4% for the year ended December 31, 2003, as compared to the same period in 2002. The change in the amount of the TEFA related to changes in PSE&G’s higher taxable sales in 2003. Legislation enacted in January 2002 freezes the TEFA unit rate surcharges at the 2001 levels through 2004 and then reduces the rates over the next three years, phasing out the TEFA by 2007.

Taxes Other Than Income Taxes increased $10 million or 8% in 2002, as compared to 2001. This increase was primarily due to a reduction of $6 million in the prior year’s TEFA recorded in 2001 and an increase of $3 million in the 2002 TEFA due to increased sales.

Other Income

For the year ended December 31, 2003, Other Income increased by $139 million, as compared to the year ended December 31, 2002, due primarily to a $148 million increase at Power. Power’s increase was primarily due to the recognition of realized gains and income related to Power’s Nuclear Decommissioning Trust (NDT) Fund.

Other Deductions

For the year ended December 31, 2003, Other Deductions increased by $21 million, as compared to the year ended December 31, 2002, due primarily an increase at Power of $77 million, partially offset by a decrease at Energy Holdings of approximately $72 million. Power’s increase was primarily due to the recognition of realized losses in Power’s NDT Fund. The decrease at Energy Holdings was largely attributable to lower foreign currency transaction losses, primarily related to U.S. Dollar debt in Argentina recorded in 2002.

For the year ended December 31, 2002, Other Deductions increased by $59 million as compared to 2001, primarily due to a $60 million increase in foreign currency transaction losses at Energy Holdings.

Interest Expense

For the year ended December 31, 2003, Interest Expense increased by $17 million or 2%, as compared to the year ended December 31, 2002, primarily due to a $40 million and $1 million increase at PSEG and Energy Holdings, respectively related to higher levels of debt outstanding, partially offset by decreases of $16 million and $8 million at PSE&G and Power, respectively, as discussed below.

For the year ended December 31, 2002, Interest Expense increased $43 million or 6% as compared to 2001 primarily due to higher amounts of debt outstanding at PSEG, Power and Energy Holdings used to support various projects and acquisitions and for other general corporate purposes, partially offset by decreases at PSE&G due to lower debt levels.

Income Taxes

For the year ended December 31, 2003, Income Taxes increased by $210 million or 83%, as compared to the year ended December 31, 2002, due primarily to higher pre-tax Income from Continuing Operations.

For the year ended December 31, 2002, Income Taxes decreased $119 million or 32% as compared to 2001 primarily due to lower pre-tax Income from Continuing Operations partially offset by adjustments in 2001 reflecting the conclusion of the 1994-96 Internal Revenue Service (IRS) audit.

Loss From Discontinued Operations

For the years ended December 31, 2003, 2002 and 2001, Energy Holdings recorded Losses From Discontinued Operations of $44 million, $49 million and $12 million, after-tax, respectively, as detailed further below under Energy Holdings.

Extraordinary Item

For the year ended December 31, 2003, PSE&G recorded an $18 million, after-tax, charge relating to its Electric Base Rate Case, as detailed further below under PSE&G.

Cumulative Effect of a Change in Accounting Principle

For the year ended December 31, 2003, Power recorded a $370 million, after-tax, benefit relating to the adoption of SFAS 143, as detailed further below under Power. For the year ended December 31, 2002, Energy Holdings recorded a $121 million, after-tax, charge due to goodwill impairments relating to the adoption of SFAS 142, as detailed further below under Energy Holdings.

PSE&G

Operating Revenues

PSE&G’s Operating Revenues increased by $821 million or 14% for the year ended December 31, 2003, as compared to the year ended December 31, 2002, due to a $758 million increase in gas revenues and a $63 million increase in electric revenues for the year ended December 31, 2003.

The increase in gas revenues primarily related to a $531 million increase due to price changes and $227 million due to higher sales volumes. The average cost of gas, which is passed through to customers, increased by 26% and total gas sales volumes increased by 10% due primarily to colder weather conditions.

The $63 million increase in electric revenues resulted from a $191 million increase due to price changes primarily relating to higher rates set in the BGS auction and the impact of the BPU order in its Electric Base Rate Case, both of which took effect on August 1, 2003. These were partially offset by the 4.9% rate reduction which was effective from August 1, 2002 through July 31, 2003, combined with increased sales of NUG power, primarily due to higher locational marginal pricing (LMP) in the PJM market. The increase related to price changes was partially offset by $129 million in lower sales volumes. While distribution sales volumes were higher by 1%, BGS volumes were down 7% due to the milder weather plus large customers switching to third party suppliers.

For the year ended December 31, 2002, PSE&G’s Operating Revenues decreased $172 million or 3%, as compared to the year ended December 31, 2001, primarily due to a decrease of $155 million in gas distribution revenues. This decrease was due to lower commodity revenues resulting from an average cost reduction of more than 10% in the cost of gas of approximately $125 million. Also contributing to the decrease were lower sales of approximately $88 million to interruptible customers resulting from the lower cost of gas and lower off-system sales revenues of approximately $26 million. These decreases were partially offset by increased gas base rates and increased volumes of approximately $75 million, primarily due to residential usage driven by favorable weather conditions and increased appliance service revenues of approximately $14 million. In addition, electric transmission and distribution revenues decreased $17 million, primarily due to a 4.9% rate reduction implemented in August 2002 under the Final Decision and Order in PSE&G’s rate unbundling, stranded costs and restructuring proceedings (Final Order) and approximately $123 million in rate reductions in February and August 2001 totaling 4%, which were recorded as reductions in MTC revenues. Also affecting 2002 performance were decreases of approximately $15 million in NUG sales at market prices, lower DSM sales due to revenue adjustments in 2001 of approximately $19 million and approximately $7 million in lower fiber optic attachment revenues due to unfavorable market conditions. These were offset by increased BGS revenues, primarily due to customers returning to PSE&G from third party suppliers of approximately $104 million, and higher distribution volumes for residential and commercial customers of approximately $37 million due to favorable weather conditions.

Operating Expenses

Energy Costs

For the year ended December 31, 2003, Energy Costs increased $737 million or 20%, as compared to the same period in 2002. Energy costs represent the cost of electric and gas purchases necessary to meet customer load. The differences between energy cost incurred and associated energy revenue is deferred for future collection or refund to customers.

Gas costs increased $658 million or 48% for the year ended December 31, 2003, as compared to the same period in 2002. The increase is a combination of a 26% increase in the price of gas ($527 million) and a 9% increase in sales volumes ($131 million).

Electric costs increased $79 million or 3% for the year ended December 31, 2003, as compared to the same period in 2002. The increase is the combination of higher prices for BGS and NUG purchases and higher MTC payments ($250 million) offset by lower BGS and NUG volumes ($170 million). As described above under revenues, BGS volumes are declining due to large customers switching to third party suppliers. NUG volumes are a function of the NUG generator and contract limits.

For the year ended December 31, 2002, PSE&G’s Energy Costs decreased $229 million or 6%, as compared to the year ended December 31, 2001, due primarily to a decrease in gas costs of approximately $230 million which resulted from lower commodity sales volumes of approximately $125 million, lower volumes of $88 million from interruptible customers due to lower rates and lower off-system sales volumes of approximately $18 million. Also contributing to the decrease were lower electric costs of $123 million due to the MTC rate reductions discussed above in Operating Revenues and decreased NUG energy sales of $15 million due to lower rates. Offsetting these decreases were increased electric energy costs of $104 million due to higher commodity sales volumes from customers returning from third party suppliers and a scheduled increase in the shopping credit and $30 million in higher amounts paid to Power relating to the amortization of the excess electric distribution depreciation reserve, which is a component of MTC.

Operation and Maintenance

Operation and Maintenance costs increased $68 million or 7% for the year ended December 31, 2003, as compared to the same periods in 2002. The increase primarily related to higher labor and fringe benefits of $49 million, due primarily to wage and incentive increases, the costs of an incentive program, higher pension costs and increased weather and storm-related expenses due to Hurricane Isabel and the extreme winter weather. Also contributing to the increase were higher bad debt expense of $10 million due to high winter gas sales and higher DSM costs of approximately $38 million relating to the increased sales, discussed above. DSM costs are deferred when incurred and amortized to expense when recovered in revenues. Partially offsetting these increases is a reduction in real estate tax expense of $18 million and the reversal of a $10 million reserve against a regulatory asset that is now being recovered.

Operation and Maintenance expense decreased $14 million or 1% in 2002, as compared to 2001, primarily comprised of decreased labor costs of approximately $9 million, decreased use of professional and contract services of approximately $7 million, $7 million in lower charges for administrative and general services and lower equipment rental of approximately $8 million. These decreases were offset by $14 million in increased DSM amortization and increased miscellaneous accounts receivable reserves of approximately $3 million.

Depreciation and Amortization

Depreciation and Amortization decreased $37 million or 9% for the year ended December 31, 2003, as compared to the year ended December 31, 2002, due primarily to a $52 million additional amortization of an excess electric distribution depreciation reserve and an $11 million decrease from the use of a lower book depreciation rate for electric distribution plant. Partially offsetting this decrease was a $13 million increase in depreciation expense due to increased plant in service and $9 million increase

in the amortization of the regulatory asset related to securitization, resulting from higher Securitization Transition Charge (STC) revenues.

Depreciation and Amortization expense increased $39 million or 11% in 2002, as compared to 2001, primarily due to $37 million in amortization of the regulatory asset related to stranded costs for securitization, $13 million in increased plant in service and $7 million in gas base rates for plant assets. Offsetting this increase is $22 million in amortization of an excess electric distribution depreciation reserve.

Taxes Other Than Income Taxes

Other Income

Other Income decreased $9 million or 60% for the year ended December 31, 2003, as compared to the same period in 2002, due primarily to equity return adjustments to regulatory assets of $11 million offset by $1 million in increased gains on the disposal of various electric transmission properties.

Other Income decreased $80 million or 84% in 2002, as compared to 2001, due primarily to $65 million related to PSEG’s settlement of an intercompany loan from PSE&G in 2001 and $16 million related to lower interest income on investments. This was offset by a $6 million gain on disposal of properties.

Interest Expense

Interest Expense decreased by $16 million or 4% for the year ended December 31, 2003, as compared to the same period in 2002. These decreases were due primarily to lower interest on long-term debt of $23 million for the year ended December 31, 2003, as compared to the same period in 2002, due to various maturities and redemptions of approximately $250 million. These decreases were partially offset by increased short-term interest expense of $2 million due to higher short-term debt balances outstanding due to increased working capital needs and $6 million in increased interest related to certain regulatory assets.

Interest Expense decreased $52 million or 11% for the year ended December 31, 2002, as compared to 2001, due to the $14 million in decreased debt redemptions, particularly of short-term debt in third quarter of 2001 and lower interest rates in 2002, $8 million related to the redemption of a floating rate note in 2001, the maturity of long-term debt of approximately $14 million, $3 million related to the repurchase of Pollution Control Bonds, the carrying costs on the deferred repair allowance of approximately $7 million and $2 million in New Jersey state accrued tax interest adjustments. These decreases were partially offset by higher securitization bond interest expense of approximately $7 million related to PSE&G Transition Funding LLC’s (Transition Funding) securitization bonds.

Income Taxes

Income Taxes increased by $14 million or 12% for the year ended December 31, 2003, as compared to the same period in 2002, due primarily to increases in pre-tax Income from Continuing Operations, offset by tax benefits recorded in 2003 attributable to the actual filing of the 2002 tax return.

Income taxes increased $26 million or 29% for the year ended December 31, 2002, as compared to 2001, primarily due to prior period tax adjustments recorded in 2001 reflecting the conclusion of the 1994-96 IRS audit.

Extraordinary Item

As discussed previously, included in the Electric Base Rate Case decision issued by the BPU was a refund related to revenues collected through the Societal Benefits Charge (SBC) for nuclear decommissioning. Because this amount reflects the final accounting for PSEG’s generation-related business pursuant to the four-year transition plan mandated by the Final Order, the adjustment has been recorded as an $18 million, after-tax, Extraordinary Item as required under Accounting Principles Board (APB) Opinion No. 30, “Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions” (APB 30) and SFAS No. 101, “Regulated Enterprises—Accounting for the Discontinuation of Application of FASB Statement No. 71”.

Power

Operating Revenues

For the year ended December 31, 2003, Operating Revenues increased approximately $2.0 billion, as compared to the year ended December 31, 2002, primarily due to an increase in gas supply revenues of approximately $1.3 billion. The increase is due to 2003 being the first full year of the Basic Gas Supply Service (BGSS) contract with PSE&G compared to a partial year in 2002 since the contract commenced in May 2002. Gas revenues for the first four months of 2003, totaled $1.1 billion. Also contributing to the increase in gas revenues were higher sales volumes and higher gas prices. Generation revenues also increased approximately $640 million for the year ended December 31, 2003, as compared to the same period in 2002, due to the increased supply obligations and new operations, as discussed above, as compared to the same period in 2002.

For the year ended December 31, 2002, Power’s Operating Revenues increased $1.2 billion, as compared to 2001, primarily due to the inclusion of $804 million of gas revenues relating to its BGSS contract and off-system gas sales resulting from the operations under the Gas Contracts transferred from PSE&G in May 2002. Also contributing to the increase was a $560 million increase in BGS related revenues, primarily due to the new BGS related revenues from third party wholesale electric suppliers which went into effect August 1, 2002 which was partially offset by lower MTC revenues of $98 million mostly due to a 4.9% rate reduction in August 2002 and two 2% rate reductions in August 2001 and February 2001. Also offsetting the increases were lower net trading revenues of approximately $104 million due to lower trading volumes and prices during 2002, as compared to 2001.

Operating Expenses

Energy Costs

For the year ended December 31, 2003, Energy Costs increased approximately $1.9 billion, as compared to the same period in 2002, primarily due to a $1.3 billion increase in gas costs due to the effect of a full year under the BGSS contract combined with higher gas sales volumes and prices and higher gas, oil and coal costs for generation. The increase in Energy Costs was also due to increased energy purchases on the spot market, as well as bilateral energy purchases, of approximately $413 million. Also, Power incurred an increase of approximately $116 million in network transmission expenses given that there were no payments for the first seven months in 2002. Additional charges associated with fuel and energy purchases to satisfy wholesale power agreements related to its Connecticut generating facilities totaled approximately $80 million for the year ended December 31, 2003.

For the year ended December 31, 2002, Power’s energy costs increased $1 billion compared to 2001 primarily due to increased energy purchase volumes and third party wholesale electric supplier contracts of approximately $297 million and $738 million of increased gas purchases to satisfy Power’s BGSS contract with PSE&G. Also contributing to the increase were higher network transmission expenses of $102 million. These higher expenses were partially offset by a $67 million decrease in NUG purchases. Additionally, the record capacity factor of its nuclear units enabled Power to produce low cost generation for a greater portion of its supply needs.

Operation and Maintenance

Operation and Maintenance expense increased $141 million or 18% for the year ended December 31, 2003 from the comparable period in 2002 due to costs of generating facilities in Connecticut acquired in December 2002 of $56 million, accretion expense of $24 million associated with the nuclear decommissioning liabilities, higher pension expense of $20 million, higher nuclear refueling outage costs of $24 million and other items.

For the period ended December 31, 2002, Operation and Maintenance expense increased $35 million or 5% as compared to the same period in 2001, due primarily to increases caused by scheduled outage work at electric generating stations.

Depreciation and Amortization

Depreciation and Amortization expense decreased $6 million or 6% for the year ended December 31, 2003 from the comparable periods in 2002. The net decrease was composed of lower depreciation costs of approximately $30 million due to the absence of decommissioning charges, which are no longer recorded as a result of the implementation of SFAS 143, partially offset by higher depreciation and amortization primarily related to generating facilities in Connecticut acquired in December 2002 and a higher asset base.

For the period ended December 31, 2002, Depreciation and Amortization expense increased $13 million or 14%, as compared to the same period in 2001, due primarily to increases from Bergen 2 being placed into service in 2002 and a 2001 reversal of cost of removal reserves.

Other Income

Other Income increased $148 million for the year ended December 31, 2003 from the comparable period in 2002, due primarily to the recording of realized gains and income on the NDT Fund.

Other Deductions

Other Deductions increased $77 million for the year ended December 31, 2003 from the comparable period in 2002, due primarily to the recording of realized losses on the NDT Fund.

Interest Expense

Interest Expense decreased by $8 million for the year ended December 31, 2003, as compared to the same period in 2002. Power incurred additional interest charges of $20 million due primarily to the new long-term financing of $600 million in June 2002, this increase was more than offset by lower interest expense on variable rate debt and other lower charges of approximately $15 million. Additionally, capitalized interest relating to various construction projects reduced interest expense by approximately $13 million for the year ended December 31, 2003, as compared to the same period in 2002.

Interest Expense decreased $21 million for the year ended December 31, 2002 from the comparable period in 2001 primarily due to improved financing rates and the repayment of intercompany notes, which resulted in a decrease in expense of $83 million. Offsetting these reductions were $94 million of increased interest expense associated with the issuance of the $2.4 billion of senior notes, including $600 million issued in 2002, $124 million of Pollution Control Notes and increased non-recourse financing

associated with the Lawrenceburg and Waterford construction projects, offset by increased capitalized interest relating to various construction projects of $32 million.

Income Taxes

Income taxes increased by $13 million or 4% for the year ended December 31, 2003, as compared to the same period in 2002. The increase was due primarily to higher pre-tax income.

Income Taxes increased $63 million or 25% for the year ended December 31, 2002, as compared to comparable period in 2001. The increase was due primarily to higher pre-tax income.

Cumulative Effect of Change in Accounting Principle

Upon adoption of SFAS 143 on January 1, 2003, Power recorded a Cumulative Effect of a Change in Accounting Principle in the amount of $370 million, after-tax. For additional information, see Note 4. Adoption of SFAS 143 of the Notes.

Energy Holdings

Operating Revenues

For the year ended December 31, 2003, Energy Holdings’ Operating Revenues increased $116 million or 19%, from the comparable period in 2002. Higher electric generation and distribution revenues at Global of $115 million and $6 million, respectively, was the primary reason for this increase. This increase was partially offset by lower revenues at Resources of $10 million, as discussed below.

For the year ended December 31, 2002, Energy Holdings’ Operating Revenues increased $155 million or 34%, from the comparable period in 2001. Higher electric generation and distribution revenues at Global of $116 million and $56 million, respectively, was the primary reason for this increase. Also contributing to this increase was higher revenues at Resources of $8 million. Partially offsetting the increase was a lower gain from partnership withdrawal relating to EPCP of $28 million compared to the same period in 2001. In 2001, Global withdrew from its interest in EPCP in exchange for a series of payments through 2005, provided certain operating contingencies are met.

Global

For the year ended December 31, 2003, Global’s Operating Revenues increased $124 million or 35% from the comparable period in 2002. Contributing to the increase was a $47 million increase from Skawina CHP (Skawina), a generation facility in Poland, in which Global purchased a majority ownership in June 2002, a $38 million increase from Salalah, a generation facility in Oman, which began commercial operation in May 2003 and a $28 million increase in revenue from GWF Energy LLC (GWF Energy). This increase in revenue at GWF Energy was due to the Henrietta and Tracy Peaking Plants becoming operational in the second quarter of 2003 and 2002, respectively and consolidation of GWF Energy from the fourth quarter 2002 to the fourth quarter 2003. In the second half of 2002, Global’s ownership of GWF Energy exceeded 75% and under the operating agreement Global gained a controlling interest. Accordingly, Global consolidated GWF Energy for the first three quarters of 2003 as compared to the first three quarters of 2002 when it was accounted for under the equity method. Global recommenced recording GWF Energy under the equity method in the fourth quarter of 2003 when its ownership was reduced to less than 75%. Also contributing to the increase was a $19 million increase in revenue from Sociedad Austral de Electricidad S.A. (SAESA), a distribution facility in Chile, due to improved sales volume compared to same period in 2002. These increases were partially offset by the absence of $19 million in revenue from Empresa Distribuidora de Electricidad de Entre Rios S.A. (EDEERSA), in Argentina, which was abandoned in 2003.

For the year ended December 31, 2002, Global’s, Operating Revenues increased $148 million or 73% from the comparable period in 2001. The increase was primarily due to the acquisition in the second half of 2001 of SAESA and Electroandes, a Peruvian hydroelectric generation and transmission company, resulting in increased revenue of $97 million and $42 million, respectively. Also contributing

was $49 million related to the increase in revenues at Skawina, in which Global purchased a majority ownership in the second quarter of 2002. Revenues increased at the GWF Energy peaker plants by $25 million as the Hanford and Henrietta Peaker Plants became operational in the third quarter of 2001 and second quarter of 2002, respectively. Partially offsetting these increases was a decrease in revenue of $37 million at EDEERSA due to the economic crisis in Argentina. In addition, in 2001, Global recorded $76 million for the gain on the sale and withdrawal from the EPCP compared to the $47 million recorded for the withdrawal in 2002, resulting in a reduction of approximately $29 million.

Resources

For the year ended December 31, 2003, Resources’ Operating Revenues decreased $10 million or 4% from the comparable period in 2002. This decrease was primarily related to a $45 million net decrease in leveraged lease income and a $6 million decrease in realized income due to the termination of two leveraged leases in December 2002. Partially offsetting this decrease was the absence of an other than temporary impairment of non-publicly traded equity securities held within the leveraged buyout funds of $42 million that was recorded in 2002.

For the year ended December 31, 2002, Resources’ Operating Revenues increased $8 million from the comparable period in 2001. This increase was primarily due to $45 million from higher leveraged lease income. The increase was mostly offset by lower net investment results of $39 million, of which $37 million resulted from other than temporary impairments of non-publicly traded equity securities within certain leveraged buyout funds and other investments, and $9 million resulted from a net decrease in the gains on the sale of properties subject to leveraged leases. For further discussion of other than temporary impairments, see Note 16. Risk Management—Equity Securities of the Notes. There was also a net increase of $6 million associated with the change in the carrying value of publicly traded equity securities in certain leveraged buyout funds. The values of the publicly traded equity securities in 2002 decreased by $10 million compared to the same period in 2001.

Of the $45 million increase in leveraged lease income in 2002, $29 million resulted from a gain due to a recalculation of certain leveraged leases. A change in an essential assumption which affects the estimated total net income over the life of a leveraged lease requires a recalculation of the leveraged lease, from inception, using the revised information. The change in the net investment in the leveraged leases is recognized as a gain or loss in the year the assumption is changed. The change in assumption which occurred was related to a change in New Jersey tax rates applied in the leveraged lease calculations. This was due to the restructuring of Resources from a corporation to a limited liability company, which resulted in the ability to more efficiently match state tax expenses of an affiliate company with the state tax benefits associated with Resources’ lease portfolio. The remaining $16 million increase in leveraged lease income was due to additional investments in leveraged lease transactions in 2002 and 2001.

Operating Expenses

For the year ended December 31, 2003, Energy Holdings’ Operating Expenses decreased $450 million or 55% from the comparable period in 2002. This decrease was primarily due to Global’s $511 million write-down of investments in 2002, primarily in Argentina, as well as decreased operating expenses in 2003 compared to the same period in 2002. Also contributing were decreased expenses at Global of $28 million related to the abandonment of Global’s Argentine investments combined with lower labor and administrative costs due to reduced headcounts. Partially offsetting this decrease was an increase in operating expenses of $42 million from Skawina and $28 million from Salalah. Also offsetting the decrease was an increase of approximately $16 million from GWF Energy, primarily due to the consolidation of this project beginning in the fourth quarter of 2002.

For the year ended December 31, 2002, Energy Holdings’ Operating Expenses increased $626 million from the comparable period in 2001, primarily due to the investment write-down in 2002 discussed above. In addition to the write-down, Operating Expenses, increased $115 million for the year ended 2002 compared to 2001 primarily due to an increase at SAESA of $64 million and Empresa de Electricidad de los Andes S.A. (Electroandes) of $20 million, two acquisitions that occurred in the

second half of 2001 and Skawina of $45 million which became operational in 2002. Partially offsetting these increases were decreased operating expenses at EDEERSA which was accounted for under the equity method of accounting for the second half of 2002.

Income from Equity Method Investments

For the year ended December 31, 2003, Energy Holdings’ Income from Equity Method Investments decreased by $5 million or 4% from the comparable period in 2002. This decrease was primarily due to lower earnings in 2003 of $17 million at GWF Energy, which was recorded as a consolidated company for the first three quarters in 2003, as well as decreased earnings at Chilquinta of $4 million. Partially offsetting this decrease was improved earnings at TIE of $14 million related to PPA’s entered into in early 2003 and improved market conditions in Texas.

For the year ended December 31, 2002, Energy Holdings’ Income from Equity Method Investments decreased by $59 million or 33% from the comparable period in 2001. The decrease is due to lower earnings from Global’s Argentine investments in 2002 of $26 million due to the economic crisis in Argentina, which led to Global’s abandonment of its assets in Argentina. The decrease also resulted from reduced earnings of $21 million at the GWF facilities and a $17 million decrease at TIE, both due to lower energy prices in those markets. Also contributing to this decrease were operational losses at Prisma of $5 million and reduced earnings at PPN of $3 million. Partially offsetting these decreases were increased earnings at GWF Energy of $24 million related to the Hanford and Henrietta Peaker Plants, which became operational in the third quarter of 2001 and second quarter of 2002, respectively.

Other Income

For the year ended December 31, 2003, Energy Holdings’ Other Income decreased by $6 million from the comparable period in 2002. This decrease is primarily due to the absence of favorable changes in fair value mainly relating to foreign exchange contracts held by Energy Holdings.

For the year ended December 31, 2002, Energy Holdings’ Other Income increased $22 million, from the comparable period in 2001. This increase was primarily driven by $11 million of net gains on foreign exchange contracts from SAESA, with no comparable amount in 2001, and a $14 million gain on the early retirement of debt in 2002.

Other Deductions

For the year ended December 31, 2003, Energy Holdings’ Other Deductions decreased by $72 million from the comparable period in 2002. The decrease was largely due to a $77 million foreign currency transaction loss during 2002, which primarily related to Global’s Argentine investments.

For the year ended December 31, 2002, Energy Holdings’ Other Deductions increased $60 million from the comparable period in 2001 primarily due to higher foreign currency exchange losses, primarily due to the remeasuring of the U.S. Dollar denominated debt relative to the devaluing Argentine Peso, which resulted in a loss of $66 million.

Interest Expense

For the year ended December 31, 2003, Energy Holdings’ Interest Expense increased by $1 million or 1% from the comparable period in 2002.

For the year ended December 31, 2002, Energy Holdings’ Interest Expense increased $34 million or 19% from the comparable period in 2001. The increase was the result of issuing $135 million of 8.625% Senior Notes in July 2002 and an increase in project level debt at Global. The increase was partially offset by the repayments of borrowings under the revolving credit facilities.

Income Taxes

For the year ended December 31, 2003, Energy Holdings’ Income Taxes from continuing operations increased $203 million from the comparable period in 2002. This increase is primarily

attributed to increased pre-tax income for the year ended December 31, 2003, as compared to pre-tax losses in the same period in 2002. The pre-tax losses in 2002 resulted from the write-off of $511 million, primarily related to investments in Argentina.

For the year ended December 31, 2002, Energy Holdings had Income Tax benefits of $144 million, compared to $58 million of Income Tax Expense in 2001. The tax benefits in 2002 resulted primarily from the write-offs recorded during 2002, which resulted in a pre-tax loss.

Loss From Discontinued Operations

CPC

Global has a 60% ownership interest in CPC which owns and operates the Rades Power Plant, an electric generation facility located in Tunisia. In December 2003, Global entered into a purchase and sale agreement related to its majority interest in CPC for approximately $43 million, plus interest. Global has reduced its carrying value of CPC to its fair value less cost to sell and recorded a loss on disposal for the year ended December 31, 2003 of $23 million (after tax). The results of operations of these discontinued operations for the years ended December 31, 2003, 2002 and 2001 yielded additional (after tax) losses of $1 million and income of $1 million and $4 million, respectively. See Note 5. Discontinued Operations of the Notes.

Energy Technologies

During 2003, Energy Holdings re-evaluated the carrying value of Energy Technologies’ assets and liabilities and determined that market conditions required an additional write-down to fair value less cost to sell. Energy Holdings recorded an additional loss on disposal of Energy Technologies of $9 million, net of a $3 million tax benefit.

In September 2003, Energy Holdings completed the sale of the remaining companies of Energy Technologies. The results of operations of these discontinued operations for the years ended December 31, 2003, 2002 and 2001 yielded additional (after-tax) losses of $11 million, $21 million and $23 million, respectively. See Note 5. Discontinued Operations of the Notes.

Tanir Bavi

In the fourth quarter of 2002, Global sold its 74% interest in Tanir Bavi, a 220 MW barge mounted, combined-cycle generating facility in India. Global reduced the carrying value of Tanir Bavi to the contracted sales price of $45 million and recorded a loss on disposal of $14 million (after-tax) for the year ended December 31, 2002. The operating results of Tanir Bavi for the years ended December 31, 2002 and December 31, 2001 yielded (after tax) income of $5 million and $7 million, respectively. See Note 5. Discontinued Operations of the Notes.

Cumulative Effect of Change in Accounting Principle

In 2002, Energy Holding finalized the evaluation of the effect of adopting SFAS 142 on its recorded amount of goodwill. Under this standard, PSEG was required to complete an impairment analysis of its recorded goodwill and record any resulting impairment. The total amount of goodwill impairments was $121 million, net of tax of $66 million and was comprised of $36 million (after-tax) at EDEERSA, $35 million (after-tax) at RGE, $32 million (after-tax) at Energy Technologies and $18 million (after-tax) at Tanir Bavi. All of the goodwill on these companies, other than RGE, was fully impaired. In accordance with SFAS 142, this impairment charge was recorded as of January 1, 2002 as a component of the Cumulative Effect of a Change in Accounting Principle and is reflected in the Consolidated Statement of Operations for the year ended December 31, 2002. See Note 3. Recent Accounting Standards of the Notes.

In 2001, Energy Holdings adopted SFAS 133, which established accounting and reporting standards
for derivative instruments. Energy Holdings recorded an after-tax gain of $10 million as a result of adopting SFAS 133.

Other

Global

The following table summarizes the net contribution to Earnings Before Interest and Taxes (EBIT) by Global’s projects in the following regions for the years ended December 31, 2003, 2002 and 2001.

	For the Years Ended December 31,
Earnings Before Interest and Taxes (EBIT)	2003			2002			2001
	(Millions)
North America	$	87		$	76		$	87
Latin America
Chilquinta		28			33			32
Electroandes		28			25			(1	)
LDS		19			16			16
RGE		17			6			5
SAESA		55			51			21
Other(A)		1			(555	)		46
Total Latin America		148			(424	)		119
Asia Pacific		9			7			9
Europe		24			(18	)		(3	)
India		9			1			4
EBIT		277			(358	)		216
Interest Expense(B)		(119	)		(118	)		(81	)
Income (Loss) Before Income Taxes	$	158		$	(476	)	$	135

______________

(A)

Primarily relates to investments in Argentina which were abandoned in 2002.

(B)

For the consolidated projects above, interest associated with nonrecourse debt totaled $31 million, $26 million and $13 million for the years ended December 31, 2003, 2002 and 2001, respectively.

For additional information, see Note 23. Financial Information by Business Segment of the Notes.

LIQUIDITY AND CAPITAL RESOURCES

The following discussion of liquidity and capital resources is on a consolidated basis for PSEG, noting the uses and contributions of PSEG’s three direct operating subsidiaries, PSE&G, Power and Energy Holdings.

Financing Methodology

PSEG, PSE&G, Power and Energy Holdings

Capital requirements for PSE&G, Power and Energy Holdings are met through liquidity provided by internally generated cash flow and external financings. Although earnings growth has moderated, PSEG expects to be able to fund existing commitments, reduce debt and meet dividend requirements using internally generated cash. PSEG, Power and Energy Holdings from time to time make equity contributions or otherwise provide credit support to their respective direct and indirect subsidiaries to provide for part of their capital and cash requirements, generally relating to long-term investments. PSEG does not intend to contribute additional equity to Energy Holdings.

At times, PSEG utilizes intercompany dividends and intercompany loans (except however, that PSE&G may not, without prior BPU approval, make loans to its parent or to affiliates that are not its direct subsidiaries) to satisfy various subsidiary or parental needs and efficiently manage short-term cash. Any excess funds are invested in short-term liquid investments.

External funding to meet PSEG’s and PSE&G’s needs and a majority portion of the requirements of Power and Energy Holdings consist 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.

As discussed below, depending on the particular company, external financing may consist of public and private capital market debt and equity transactions, bank revolving credit and term loans, commercial paper and/or project financings. Some of these transactions involve special purpose entities (SPEs), formed in accordance with applicable tax and legal requirements in order to achieve specified beneficial financial advantages, such as favorable legal liability treatment. PSEG consolidates SPE’s, as applicable, in accordance with Financial Accounting Standards Board (FASB) Interpretation No. 46, “Consolidation of Variable Interest Entities (VIEs)”(FIN 46). See Note 3. Recent Accounting Standards of the Notes.

The availability and cost of external capital could be affected by each entity’s performance, as well as by the performance of their respective subsidiaries and affiliates. This could include the degree of structural separation between PSEG and its subsidiaries 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.

Over the next several years, PSEG, PSE&G, Power and Energy Holdings may be required to extinguish or refinance maturing debt and to the extent there is not sufficient internally generated funds may incur additional debt and/or provide equity to fund investment activities. 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 adversely affect PSEG’s, PSE&G’s, Power’s and Energy Holdings' respective financial condition, results of operations and net cash flows.

From time to time, PSEG, PSE&G, Power and Energy Holdings may repurchase portions of their respective debt securities using funds from operations, asset sales, commercial paper, debt issuances, equity issuances and other sources of funding and may make exchanges of new securities, including common stock, for outstanding securities. Such repurchases may be at variable prices below, at or above prevailing market prices and may be conducted by way of privately negotiated transactions, open-market purchases, tender or exchange offers or other means. PSEG, PSE&G, Power and Energy Holdings may utilize brokers or dealers or effect such repurchases directly. Any such repurchases may be commenced or discontinued at any time without notice.

Power and Energy Holdings

A portion of the financing for Global’s projects and investments is normally provided by non-recourse project financing transactions. These consist of loans from banks and other lenders that are typically secured by project assets and/or cash flows. Power’s projects in Ohio and Indiana currently have similar financing. Nonrecourse transactions generally impose no material obligation on the parent-level investor to repay any debt incurred by the project borrower. The consequences of permitting a project-level default includes loss of any invested equity by the parent. However, in some cases, certain obligations relating to the investment being financed, including additional equity commitments, may be guaranteed by Global, Energy Holdings and/or Power for their respective subsidiaries. PSEG has not currently provided any guarantees or credit support to Power and does not provide guarantees or credit support to Energy Holdings or its subsidiaries.

Operating Cash Flows

PSEG

For the year ended December 31, 2003, PSEG’s operating cash flow increased by approximately $135 million from $1.3 billion to $1.4 billion, as compared to the year ended December 31, 2002 due to net increases from its subsidiaries as discussed below.

PSE&G

PSE&G’s operating cash flow decreased approximately $225 million from $830 million to $605 million for the year ended December 31, 2003, as compared to the year ended December 31, 2002. The 2002 operating cash flow was abnormally high primarily due to the sale of the gas inventory totaling approximately $415 million in 2002, $183 million of which related to PSE&G’s sale of the gas supply business to Power. Working capital needs also increased during 2003 due to changes in the over/under collected balances of PSE&G’s energy clauses and increased Accounts Receivable balances resulting from higher billings.

Power

Power’s operating cash flow increased approximately $163 million from $417 million to $580 million for the year ended December 31, 2003, as compared to the year ended December 31, 2002. The 2002 operating cash flow was abnormally low, due to the purchase of the gas contracts from PSE&G in May 2002 for approximately $183 million and gas storage volume requirements, including higher gas prices, to meet its BGSS and generation requirements in 2002. However, higher gas prices in 2003 led to higher working capital requirements for fuels than in 2002.

Energy Holdings

Energy Holdings’ operating cash flow increased approximately $188 million from $108 million to $296 million for the year ended December 31, 2003, as compared to the year ended December 31, 2002. This increase is primarily related to increased earnings and realization of deferred tax assets, partially offset by a $115 million tax payment in the first quarter of 2003 related to two leveraged lease transactions at Resources with affiliates of TXU-Europe that were terminated in the fourth quarter of 2002 and other miscellaneous items. Also, Global received a $137 million return of capital from its investment in GWF Energy that is reflected in financing activities rather than operating cash flows as that project had been consolidated at that time.

PSEG, PSE&G, Power and Energy Holdings

The cash flow metric PSEG uses to manage the business is cash available to pay down recourse debt (i.e., excess cash). This metric is calculated by taking PSEG’s operating cash flows, less investing activities, less dividends and adjusted for the operating and investing activities of consolidated subsidiaries of Energy Holdings that do not affect its liquidity position, such as capital expenditures made by SAESA that are funded locally, rather than through Global.

In 2003, PSEG did not achieve its target of up to $200 million in excess cash due to increased working capital requirements of about $200 million at PSE&G and Power driven by increases in gas prices and because of the delay of securitization financing at PSE&G. In the future, PSEG expects operating cash flows to be sufficient to fund the majority of future capital requirements and dividend payments. PSEG expects that cash available to pay down recourse debt will increase substantially in the later part of its business plan as capital expenditures are expected to decrease materially after 2005 when the current construction program at Power is completed.

Debt Covenants

PSEG, PSE&G, Power and Energy Holdings

PSEG’s, PSE&G’s, Power’s and Energy Holdings’ respective credit agreements generally contain customary provisions under which the lenders could refuse to advance loans in the event of a material adverse change in the borrower’s business or financial condition.

As explained in detail below, 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 the respective future financial position, level of earnings and cash flows of PSEG, PSE&G, Power and Energy Holdings, as to which no assurances can be given. The ratios presented below are for the benefit of the investors of the related securities to which the covenants apply. They are not intended as a financial performance or liquidity measure. The debt underlying the preferred securities of PSEG, which is presented in Long-Term Debt in accordance with FIN 46, is not included as debt when calculating these ratios, as provided for in the various credit agreements.

PSEG

Financial covenants contained in PSEG’s credit facilities include a ratio of debt (excluding non-recourse project financings, securitization debt and debt underlying preferred securities and including commercial paper and loans, certain letters of credit and similar instruments) to total capitalization covenant. This covenant requires that at the end of any quarterly financial period, such ratio not be more than 70.0%. As of December 31, 2003, PSEG’s ratio of debt to capitalization (as defined above) was 57.0%. PSEG expects to continue to meet the financial covenants necessary to maintain its credit ratings.

PSE&G

Financial covenants contained in PSE&G’s credit facilities include a ratio of long-term debt (excluding securitization debt and long-term debt maturing within one year) to total capitalization covenant. This covenant requires that at the end of any quarterly financial period, such ratio will not be more than 65.0%. As of December 31, 2003, PSE&G’s ratio of long-term debt to total capitalization (as defined above) was 54.5%.

In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements, provided that its ratio of earnings to fixed charges calculated in accordance with its Mortgage is at least 2:1, and/or against retired Mortgage Bonds. As of December 31, 2003, PSE&G’s Mortgage coverage ratio was 3:1 and the Mortgage would permit up to approximately $1.5 billion aggregate principal amount of new Mortgage Bonds to be issued against previous additions and improvements.

PSEG and Power

Financial covenants contained in the PSEG/Power joint and several credit facility include a ratio of debt to total capitalization for each specific borrower. Where PSEG is the borrower, the covenant described above in PSEG is applicable. Where Power is the borrower, a debt (excluding non-recourse project financings and including loans, certain letters of credit and similar instruments) to total capitalization, adjusted for the $986 million Basis Adjustment (see Consolidated Balance Sheets), covenant applies. This covenant requires that at the end of any quarterly financial period, such ratio will not exceed 65.0%. As of December 31, 2003, Power’s ratio of debt to capitalization (as defined above) was 44.7%.

Energy Holdings

In April 2003, Energy Holdings issued $350 million of Senior Notes which contain financial covenants that include debt incurrence tests consisting of a debt service coverage test and a ratio of

consolidated recourse indebtedness to recourse capitalization test, which covenants require that Energy Holdings will not incur additional consolidated recourse indebtedness, other than certain permitted indebtedness, unless, on a pro forma basis, giving effect to the incurrence of the additional consolidated recourse indebtedness: (i) the debt service coverage ratio would be at least 2 to 1 and (ii) the ratio of consolidated recourse indebtedness to recourse capitalization would not exceed 0.60 to 1. Certain permitted indebtedness, such as permitted refinancings and borrowings are excluded from the requirements under this test. The provisions of the Senior Notes also restrict Energy Holdings from selling assets with a net book value greater than 10% of its assets in any four consecutive quarters, unless the proceeds are used to reduce debt of Energy Holdings or its subsidiaries or are retained by Energy Holdings.

Energy Holdings entered into a new $200 million three-year bank revolving credit agreement in October 2003 with a covenant requiring the ratio of Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA) to fixed charges to be greater than 1.75x. As of December 31, 2003, Energy Holdings’ coverage of this covenant was 2.60x. Additionally, Energy Holdings must maintain a ratio of net debt to EBITDA of less than 5.25. As of December 31, 2003, Energy Holdings’ ratio under this covenant was 3.87. Energy Holdings is a co-borrower under this facility with Global and Resources, which are joint and several obligors. The terms of the agreement include a pledge of Energy Holdings’ membership interest in Global, restrictions on the use of proceeds related to material sales of assets and the satisfaction of certain financial covenants. Cash proceeds from asset sales in excess of 5% of total assets of Energy Holdings during any 12-month period must be used to repay any outstanding amounts under the credit agreement. Cash proceeds in excess of 10% must be retained by Energy Holdings or used to repay the debt of Energy Holdings, Global or Resources.

Energy Holdings has been informed that its indirect subsidiary, CPC, has incurred a non-payment related default under its non-recourse project financing. There are no cross-defaults associated with this technical default. CPC is seeking a waiver and although no acceleration of the approximately $160 million of outstanding project debt is expected, no assurances can be given.

Cross Default Provisions

PSEG, PSE&G, Power and Energy Holdings

The PSEG credit agreements contain default provisions under which a default by it, PSE&G or Power in an aggregate amount of $50 million or greater would result in a default and the potential acceleration of payment under those agreements.

PSEG’s bank credit agreements and note purchase agreements (collectively, Credit Agreements) related to its private placement of debt contain cross default provisions under which certain payment defaults by PSE&G or Power, certain bankruptcy events relating to PSE&G or Power, the failure by PSE&G or Power to satisfy certain final judgments or the occurrence of certain events of default under the financing agreements of PSE&G or Power, would each constitute an event of default under the PSEG Credit Agreements. It is also an event of default under the PSEG Credit Agreements if PSE&G or Power ceases to be wholly-owned by PSEG.

PSEG removed Energy Holdings from all cross default provisions effective with the cancellation of Energy Holdings’ $495 million revolving credit agreement in September 2003. In October 2003, Energy Holdings entered into a new three-year bank revolving credit agreement in the amount of approximately $200 million that does not include PSEG-level covenants other than the maintenance of ownership of at least 80% of the capital stock of Energy Holdings.

PSE&G

PSE&G’s Mortgage has no cross-defaults. The PSE&G Medium-Term Note Indenture has a cross-default to the PSE&G Mortgage. The credit agreements have cross-defaults under which a default by PSE&G in the aggregate of $50 million or greater would result in an event of default and the potential acceleration of payment under the credit agreements.

Power

The Power Senior Debt Indenture contains a default provision under which a default by it, Nuclear, Fossil or ER&T in an aggregate amount of $50 million would result in an event of default and the potential acceleration of payment under the indenture. There are no cross-defaults within Power’s indenture from PSEG, Energy Holdings or PSE&G.

Energy Holdings

Energy Holdings’ Credit Agreement and Senior Note Indenture contain default provisions under which a default by it, Resources or Global in an aggregate amount of $25 million or greater would result in an event of default and the potential acceleration of payment under those agreements or the Indenture.

Ratings Triggers

PSEG, PSE&G, Power and Energy Holdings

The debt indentures and credit agreements of PSEG, PSE&G, Power and Energy Holdings do not contain any material “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, any one or more of the affected companies may be subject to increased interest costs on certain bank debt and certain collateral requirements.

PSE&G

In accordance with the BPU credit requirements under the BGS contracts that PSE&G enters into with suppliers, PSE&G is required to maintain an investment grade credit rating. If PSE&G were to lose its investment grade rating, PSE&G would be required to file with the BPU a plan to assure continued payment for the BGS requirements of its customers.

Power

In connection with its energy marketing and trading activities, Power must meet certain credit quality standards 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 materially impact the cost of its energy trading activities. In addition, all master agreements and other supply contracts contain margin and/or other collateral requirements that, as of December 31, 2003, could require Power to post additional collateral of approximately $377 million if Power were to lose its investment grade credit rating and all counterparties to contracts in which Power is “out-of-the money” were entitled to and called for collateral. Providing this credit support would increase Power’s costs of doing business and could limit Power’s ability to successfully conduct its energy trading operations. See Note 17. Commitments and Contingent Liabilities of the Notes.

Energy Holdings

Energy Holdings and Global posted letters of credit of approximately $9 million and $35 million for certain of their equity commitments in September 2003 and October 2003, respectively, as a result of Energy Holdings’ ratings falling below investment grade. The letters of credit totaling $35 million issued in October 2003 have been reduced to approximately $10 million as of December 31, 2003. Under existing agreements, no further letters of credit will need to be posted should there be a future downgrade.

Credit Ratings

PSEG, PSE&G, Power and Energy Holdings

The current ratings of securities of PSEG and its subsidiaries are shown below and reflect the respective views of the rating agencies. Any downward revision or withdrawal may adversely affect the market price of PSEG’s, PSE&G’s, Power’s and Energy Holdings’ securities and serve to increase those companies’ cost of capital and limit their access to capital. All ratings have a stable outlook unless otherwise noted. (N) denotes a negative outlook. There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances so warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security.

The financial objectives for PSEG include maintaining credit ratings for each of PSEG, PSE&G, Power and Energy Holdings. To accomplish this, PSEG expects to improve its funds from operations and interest coverage ratios and continue to lower its leverage ratio over the planning period. Failure to meet these targets could lead to a lower credit rating.

In the fourth quarter of 2003, Standard & Poor’s (S&P) affirmed the corporate credit ratings of PSEG, PSE&G and Power, and downgraded the credit rating of Energy Holdings from BBB- to BB-. Moody’s Investors Service (Moody’s) similarly has recently affirmed the credit ratings of PSEG, PSE&G and Power and downgraded Energy Holdings’ credit rating from Baa3 to Ba3. These actions concluded the review for possible downgrade of Power and Energy Holdings that was initiated by Moody’s in June 2003. On September 26, 2003, Moody’s confirmed PSEG’s P2 commercial paper rating. The current ratings of securities of PSEG and its subsidiaries are shown below:

	Moody’s(A)	S&P(B)	Fitch(C)
PSEG:
Preferred Securities	Baa3(N)	BB+	BBB(N)
Commercial Paper	P2(N)	A2	Not Rated
PSE&G:
Mortgage Bonds	A3	A–	A(N)
Preferred Securities(D)	Baa3	BB+	BBB+(N)
Commercial Paper	P2	A2	F1
Power:
Senior Notes	Baa1	BBB	BBB+
Energy Holdings:
Senior Notes	Ba3(N)	BB–	BBB–

______________

(A)

Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P-1 (highest) to NP (lowest) for short-term securities.

(B)

S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A-1 (highest) to D (lowest) for short-term securities.

(C)

Fitch ratings range from AAA (highest) to D (lowest) for long-term securities and F-1 (highest) to D (lowest) for short-term securities.

(D)

Rating for PSE&G Cumulative Preferred Stock without Mandatory Redemption.

Short-Term Liquidity

PSEG, PSE&G, Power and Energy Holdings

As of December 31, 2003, PSEG and its subsidiaries had a total of approximately $1.9 billion of committed credit facilities with approximately $1.5 billion of available liquidity under these facilities, supplemented by cash investments of approximately $200 million. In addition to this amount, PSEG and PSE&G have access to certain uncommitted credit facilities. Neither PSEG nor PSE&G had any loans outstanding under these facilities as of December 31, 2003. Each facility is restricted to availability and use to the specific companies as listed below.

Company	Expiration Date	Total Facility		Primary Purpose	Usage at 12/31/2003			Available Liquidity at 12/31/2003
	(Millions)
PSEG:
364-day Credit Facility	March 2004	$	350	CP Support	$	299		$	51
5-year Credit Facility	March 2005	$	280	CP Support	$	—		$	280
3-year Credit Facility	December 2005	$	350	CP Support/	$	10	(C)	$	340
				Funding/Letters
				of Credit
Uncommitted Bilateral Agreement	N/A		N/A	Funding	$	—			N/A
PSE&G:
364-day Credit Facility	June 2004	$	200	CP Support	$	—		$	200
3-year Credit Facility	June 2005	$	200	CP Support	$	—		$	200
Uncommitted Bilateral Agreement	N/A		N/A	Funding	$	—			N/A
PSEG and Power:
364-day Credit Facility(A)	March 2004	$	250	CP Support/ Funding	$	—		$	250
Power:
3-year Credit Facility	August 2005	$	25	Funding/Letters	$	19	(C)	$	6
				of Credit
Energy Holdings:
3-year Credit Facility(B)	October 2006	$	200	Funding/	$	56	(C)	$	144
				Letters of
				Credit

______________

(A)

PSEG/Power co-borrower facility

(B)

The facility could be reduced to a total of $100 million on June 30, 2004 if available liquidity during the period, after repayment of the Energy Holdings’ Senior Notes due in February 2004 to June 30, 2004 does not reach $100 million for 15 days.

(C)

These amounts relate to letters of credit outstanding.

Energy Holdings

As of December 31, 2003, in addition to amounts outstanding under Energy Holdings’ credit facilities shown in the above table, subsidiaries of Global had $35 million of non-recourse short-term financing at the project level. As of December 31, 2003, Energy Holdings had loaned $300 million of excess cash to PSEG. For information regarding affiliate borrowings, see Note 26. Related-Party Transactions of the Notes.

External Financings

PSEG

On October 7, 2003, PSEG issued $356 million (approximately 8.8 million shares) of common equity. Proceeds from the offering were used for the repayment of short-term debt.

In 2002, PSEG began issuing shares of its common stock under its Dividend Reinvestment Program and Employee Stock Purchase Plan, rather than purchasing shares on the open market. For the year ended December 31, 2003, PSEG issued approximately 2.1 million shares for approximately $85 million pursuant to these plans.

Dividend payments on common stock for the year ended December 31, 2003 were $2.16 per share and totaled approximately $493 million. In January 2004, PSEG’s Board of Directors approved an increase in the quarterly dividend by $0.01 per share, from $0.54 to $0.55. Future dividends declared will be dependent upon PSEG’s future earnings, cash flows, financial requirements, alternative investment opportunities and other factors.

PSE&G

In January 2003, PSE&G issued $150 million of 5.000% Medium-Term Notes due 2013. The proceeds of this issuance were used to repay $150 million of 6.875% Series MM Mortgage Bonds which matured in January 2003.

Also in January 2003, PSEG contributed $170 million to PSE&G to support its capital structure. PSE&G paid a common stock dividend of approximately $200 million to PSEG in September 2003.

In June 2003, $150 million of 8.875% Series DD Mortgage Bonds matured.

In September 2003, PSE&G issued $300 million of 5.375% Medium-Term Notes due 2013. The proceeds of this issuance were used to both repay short-term debt incurred to pay for the previously matured $150 million of Series DD Mortgage Bonds, as well as to reduce other short-term debt.

In November 2003, PSE&G issued $250 million of 4.000% Medium-Term Notes due 2008. The proceeds of this issuance were used to retire $60 million and $95 million of its subordinated debt which supported cumulative Monthly Income Preferred Securities and cumulative Quarterly Income Preferred Securities, respectively, in December as detailed below and to reduce short-term debt.

During 2003, PSE&G Transition Funding LLC repaid approximately $129 million of its transition bonds.

On December 31, 2003, PSE&G Capital, L.P., a limited partnership of which PSE&G is the sole general partner, redeemed all of its $60 million outstanding 8.000% Cumulative Monthly Income Preferred Securities, Series B at a price of $25 per preferred security for approximately $60 million.

On December 31, 2003, PSE&G Capital Trust II, a statutory trust of which PSE&G is the sole depositor, redeemed all of its $95 million outstanding 8.125% Cumulative Quarterly Income Preferred Securities, Series B at a price of $25 per preferred security for approximately $95 million.

In December 2003, PSE&G redeemed $64 million of its 5.700% First and Refunding Mortgage Bonds, Pollution Control Series L due 2028 (Series L Bonds) and $145 million of its 5.550% First and Refunding Mortgage Bonds, Pollution Control Series N due 2033 (Series N Bonds). Each of these series of mortgage bonds serviced and secured like principal amounts of pollution control revenue refunding bonds of The Pollution Control Financing Authority of Salem County, New Jersey (Salem Authority). The Series L Bonds and the Series N Bonds were refinanced through the issuance of new series of mortgage bonds that are multi-mode and that were initially issued in a floating rate 35-day auction mode. The Series L Bonds were refinanced by the issuance of $64 million of First and Refunding Mortgage Bonds, Pollution Control Series Y due 2028, with an initial auction rate of 1.100%. The Series N Bonds were refinanced by the issuance of three separate series of mortgage bonds: $50 million First and Refunding Mortgage Bonds, Pollution Control Series Z due 2033 with an initial rate of 1.140%, $50 million First and Refunding Mortgage Bonds, Pollution Control Series AA due 2033 with an initial rate of 1.100%, and a $45.2 million First and Refunding Mortgage Bonds, Pollution Control Series AB due

2033 with an initial rate of 1.150%. Similarly, these new mortgage bonds service and secure like principal amounts of pollution control revenue refunding bonds of the Salem Authority.

Power

In December 2003, PSEG contributed approximately $150 million of equity to Power.

In December 2003, Power issued $300 million of 5.500% Senior Notes due 2015. The proceeds of this issuance were used to repay intercompany debt and for general corporate purposes.

Energy Holdings

In April 2003, Energy Holdings, in a private placement, issued $350 million of 7.750% Senior Notes due in 2007. The proceeds were used in part to repay PSEG Capital’s remaining $252 million of 6.250% Medium-Term Notes that matured in May 2003. The remaining proceeds from the sale of the Senior Notes were used for general corporate purposes. In July 2003, Energy Holdings completed an exchange of the Senior Notes for registered securities.

In September 2003, Energy Holdings repurchased approximately $12 million of its outstanding Senior Notes. In February 2004, Energy Holdings redeemed the remaining $267 million of these Senior Notes at maturity. In addition, Energy Holdings expects to redeem approximately $75 million of preferred securities held by PSEG in the first quarter of 2004.

In addition, as detailed below, a number of entities in which Global has invested engaged in financing transactions, each of which is non-recourse to Global and Energy Holdings:

During January and February of 2003, Sociedad Austral de Electricidad S.A. (SAESA) and Empresa Electrica de la Frontera S.A. (Frontel), two distribution companies in Chile, refinanced certain short-term obligations through a combination of bonds, a syndicated bank facility and equity from Global. SAESA issued two series of bonds equivalent to $117 million with respective final maturities in 2009 and 2023. Frontel executed a syndicated loan facility equivalent to $23 million with final maturity in 2010. In addition, during January 2003, Global made equity contributions to SAESA and Frontel totaling $55 million.

In March 2003, Electroandes, a generation facility in Peru, refinanced a $100 million bridge loan with a $70 million seven-year amortizing facility and two $15 million one-year facilities (each guaranteed by Energy Holdings). Additionally, in June 2003, Electroandes sold $50 million of bonds in the local market. These bonds have a 6.440% coupon and mature in 2013. The bonds include a five-year grace period on principal payments. Proceeds from this bond issue were used to repay the two $15 million one-year facilities, at which time the related guarantees by Energy Holdings were eliminated, along with $20 million of the $70 million seven-year facility.

In September 2003, Electroandes sold an additional $30 million of Peruvian Sol denominated bonds with a coupon of 6.000%. The proceeds from this bond issue were used to repay $30 million of the $50 million balance of the seven-year facility. In the fourth quarter of 2003, Electroandes completed the refinancing of the final $20 million of the seven-year facility with a ten-year bond issued at 5.875%.

In May 2003, GWF Power Systems, L.P. (GWF) and Hanford L.P. (Hanford) closed on a $55 million syndicated bank loan along with an additional $7 million letter of credit facility. Interest on this bank loan is at LIBOR plus 2.000% through September 30, 2004 and LIBOR plus 2.250% thereafter. Global and Harbert Power (Harbert) each own 50% of GWF and Hanford. GWF and Hanford used the net proceeds from the bank loan to pay back investments from Global and Harbert. Global received a cash distribution of approximately $27 million in May 2003 and reduced its investment in GWF to $66 million as of September 30, 2003.

In September 2003, GWF Energy issued $226 million of 6.131% senior secured notes that mature on December 30, 2011. The note proceeds were used by GWF Energy to repay a $45 million bank loan that matured on September 30, 2003, to make distributions to its members and for general corporate purposes. GWF Energy also closed a $35 million letter of credit and working capital facility simultaneous with the issuance of the notes. The bank facility is available to GWF Energy to provide letters of credit to fund the debt service reserve account required by the notes’ indenture and to secure

project obligations. The portion of the bank facility that is not used to provide letters of credit may be used to provide working capital loans to GWF Energy up to a maximum of $7.5 million. GWF Energy has approximately $27 million of issued and undrawn letters of credit outstanding under the bank facility and approximately $8 million available for working capital loans and/or additional letters of credit, subject to the $7.5 million cap on working capital loans. GWF Energy made cash distributions to Global prior to September 30, 2003 of approximately $137 million from the proceeds of this financing.

As of December 31, 2003, RGE had total outstanding debt equivalent to approximately $240 million of which approximately $204 million matures over the next two years. RGE is currently in discussions with various financial institutions to obtain financing for approximately $35 million. Proceeds from these facilities will be used to refinance certain short-term obligations and to fund capital expenditures. Due to the macroeconomic conditions in Brazil, the country’s debt markets have become increasingly short term in nature, impacting RGE’s ability to refinance on a long-term basis, which could negatively impact RGE’s liquidity and increase their costs of borrowing. RGE’s current average interest rate is approximately 18%.

OCI Charge for Pension Liability

PSEG, PSE&G, Power and Energy Holdings

PSEG maintains certain pension plans for the benefit of its and its subsidiaries’ employees. Due to general market conditions in 2002, the master trust fund for PSEG’s pension plans experienced significant unrealized losses and deteriorated below the accumulated benefit obligation (ABO) of these plans. In accordance with SFAS No. 87, “Employers Accounting for Pensions” (SFAS 87), PSEG, PSE&G, Power and Energy Holdings were required to record a minimum pension liability on their respective Consolidated Balance Sheets as of December 31, 2002. As calculated under SFAS 87, a minimum pension liability was recorded because the ABO of the plan exceeded the fair value of the plan assets as of December 31, 2002. The excess of the ABO over the fair value of the plan assets was recorded as a charge to OCI within the equity section of the Consolidated Balance Sheets. The offsetting adjustment was recorded as a pension liability or as a reduction of certain pension plan intangible assets as applicable. The minimum pension liabilities totaling $289 million related to the qualified pension plans were reversed as of December 31, 2003, as the fair value of the pension plan assets exceeded the ABO. This was achieved by improved conditions in the financial markets, as well as contributions by the respective companies of approximately $210 million during 2003. In 2004, PSEG plans to contribute approximately $90 million to fund the pension plans. For additional information, see Note 21. Pension, Other Postretirement Benefit (OPEB) and Savings Plans of the Notes.

CAPITAL REQUIREMENTS

Forecasted Expenditures

PSEG, Power and Energy Holdings

PSEG, Power and Energy Holdings have materially reduced their respective capital expenditure forecasts in response to tightening market conditions resulting from market and lender concerns regarding the overall economy and the industry in particular, including an investor and rating agency focus on leverage ratios.

It is expected that the majority of each subsidiary’s capital requirements over the next five years will come from internally generated funds, with the balance to be provided through equity from PSEG (other than to Energy Holdings) and by the issuance of debt at the project level. Projected construction and investment expenditures, excluding nuclear fuel purchases, for PSEG’s subsidiaries for the next five years are as follows:

	2004		2005		2006			2007		2008
	(Millions)
PSE&G
Facilities Support	$	40	$	45	$	45	$		70	$	90
Environmental/Regulatory		20		15		20			20		20
Facility Replacement		160		135		150			145		155
System Reinforcement		90		100		90			95		90
New Business		150		145		150			155		155
Total PSE&G		460		440		455			485		510
Power
Non-recurring (new MWs and Environmental)		590		150		75			75		80
Maintenance		110		140		100			90		110
Total Power		700		290		175			165		190
Energy Holdings		40		30		15			20		20
Other		20		10		10			10		15
Total PSEG	$	1,220	$	770	$	655	$		680	$	735

PSE&G

PSE&G projects future capital needs for additions to its transmission and distribution systems to meet expected growth and to manage reliability.

Power

Power has revised its schedule for completion of several projects under development to provide better sequencing of its construction program with anticipated market demand. In 2003, Power made approximately $655 million of capital expenditures, primarily related to developing the Lawrenceburg, Indiana, Waterford, Ohio and Bethlehem, New York (Albany) sites and adding capacity to the Linden station in New Jersey. The Waterford, Ohio facility was placed in service in August 2003.

Energy Holdings

Energy Holdings’ capital needs in 2004 will be limited to fulfilling existing contractual and potential contingent commitments. The balance relates to capital requirements of consolidated subsidiaries, which will be financed from internally generated cash flow within the projects, from local sources on a non-recourse basis or discretionary investments at Energy Holdings.

In 2003, Energy Holdings invested approximately $307 million of capital expenditures, primarily related to capital projects at SAESA, Salalah, Elcho and the GWF Energy plants. This amount exceeded Energy Holdings’ original 2003 plan largely due to capital expenditures at Global’s

investments using internally generated funds or local financing, but is included in Energy Holdings’ capital expenditures as certain of these investments are consolidated. Approximately $133 million of this amount was funded by Energy Holdings’ equity contributions to Global primarily to fulfill existing commitments for projects in construction.

Disclosures about Long-Term Maturities, Contractual and Commercial Obligations and Certain Investments

The following tables, reflect PSEG’s and its subsidiaries’ contractual cash obligations and other commercial commitments in the respective periods in which they are due. In addition the table summarizes anticipated recourse and non-recourse debt maturities for the years shown. The chart below does not reflect debt maturities of non-consolidated investments. If those obligations were not able to be refinanced by the project, Energy Holdings may elect to make additional contributions in these investments. For additional information, see Note 15. Schedule of Consolidated Debt of the Notes.

Contractual Cash Obligations	Total Amounts Committed		Less Than 1 year		2–3 years		4–5 years		Over 5 years
					(Millions)
Short-Term Debt Maturities:
PSEG	$	299	$	299	$	—	$	—	$	—
Energy Holdings		2		2		—		—		—
Long-Term Debt Maturities:
Recourse Debt Maturities
PSEG (A)		1,462		—		98		558		806
PSE&G		3,330		286		272		363		2,409
Transition Funding (PSE&G)		2,222		137		302		331		1,452
Power		2,816		—		500		—		2,316
Energy Holdings		2,067		267		—		857		943
Non-Recourse Project Financing
Power		800		—		800		—		—
Energy Holdings		974		36		99		147		692
Capital Lease Obligations
PSEG		76		6		13		14		43
Power		18		1		2		4		11
Operating Leases
PSE&G		11		3		5		3		—
Energy Holdings		48		8		13		11		16
Services		8		1		2		2		3
Energy Related Purchase Commitments
Power		1,493		414		510		336		233
Restructuring Commitments
Power		6		6		—		—		—
Energy Holdings		4		4		—		—		—
Total Contractual Cash Obligations	$	15,636	$	1,470	$	2,616	$	2,626	$	8,924
Standby Letters of Credit
Power	$	74	$	74	$	—	$	—	$	—
Energy Holdings		56		51		5		—		—
Guarantees and Equity Commitments
Power		25		25		—		—		—
Energy Holdings		125		—		—		49		76
Total Commercial Commitments	$	280	$	150	$	5	$	49	$	76

	(A)	Includes debt supporting trust preferred securities of $1.2 billion.
	*	Power has also entered into contractual commitments for a variety of services for which annual amounts are not quantifiable. See Note 17, Commitments and Contingent Liabilities.

OFF BALANCE SHEET ARRANGEMENTS

Power

Power issues guarantees in conjunction with certain of its energy trading activities, see Note 17. Commitments and Contingent Liabilities of the Notes for further discussion.

Energy Holdings

Global has certain investments that are accounted for under the equity method in accordance with accounting principles generally accepted in the U.S. (GAAP). Accordingly, amounts recorded on the Consolidated Balance Sheets for such investments represent Global’s equity investment, which is increased for Global’s pro-rata share of earnings less any dividend distribution from such investments. The companies in which PSEG invests that are accounted for under the equity method have an aggregate $1.8 billion of debt on their combined, consolidated financial statements. PSEG’s pro-rata share of such debt is $800 million. This debt is non-recourse to PSEG, Energy Holdings and Global. PSEG is generally not required to support the debt service obligations of these companies. However, default with respect to this non-recourse debt could result in a loss of invested equity.

Resources has investments in leveraged leases that are accounted for in accordance with SFAS No. 13, “Accounting for Leases.” Leveraged lease investments generally involve three parties: an owner/lessor, a creditor and a lessee. In a typical leveraged lease financing, the lessor purchases an asset to be leased. The purchase price is typically financed 80% with debt provided by the creditor and the balance comes from equity funds provided by the lessor. The creditor provides long-term financing to the transaction, and is secured by the property subject to the lease. Such long-term financing is non- recourse to the lessor. As such, in the event of default, the leased asset, and in some cases the lessee, secure the loan. As a lessor, Resources has ownership rights to the property and rents the property to the lessees for use in their business operation. As of December 31, 2003, Resources’ equity investment in leased assets was approximately $1.4 billion, net of deferred taxes of approximately $1.6 billion. For additional information, see Note 12. Long-Term Investments of the Notes.

In the event that collectibility of the minimum lease payments to be received by the lessor is no longer reasonably assumed, the accounting treatment for some of the leases may change. In such cases, Resources may deem that a lessee has a high probability of defaulting on the lease obligation. Should Resources ever directly assume a debt obligation, the fair value of the underlying asset and the associated debt would be recorded on the Consolidated Balance Sheets instead of the net equity investment in the lease.

Energy Holdings have guaranteed certain obligations of their subsidiaries or affiliates related to certain projects. See Note 17. Commitments and Contingent Liabilities of the Notes for further discussion.

CRITICAL ACCOUNTING ESTIMATES

PSEG, PSE&G, Power and Energy Holdings

Under GAAP, there are many accounting standards that require the use of estimates, variable inputs and assumptions (collectively referred to as estimates) that are subjective in nature. Because of this, differences between the actual measure realized versus the estimate can have a material impact on results of operations, financial position and cash flows. The managements of PSEG, PSE&G, Power and Energy Holdings have each, respectively, determined that the following estimates are considered critical to the application of rules that relate to its business.

Accounting for Pensions

PSEG, PSE&G, Power and Energy Holdings account for pensions under SFAS 87. Pension costs under SFAS 87 are calculated using various economic and demographic assumptions. Economic assumptions include the discount rate and the long-term rate of return on trust assets. Demographic assumptions include projections of future mortality rates, pay increases and retirement patterns. In

2003, PSEG recorded pension expense of $147 million, compared to $89 million in 2002 and $58 million in 2001. Additionally, in 2003, PSEG and its respective subsidiaries contributed cash of approximately $210 million compared to cash contributions of $240 million in 2002, and $90 million in 2001.

PSEG’s discount rate assumption, which is determined annually, is based on the rates of return on high-quality fixed-income investments currently available and expected to be available during the period to maturity of the pension benefits. The discount rate used to calculate pension obligations is determined as of December 31 each year, PSEG’s SFAS 87 measurement date. The discount rate used to determine year-end obligations is also used to develop the following year’s net periodic pension cost. The discount rates used in PSEG’s 2002 and 2003 net periodic pension costs were 7.25% and 6.75%, respectively. PSEG’s 2004 net periodic pension cost was developed using a discount rate of 6.25%.

PSEG’s expected rate of return on plan assets reflects current asset allocations, historical long-term investment performance, and an estimate of future long-term returns by asset class using input from PSEG’s actuary and investment advisors, as well as long-term inflation assumptions. For 2002, and 2003, PSEG assumed a rate of return of 9.0% on PSEG’s pension plan assets. For 2004, PSEG has reduced the rate of return assumption to 8.75%.

As indicated above, the 2004 pension expense is calculated using a reduced discount rate of 6.25%, which is based on high-quality fixed-income rates as of December 31, 2003, and a reduced expected rate of return on plan assets of 8.75%. However, PSEG’s 2004 pension costs are expected to decrease significantly as a result of the material increase in the value of its pension funds during 2003. This increase was driven by PSEG’s contributions of approximately $210 million and a 2003 return of 25%.

Based on the above assumptions, PSEG has estimated net period pension costs of approximately $90 million and contributions of up to $100 million in 2004. As part of the business planning process, PSEG has modeled its future costs assuming an 8.75% rate of return and the return to a 6.75% discount rate for 2005 and beyond. Based on these assumptions, PSEG has estimated net period pension costs of approximately $60 million in 2005 and $50 million in 2006. Actual future pension expense and funding levels will depend on future investment performance, changes in discount rates, market conditions, funding levels relative to PSEG’s Pension Benefit Obligation (PBO) and ABO and various other factors related to the populations participating in PSEG’s pension plans.

The following chart reflects the sensitivities associated with a change in certain actuarial assumptions. The effects of the assumption changes shown below solely reflect the impact of that specific assumption.

Actuarial Assumption	Current	Change/ (Decrease)	As of December 31, 2003 Impact on Pension Benefit Obligation			Increase to Pension Expense in 2004
			(Millions)
Discount Rate	6.25%	(1%)		$	473	$81
Rate of Return on Plan Assets	8.75%	(1%)		$	—	$27

Accounting for Deferred Taxes

PSEG, PSE&G, Power and Energy Holdings provide for income taxes based on the asset and liability method required by SFAS No. 109, “Accounting for Income Taxes.” Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, as well as net operating loss and credit carryforwards.

PSEG, PSE&G, Power and Energy Holdings evaluate the need for a valuation allowance against their respective deferred tax assets based on the likelihood of expected future taxable income. PSEG, PSE&G, Power and Energy Holdings do not believe a valuation allowance is necessary; however, if the expected level of future taxable income changes or certain tax planning strategies become unavailable, PSEG, PSE&G, Power and Energy Holdings would record a valuation allowance through income tax expense in the period the valuation allowance is deemed necessary. Resources’ and Global’s ability to realize their deferred tax assets are dependent on PSEG’s subsidiaries’ ability to generate ordinary income and capital gains.

PSE&G

Unbilled Revenues

Electric and gas revenues are recorded based on services rendered to customers during each accounting period. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period. Unbilled usage is calculated in two steps. The initial step is to apply a base usage per day to the number of unbilled days in the period. The second step estimates seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms. The resulting usage is priced at current rate levels and recorded as revenue. A calculation of the associated energy cost for the unbilled usage is recorded as well. Each month the prior month’s unbilled amounts are reversed and the current month’s amounts are accrued. Using benchmarks other than those used in this calculation could have a material effect on the amounts accrued for in a reporting period. The resulting revenue and expense reflect the billed data less the portion recorded in the prior month plus the unbilled portion of the current month.

SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71)

PSE&G prepares its Consolidated Financial Statements in accordance with the provisions of SFAS 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 recognize 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. See Note 10. Regulatory Assets and Liabilities of the Notes for further discussion of these and other regulatory issues.

Power and PSEG

Nuclear Decommissioning Trust (NDT) Fund

Power accounts for the assets in the NDT Fund under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (SFAS 115). The assets in the NDT Fund are classified as available-for-sale securities and are marked to market with unrealized gains and losses recorded in OCI. Realized gains, losses, and dividend and interest income are recorded on Power’s and PSEG’s Statements of Operations under Other Income and Other Deductions. Unrealized losses that are deemed to be Other Than Temporarily Impaired (OTTI), as defined under SFAS 115, Emerging Issues Task Force 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” (EITF 03-1), and related interpretive guidance, will be charged against earnings rather than OCI. These factors, such as the length of time and extent to which the fair value is below carrying value, the potential for impairments of securities when the issuer or industry is experiencing significant financial difficulties and Power’s intent and ability to continue to hold securities, are used as indicators of the prospects of the securities to recover their value 10% test.

ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

PSEG, PSE&G, Power and Energy Holdings

The market risk inherent in PSEG’s, PSE&G’s, Power’s and Energy Holdings’ 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 Consolidated Financial Statements. It is the policy of each entity to use derivatives to manage risk

consistent with its respective business plans and prudent practices. PSEG, PSE&G, Power and Energy Holdings use a Risk Management Committee (RMC) comprised of executive officers who utilize an independent risk oversight function to ensure compliance with corporate policies and prudent risk management practices.

Additionally, PSEG, PSE&G, Power and Energy Holdings are exposed to counterparty credit losses in the event of non-performance or non-payment. PSEG has a credit management process, which is used to assess, monitor and mitigate counterparty exposure for PSEG and its subsidiaries. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on PSEG and its subsidiaries’ financial condition, results of operations or net cash flows.

Foreign Exchange Rate Risk

Energy Holdings

Global is exposed to foreign currency risk and other foreign operations risk that arise from investments in foreign subsidiaries and affiliates. A key component of this risk is that some of its foreign subsidiaries and affiliates utilize currencies other than the consolidated reporting currency, the U.S. Dollar. Additionally, certain of Global’s foreign subsidiaries and affiliates have entered into monetary obligations and maintain receipts/receivables in U.S. Dollars or currencies other than their own functional currencies. Primarily, Global is exposed to changes in the U.S. Dollar to Brazilian Real, Euro, Polish Zloty, Peruvian Nuevo Sol and the Chilean Peso exchange rates. With respect to the foreign currency risk associated with the Brazilian Real, there has already been significant devaluation since the initial acquisition of these investments, which has resulted in reduced U.S. Dollar earnings and cash flows relative to initial projections. However, there have been material improvements during 2003. Whenever possible, these subsidiaries and affiliates have attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in foreign exchange rates. Global also uses foreign currency forward, swap and option agreements, wherever possible, to manage risk related to certain foreign currency fluctuations.

As of December 31, 2003, the devaluing Brazilian Real has resulted in a cumulative $253 million loss of value which is recorded as a $228 million after-tax charge to OCI related to Global’s equity method investments in RGE. An additional devaluation in the December 31, 2003 Brazilian Real to the U.S. Dollar exchange rate of 10% would result in a $18 million change in the value of the investment in RGE and corresponding impact to OCI. In addition, Global had transactional exposure to the Real in which a 10% adverse change in the exchange rate would result in a loss to earnings of $3 million.

Additionally, Global has $64 million of Euro-denominated receivables subject to fluctuations in the U.S. Dollar to Euro exchange rate. If the December 31, 2003 Euro to U.S. Dollar exchange rate were to appreciate by 10%, Global would record a $6 million after-tax foreign currency transaction gain. If the December 31, 2003 Euro to U.S. Dollar exchange rate were to devalue by 10%, Global would record a $5 million after-tax foreign currency transaction loss.

Global also has net monetary positions in the Polish Zloty related to its consolidated investments in Elcho. If the December 31, 2003 Polish Zloty to U.S. Dollar exchange rate were to appreciate by 10%, Global would record a $4 million after-tax foreign currency transaction gain. If the December 31, 2003 Polish Zloty to U.S. Dollar exchange rate were to devalue by 10%, Global would record a $5 million after-tax foreign currency transaction loss.

Global has various other foreign currency exposures related to translation adjustments. In aggregate, a 10% devaluation in such foreign currencies would result in an after-tax charge to OCI of $93 million.

Commodity Contracts

PSEG and Power

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, Power enters into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties, to hedge its anticipated supply and demand differential. These contracts, in conjunction with owned electric generation capacity and demand obligations, make up the portfolio.

VaR Model

Power

Power uses value-at-risk (VaR) models to assess the market risk of its commodity businesses. The model for Power includes its owned generation and physical contracts, as well as fixed price sales requirements, load requirements and financial derivative instruments. VaR represents the potential gains or losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. Power estimates VaR across its commodity businesses.

Power manages its exposure at the portfolio level. Its portfolio consists of owned generation, load-serving contracts (both gas and electric), fuel supply contracts and energy derivatives designed to manage the risk around the differential between generation and load.

The RMC established a VaR threshold of $50 million for a one-week (5 business days) holding period at a 95% (two-tailed) confidence level. The RMC will be notified if the VaR reaches $40 million and the portfolio will be closely monitored. The Board of Directors of PSEG is notified if a VaR threshold of $75 million is reached.

The model is an augmented variance/covariance model adjusted for the delta of positions with a 95% two-tailed confidence level for a one-week holding period. The model is augmented to incorporate the non-log-normality of energy-related commodity prices, especially emissions and capacity and the non-stationary nature of energy volatility. In many commodities, the natural log of prices is normally distributed. This is not true of energy commodities which have a higher frequency of extreme events than would be predicted by a normal distribution. The model also assumes no hedging activity throughout the holding period, whereas Power actively manages its portfolio.

As of December 31, 2003, VaR was approximately $18 million, compared to the December 31, 2002 level of $7 million. As of December 31, 2003, Power’s load obligation is determined primarily by the results of the annual BGS auction. To maintain an actionable VaR and to match the terms of the auction, generation is modeled at 100% of its expected output through May 2004 and at one-third of the expected output from June 2004 through May 2006.

For the Year Ended December 31, 2003	Total VaR
	(Millions)
95% Confidence Level, Five-Day Holding Period, Two-Tailed:
Period End		$	18
Average for the Period		$	18
High		$	35
Low		$	9
99% Confidence Level, One-Day Holding Period, Two-Tailed:
Period End		$	11
Average for the Period		$	10
High		$	20
Low		$	5

Energy Holdings

In general, Energy Holdings manages its commodity exposure through long-term power purchase agreements. One notable exception is Global’s partial ownership of TIE, which owns two merchant energy plants that sell their output in the day ahead and forward market. As a result of this open

position, as of December 31, 2003, VaR was approximately $11 million, compared to the December 31, 2002 level of $4 million.

The model is a variance/covariance model with a two-tailed 95% confidence level for a one-week holding period. Expected energy output and fuel usage are modeled as forward obligations over a rolling 12-month period. The Electric Reliability Council of Texas (ERCOT) system is a closed system and is less liquid than the PJM. This lack of liquidity in ERCOT limits how far forward TIE is able to sell. This lack of liquidity also makes estimates of volatility and correlation less reliable.

Interest Rates

PSEG, PSE&G, Power and Energy Holdings

PSEG, PSE&G, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. PSEG’s, PSE&G, Power and Energy Holdings’ policy is to manage interest rate risk through the use of fixed and floating rate debt, interest rate swaps and interest rate lock agreements. PSEG, PSE&G, Power and Energy Holdings manage their respective interest rate exposures by maintaining a targeted ratio of fixed and floating rate debt. As of December 31, 2003, a hypothetical 10% change in market interest rates would result in a $3 million, $2 million and $2 million change in annual interest costs related to debt at PSE&G, Power and Energy Holdings, respectively. In addition, as of December 31, 2003, a hypothetical 10% change in market interest rates would result in a $5 million, $233 million, $118 million and $53 million change in the fair value of the debt of PSEG, PSE&G, Power and Energy Holdings, respectively.

Debt and Equity Securities

PSEG, PSE&G, Power and Energy Holdings

PSEG has approximately $2.7 billion invested in its pension plans. Although fluctuations in market prices of securities within this portfolio do not directly affect PSEG’s earnings in the current period, changes in the value of these investments could affect PSEG’s future contributions to these plans, its financial position if its ABO under its pension plans exceeds the fair value of its pension funds and future earnings as PSEG would earn a different return on the fund balance and could be required to adjust its assumed rate of return.

Power

Power’s NDT Fund is comprised of both fixed income and equity securities totaling $985 million as of December 31, 2003. The fair value of equity securities is determined independently each month by the Trustee. As of December 31, 2003, the portfolio was comprised of approximately $619 million of equity securities and approximately $344 million in fixed income securities. The fair market value of the NDT assets will fluctuate depending on the performance of equity markets. As of December 31, 2003, a hypothetical 10% change in the equity market would impact the value of the equity securities in the NDT Fund by approximately $61 million.

Power uses duration to measure the interest rate sensitivity of the fixed income portfolio. Duration is a summary statistic of the effective average maturity of the fixed income portfolio. The benchmark for the fixed income component of the NDT Fund is the Lehman Brothers Aggregate Bond Index, which currently has a duration of 4.5 years and a yield of 4.1%. The portfolio’s value will appreciate or depreciate by the duration with a 1% change in interest rates. As of December 31, 2003, a hypothetical 1% increase in interest rates would result in a decline in the market value for the fixed income portfolio of approximately $14 million.

Energy Holdings

Resources has investments in equity securities and limited partnerships. Resources carries its investments in equity securities at their 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.

As of December 31, 2003, Resources had investments in leveraged buyout funds of approximately $74 million, of which $25 million was comprised of public securities with available market prices and $49 million was comprised of privately held interests in certain companies. The potential change in fair value resulting from a hypothetical 10% change in quoted market prices of the publicly traded investments amounted to $3 million as of December 31, 2003.

Credit Risk

PSEG, PSE&G, Power and Energy Holdings

Credit risk relates to the risk of loss that PSEG, PSE&G, Power and Energy Holdings would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. PSEG, PSE&G, Power and Energy Holdings have established credit policies that they 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.

PSE&G

BGS suppliers expose PSE&G to credit losses in the event of non-performance or non-payment upon a default of the BGS supplier. Credit requirements are governed under the BPU approved BGS contract.

Power

Counterparties expose Power’s trading operation to credit losses in the event of non-performance or non-payment. Power has a credit management process, which is used to assess, monitor and mitigate counterparty exposure for Power and its subsidiaries. Power’s counterparty credit limits are based on a scoring model that considers a variety of factors, including leverage, liquidity, profitability, credit ratings and risk management capabilities. Power’s trading operations have entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties, which reduce Power’s exposure to counterparty risk by providing the offset of amounts payable to the counterparty against amounts receivable from the counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power and its subsidiaries’ financial condition, results of operations or net cash flows. As of December 31, 2003 over 96% of the credit exposure (mark-to-market plus net receivables and payables, less cash collateral) for Power’s trading operations was with investment grade counterparties. The majority of the credit exposure with non-investment grade counterparties is with certain companies that supply fuel to Power. Therefore, this exposure relates to the risk of a counterparty performing under its obligations rather than payment risk. As of December 31, 2003, Power’s trading operations had over 160 active counterparties.

As a result of the 2003 New Jersey BGS auction, Power’s trading operation contracted to provide energy to the direct suppliers of New Jersey electric utilities, including PSE&G, commencing August 1, 2003. The revenue from the majority of the suppliers is paid directly to Power from the utilities that those suppliers serve. These bilateral contracts are subject to credit risk. A material portion of credit risk relates to the ability of suppliers to meet their payment obligations for the power delivered under each contract. Any failure to collect these payments under the contracts could have a material impact on Power’s results of operations, cash flows and financial position. The payment risk that is associated with potential nonpayment by any EDC making direct payment under the BGS contracts is lower than the risk under standard bilateral contracts, since the EDCs are rate-regulated entities.

Energy Holdings

Global

Eagle Point

In 2000, Global withdrew from its interest in the Eagle Point Cogeneration Project (EPCP) with El Paso Corporation (El Paso) in exchange for a series of contingent payments over five years. The payments to date have been received in accordance with the terms of the agreement, including a payment of $44 million in January 2004. The final principal payment of $37 million under the terms of the agreement is expected to occur in the first quarter of 2005. In the event that EPCP operating cash flows are insufficient to make payment, mandatory capital contributions are required from the partners to pay the note to Global as amounts become due. Additional covenants in the note security package include mandatory restrictions on cash distributions to the partners and performance guarantees of EPCP’s obligations are required. El Paso indirectly owns more than 85% of the partnership interests of EPCP. In February 2003, S&P downgraded El Paso’s long-term corporate credit rating to B+ from BB and Moody’s reduced El Paso’s debt rating to Caa1 from Ba2. If El Paso or its subsidiaries or affiliates is required to fulfill an obligation in accordance with the terms of the agreement and is unable to perform, there could be a material impact to Energy Holdings’ Consolidated Statements of Operations and net cash flows in 2005.

Other

Global has credit risk with respect to its counterparties to PPA’s and other parties. For further discussion, see MD&A—Future Outlook—Energy Holdings.

Resources

Resources has credit risk related to its investments in leveraged leases, totaling $1.4 billion, which is net of deferred taxes of $1.6 billion, as of December 31, 2003. These investments are largely concentrated in the energy industry and have some exposure to the airline industry. As of December 31, 2003, 65% of counterparties in the lease portfolio were rated investment grade by both S&P and Moody’s. Resources is the lessor of various aircraft to several domestic airlines. Resources leases a Boeing B767 aircraft to United Airlines (UAL). In December 2002, UAL filed for Chapter 11 bankruptcy protection. UAL has stated that it intends to retain its B767 aircraft to use in place of other aircraft. UAL has an additional debt obligation of $53 million associated with this aircraft. Resources will work constructively with UAL to keep the leveraged lease in place. The gross invested balance of this investment as of December 31, 2003 was $21 million.

Resources is the lessor of domestic generating facilities in several U.S. energy markets. As a result of recent actions of the rating agencies due to concerns over forward energy prices, the credit of some of the lessees was downgraded. Specifically, the lessees in the following transactions were downgraded below investment grade during 2002 by these rating agencies. Resources’ investment in such transactions was approximately $412 million, net of deferred taxes of $398 million as of December 31, 2003.

Resources leases a generation facility to Reliant Energy Mid Atlantic Power Holdings LLC (REMA), an indirect wholly-owned subsidiary of Reliant Resources Incorporated (RRI). The leased assets are the Keystone, Conemaugh and Shawville generating facilities located in the PJM West market in Pennsylvania. REMA is capitalized with over $1 billion of equity from RRI and has no debt obligations senior to the lease obligations. REMA is currently rated B- by S&P and B3 by Moody’s. As the lessor/equity participant in the lease, Resources is protected with significant lease covenants that restrict the flow of dividends from REMA to its parent, and by over-collateralization of REMA with non-leased assets, transfer of which is restricted by the financing documents. Restrictive covenants include historical and forward cash flow coverage tests that prohibit discretionary capital expenditures and dividend payments to the parent/lessee if stated minimum coverages are not met, and similar cash flow restrictions if ratings are not maintained at stated levels. The covenants are designed to maintain cash reserves in the transaction entity for the benefit of the non-recourse lenders and the lessor/equity participants in the event of a market downturn or degradation in operating performance of the leased

assets. Resources’ investment in the REMA transaction was $117 million, net of deferred taxes of $122 million as of December 31, 2003.

Resources is the lessor/equity participant of the Collins facility, as well as the Powerton and Joliet stations to Midwest Generation LLC (Midwest), an indirect subsidiary of Edison Mission Energy (EME). Edison Mission Midwest Holdings (EMM Holdings) is also an indirect subsidiary of EME. As of December 31, 2003, the gross investment balances for the Collins facility and the Powerton and Joliet facilities were $101 million and $72 million, respectively net of taxes of $98 million and $110 million, respectively. On October 16, 2003, certain of EMM Holdings’ corporate credit ratings were placed on credit watch with negative implications. On December 12, 2003, after completion of a refinancing, S&P removed EMM Holdings from credit watch and affirmed its B rating.

Resources has lease covenants that include historical and forward cash flow coverage tests that prohibit certain capital expenditures and dividend payments to the parent/lessee if stated minimum coverages are not met, and similar cash flow restrictions if ratings are not maintained at stated levels. The covenants are designed to maintain cash reserves in the transaction entity for the benefit of the non-recourse lenders and the lessor/equity participants in the event of a market downturn or degradation in operating performance of the leased assets. In the event of default under the lease covenants, Resources among others would have rights to the cash trapped at EMM Holdings. While these covenants help to provide liquidity to the creditors and the lease equity in the transaction, no assurances can be given that such covenants will be sufficient to prevent Resources from incurring a material loss of its equity investment and future earnings and cash flow.

In the event of a default, Energy Holdings would exercise its rights and attempt to seek recovery of its investment. The results of such efforts may not be known for a period of time. A bankruptcy of a lessor and failure to recover adequate value could lead to a foreclosure of the lease. Under a worst-case scenario, if a foreclosure were to occur, Resources would record a pre-tax write-off up to its gross investment in these facilities. The investment balance increases as earnings are recognized and decreases as rental payments are received by the lessor. Also, in the event of a potential foreclosure, the net tax benefits generated by Resources’ portfolio of investments could be materially reduced in the period in which gains associated with the potential forgiveness of debt at these projects occurs. The amount and timing of any potential reduction in net tax benefits is dependent upon a number of factors including, but not limited to, the time of a potential foreclosure, the amount of lease debt outstanding, any cash trapped at the projects and negotiations during such potential foreclosure process. The potential loss of earnings, impairment and/or tax payments could have a material impact to PSEG’s and Energy Holdings’ financial position, results of operations and net cash flows.

As of December 31, 2003, lease payments on these facilities were current. Also, as of December 31, 2003, Resources determined that the collectibility of the minimum lease payments under its leveraged lease investments is still reasonably probable and therefore continues to account for these investments as leveraged leases.

Other Supplemental Information Regarding Market Risk

PSEG and Power

The following presentation of the activities of Power is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers. For additional information, see Note 16. Risk Management of the Notes.

Normal Operations and Hedging Activities

Power enters into physical contracts, as well as financial contracts, including forwards, futures, swaps and options designed to eliminate risk associated with volatile commodity prices. Commodity

price risk is associated with market price movements resulting from market generation demand, changes in fuel costs and various other factors.

Power’s derivative contracts are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133), its amendments and related guidance. Most non-trading contracts qualify for the normal purchases and normal sales exemption under SFAS 133 and/or SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS 149). Changes in the fair value of qualifying cash flow hedge transactions are recorded in OCI, and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet hedge criteria under SFAS 133 and the ineffective portion of hedge contracts are recognized in earnings currently. Additionally, changes in the fair value attributable to fair value hedges are similarly recognized in earnings.

Trading

Power’s objective for its trading activities is to produce net earnings from trading energy-related products around its owned electric generation assets, gas supply contracts and electric and gas supply obligations. These activities are marked to market in accordance with SFAS 133, its amendments and related guidance, with gains and losses recognized in earnings.

The following table describes the drivers of Power’s energy trading and marketing activities and operating revenues included in its Consolidated Statements of Operations for the year ended December 31, 2003. Normal operations and hedging activities represent the marketing of electricity available from Power’s owned or contracted generation sold into the wholesale market. As the information in this table highlights, mark-to-market activities represent a small portion of the total Operating Revenues for Power. Activities accounted for under the accrual method, including normal purchases and sales, account for the majority of the revenue. The mark-to-market activities reported here are those relating to changes in fair value due to external movement in prices.

Operating Revenues
For the Year Ended December 31, 2003

	Normal Operations and Hedging(A)				Trading				Total
	(Millions)
Mark-to-Market Activities:
Unrealized Mark-to-Market Gains (Losses)
Changes in Fair Value of Open Positions		$	29			$	66			$	95
Origination Unrealized Gain at Inception			—				—				—
Changes in Valuation Techniques and Assumptions			—				—				—
Realization at Settlement of Contracts			(41	)			(87	)			(128	)
Total Change in Unrealized Fair Value			(12	)			(21	)			(33	)
Realized Net Settlement of Transactions Subject to Mark-to-Market			41				87				128
Broker Fees and Other Related Expenses			—				(8	)			(8	)
Net Mark-to-Market Gains			29				58				87
Accrual Activities
Accrual Activities—Revenue, Including Hedge Reclassifications			5,518				—				5,518
Total Operating Revenues		$	5,547			$	58			$	5,605

______________

(A)

Includes derivative contracts that Power enters into to hedge anticipated exposures related to its owned and contracted generation supply, all asset backed transactions (ABT) and hedging activities, but excludes owned and contracted generation assets.

The following table indicates Power’s energy trading assets and liabilities, as well as Power’s hedging activity related to asset backed transactions and derivative instruments that qualify for hedge accounting under SFAS 133, its amendments and related guidance. This table presents amounts segregated by portfolio which are then netted for those counterparties with whom Power has the right to set off and therefore, are not necessarily indicative of amounts presented on the Consolidated Balance Sheets since balances with many counterparties are subject to offset and are shown net on the Consolidated Balance Sheets regardless of the portfolio in which they are included.

Energy Contract Net Assets/Liabilities
As of December 31, 2003

	Normal Operations and Hedging				Trading				Total
	(Millions)
Mark-to-Market Energy Assets
Current Assets		$	33			$	69			$	102
Noncurrent Assets			—				12				12
Total Mark-to-Market Energy Assets		$	33			$	81			$	114
Mark-to-Market Energy Liabilities
Current Liabilities		$	(41	)		$	(74	)		$	(115	)
Noncurrent Liabilities			—				(5	)			(5	)
Total Mark-to-Market Current Liabilities		$	(41	)		$	(79	)		$	(120	)
Total Mark-to-Market Energy Contract Net Assets (Liabilities)		$	(8	)		$	2			$	(6	)

The following table presents maturity of net fair value of mark-to-market energy trading contracts.

Maturity of Net Fair Value of Mark-to-Market Energy Trading Contracts
As of December 31, 2003

	Maturities within
	2004			2005			2006			2007- 2008			Total
	(Millions)
Trading	$	(4	)	$	7		$	(1	)	$	—		$	2
Normal Operations and Hedging		5			(7	)		—			(6	)		(8	)
Total Net Unrealized Gains (Losses) on Mark-to-Market Contracts	$	1		$	—		$	(1	)	$	(6	)	$	(6	)

Wherever possible, fair values for these contracts were obtained from quoted market sources. For contracts where no quoted market exists, modeling techniques were employed using assumptions reflective of current market rates, yield curves and forward prices as applicable to interpolate certain prices. The effect of using such modeling techniques is not material to Power’s financial results.

PSEG, PSE&G, Power and Energy Holdings

The following table identifies gains (losses) on cash flow hedges that are currently in Accumulated OCI, a separate component of equity. Power uses forward sale and purchase contracts, swaps and fixed transmission rights (FTRs) contracts to hedge forecasted energy sales from its generation stations. Power also enters into swaps, options and futures transactions to hedge the price of fuel to meet its fuel purchase requirements for generation. PSEG, PSE&G, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. PSEG’s policy is to manage interest rate risk through the use of fixed rate debt, floating rate debt and interest rate derivatives. Affiliates of Energy Holdings purchase forward-exchange contracts as hedges of anticipated payments to contractors for projects under construction. These contracts are designed to hedge against the risk that the future cash payments will be adversely affected by changes in foreign currency rates. The table also provides an estimate of the gains (losses) that are expected to be reclassified out of OCI and into earnings over the next twelve months.

Cash Flow Hedges Included in OCI
As of December 31, 2003

	Accumulated OCI			Portion Expected to be Reclassified in next 12 months
	(Millions)
Cash Flow Hedges Included in OCI
Commodities	$	(25	)		$ (17	)
Interest Rates		(104	)		(31	)
Foreign Currency		7			—
Net Cash Flow Hedge Loss Included in OCI	$	(122	)		$ (48	)

Power

Credit Risk

Counterparties expose Power to credit losses in the event of non-performance or non-payment. Power has a credit management process which is used to assess, monitor and mitigate counterparty exposure for Power and its subsidiaries. Power’s counterparty credit limits are based on a variety of factors, including credit ratings, leverage, liquidity, profitability and risk management capabilities. Power has entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties, which reduce Power’s exposure to counterparty risk by

providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty.

The following table provides information on Power’s credit exposure, net of collateral, as of December 31, 2003. Credit exposure, in the table below, is defined as net accounts receivable as well as any net “in-the-money” forward mark-to-market exposure. It further delineates that exposure by the credit rating of the counterparties and provides guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of a company’s credit risk by credit rating of the counterparties.

Schedule of Credit Risk Exposure on Energy Contracts Net Assets
As of December 31, 2003

Rating	Current Exposure		Securities Held as Collateral			Net Exposure		Number of Counterparties >10%		Net Exposure of Counter parties >10%
			(Millions)							(Millions)
Investment Grade—External Rating	$	406		$	28	$	398		1		$186	(A)
Non-Investment Grade—External Rating		18			14		6		—		—
Investment Grade—No External Rating		13			—		13		—		—
Non-Investment Grade—No External Rating		13			—		13		—		—
Total	$	450		$	42	$	430		1		$186

______________

(A)

Represents exposure with PSE&G

The net exposure listed above, in some cases, will not be the difference between the current exposure and the collateral held. A counterparty may have posted more collateral than the outstanding exposure, in which case there would not be exposure. As of December 31, 2003, Power’s trading operations had over 160 active counterparties.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

This combined Form 10-K is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings LLC (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each make representations only as to itself and makes no representations as to any other company.

INDEPENDENT AUDITORS’ REPORT

To the Stockholders and Board of Directors of
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED:

We have audited the consolidated balance sheets of Public Service Enterprise Group Incorporated and its subsidiaries (the ‘Company’) as of December 31, 2003 and 2002, and the related consolidated statements of operations, common stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2003. Our audits also included the consolidated financial statement schedule listed in the Index in Item 15. These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and consolidated financial statement schedule based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.

As discussed in Note 2 to the consolidated financial statements, the accompanying 2002 and 2001 consolidated financial statements have been restated.

As discussed in Note 3 to the consolidated financial statements, on January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets.”

As discussed in Note 3 to the consolidated financial statements, on January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”

DELOITTE & TOUCHE LLP

Parsippany, New Jersey
February 17, 2004

INDEPENDENT AUDITORS’ REPORT

To the Sole Stockholder and Board of Directors of
PUBLIC SERVICE ELECTRIC AND GAS COMPANY:

We have audited the consolidated balance sheets of Public Service Electric and Gas Company and its subsidiaries (the “Company”) as of December 31, 2003 and 2002, and the related consolidated statements of operations, common stockholder’s equity and cash flows for each of the three years in the period ended December 31, 2003. Our audits also included the consolidated financial statement schedule listed in the Index in Item 15. These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and consolidated financial statement schedule based on our audits.

DELOITTE & TOUCHE LLP

Parsippany, New Jersey February 17, 2004

INDEPENDENT AUDITORS’ REPORT

To the Sole Member and Board of Directors of
PSEG POWER LLC:

We have audited the consolidated balance sheets of PSEG Power LLC and its subsidiaries (the “Company”) as of December 31, 2003 and 2002, and the related consolidated statements of operations, capitalization and member’s equity and cash flows for each of the three years in the period ended December 31, 2003. Our audits also included the consolidated financial statement schedule listed in the Index in Item 15. These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and consolidated financial statement schedule based on our audits.

DELOITTE & TOUCHE LLP

Parsippany, New Jersey February 17, 2004

INDEPENDENT AUDITORS’ REPORT

To the Sole Member and Board of Directors of
PSEG ENERGY HOLDINGS L.L.C.:

We have audited the consolidated balance sheets of PSEG Energy Holdings L.L.C. and its subsidiaries (the “Company”) as of December 31, 2003 and 2002, and the related consolidated statements of operations, member’s/stockholder’s equity and cash flows for each of the three years in the period ended December 31, 2003. Our audits also included the consolidated financial statement schedule listed in the Index in Item 15. These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and consolidated financial statement schedule based on our audits.

As discussed in Note 2 to the consolidated financial statements, the accompanying 2002 and 2001 consolidated financial statements have been restated.

DELOITTE & TOUCHE LLP

Parsippany, New Jersey February 17, 2004

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions, except for Share Data)

	For The Years Ended December 31,
				As Restated, see Note 2
	2003			2002			2001
OPERATING REVENUES	$	11,116		$	8,216		$	6,883
OPERATING EXPENSES
Energy Costs		6,368			3,706			2,686
Operation and Maintenance		2,120			1,899			1,844
Write-down of Project Investments		—			511			7
Depreciation and Amortization		527			565			495
Taxes Other Than Income Taxes		136			131			121
Total Operating Expenses		9,151			6,812			5,153
Income from Equity Method Investments		114			119			178
OPERATING INCOME		2,079			1,523			1,908
Other Income		178			39			33
Other Deductions		(101	)		(80	)		(21	)
Interest Expense		(836	)		(819	)		(776	)
Preferred Stock Dividends		(4	)		(4	)		(5	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		1,316			659			1,139
Income Tax Expense		(464	)		(254	)		(373	)
INCOME FROM CONTINUING OPERATIONS		852			405			766
Loss from Discontinued Operations, including Loss on Disposal, net of tax benefit of $8, $28 and $13 for the years ended 2003, 2002 and 2001, respectively		(44	)		(49	)		(12	)
INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE.		808			356			754
Extraordinary Item, net of tax benefit of $12		(18	)		—			—
Cumulative Effect of a Change in Accounting Principle, net of tax (expense) benefit of ($255), $66 and ($8)for the years ended 2003, 2002 and 2001, respectively		370			(121	)		10
NET INCOME	$	1,160		$	235		$	764
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC		228,222			208,647			207,737
DILUTED		228,824			208,813			208,226
EARNINGS PER SHARE:
BASIC
INCOME FROM CONTINUING OPERATIONS	$	3.73		$	1.94		$	3.68
NET INCOME	$	5.08		$	1.13		$	3.67
DILUTED
INCOME FROM CONTINUING OPERATIONS	$	3.72		$	1.94		$	3.68
NET INCOME	$	5.07		$	1.13		$	3.67
DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	2.16		$	2.16		$	2.16

See Notes to Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions)

	December 31,
				As Restated, see Note 2
	2003			2002
CURRENT ASSETS
Cash and Cash Equivalents	$	548		$	171
Accounts Receivable, net of allowances of $40 and $47 in 2003 and 2002, respectively		1,547			1,404
Unbilled Revenues		261			275
Fuel		527			413
Materials and Supplies		227			203
Energy Trading Contracts		101			157
Assets Held for Sale		—			83
Prepayments		164			73
Assets of Discontinued Operations		298			419
Other		44			91
Total Current Assets		3,717			3,289
PROPERTY, PLANT AND EQUIPMENT		17,406			16,374
Less: Accumulated Depreciation and Amortization		(4,984	)		(4,734	)
Net Property, Plant and Equipment		12,422			11,640
NONCURRENT ASSETS
Regulatory Assets		4,801			5,002
Long-Term Investments		4,808			4,468
Nuclear Decommissioning Trust (NDT) Funds		985			766
Other Special Funds		470			72
Goodwill		507			446
Other Intangibles		103			206
Energy Trading Contracts		12			21
Other		230			225
Total Noncurrent Assets		11,916			11,206
TOTAL ASSETS	$	28,055		$	26,135

See Notes to Consolidated Financial Statements.

100

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED BALANCE SHEETS
LIABILITIES AND CAPITALIZATION
(Millions, except for Share Data)

	December 31,
				As Restated, see Note 2
	2003			2002
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	726		$	730
Commercial Paper and Loans		301			760
Accounts Payable		1,216			1,137
Energy Trading Contracts		72			101
Accrued Taxes		33			229
Liabilities of Discontinued Operations		242			324
Other		795			746
Total Current Liabilities		3,385			4,027
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		4,196			2,903
Regulatory Liabilities		536			252
Nuclear Decommissioning Liabilities		284			766
Other Postemployment Benefit (OPEB) Costs		532			501
Accrued Pension Costs		67			336
Cost of Removal		—			524
Other		501			623
Total Noncurrent Liabilities		6,116			5,905
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 17)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt		7,921			7,116
Securitization Debt		2,085			2,222
Project Level, Non-Recourse Debt		1,738			1,539
Debt Supporting Trust Preferred Securities		1,201			1,361
Total Long-Term Debt		12,945			12,238
SUBSIDIARIES’ PREFERRED SECURITIES
Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2003 and 2002—795,234 shares		80			80
COMMON STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 500,000,000 shares; issued 2003—262,252,032 shares 2002—251,385,937 shares		4,490			4,051
Treasury Stock, at cost; 2003 and 2002—26,118,590 shares		(981	)		(981	)
Retained Earnings		2,221			1,554
Accumulated Other Comprehensive Loss		(201	)		(739	)
Total Common Stockholders’ Equity		5,529			3,885
Total Capitalization		18,554			16,203
TOTAL LIABILITIES AND CAPITALIZATION	$	28,055		$	26,135

See Notes to Consolidated Financial Statements.

101

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)

	For The Years Ended December 31,
				As Restated, see Note 2
	2003			2002			2001
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	1,160		$	235		$	764
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Extraordinary Item, net of tax		18			—			—
Loss on Disposal of Discontinued Operations, net of tax		32			34			—
Cumulative Effect of a Change in Accounting Principle, net of tax		(370	)		121			(10	)
Write-Down of Project Investments		—			511			7
Depreciation and Amortization		527			565			495
Amortization of Nuclear Fuel		89			89			101
Provision for Deferred Income Taxes (Other than Leases) and ITC		368			(139	)		(116	)
Non-Cash Employee Benefit Plan Costs		258			193			158
Leveraged Lease Income, Adjusted for Rents Received		77			(44	)		(6	)
Undistributed Earnings from Affiliates		40			(5	)		(96	)
Foreign Currency Transaction (Gain) Loss		(16	)		77			11
Unrealized Losses (Gains) on Energy Contracts and Other Derivatives		38			(35	)		22
Under Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs		(38	)		(60	)		(87	)
Under (Over) Recovery of SBC		(105	)		61			88
Net Realized Gains and Income from NDT Fund		(65	)		—			—
Other Non-Cash Charges (Credits)		75			(3	)		(65	)
Net Change in Certain Current Assets and Liabilities		(280	)		77			136
Employee Benefit Plan Funding and Related Payments		(279	)		(308	)		(210	)
Proceeds from the Withdrawal of Partnership Interests and Other Distributions		66			54			124
Other		(148	)		(136	)		(147	)
Net Cash Provided By Operating Activities		1,447			(1,287	)		1,169
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(1,351	)		(1,549	)		(2,029	)
Investments in Joint Ventures, Partnerships and Capital Leases		(36	)		(242	)		(597	)
Proceeds from the Sale of Investments and Return of Capital from Partnerships		47			398			146
Acquisitions, Net of Cash Provided		—			(288	)		(832	)
Other		(24	)		(34	)		(175	)
Net Cash Used In Investing Activities		(1,364	)		(1,715	)		(3,487	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt		(327	)		(421	)		(1,511	)
Issuance of Long-Term Debt		1,537			1,293			2,838
Issuance of Non-Recourse Debt		676			103			3,418
Issuance of Participating Units		—			446			—
Issuance of Common Stock		441			521			—
Issuance of Preferred Securities		—			174			—
Redemptions of Long-Term Debt		(1,303	)		(1,213	)		(1,304	)
Redemptions of Preferred Securities		(155	)		—			(448	)
Purchase of Treasury Stock		—			—			(91	)
Cash Dividends Paid on Common Stock		(493	)		(456	)		(448	)
Distributions to (Proceeds from) Minority Shareholders		(48	)		5			(61	)
Other		(36	)		(7	)		(4	)
Net Cash Provided By Financing Activities		292			445			2,389
Effect of Exchange Rate Change		2			(13	)		—
Net Change In Cash and Cash Equivalents		377			4			71
Cash and Cash Equivalents at Beginning of Period		171			167			96
Cash and Cash Equivalents at End of Period	$	548		$	171		$	167
Supplemental Disclosure of Cash Flow Information:
Income Taxes (Received) Paid	$	(21	)	$	145		$	87
Interest Paid, Net of Amounts Capitalized	$	975		$	843		$	713

See Notes to Consolidated Financial Statements.

102

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
(Millions)

	Common Stock				Treasury Stock					As Restated, see Note 2			As Restated, see Note 2				As Restated, see Note 2
										As Restated, see Note 2			Accumulated Other Comprehensive Loss
										Retained Earnings
	Shs.	Amount			Shs.		Amount			Retained Earnings							Total
Balance as of January 1, 2001	232	$	3,604		(24	)	$	(895	)	$	1,459			$	(222	)	$	3,946
Net Income	—		—		—			—			764				—			764
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax $(7)	—		—		—			—			—				(68	)		(68	)
Change in Fair Value of Derivative Instruments, net of tax $(31)	—		—		—			—			—				(39	)		(39	)
Cumulative Effect of Change in Accounting Principle, net of tax $ (14)	—		—		—			—			—				(15	)		(15	)
Reclassification Adjustments for Net Amounts Included in Net Income, net of tax of $19	—		—		—			—			—				25			25
Pension Adjustments, net of tax $ (1)	—		—		—			—			—				2			2
Change in Fair Value of Equity Investments, net of tax $(1)	—		—		—			—			—				(2	)		(2	)
Other Comprehensive Loss	—		—		—			—			—				—			(97	)
Comprehensive Income																		667
Cash Dividends on Common Stock	—		—		—			—			(448	)			—			(448	)
Purchase of Treasury Stock	—		—		(2	)		(91	)		—				—			(91	)
Other	—		(5	)	—			5			(6	)			—			(6	)
Balance as of December 31, 2001	232	$	3,599		(26	)	$	(981	)	$	1,769			$	(319	)	$	4,068
Net Income	—		—		—			—			235				—			235
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax $(45)	—		—		—			—			—				(140	)		(140	)
Reclassification Adjustment for Losses Included in Net Income	—		—		—			—			—				68			68
Change in Fair Value of Derivative Instruments, net of tax $(13)	—		—		—			—			—				(60	)		(60	)
Reclassification Adjustments for Net Amounts Included in Net Income	—		—		—			—			—				9			9
Settlement Adjustments Related to Projects Under Construction															(3	)		(3	)
Minimum Pension Liability, net of tax $ (201)	—		—		—			—			—				(293	)		(293	)
Change in Fair Value of Equity Investments	—		—		—			—			—				(1	)		(1	)
Other Comprehensive Loss	—		—		—			—			—				—			(420	)
Comprehensive Loss																		(185	)
Cash Dividends on Common Stock	—		—		—			—			(456	)			—			(456	)
Issuance of Equity	19		536		—			—			—				—			536
Issuance Costs and Other	—		(84	)	—			—			6				—			(78	)
Balance as of December 31, 2002	251	$	4,051		(26	)	$	(981	)	$	1,554			$	(739	)	$	3,885
Net Income	—		—		—			—			1,160				—			1,160
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax $(4)	—		—		—			—			—				164			164
Available for Sale Securities, net of tax $81	—		—		—			—			—				118			118
Change in Fair Value of Derivative Instruments, net of tax $(32)	—		—		—			—			—				(57	)		(57	)
Reclassification Adjustments for Net Amounts Included in Net Income	—		—		—			—			—				32			32
Settlement Adjustments Related to Projects Under Construction	—		—		—			—			—				(11	)		(11	)
Minimum Pension Liability, net of tax $200	—		—		—			—			—				289			289
Change in Fair Value of Equity Investments	—		—		—			—			—				3			3
Other Comprehensive Income	—		—		—			—			—				—			538
Comprehensive Income																		1,698
Cash Dividends on Common Stock	—		—		—			—			(493	)			—			(493	)
Issuance of Equity	11		452		—			—			—				—			452
Issuance Costs and Other	—		(13	)	—			—			—				—			(13	)
Balance as of December 31, 2003	262	$	4,490		(26	)	$	(981	)	$	2,221			$	(201	)	$	5,529

See Notes to Consolidated Financial Statements.

103

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104

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions)

	For The Years Ended December 31,
	2003			2002			2001

OPERATING REVENUES	$	6,740		$	5,919		$	6,091
OPERATING EXPENSES
Energy Costs.		4,421			3,684			3,913
Operation and Maintenance		1,050			982			996
Depreciation and Amortization		372			409			370
Taxes Other Than Income Taxes		136			131			121
Total Operating Expenses		5,979			5,206			5,400
OPERATING INCOME		761			713			691
Other Income		6			15			95
Other Deductions		(1	)		(2	)		(4	)
Interest Expense		(390	)		(406	)		(458	)
INCOME BEFORE INCOME TAXES AND EXTRAORDINARY ITEM		376			320			324
Income Tax Expense		(129	)		(115	)		(89	)
INCOME BEFORE EXTRAORDINARY ITEM		247			205			235
Extraordinary Item, net of tax benefit of $12		(18	)		—			—
NET INCOME		229			205			235
Preferred Stock Dividends		(4	)		(4	)		(5	)
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	225		$	201		$	230

See disclosures regarding Public Service Electric and Gas Company included in the
Notes to Consolidated Financial Statements.

105

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions)

	December 31,
	2003			2002
CURRENT ASSETS
Cash and Cash Equivalents	$	140		$	35
Accounts Receivable, net of allowances of $34 and $32 in 2003 and 2002, respectively		804			769
Unbilled Revenues		261			275
Materials and Supplies		50			45
Prepayments		44			25
Other		22			17
Total Current Assets		1,321			1,166
PROPERTY, PLANT AND EQUIPMENT		9,793			9,581
Less: Accumulated Depreciation and Amortization		(3,258	)		(3,211	)
Net Property, Plant and Equipment		6,535			6,370
NONCURRENT ASSETS
Regulatory Assets		4,801			5,002
Long-Term Investments		131			128
Other Special Funds		272			44
Intangibles		2			60
Other		74			71
Total Noncurrent Assets		5,280			5,305
TOTAL ASSETS	$	13,136		$	12,841

See disclosures regarding Public Service Electric and Gas Company included in the
Notes to Consolidated Financial Statements.

106

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED BALANCE SHEETS
LIABILITIES AND CAPITALIZATION
(Millions, except for Share Data)

	December 31,
	2003			2002
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	423		$	429
Commercial Paper and Loans		—			224
Accounts Payable		286			336
Accounts Payable — Affiliated Companies net		405			388
Clean Energy Program		110			18
Other		322			311
Total Current Liabilities		1,546			1,706
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC		2,715			2,436
OPEB Costs		509			486
Regulatory Liabilities		536			252
Cost of Removal		—			393
Accrued Pension Costs		16			175
Other		145			209
Total Noncurrent Liabilities		3,921			3,951

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 17)

CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt		3,044			2,627
Securitization Debt		2,085			2,222
Debt Supporting Trust Preferred Securities		—			160
Total Long-Term Debt		5,129			5,009
PREFERRED SECURITIES
Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2003 and 2002 — 795,234 shares		80			80
COMMON STOCKHOLDER’S EQUITY
Common Stock; 150,000,000 shares authorized, 132,450,344 shares issued and outstanding		892			892
Contributed Capital		170			—
Basis Adjustment		986			986
Retained Earnings		414			389
Accumulated Other Comprehensive Loss		(2	)		(172	)
Total Common Stockholder’s Equity		2,460			2,095
Total Capitalization		7,669			7,184
TOTAL LIABILITIES AND CAPITALIZATION	$	13,136		$	12,841

See disclosures regarding Public Service Electric and Gas Company included in the
Notes to Consolidated Financial Statements.

107

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)

	For The Years Ended December 31,
	2003				2002			2001
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	229		$	205		$	235
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Extraordinary Item, net of tax benefit		18			—			—
Depreciation and Amortization		372			409			370
Provision for Deferred Income Taxes and ITC		132			(21	)		(201	)
Non-Cash Employee Benefit Plan Costs		179			141			125
Non-Cash Interest Expense		50			18			(6	)
(Under) Over Recovery of Electric Energy Costs (BGS and NTC)		(139	)		(19	)		56
Over (Under) Recovery of Gas Costs		101			(41	)		(143	)
(Under) Over Recovery of SBC		(105	)		61			88
Gain on the Sale of Property, Plant and Equipment		(11	)		(10	)		(4	)
Other Non-Cash Credits		(1	)		(17	)		(1	)
Net Changes in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues		(21	)		(154	)		127
Natural Gas		—			415			(43	)
Materials and Supplies		(5	)		5			(2	)
Prepayments		(19	)		15			(35	)
Accrued Taxes		2			(22	)		5
Accrued Interest		2			(13	)		11
Accounts Payable		(33	)		82			56
Other Current Assets and Liabilities		109			—			20
Employee Benefit Plan Funding and Related Payments		(177	)		(198	)		(139	)
Other		(78	)		(26	)		(82	)
Net Cash Provided By Operating Activities		605			830			437
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(411	)		(447	)		(351	)
Proceeds from the Sale of Property, Plant and Equipment—Affiliate		53			—			—
Proceeds from the Sale of Property, Plant and Equipment		13			10			4
Return of Capital from Trusts		5			—			11
Net Cash Used In Investing Activities		(340	)		(437	)		(362	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt		(224	)		224			(1,543	)
Issuance of Securitization Debt		—			—			2,525
Issuance of Long-Term Debt		909			300			—
Redemption of Securitization Debt		(129	)		(120	)		(53	)
Redemption of Long-Term Debt		(514	)		(547	)		(528	)
Redemption of Preferred Securities		(155	)		—			(448	)
Capital Lease Payments		(3	)		(6	)		(6	)
Contributed Capital		170			—			—
Return of Capital		—			—			(2,265	)
Deferred Issuance Costs		(10	)		(2	)		(201	)
Collection of Note Receivable—Affiliated Company		—			—			2,786
Cash Dividends Paid on Common Stock		(200	)		(305	)		(274	)
Preferred Stock Dividends		(4	)		(4	)		(5	)
Net Cash Used In Financing Activities		(160	)		(460	)		(12	)
Net Change In Cash and Cash Equivalents		105			(67	)		63
Cash and Cash Equivalents at Beginning of Period		35			102			39
Cash and Cash Equivalents at End of Period	$	140		$	35		$	102
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid	$	16		$	161		$	264
Interest Paid, Net of Amounts Capitalized	$	371		$	428		$	427

See disclosures regarding Public Service Electric and Gas Company included in the
Notes to Consolidated Financial Statements.

108

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
(Millions)

	Common Stock			Contributed Capital from PSEG				Basis Adjustment			Retained Earnings			Accumulated Other Comprehensive Loss				Total

Balance as of January 1, 2001	$	2,563			$	594			$	986	$	375			$	(3	)	$	4,515
Net Income		—				—				—		235				—			235
Other Comprehensive Income, net of tax:
Pension Adjustments, netof tax $1		—				—				—		—				2			2
Comprehensive Income																			237
Cash Dividends on Common Stock		—				—				—		(112	)			—			(112	)
Cash Dividends on Preferred Stock		—				—				—		(5	)			—			(5	)
Return of Capital		(1,671	)			(594	)			—		—				—			(2,265	)
Balance as of December 31, 2001	$	892			$	—			$	986	$	493			$	(1	)	$	2,370
Net Income		—				—				—		205				—			205
Other Comprehensive Loss, net of tax:
Minimum Pension Liability, net of tax $(104)		—				—				—		—				(171	)		(171	)
Comprehensive Income																			34
Cash Dividends on Common Stock		—				—				—		(305	)			—			(305	)
Cash Dividends on Preferred Stock		—				—				—		(4	)			—			(4	)
Balance as of December 31, 2002	$	892			$	—			$	986	$	389			$	(172	)	$	2,095
Net Income		—				—				—		229				—			229
Other Comprehensive Income, net of tax:
Minimum Pension Liability, net of tax $117		—				—				—		—				170			170
Comprehensive Income																			399
Cash Dividends on Common Stock		—				—				—		(200	)			—			(200	)
Cash Dividends on Preferred Stock		—				—				—		(4	)			—			(4	)
Contributed Capital		—				170				—		—				—			170
Balance as of December 31, 2003	$	892			$	170			$	986	$	414			$	(2	)	$	2,460

See disclosures regarding Public Service Electric and Gas Company included in the
Notes to Consolidated Financial Statements.

109

PSEG POWER LLC

CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions)

	For the Years Ended December 31,
	2003			2002			2001
OPERATING REVENUES	$	5,605		$	3,636		$	2,464
OPERATING EXPENSES
Energy Costs		3,746			1,852			844
Operation and Maintenance		914			773			738
Depreciation and Amortization		102			108			95
Total Operating Expenses		4,762			2,733			1,677
OPERATING INCOME		843			903			787
Other Income		149			1			—
Other Deductions		(78	)		(1	)		—
Interest Expense		(114	)		(122	)		(143	)
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		800			781			644
Income Tax Expense		(326	)		(313	)		(250	)
INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		474			468			394
Cumulative Effect of a Change in Accounting Principle, net of tax expense of $255		370			—			—
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	844		$	468		$	394

See disclosures regarding PSEG Power LLC included in the
Notes to Consolidated Financial Statements.

110

PSEG POWER LLC

CONSOLIDATED BALANCE SHEETS
(Millions)

	December 31,
	2003			2002
A S S E T S
CURRENT ASSETS
Cash and Cash Equivalents	$	66		$	26
Accounts Receivable		615			527
Accounts Receivable — Affiliated Companies, net		240			238
Short-Term Loan to Affiliate		77			—
Fuel		516			406
Materials and Supplies		162			148
Energy Trading Contracts		101			157
Other		32			72
Total Current Assets		1,809			1,574
PROPERTY, PLANT AND EQUIPMENT		5,980			5,342
Less: Accumulated Depreciation and Amortization		(1,399	)		(1,302	)
Net Property, Plant and Equipment		4,581			4,040
NON CURRENT ASSETS
Deferred Income Taxes and Investment Tax Credits (ITC)		24			547
Nuclear Decommissioning Trust (NDT) Funds		985			766
Intangibles		108			141
Energy Trading Contracts		12			21
Other Special Funds		115			10
Other		94			118
Total Noncurrent Assets		1,338			1,603
TOTAL ASSETS	$	7,728		$	7,217
L I A B I L I T I E S A N D M E M B E R’S E Q U I T Y
CURRENT LIABILITIES
Accounts Payable	$	800		$	690
Short-Term Loan from Affiliate		—			239
Energy Trading Contracts		72			101
Other		207			282
Total Current Liabilities		1,079			1,312
NON CURRENT LIABILITIES
Nuclear Decommissioning Liabilities		284			766
Cost of Removal		—			131
Environmental Costs		58			59
Accrued Pension Costs		14			101
Other		72			93
Total Noncurrent Liabilities		428			1,150
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 17)

LONG-TERM DEBT
Project Level, Non-Recourse Debt		800			800
Long-Term Debt		2,816			2,516
Total Long-Term Debt		3,616			3,316
MEMBER’S EQUITY
Contributed Capital		1,700			1,550
Basis Adjustment		(986	)		(986	)
Retained Earnings		1,810			966
Accumulated Other Comprehensive Income (Loss)		81			(91	)
Total Member’s Equity		2,605			1,439
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	7,728		$	7,217

See disclosures regarding PSEG Power LLC included in the
Notes to Consolidated Financial Statements.

111

PSEG POWER LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)

	For the Years Ended December 31,
	2003			2002			2001
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	844		$	468		$	394
Adjustments to Reconcile Net Income to Net Cash Flows from
Operating Activities:
Cumulative Effect of a Change in Accounting Principle, net of tax		(370	)		—			—
Depreciation and Amortization		102			108			95
Amortization of Nuclear Fuel		89			89			101
Interest Accretion on NDT Liability		24			—			—
Provision for Deferred Income Taxes		151			88			94
Unrealized Losses (Gains) on Energy Contracts and Derivatives		33			(23	)		22
Non-Cash Employee Benefit Plan Costs		54			32			20
Net Realized Gains and Income on NDT Fund		(65	)		—			—
Net Changes in Certain Current Assets and Liabilities
Fuel, Materials and Supplies		(125	)		(329	)		(35	)
Accounts Receivable		(90	)		(212	)		2
Accounts Payable		110			263			(84	)
Other Current Assets and Liabilities		(37	)		94			80
Employee Benefit Plan Funding and Other Payments		(70	)		(76	)		(34	)
Other		(70	)		(85	)		(80	)
Net Cash Provided By Operating Activities		580			417			575
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(655	)		(1,046	)		(1,592	)
Short-Term Loan—Affiliate		(77	)		—			—
Acquisition of Generation Businesses, net of cash		—			(271	)		(22	)
Proceeds from the Sale of Property, Plant and Equipment		—			47			30
Other		(17	)		(29	)		(29	)
Net Cash Used In Investing Activities		(749	)		(1,299	)		(1,613	)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Recourse Long-Term Debt		300			600			1,915
Issuance of Non-Recourse Long-Term Debt		—			30			770
Proceeds from Contributed Capital		150			200			1,200
Deferred Issuance Costs		(2	)		(6	)		(16	)
Repayment of Note Payable—Affilated Company		—			—			(2,786	)
Short-Term Loan (Repayment)—Affiliate		(239	)		75			(56	)
Net Cash Provided By Financing Activities		209			899			1,027
Net Change In Cash and Cash Equivalents		40			17			(11	)
Cash and Cash Equivalents at Beginning of Period		26			9			20
Cash and Cash Equivalents at End of Period	$	66		$	26		$	9
Supplemental Disclosure of Cash Flow Information:
Property, Plant, and Equipment Assumed from Acquisitions	$	—		$	235		$	24
Income Taxes Paid	$	99		$	91		$	166
Interest Paid, Net of Amounts Capitalized	$	217		$	200		$	197

See disclosures regarding PSEG Power LLC included in the
Notes to Consolidated Financial Statements.

112

PSEG POWER LLC

CONSOLIDATED STATEMENTS OF CAPITALIZATION AND MEMBER’S EQUITY
(Millions)

	Contributed Capital		Basis Adjustment				Retained Earnings		Accumulated Other Comprehensive Income (Loss)				Total Member's Equity
Balance as of January 1, 2001	$	150		$	(986	)	$	104		$	—			$	(732	)
Net Income		—			—			394			—				394
Other Comprehensive Income (Loss), net of tax:
Change in Fair Value of Derivative Instruments, net of tax $(16)		—			—			—			(23	)			(23	)
Reclassification Adjustments for Net Amount included in Net Income, net of tax $14		—			—			—			21				21
Other Comprehensive Loss		—			—			—			—				(2	)
Comprehensive Income															392
Contributed Capital		1,200			—			—			—				1,200
Balance as of December 31, 2001	$	1,350		$	(986	)	$	498		$	(2	)		$	860
Net Income		—			—			468			—				468
Other Comprehensive Income (Loss), net of tax:
Change in Fair Value of Derivative Instruments, net of tax $(3)		—			—			—			(5	)			(5	)
Pension Adjustments, net of tax $(50)		—			—			—			(84	)			(84	)
Other Comprehensive Loss		—			—			—			—				(89	)
Comprehensive Income															379
Contributed Capital		200			—			—			—				200
Balance as of December 31, 2002	$	1,550		$	(986	)	$	966		$	(91	)		$	1,439
Net Income		—			—			844			—				844
Other Comprehensive Income (Loss), net of tax:
Available for Sale Securities, net of tax $81		—			—			—			118				118
Change in Fair Value of Derivative Instruments, net of tax $(21)		—			—			—			(40	)			(40	)
Reclassification Adjustments for Net Amount Included in Net Income		—			—			—			11				11
Pension Adjustments, net of tax $58		—			—			—			83				83
Other Comprehensive Income		—			—			—			—				172
Comprehensive Income															1,016
Contributed Capital		150			—			—			—				150
Balance as of December 31, 2003	$	1,700		$	(986	)	$	1,810		$	81			$	2,605

See disclosures regarding PSEG Power LLC included in the
Notes to Consolidated Financial Statements.

113

[THIS PAGE INTENTIONALLY LEFT BLANK]

114

PSEG ENERGY HOLDINGS LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

(Millions)

	For The Years Ended December 31,
					As Restated, see Note 2
			2003				2002			2001
OPERATING REVENUES
Electric Generation and Distribution Revenues		$	431			$	304		$	128
Income from Capital and Operating Leases			217				260			214
Other			77				45			112
Total Operating Revenues			725				609			454
OPERATING EXPENSES
Energy Costs			155				118			55
Operation and Maintenance			176				168			122
Write-down of Project Investments			—				511			7
Depreciation and Amortization			44				28			15
Total Operating Expenses			375				825			199
Income from Equity Method Investments			114				119			178
OPERATING INCOME (LOSS)			464				(97	)		433
Other Income			20				26			4
Other Deductions			(5	)			(77	)		(17	)
Interest Expense			(218	)			(217	)		(183	)
INCOME (LOSS) BEFORE INCOME TAXES, MINORITY INTEREST, DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE			261				(365	)		237
Income Tax (Expense) Benefit			(59	)			144			(58	)
Minority Interests in (Earnings) Losses of Subsidiaries			(13	)			1			—
INCOME (LOSS) BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE			189				(220	)		179
Loss From Discontinued Operations, net of tax benefit of $4, $10, and $13 for the years ended 2003, 2002and 2001, respectively			(12	)			(15	)		(12	)
Loss on Disposal of Discontinued Operations, net of tax benefit of $4 and $18 for the years ended 2003and 2002, respectively			(32	)			(34	)		—
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE			145				(269	)		167
Cumulative Effect of a Change in Accounting Principle, net of tax (expense) benefit of $66 and ($8) for the years ended 2002 and 2001, respectively			—				(121	)		10
NET INCOME (LOSS)			145				(390	)		177
Preference Units Distributions/Preferred Stock Dividends			(23	)			(23	)		(23	)
EARNINGS (LOSS) AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED		$	122			$	(413	)	$	154

See disclosures regarding PSEG Energy Holdings LLC included in the
Notes to Consolidated Financial Statements.

115

PSEG ENERGY HOLDINGS LLC

CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions)

	December 31,
				As Restated, see Note 2
		2003				2002
CURRENT ASSETS
Cash and Cash Equivalents	$	161			$	109
Accounts Receivable:
Trade—net of allowances of $6 and $15 in 2003 and 2002, respectively		103				78
Other Accounts Receivable		19				20
Affiliated Companies		173				—
Assets Held for Sale		—				83
Notes Receivable:
Affiliated Companies		300				62
Other		2				12
Inventory		26				17
Prepayments		7				4
Assets of Discontinued Operations		298				419
Total Current Assets		1,089				804
PROPERTY, PLANT AND EQUIPMENT		1,362				1,352
Less: Accumulated Depreciation and Amortization		(184	)			(154	)
Net Property, Plant and Equipment		1,178				1,198
INVESTMENTS
Capital Leases-net		2,981				2,844
Corporate Joint Ventures		1,040				865
Partnership Interests		531				468
Other Investments		31				38
Total Investments		4,583				4,215
OTHER ASSETS
Goodwill		491				430
Other		116				108
Total Other Assets		607				538
Total Assets	$	7,457			$	6,755

See disclosures regarding PSEG Energy Holdings LLC included in the
Notes to Consolidated Financial Statements.

116

PSEG ENERGY HOLDINGS LLC

CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER'S EQUITY
(Millions)

	December 31,
				As Restated, see Note 2
	2003			2002
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	303		$	301
Accounts Payable		181			165
Accounts Payable—Affiliated Companies		—			61
Notes Payable		2			133
Liabilities of Discontinued Operations		242			336
Total Current Liabilities		728			996
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment and Energy Tax Credits		1,487			1,022
Other Noncurrent Liabilities		165			180
Total Noncurrent Liabilities		1,652			1,202
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 17)

MINORITY INTERESTS		35			70
LONG-TERM DEBT
Project Level, Non-Recourse Debt		938			739
Senior Notes		1,800			1,725
Total Long-Term Debt		2,738			2,464
MEMBER’S EQUITY
Ordinary Unit		1,888			1,888
Preference Units		509			509
Retained Earnings		178			56
Accumulated Other Comprehensive Loss		(271	)		(430	)
Total Member’s Equity		2,304			2,023
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	7,457		$	6,755

See disclosures regarding PSEG Energy Holdings LLC included in the
Notes to Consolidated Financial Statements.

117

PSEG ENERGY HOLDINGS LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)

	For The Years Ended December 31,
				As Restated, see Note 2
	2003			2002			2001
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	145		$	(390	)	$	177
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:
Write-down of Project Investments		—			511			7
Cumulative Effect of a Change in Accounting Principle, net of tax		—			121			(10	)
Loss on Disposal of Discontinued Operations, net of tax		32			34			—
Depreciation and Amortization		44			28			15
Deferred Income Taxes (Other than Leases)		82			(212	)		(21	)
Leveraged Lease Income, Adjusted for Rents Received		77			(44	)		(6	)
Change in Fair Value of Derivative Financial Instruments		5			(12	)		—
Undistributed Earnings from Affiliates		40			(5	)		(96	)
Gain on Sale of Investments		(45	)		(6	)		(74	)
Foreign Currency Transaction (Gain) Loss		(16	)		77			11
Other Non-Cash Charges		48			5			34
Net Changes in Certain Current Assets and Liabilities:
Accounts Receivable		(12	)		(6	)		(60	)
Inventory		(12	)
Accounts Payable		(136	)		(37	)		88
Current Assets and Liabilties from Discontinued Operations		(21	)		(62	)		(35	)
Other Current Assets and Liabilities		—			57			55
Proceeds from the Withdrawal of Partnership Interests and Other Distributions		66			54			124
Other		(1	)		(5	)		(22	)
Net Cash Provided By Operating Activities		296			108			187
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(271	)		(113	)		(105	)
Investments in Joint Ventures and Partnerships		(36	)		(191	)		(136	)
Investments in Capital Leases		—			(31	)		(460	)
Proceeds from the Sale of Investments and Return of Capital from Partnerships		18			205			27
Proceeds from Capital Leases		11			183			103
Acquisitions, Net of Cash Provided		—			(17	)		(810	)
Short-Term Loan Receivable—Affiliated Company		(238	)		(62	)		—
Other		(7	)		(3	)		(101	)
Net Cash Used In Investing Activities		(523	)		(29	)		(1,482	)
CASH FLOWS FROM FINANCING ACTIVITIES
Short-Term Loan (Repayment)—Affiliate		—			(38	)		38
Net Change in Short-Term Debt		—			(294	)		139
Proceeds from Sale of Senior Notes		350			139			324
Proceeds from Project-Level Non-Recourse Long-Term Debt		686			73			950
Proceeds from Capital Contributions		—			400			400
Deferred Issuance Costs		(20	)		(2	)		(11	)
Repayment of Medium-Term and Project-Level Non-Recourse Debt		(660	)		(271	)		(423	)
Distributions to (Proceeds from) Minority Shareholders		(48	)		5			(61	)
Cash Dividends Paid on Common Stock		—			—			(3	)
Cash Dividends Paid on Preferred Stock		(23	)		(23	)		(23	)
Restricted Cash		(8	)		—			2
Net Cash Provided By (Used In) Financing Activities		277			(11	)		1,332
Effect of Exchange Rate Change		2			(13	)		—
Net Change In Cash and Cash Equivalents		52			55			37
Cash and Cash Equivalents at Beginning of Period		109			54			17
Cash and Cash Equivalents at End of Period	$	161		$	109		$	54
Supplemental Disclosure of Cash Flow Information:
Income Taxes Received	$	(154	)	$	(126	)	$	(178	)
Interest Paid, Net of Amounts Capitalized	$	166		$	193		$	155

See disclosures regarding PSEG Energy Holdings LLC included in the
Notes to Consolidated Financial Statements.

118

PSEG ENERGY HOLDINGS LLC

CONSOLIDATED STATEMENTS OF MEMBER’S/STOCKHOLDER’S EQUITY
(Millions)

																As Restated, see Note 2 Retained Earnings				As Restated, see Note 2				As Restated, see Note 2 Total Member’s/ Stockholder’s Equity
	Ordinary Unit				Preference Units			Preferred Stock				Additional Paid-In Capital				As Restated, see Note 2 Retained Earnings				Accumulated Other Comprehensive Loss
Balance as of January 1, 2001		$	—			$	—		$	509			$	1,090			$	318			$	(218	)		$	1,699
Net Income			—				—			—				—				177				—				177
Other Comprehensive Income (Loss), net of tax: Currency Translation Adjustment, net of tax of $(7)			—				—			—				—				—				(68	)			(68	)
Cumulative Effect of a Change in Accounting Principle, net of tax of $(14)			—				—			—				—				—				(15	)			(15	)
Current Period Declines in Fair Value of Derivative Instruments—Net			—				—			—				—				—				(16	)			(16	)
Reclassification Adjustments for Net Amounts Included in Net Income			—				—			—				—				—				4				4
Other Comprehensive Loss			—				—			—				—				—				—				(95	)
Comprehensive Income																										82
Additional Contributed Capital			—				—			—				400				—				—				400
Preferred Stock Dividends			—				—			—				—				(23	)			—				(23	)
Other			—				—			—				—				(3	)			—				(3	)
Balance as of December 31, 2001		$	—			$	—		$	509			$	1,490			$	469			$	(313	)		$	2,155
Net Loss			—				—			—				—				(390	)			—				(390	)
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax of ($45)			—				—			—				—				—				(140	)			(140	)
Reclassification Adjustment for Losses Included in Net Income, net of tax of $37			—				—			—				—				—				68				68
Current Period Declines in Fair Value of Derivative Instruments, net of tax of $(10)			—				—			—				—				—				(45	)			(45	)
Reclassification Adjustments for Net Amounts Included in Net Income			—				—			—				—				—				9				9
Settlement Adjustments Related to Projects Under Construction			—				—			—				—				—				(3	)			(3	)
Minimum Pension Liability Adjustment			—				—			—				—				—				(6	)			(6	)
Other Comprehensive Loss			—				—			—				—				—				—				(117	)
Comprehensive Loss																										(507	)
Additional Contributed Capital			100				—			—				300				—				—				400
Recapitalization of Energy Holdings’ Assets and Liabilities			1,790				509			(509	)			(1,790	)			—
Preference Units/Preferred Stock Dividends			—				—			—				—				(23	)			—				(23	)
Dividend of Pantellos Corporation to PSEG			(2	)			—			—				—				—				—				(2	)
Balance as of December 31, 2002		$	1,888			$	509		$	—			$	—			$	56			$	(430	)		$	2,023
Net Income			—				—			—				—				145				—				145
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax of $4			—				—			—				—				—				164				164
Current Period Declines in Fair Value of Derivative Instruments, net of tax of $(11)			—				—			—				—				—				(22	)			(22	)
Reclassification Adjustments for Net Amounts Included in Net Income			—				—			—				—				—				23				23
Settlement Adjustments Related to Projects Under Construction			—				—			—				—				—				(11	)			(11	)
Minimum Pension Liability Adjustment			—				—			—				—				—				5				5
Other Comprehensive Income			—				—			—				—				—				—				159
Comprehensive Income																										304
Preference Units/Preferred Stock Dividends			—				—			—				—				(23	)			—				(23	)
Balance as of December 31, 2003		$	1,888			$	509		$	—			$	—			$	178			$	(271	)		$	2,304

See disclosures regarding PSEG Energy Holdings LLC included in the
Notes to Consolidated Financial Statements.

119

Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each make representations only as to itself and make no other representations whatsoever as to any other company.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Organization and Summary of Significant Accounting Policies

Organization

Public Service Enterprise Group Incorporated (PSEG)

PSEG has four principal direct wholly-owned subsidiaries: Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power), PSEG Energy Holdings LLC (Energy Holdings) and PSEG Services Corporation (Services).

PSE&G

PSE&G is a public utility providing electric and gas transmission and distribution service in certain areas within the State of New Jersey. Following the transfer of its generation-related assets and liabilities to Power in August 2000 and gas supply business to Power in May 2002, PSE&G continues to own and operate its transmission and distribution business. PSE&G owns PSE&G Transition Funding LLC (Transition Funding), a bankruptcy remote entity established for the purpose of purchasing intangible transition property and issuing transition bonds.

Power

Power is a multi-regional wholesale energy supply business that utilizes energy trading to manage its portfolio of electric generation assets, gas supply and storage contracts and electric and gas supply obligations. Power has three principal direct wholly-owned subsidiaries: PSEG Nuclear LLC (Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC (ER&T). Power and its subsidiaries were established to acquire, own and operate the electric generation-related business of PSE&G pursuant to the Final Decision and Order (Final Order) issued by the New Jersey Board of Public Utilities (BPU) under the New Jersey Electric Discount and Energy Competition Act (EDECA) discussed below.

Energy Holdings

Energy Holdings is the parent of PSEG Global LLC (Global), which invests and participates in the development and operation of international and domestic projects engaged in the generation and distribution of energy, including cogeneration and independent power production facilities and electric distribution companies; PSEG Resources LLC (Resources), which makes investments primarily in energy-related leveraged leases; and Enterprise Group Development Corporation (EGDC), a commercial real estate property management business. During the third quarter of 2003, Energy Holdings completed the sale of PSEG Energy Technologies Inc. (Energy Technologies) and its assets. For additional information relating to Energy Technologies, see Note 5. Discontinued Operations.

Services

Services provides management and administrative services to PSEG and its subsidiaries. These include accounting, legal, communications, human resources, information technology, treasury and financial, investor relations, stockholder services, real estate, insurance, risk management, tax, library and information services, security, corporate secretarial and certain planning, budgeting and forecasting services. Services charges PSEG and its subsidiaries for the cost of work performed and services provided pursuant to the terms and conditions of intercompany service agreements.

120

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Summary of Significant Accounting Policies

Principles of Consolidation

PSEG, PSE&G, Power and Energy Holdings

PSEG’s, PSE&G’s, Power’s and Energy Holdings’ consolidated financial statements include their respective accounts and consolidate those entities in which they have a controlling interest or are the primary beneficiary, except for certain of PSEG’s and PSE&G’s capital trusts which were deconsolidated in accordance with of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46, “Consolidation of Variable Interest Entities (VIE)” (FIN 46), as discussed in Note 3. Recent Accounting Standards. Entities over which PSEG, PSE&G, Power and Energy Holdings exhibit significant influence, but do not have a controlling interest and/or are not the primary beneficiary are accounted for under the equity method of accounting. For investments in which significant influence does not exist and it is not the primary beneficiary, the cost method of accounting is applied. All significant intercompany accounts and transactions are eliminated in consolidation.

PSE&G and Power

PSE&G and Power each has undivided interests in certain jointly owned facilities. PSE&G and Power are responsible to pay for their respective ownership share of additional construction costs, fuel inventory purchases and operating expenses. All revenues and expenses related to these facilities are consolidated at their respective pro-rata ownership share in the appropriate revenue and expense categories on the Consolidated Statements of Operations. For additional information regarding these jointly owned facilities, see Note 24. Property, Plant and Equipment and Jointly Owned Facilities.

Accounting for the Effects of Regulation

PSE&G

PSE&G prepares its financial statements in accordance with the provisions of Statement of Financial Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71). In general, SFAS 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (a regulatory asset) or record 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 and recoveries, which are being amortized over various future periods. To the extent that collection of any 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. PSE&G’s transmission and distribution business continues to meet the requirements for application of SFAS 71. For additional information, see Note 10. Regulatory Assets and Liabilities.

Derivative Financial Instruments

PSEG, PSE&G, Power and Energy Holdings

PSEG, PSE&G, Power and Energy Holdings use derivative financial instruments to manage risk from changes in interest rates, congestion credits, emission credits, commodity prices and foreign currency exchange rates, pursuant to their business plans and prudent practices.

PSEG, PSE&G, Power and Energy Holdings recognize derivative instruments on the balance sheet at their fair value. Changes in the fair value of a derivative that is highly effective as, and that is designated and qualifies as, a fair-value hedge (including foreign currency fair-value hedges), along with changes of the fair value of the hedged asset or liability that are attributable to the hedged risk, are recorded in current-period earnings. Changes in the fair value of a derivative that is highly effective as

121

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

and that is designated and qualifies as a cash flow hedge (including foreign currency cash flow hedges) are recorded in Other Comprehensive Income (OCI) until earnings are affected by the variability of cash flows of the hedged transaction. Any hedge ineffectiveness is included in current-period earnings. In certain circumstances, PSEG, PSE&G, Power and/or Energy Holdings enter into derivative contracts that do not qualify as hedges or choose not to designate them as fair value or cash flow hedges, in such cases, changes in fair value are recorded in current period earnings.

For additional information regarding derivative financial instruments, see Note 16. Risk Management.

Revenue Recognition

PSE&G

PSE&G’s Operating Revenues are recorded based on services rendered to customers during each accounting period. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period. The unbilled revenue is estimated each month based on usage per day, the number of unbilled days in the period, estimated seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms.

Power

The majority of Power’s revenues relate to bilateral contracts, which are accounted for on the accrual basis as the energy is delivered. Power also records revenues and energy costs for physical energy delivered to and received from power pools. Power also records margins from energy trading on a net basis pursuant to accounting principles generally accepted in the U.S. (GAAP). See Note 16. Risk Management for further discussion.

Energy Holdings

Global records revenues from its investments in generation and distribution facilities. Certain of Global’s investments are majority owned, controlled and consolidated by Global and the revenues from these projects are recorded as Global’s revenues. Other investments are less than majority owned and are accounted for under the equity or cost methods as appropriate. Revenues for many of these investments are estimated on a monthly basis and trued up to actual results in the next accounting month. Gains or losses incurred as a result of exiting one of these businesses are typically recorded as a component of Operating Income.

The majority of Resources’ revenues relate to its investments in leveraged leases and are accounted for under SFAS No. 13 “Accounting for Leases” (SFAS 13). Income on leveraged leases is recognized by a method which produces a constant rate of return on the outstanding net investment in the lease, net of the related deferred tax liability, in the years in which the net investment is positive. Any gains or losses incurred as a result of a lease termination are recorded as revenues as these events occur in the ordinary course of business of managing the investment portfolio. Related to its equity securities, Resources records revenues from the changes in share prices of publicly-traded equity securities held within its leveraged buyout funds. See Note 12. Long-Term Investments for further discussion.

Depreciation and Amortization

PSE&G

PSE&G calculates depreciation under the straight-line method based on estimated average remaining lives of the several classes of depreciable property. These estimates are reviewed on a periodic basis and necessary adjustments are made as approved by the BPU. The depreciation rate

122

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

stated as a percentage of original cost of depreciable property was 3.30% for 2003, 3.37% for 2002 and 3.32% for 2001.

Power

Power calculates depreciation on generation-related assets under the straight-line method based on the assets’ estimated useful life which is determined based on planned operations. The estimated useful lives are from 3 years to 20 years for general plant assets. The estimated useful lives are 30 years to 55 years for fossil production assets, 49 years to 56 years for nuclear generation assets and 45 years for pumped storage facilities.

Energy Holdings

Energy Holdings calculates depreciation on property, plant and equipment under the straight-line method with estimated useful lives ranging from 3 years to 40 years.

Taxes Other Than Income Taxes

PSE&G

Excise taxes, transitional energy facilities assessment (TEFA) and gross receipts tax (GRT) collected from PSE&G customers are presented on the financial statements on a gross basis. As a result of New Jersey energy tax reform, effective January 1, 1998, TEFA and GRT are the residual of the prior excise tax, New Jersey gross receipts and franchise taxes. For the years ended December 31, 2003, 2002 and 2001, combined TEFA and GRT of approximately $152 million, $145 million and $142 million, respectively, are reflected in Operating Revenues and $136 million, $131 million and $121 million, respectively, are included in Taxes Other Than Income Taxes on the Consolidated Statements of Operations.

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized During Construction (IDC)

PSE&G

AFUDC represents the cost of debt and equity funds used to finance the construction of new utility assets under the guidance of SFAS 71. The amount of AFUDC capitalized was reported in the Consolidated Statements of Operations as a reduction of interest charges. PSE&G’s average rate used for calculating AFUDC in 2003, 2002, and 2001 was 3.43%, 8.34% and 6.65%, respectively. In 2003, 2002, and 2001, PSE&G’s AFUDC amounted to less than $1 million, $1 million and $2 million, respectively.

Power and Energy Holdings

IDC represents the cost of debt used to finance construction at Power and Energy Holdings. The amount of IDC capitalized is reported in the Consolidated Statements of Operations as a reduction of interest charges and is included in Property, Plant and Equipment on the Consolidated Balance Sheets. Power’s average rate used for calculating IDC in 2003, 2002 and 2001 was 7.07%, 7.01% and 8.59%, respectively. In 2003, 2002, and 2001, Power’s IDC amounted to $109 million, $95 million and $63 million, respectively. Energy Holdings’ average rate used for calculating IDC in 2003, 2002 and 2001 was 8.70%, 9.06% and 8.05%, respectively. In 2003, 2002, and 2001, Energy Holdings’ IDC amounted to $12 million, $13 million and $14 million, respectively.

123

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Income Taxes

PSEG, PSE&G, Power and Energy Holdings

PSEG and its subsidiaries file a consolidated Federal income tax return and income taxes are allocated to PSEG’s subsidiaries based on the taxable income or loss of each subsidiary. Investment tax credits were deferred in prior years and are being amortized over the useful lives of the related property.

Foreign Currency Translation/Transactions

Energy Holdings

Revenues and expenses are translated at average exchange rates for the year. Transaction gains and losses that arise from exchange rate fluctuations on normal operating transactions denominated in a currency other than the functional currency are included in earnings as incurred.

The assets and liabilities of foreign operations are translated into U.S. Dollars at current exchange rates. Resulting translation adjustments are reflected in OCI, net of taxes, as a separate component of member’s/stockholders’ equity.

Cash and Cash Equivalents

PSEG, PSE&G, Power and Energy Holdings

Cash and cash equivalents consist primarily of working funds and highly liquid marketable securities (commercial paper and money market funds) with an original maturity of three months or less.

Materials and Supplies and Fuel

PSE&G

PSE&G’s materials and supplies are carried at average cost consistent with the rate-making process.

Power and Energy Holdings

The carrying value of the materials and supplies and fuel for Power and Energy Holdings is valued at the lower of average cost or market.

Property, Plant and Equipment

PSE&G

PSE&G’s additions to plant, property and equipment and replacements that are either retirement units or property record units are capitalized at original cost. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. At the time units of depreciable property are retired or otherwise disposed of, the original cost, adjusted for salvage value, is charged to accumulated depreciation.

Power and Energy Holdings

Power and Energy Holdings only capitalize costs which increase the capacity or extend the life of an existing asset, represent a newly acquired or constructed asset or represent the replacement of a retired asset. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. Environmental costs are capitalized if the costs mitigate or

124

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

prevent future environmental contamination or if the costs improve existing assets’ environmental safety or efficiency. All other environmental expenditures are expensed as incurred.

Other Special Funds

PSEG, PSE&G, Power and Energy Holdings

Other Special Funds represents amounts deposited to fund the qualified pension plans and to fund a Rabbi Trust which was established to meet the obligations related to three non-qualified pension plans and a deferred compensation plan.

Nuclear Decommissioning Trust (NDT) Fund

Power

Prior to the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143), amounts collected from PSE&G customers that have been deposited into the NDT Fund and realized and unrealized gains and losses in the trust were all recorded as changes in the NDT Fund with an offsetting charge to the nuclear decommissioning liability.

Effective January 1, 2003, Power adopted SFAS 143, which addresses accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. In addition, the BPU issued an order that PSE&G’s customers will no longer fund the NDT Fund. Therefore, deferral accounting is no longer appropriate. Beginning January 1, 2003, realized gains and losses were recorded in earnings and unrealized gains and losses were recorded as a component of OCI, as required under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (SFAS 115). See Note 3. Recent Accounting Standards and Note 4. Adoption of SFAS 143 for a discussion of SFAS 143 and the impact of its adoption.

Investments in Corporate Joint Ventures and Partnerships

Energy Holdings

Generally, Global’s and Resources’ interests in active joint ventures and partnerships are accounted for under the equity method of accounting where its respective ownership interests are 50% or less, it is not the primary beneficiary, as defined under FIN 46, and significant influence over joint venture or partnership operating and management decisions exists. For investments in which significant influence does not exist and it is not the primary beneficiary, the cost method of accounting is applied. Interest is capitalized on investments during the construction and development of qualifying assets.

There are several investments recorded in accordance with the equity method of accounting for which there is a difference in the investment account when compared to the underlying equity in net assets. The reconciling items include amounts for loans to the operating entities, capitalized interest and capitalized expenses. From time to time, Global loans funds to certain operating entities in which it participates, which are used to construct generation facilities. Such loans earn interest at market rates. For additional information on these loans, see Note 26. Related-Party Transactions. In the instance of capitalized interest, to the extent borrowings on the part of Global were required to fund the underlying investment of the project, and such project is under construction, the interest accrued on such borrowings is recorded in the investment account. This is a temporary difference, as amortization of the amount of interest capitalized will begin upon commencement of the project. In the instance of capitalized expenses, all direct external and internal costs related to project development are capitalized once a project reaches certain milestones. When the project reaches financial closing, Global transfers the deferred project balance to the investment account. This is a temporary difference, as the capitalized expenses will amortize upon commencement of the project. For additional information related to these investments, see Note 12. Long-Term Investments.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Resources carries its partnership investments in certain venture capital and leveraged buyout funds investing in securities at fair value where market quotations and an established liquid market of underlying securities in the portfolio are available. Fair value is determined based on the review of market price and volume data in conjunction with Resources’ invested liquid position in such securities. Changes in fair value are recorded in Operating Revenues in the Consolidated Statements of Operations.

Deferred Project Costs

Power and Energy Holdings

Power and Energy Holdings capitalize all direct external and direct incremental internal costs related to project development once a project reaches certain milestones. Once the project reaches financial closing, the deferred project balance is transferred to the investment account. These costs are amortized on a straight-line basis over the lives of the related project assets. Such amortization commences upon the date of commercial operation. Development costs related to unsuccessful projects are charged to expense. Deferred project costs are recorded in Construction Work in Progress on Power’s Consolidated Balance Sheets. Deferred project costs are recorded in Investments or Other Assets on Energy Holdings’ Consolidated Balance Sheets.

Stock Compensation

PSEG

PSEG applies Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations in accounting for stock-based compensation plans, which are described below. Accordingly, no compensation cost has been recognized for fixed stock option grants since the exercise price of the stock options equaled the market price of the underlying stock on the date of grant. Had compensation costs for stock option grants been determined based on the fair value at the grant dates for awards under these plans in accordance with SFAS No. 123 “Accounting for Stock-Based Compensation,” there would have been a charge to Net Income of approximately $8 million, $10 million and $10 million in 2003, 2002 and 2001, respectively, with a $(0.04), $(0.05) and $(0.05) impact on diluted earnings per share in 2003, 2002, and 2001, respectively.

The following table illustrates the effect on Net Income and Earnings Per Share if PSEG had applied the fair value recognition provisions of SFAS No. 123 to stock-based employee compensation:

	Years Ended December 31,

	2003			2002			2001
	(Millions, except Share Data)

Net Income, as reported	$	1,160		$	235		$	764
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(8	)		(10	)		(10	)

Pro forma Net Income	$	1,152		$	225		$	754

Earnings per share:
Basic—as reported	$	5.08		$	1.13		$	3.67
Basic—pro forma	$	5.05		$	1.08		$	3.62
Diluted—as reported	$	5.07		$	1.13		$	3.67
Diluted—pro forma	$	5.03		$	1.08		$	3.62

See Note 11. Earnings Per Share for further information.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Basis Adjustment

PSE&G and Power

PSE&G and Power have recorded a Basis Adjustment on their Consolidated Balance Sheets relating to the generation assets that were transferred from PSE&G to Power in August 2000 at the price specified by the BPU. Because the transfer was between affiliates, PSE&G and Power, the transaction was recorded at the net book value of the assets and liabilities rather than the transfer price. The difference between the total transfer price and the net book value of the generation-related assets and liabilities, approximately $986 million, net of tax, was recorded as a Basis Adjustment on PSE&G’s and Power’s Consolidated Balance Sheets. These amounts are eliminated on PSEG’s consolidated financial statements.

Use of Estimates

PSEG, PSE&G, Power and Energy Holdings

The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions regarding certain types of assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, upon settlement, actual results may materially differ from estimated amounts.

Reclassifications

PSEG, PSE&G, Power and Energy Holdings

Certain reclassifications of amounts reported in prior periods have been made to conform with the current presentation.

Note 2. Restatement of Financial Statements

PSEG and Energy Holdings

Subsequent to the issuance of the Consolidated Financial Statements for the year ended December 31, 2002 and in preparation of the Consolidated Financial Statements for the year ended December 31, 2003, management determined that the recorded amount of Energy Holdings’ investment in Rio Grande Energia S.A. (RGE) was overstated due to a miscalculation of the amount of foreign currency translation adjustments. In addition, certain amounts related to this investment had been erroneously recorded as translation adjustments instead of foreign currency transactions. The impact on previously reported Net Income of PSEG and Energy Holdings of these adjustments resulted in a decrease of $7 million and $2 million for the years ended December 31, 2002 and 2001, respectively. As a result, the accompanying consolidated financial statements of PSEG and Energy Holdings for the years ended December 31, 2002 and 2001 have been restated from the amounts previously reported to reflect the correct amount of foreign currency translation adjustments and to record the effects of foreign currency transactions in earnings rather than as an adjustment to OCI. The effects of this miscalculation also resulted in a reduction of Retained Earnings and an increase to Accumulated Other Comprehensive Loss of $42 million and $29 million as of January 1, 2002. In addition to the adjustments described above, certain other adjustments, previously considered to be immaterial individually and in the aggregate, were also recorded in the restated financial statements for the years ended December 31, 2002 and 2001. The impact on previously reported Net Income of PSEG and Energy Holdings of these other adjustments resulted in a decrease of $3 million and $4 million for the years ended December 31, 2002 and 2001, respectively.

The effects on the financial statements of all adjustments and their related tax effects are detailed as follows:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Statement of Operations

	As Previously Reported				As Restated

	2002				2002
	(Millions, except for Share Data)
PSEG
Energy Costs		$	3,769			$	3,706
Operation and Maintenance		$	1,896			$	1,899
Other Income		$	57			$	39
Other Deductions		$	(79	)		$	(80	)
Interest Expense		$	(783	)		$	(819	)
Income Taxes		$	(248	)		$	(254	)
Loss from Discontinued Operations, including Loss on Disposal, net of tax		$	(51	)		$	(49	)
Cumulative Effect of a Change in Accounting Principle, net of tax		$	(120	)		$	(121	)
Net Income		$	245			$	235
Earnings Per Share (Basic and Diluted)		$	1.17			$	1.13

Consolidated Statement of Operations

	As Previously Reported				As Restated

	2002				2002
	(Millions)
Energy Holdings
Electric Distribution and Generation Revenues		$	364			$	304
Other Operating Revenues		$	30			$	45
Energy Costs		$	147			$	118
Operation and Maintenance		$	165			$	168
Other Income		$	25			$	26
Other Deductions		$	(73	)		$	(77	)
Interest Expense		$	(214	)		$	(217	)
Income Tax Benefit		$	150			$	144
Loss from Discontinued Operations, net of tax		$	(16	)		$	(15	)
Cumulative Effect of a Change in Accounting Principle, net of tax		$	(120	)		$	(121	)
Net Loss		$	(380	)		$	(390	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Statement of Operations

	As Previously Reported				As Restated

	2001				2001
	(Millions, except for Share Data)
PSEG
Operation and Maintenance		$	1,841			$	1,844
Other Income		$	50			$	33
Income Taxes		$	(381	)		$	(373	)
Loss from Discontinued Operations, including Loss on Disposal, net of tax		$	(15	)		$	(12	)
Net Income		$	770			$	764
Earnings Per Share (Basic and Diluted)		$	3.70			$	3.67

Energy Holdings
Operation and Maintenance		$	119			$	122
Other Income		$	6			$	4
Income Tax Expense		$	(65	)		$	(58	)
Loss from Discontinued Operations, net of tax		$	(15	)		$	(12	)
Net Income		$	183			$	177

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Balance Sheet

	As Previously Reported				As Restated

	2002				2002
	(Millions)
PSEG
Cash and Cash Equivalents		$	165			$	171
Accounts Receivable, net of allowances		$	1,370			$	1,404
Prepayments		$	74			$	73
Current Assets of Discontinued Operations		$	107			$	419
Property, Plant and Equipment		$	16,562			$	16,374
Accumulated Depreciation and Amortization		$	(5,113	)		$	(4,734	)
Long-Term Investments		$	4,581			$	4,468
Goodwill		$	452			$	446
Other Noncurrent Assets		$	236			$	225
Current Liabilities of Discontinued Operations		$	83			$	324
Deferred Income Taxes and Investment Tax Credits		$	2,924			$	2,903
Other Noncurrent Liabilities		$	638			$	623
Retained Earnings		$	1,601			$	1,554
Accumulated Other Comprehensive Loss		$	(689	)		$	(739	)

Energy Holdings
Cash and Cash Equivalents		$	104			$	109
Accounts Receivable:
Trade—Net		$	91			$	78
Other Accounts Receivable—Net		$	24			$	20
Prepayments		$	4			$	4
Current Assets of Discontinued Operations		$	107			$	419
Property, Plant and Equipment		$	1,534			$	1,352
Accumulated Depreciation and Amortization		$	(139	)		$	(154	)
Corporate Joint Ventures		$	1,004			$	865
Goodwill		$	436			$	430
Other Assets		$	111			$	108
Current Liabilities of Discontinued Operations		$	95			$	336
Deferred Income Taxes and Investment and Energy Tax Credits		$	1,042			$	1,022
Other Noncurrent Liabilities		$	179			$	180
Retained Earnings		$	107			$	56
Accumulated Other Comprehensive Loss		$	(380	)		$	(430	)

The amounts as previously reported do not reflect certain reclassifications due to presentation of Energy Holdings’ investment in Carthage Power Company (CPC), a generating facility in Rades, Tunisia as a discontinued operations, as discussed in Note 5. Discontinued Operations and the effects of the adoption of FIN 46, as discussed in Note 3. Recent Accounting Standards and other reclassifications that have been made to conform with the current presentation.

Note 3. Recent Accounting Standards

SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” (SFAS 150)

PSEG and PSE&G

SFAS 150, which became effective July 1, 2003, established standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. The

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

adoption of SFAS 150 did not have any effect on PSEG’s, PSE&G’s, Power’s or Energy Holdings’ financial statements.

SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS 149)

PSEG, PSE&G, Power and Energy Holdings

SFAS 149 amends and clarifies the accounting guidance for derivative instruments (including certain derivative instruments embedded in other contracts) and hedging activities that fall within the scope of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133). Under this standard, any non-power commodity contracts (e.g., gas contracts) and power contracts that do not meet the definition in SFAS 133 and SFAS 149 that are subject to unplanned netting, will be ineligible for “normal” treatment, which would result in those contracts being marked to market. SFAS 149 is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. There was no impact on PSEG’s, PSE&G’s, Power’s or Energy Holdings’ respective financial statements due to the adoption of this standard.

SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities” (SFAS 146)

PSEG, PSE&G, Power and Energy Holdings

This Statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (EITF) Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)” (EITF 94-3). The principal difference between SFAS 146 and EITF 94-3 relates to its requirements for recognition of a liability for a cost associated with an exit or disposal activity. SFAS 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF 94-3, a liability for an exit cost as defined therein was recognized at the date of an entity’s commitment to an exit plan. A fundamental conclusion reached by the FASB was that an entity’s commitment to a plan, by itself, does not create a present obligation to others that meets the definition of a liability. Therefore, SFAS 146 eliminates the definition and requirements for recognition of exit costs in EITF 94-3. SFAS 146 also establishes that fair value is the objective for initial measurement of the liability. The adoption of SFAS 146 did not have any effect on PSEG’s, PSE&G’s, Power’s or Energy Holdings’ financial statements.

SFAS No. 145, “Rescission of FASB Statements Nos. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections” (SFAS 145)

PSEG, PSE&G, Power and Energy Holdings

Effective January 1, 2002, PSEG, PSE&G, Power and Energy Holdings adopted SFAS 145. This Statement rescinds SFAS No. 4, “Reporting Gains and Losses from Extinguishments of Debt,” (SFAS 4) and an amendment of that Statement, SFAS No. 64, “Extinguishments of Debt Made to Satisfy Sinking Fund Requirements” (SFAS 64). SFAS 4 required that gains and losses from extinguishments of debt that were included in the determination of Net Income be aggregated, and if material, classified as an Extraordinary Item. Under SFAS 145, companies are no longer permitted to classify the amounts as extraordinary and now must record these gains and losses in Other Income and Other Deductions. Energy Holdings recorded pre-tax gains of $14 million ($8 million, after-tax) from the early retirement of debt as a component of Other Income for the period ended December 31, 2002. Also, Energy Holdings reclassified a pre-tax loss of $3 million ($2 million after-tax) from the early retirement of debt to a component of Other Deductions for the period ended December 31, 2001.

SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS 144)

PSEG, PSE&G, Power and Energy Holdings

On January 1, 2002, SFAS 144, which provides guidance on the accounting for the impairment or disposal of long-lived assets, became effective. For long-lived assets to be held and used, the new rules

131

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

are similar to previous guidance, which required the recognition of an impairment when the undiscounted cash flows will not recover its carrying amount. The impairment to be recognized is measured as the difference between the carrying amount and fair value of the asset. There was no impact on the Consolidated Financial Statements of PSEG, PSE&G, Power or Energy Holdings upon adoption of these rules. For additional information, see Note 8. Asset Impairments.

SFAS 143

PSEG, PSE&G, Power and Energy Holdings

Effective January 1, 2003, PSEG, PSE&G, Power and Energy Holdings each adopted SFAS 143. SFAS 143 addresses accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. A legal obligation is a liability that a party is required to settle as a result of an existing or enacted law, statute, ordinance or contract. Under SFAS 143, a company must initially recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred and concurrently capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. A company is required to subsequently depreciate that asset retirement cost to expense over its useful life. In periods subsequent to initial measurement, an entity is required to recognize changes in the liability resulting from the passage of time (accretion) or due to revisions to either the timing or the amount of the originally estimated cash flows. Changes in the liability due to accretion are charged to Operation and Maintenance expense on the Consolidated Statements of Operations, whereas changes due to the timing or amount of cash flows are adjustments to the carrying amount of the related asset. See Note 4. Adoption of SFAS 143 for additional information.

SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142)

PSEG, PSE&G, Power and Energy Holdings

On January 1, 2002, PSEG, PSE&G, Power and Energy Holdings adopted SFAS 142. Under this standard, PSEG, PSE&G, Power and Energy Holdings were required to complete an impairment analysis of goodwill. Under SFAS 142, goodwill is a nonamortizable asset subject to an annual review for impairment and an interim review when certain events or changes in circumstances occur. At the time of adoption, PSE&G had no goodwill. The effect of no longer amortizing goodwill on an annual basis was not material to PSEG’s or Power’s financial position and results of operations upon adoption. Power and Energy Holdings evaluated the recoverability of the recorded amount of their goodwill based on certain operating and financial factors. Such impairment testing included discounted cash flow tests, which require broad assumptions and significant judgment to be exercised by management. In addition to goodwill, PSEG’s total intangible assets as of December 31, 2003 were $103 million, all of which are not subject to amortization. These intangible assets totaled $14 million, $49 million and $40 million and are related to defined benefit pension plans, emissions allowances, which are expensed as used, and various access rights, respectively. In addition to goodwill, PSEG’s total intangible assets as of December 31, 2002 were $206 million, all of which are not subject to amortization, of which $114 million, $52 million and $40 million, related to defined benefit pension plans, emissions allowances, which are expensed as used, and various access rights, respectively.

PSE&G

As of December 31, 2003 and December 31, 2002, PSE&G had intangible assets recorded related to defined benefit pension plans totaling $2 million and $60 million, respectively. These intangible assets are not subject to amortization.

Power

In addition to goodwill displayed in the table below, as of December 31, 2003, Power’s intangible assets were $92 million, of which $3 million, $49 million and $40 million, related to its defined benefit

132

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

pension plans, emissions allowances, which are expensed as used, and various access rights at its Albany Station, respectively. As of December 31, 2002, in addition to goodwill displayed in the table below, Power’s intangible assets were $125 million, of which $33 million, $52 million and $40 million, related to its defined benefit pension plans, emissions allowances, which are expensed as used, and various access rights, respectively.

Energy Holdings

In addition to goodwill displayed in the table below, Energy Holdings has an intangible asset related to its defined benefit pension plans of $4 million and $5 million as of December 31, 2003 and 2002, respectively, which is not subject to amortization.

On January 1, 2002, Energy Holdings recorded the results of its evaluation under SFAS 142. The total amount of goodwill impairments was $121 million, net of tax of $66 million, and was comprised of $36 million (after-tax) at Empresa Distribuidora de Electricidad de Entre Rios S.A. (EDEERSA), an Argentine distribution company, $35 million (after-tax) at RGE, a Brazilian distribution company, $32 million (after-tax) at Energy Technologies and $18 million (after-tax) at Tanir Bavi Power Company Ltd. (Tanir Bavi), a generating facility in India. All of the goodwill related to these companies, other than RGE, was fully impaired.

Power and Energy Holdings

Power and Energy Holdings evaluated the recoverability of the recorded amount of goodwill based on certain operating and financial factors. Such impairment testing included discounted cash flow tests which require broad assumptions and significant judgment to be exercised by management. As of December 31, 2003 and December 31, 2002, Power and Energy Holdings’ goodwill and pro-rata share of goodwill in equity method investments was as follows:

	As of December 31,

	2003		2002
	(Millions)

Consolidated Investments
Energy Holdings—Global
Sociedad Austral de Electricidad S.A. (SAESA)(A)	$	352	$	290
Empresa de Electricidad de los Andes S.A. (Electroandes)(B)		133		134
Elektrocieplownia Chorzow Sp. Z o.o. (ELCHO)		6		6

Total Energy Holdings-Global		491		430
Power—Albany Steam Station		16		16

Total PSEG Consolidated Goodwill		507		446

Pro-Rata Share of Equity Method Investments
Energy Holdings-Global
Rio Grande Energia (RGE)(A)		73		58
Chilquinta Energia S.A. (Chilquinta)(A)(C)		163		163
Luz del Sur S.A.A(C)		63		39
Kalaeloa		25		25

Pro-Rata Share of Equity Investment Goodwill		324		287

Total PSEG Goodwill	$	831	$	733

(A)

Changes relate to changes in foreign exchange rates.

(B)

Changes relate to purchase price allocation adjustments.

(C)

Changes relate to a realignment of existing investments in Chile and Peru.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SFAS 133

PSEG, PSE&G, Power and Energy Holdings

On January 1, 2001, PSE&G, Power and Energy Holdings adopted SFAS 133. SFAS 133 established accounting and reporting standards for derivative instruments, including certain derivative instruments included in other contracts, and for hedging activities. The rules require an entity to recognize the fair value of derivative instruments held as assets or liabilities on the balance sheet. For cash flow and net investment hedging, changes in the fair value of the effective portion of the gain or loss on the derivative are reported in OCI or as a Regulatory Asset (Liability), net of tax for cash flow hedge amounts in OCI and are ultimately recognized in earnings simultaneously with the related hedged forecasted transaction. The change in the fair value of the ineffective portion of the gain or loss on a derivative instrument designated as a cash flow hedge is recorded in earnings. Derivative instruments that are not cash flow or net investment hedges or have not been designated as hedges are adjusted to fair value through earnings.

Energy Holdings

On January 1, 2001, Energy Holdings recorded a Cumulative Effect of a Change in Accounting Principle of $10 million, net of tax and a decrease to OCI of $15 million related to the adoption of SFAS 133.

FIN 46

PSEG, PSE&G, Power and Energy Holdings

FASB Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities”, or FIN 46R replaces FIN 46, which was issued July 1, 2003. FIN 46R clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to certain entities in which equity investors do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support.

FIN 46R requires the adoption of either FIN 46 or FIN 46R by the first period ended after December 15, 2003 for Special Purpose Entities (SPEs), however FIN 46R must be adopted no later than the first period ended after March 15, 2004. Non-SPEs are required to be accounted for under the provisions of FIN 46R no later than the first period ended after March 15, 2004. PSEG, PSE&G, Power and Energy Holdings adopted the provisions of FIN 46 as of July 1, 2003. There was no effect on Power due to the adoption of these rules.

The adoption of FIN 46 required PSEG and PSE&G to deconsolidate their capital trusts and Energy Holdings to consolidate its investments in four real estate partnerships. Prior period financial statements have been reclassified for comparability in accordance with FIN 46.

PSEG and PSE&G

PSEG and PSE&G evaluated their respective interests in PSEG Capital Trusts I-IV, PSEG Funding Trust I (trust holding Participating Equity Preference Securities (PEPS)), PSE&G Capital Trust LP and PSE&G Capital Trusts II and determined them to be VIEs under FIN 46. It was further determined that PSEG and PSE&G were not the primary beneficiaries of those entities and therefore are prohibited from consolidating them into the financial statements. Accordingly, these entities were deconsolidated as of July 1, 2003 and were recorded under the equity method of accounting. This resulted in the removal of the preferred securities issued by the trusts from the Consolidated Balance Sheet and the addition to the Consolidated Balance Sheet of long-term debt in an equal amount between PSEG and PSE&G and the respective trusts, which previously had been eliminated in consolidation. Additionally, PSEG’s and PSE&G’s Consolidated Balance Sheets will reflect their equity investment in these entities, which also was previously eliminated in consolidation and will result in equal amounts of additional assets and long-term debt of $36 million and $41 million for PSEG as of

134

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2003 and 2002, respectively. These amounts totaled $5 million for PSE&G as of December 31, 2002. The invested cash was loaned back to PSEG and PSE&G in connection with the issuance of the preferred securities. In December 2003, PSE&G redeemed the preferred securities mentioned above. See Note 15. Schedule of Consolidated Debt for additional information.

The following table displays the securities, and their original issuance amounts, held by the trusts that have now been deconsolidated.

	As of December 31,

	2003		2002
	(Millions)

PSEG
PSEG Quarterly Guaranteed Preferred Beneficial Interest in PSEG’s Subordinated Debentures
7.44%	$	225	$	225
Floating Rate		150		150
7.25%		150		150
8.75%		180		180
PSEG Participating Units
10.25%		460		460

Total PSEG (Parent)		1,165		1,165

PSE&G
PSE&G Monthly Guaranteed Preferred Beneficial Interest in PSE&G’s 8.000% Subordinated Debentures		—		60
PSE&G Quarterly Guaranteed Preferred Beneficial Interest in PSE&G’s 8.125% Subordinated Debentures		—		95

Total PSE&G		—		155

Total PSEG Consolidated	$	1,165	$	1,320

PSEG and PSE&G now record interest expense (previously eliminated against the interest income of the trust) instead of preferred securities dividends (since the preferred dividends are in the trusts that are no longer consolidated). For PSEG, these amounts totaled $69 million, $53 million and $67 million for the years ended December 31, 2003, 2002 and 2001, respectively. For PSE&G, these amounts totaled $13 million, $13 million and $24 million for the years ended December 31, 2003, 2002 and 2001, respectively.

Energy Holdings

Energy Holdings evaluated its interests in four real estate partnerships previously accounted for under the equity method of accounting. These entities were determined to be VIEs and Energy Holdings was determined to be the primary beneficiary and therefore is required to consolidate these entities. The current presentation reflects these entities on a fully consolidated basis and all periods were restated in accordance with FIN 46.

The impact of consolidating the real estate partnerships on the Consolidated Balance Sheets is as follows:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	As of December 31,

	2003		2002
	(Millions)

Amount Previously Recorded Using Equity Method of Accounting
Investment in Real Estate Partnerships	$	23	$	23

Amount Recorded Using Consolidation
Current Assets	$	4	$	4
Noncurrent Assets		50		51

Total Assets	$	54	$	55

Noncurrent Liabilities	$	25	$	26
Minority Interest		6		6

Total Liabilities and Minority Interest	$	31	$	32

There was no material impact of consolidating the real estate partnerships on Operating Revenues and Operating Expenses.

FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45)

PSEG, PSE&G, Power and Energy Holdings

FIN 45 enhances the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. PSEG, PSE&G, Power and Energy Holdings do not anticipate the recording of such liabilities will be material to their respective consolidated financial statements. The initial recognition and initial measurement provisions of this Interpretation were applicable on a prospective basis to guarantees issued or modified after December 31, 2002. For further information regarding Power’s and Energy Holdings’ respective guarantees, refer to Note 17. Commitments and Contingent Liabilities.

EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities”, and Not “Held for Trading Purposes” as Defined in EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 03-11)

PSEG, PSE&G, Power and Energy Holdings

The EITF has previously discussed the income statement presentation of gains and losses on contracts held for trading purposes in EITF 02-3. The EITF reached a consensus that gains and losses (realized and unrealized) on all derivative instruments within the scope of SFAS 133 should be shown net when recognized in the Consolidated Statement of Operations, whether or not settled physically, if the derivative instruments are “held for trading purposes” as defined in EITF 02-3. EITF 03-11 contemplates whether realized gains and losses should be shown gross or net in the Consolidated Statement of Operations for contracts that are not held for trading purposes, but are derivatives subject to SFAS 133. On July 31, 2003, the EITF indicated that the determination of whether realized gains and losses on physically settled derivative contracts not “held for trading purposes” should be reported on a gross or net basis is a matter of judgment. The EITF indicated that companies may base their judgment on existing authoritative guidance in gross/net presentation, such as EITF 99-19, “Reporting Revenue Gross as a Principal Versus Net as an Agent” (EITF 99-19). These rules, which are effective for transactions occurring after September 30, 2003, required PSEG and Power to reduce revenues and

136

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

costs by approximately $5 million since these transactions are required to be recorded as net revenue. EITF 03-11 had no impact on PSE&G and Energy Holdings.

EITF Issue No. 03-4, “Accounting for Cash Balance Pension Plans” (EITF 03-4)

PSEG, PSE&G, Power and Energy Holdings

EITF 03-4 requires that cash balance pension plans be accounted for as defined benefit plans. EITF 03-4 indicates that cash balance plans are forms of accumulation plans with variable crediting formulas and are therefore not pay-related. As a result, a company would apply a traditional unit credit method for determining the expense associated with these plans. PSEG, PSE&G, Power and Energy Holdings each have previously accounted for their cash balance pension plans as defined benefit plans, thus there will be no material impact on their respective financial statements.

EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3)

PSEG and Power

EITF 02-3 requires all gains and losses on energy trading derivatives to be reported on a net basis. Also, energy trading contracts that are not derivatives under SFAS 133 will no longer be marked to market. EITF 02-3 became fully effective January 1, 2003. The majority of Power’s energy trading contracts qualify as derivatives under SFAS 133 and will therefore continue to be marked to market. The impact of implementing these rules had no effect on PSEG’s or Power’s Net Income. Prior period Operating Revenues and Energy Costs on the Consolidated Statements of Operations have been reclassified on a net basis for comparability.

EITF Issue No. 01-8, “Determining Whether an Arrangement is a Lease” (EITF 01-8)

PSEG, PSE&G, Power and Energy Holdings

EITF 01-8 provides guidance in determining whether an arrangement should be considered a lease subject to the requirements of SFAS 13. EITF 01-8 states that the evaluation of whether an arrangement contains a lease within the scope of SFAS 13 should be based on the substance of the arrangement. EITF 01-8 is applied to arrangements agreed or committed to, modified, or acquired in business combinations initiated on or after October 1, 2003. There were no significant impacts on PSEG’s, PSE&G’s, Power’s and Energy Holdings respective results of operations, financial position and net cash flows as a result of the adoption of EITF 01-8.

Other

PSEG, PSE&G, Power and Energy Holdings

In connection with the January 2003 EITF meeting, the FASB was requested to reconsider an interpretation of SFAS 133. The interpretation, which is contained in the Derivatives Implementation Group’s (DIG) C-11 guidance, further clarified by the issuance of DIG Issue C-20, relates to the pricing of contracts that include broad market indices. In particular, that guidance discusses whether the pricing in a contract that contains broad market indices (e.g., Consumer Price Index) could qualify as a normal purchase or sale under SFAS 133. There were no significant impacts on PSEG’s, PSE&G’s, Power’s and Energy Holdings’ respective results of operations, financial position and net cash flows as a result of this interpretation.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 4. Adoption of SFAS 143

PSEG and Power

In the first quarter of 2003, Power completed a review of potential obligations under SFAS 143 and determined that the obligations were primarily related to the decommissioning of its nuclear power plants. Power’s recorded liability for decommissioning as of December 31, 2002 was approximately $766 million and equaled the balance of its NDT Fund, as discussed below. As of January 1, 2003, this liability was recalculated under SFAS 143, and determined to be approximately $261 million. Concurrently, an asset was recorded of approximately $50 million and represented the fair value of the asset retirement obligation at adoption. This asset and liability were calculated using a probability-weighted average of multiple scenarios. The scenarios were each based on estimated cash flows, which were discounted using Power’s risk-adjusted interest rate at the required effective date of the standard and considering the expected time period of the cash outflows. The scenarios included estimates for inflation, contingencies and assumptions related to the timing of decommissioning costs, using the current license lives for each unit, as well as early shutdown and license extensions scenarios.

In addition to the $261 million nuclear decommissioning liability, Power identified certain other legal obligations that meet the criteria of SFAS 143, which are currently not quantifiable, but could be material in the future. These obligations relate to certain industrial establishments subject to the New Jersey Industrial Site Recovery Act (ISRA), underground storage tanks subject to closure requirements, permits and authorizations, the restoration of an area to be occupied by a reservoir at the end of its useful life, an obligation to retire certain plants prior to the start up of a new plant and the demolition and restoration of certain other plant sites once they are no longer in service. Because these legal obligations are not quantifiable, no amounts have been recorded.

Power also had $131 million of cost of removal liabilities recorded on its Consolidated Balance Sheet, as of December 31, 2002, which did not meet the requirements of an Asset Retirement Obligation (ARO) and were therefore reversed and included in the Cumulative Effect of a Change in Accounting Principle recorded in the first quarter of 2003.

As a result of adopting SFAS 143, PSEG and Power recorded a Cumulative Effect of a Change in Accounting Principle of $370 million, after-tax, in the first quarter of 2003. Of this amount, $292 million (after-tax) related to decommissioning at Nuclear and $78 million (after-tax) related to the cost of removal liabilities for the fossil units that were reversed.

The following table reflects pro forma results which include accretion and depreciation expense as if SFAS 143 had always been in effect.

	Years Ended December 31,

	2003		2002		2001
	(Millions)

PSEG
Net Income—as reported	$	1,160	$	235	$	764
Net Income—pro forma	$	790	$	221	$	747

Earnings per share:
Basic—as reported	$	5.08	$	1.13	$	3.67
Basic—pro forma	$	3.46	$	1.06	$	3.59

Diluted—as reported	$	5.07	$	1.13	$	3.67
Diluted—pro forma	$	3.45	$	1.06	$	3.59
Power
Net Income—as reported	$	844	$	468	$	394
Net Income—pro forma	$	474	$	454	$	377

The pro forma amount of the liability for Power’s asset retirement obligations for the period ended December 31, 2002, as well as the actual amount of the liability recorded on Power’s Consolidated

138

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Balance Sheets as of December 31, 2003 are presented in the following table. These amounts were calculated using current information, current assumptions and current interest rates.

	As of December 31,

	2003		2002
	(Millions)

PSEG and Power
Beginning of Period ARO Liability	$	260	$	238
Accretion Expense		24		22

End of Period ARO Liability	$	284	$	260

PSE&G

PSE&G identified certain legal obligations that meet the criteria of SFAS 143, which are currently not quantifiable and therefore are not recorded. These obligations relate to certain industrial establishments subject to the ISRA, underground storage tanks subject to closure requirements, leases and licenses and the requirement to seal natural gas pipelines when the pipelines are no longer in service.

PSE&G had $393 million of cost of removal liabilities recorded on its Consolidated Balance Sheet as of December 31, 2002, which did not meet the requirements of an Asset Retirement Obligation (ARO) and were therefore reclassified to a regulatory liability in 2003. See Note 10. Regulatory Assets and Liabilities for further discussion.

Energy Holdings

Energy Holdings has identified certain legal obligations that meet the criteria of SFAS 143. However, it has determined that they are not material to its financial position, results of operations or net cash flows.

SFAS 143 Effect on the NDT Fund

Power

Prior to the adoption of SFAS 143, amounts collected from PSE&G customers through rates were deposited into the NDT Fund and realized and unrealized gains and losses in the trust were all recorded as changes in the NDT Fund with an offsetting charge to the nuclear decommissioning liability. Prior to SFAS 143, this was appropriate under SFAS 71 and other related accounting guidance. Based on an order issued by the BPU, PSE&G’s customers are no longer required to fund the NDT Fund, and therefore deferral accounting is no longer appropriate for changes in the fair value of securities within the NDT Fund.

Beginning January 1, 2003, realized gains and losses were recorded in earnings and unrealized gains and losses were recorded as a component of OCI, net of tax, as required under SFAS 115. Additionally, because deferral accounting was no longer appropriate, as of January 1, 2003, Power recognized $68 million of pre-tax unrealized losses on securities in the NDT Fund, approximately $40 million of which were deemed other than temporarily impaired and recorded this amount against earnings in the Cumulative Effect of a Change in an Accounting Principle in the first quarter of 2003.

As of December 31, 2003, the fair market value of the NDT Fund was $985 million. For further information regarding the NDT Fund, refer to Note 18. Nuclear Decommissioning Trust.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5. Discontinued Operations

Energy Holdings

CPC

Global has a controlling interest in CPC, which owns and operates a power plant located in Rades, Tunisia. In December 2003, Global entered into a definitive purchase and sale agreement related to its majority interest in CPC, for approximately $43 million. Global will receive approximately $17 million in cash and a promissory note of $26 million, bearing interest at 5%. The note will be payable in three annual installments following the close of the sale of approximately $5 million, $10 million and $11 million, plus interest. The completion of the sale is expected to occur in the latter part of 2004 and is subject to certain conditions, including government and lender approvals. If the sale is unable to be completed, Global will seek another buyer for this facility. CPC meets the criteria for classification as a component of discontinued operations and all prior periods have been reclassified to conform to the current year’s presentation. Global has reduced its carrying value of CPC to its fair value less cost to sell and recorded a loss on disposal for the year ended December 31, 2003 of $23 million. The operating results of CPC for the years ended December 31, 2003, 2002 and 2001 are summarized below.

	Years Ended December 31,

	2003				2002			2001
	(Millions)

Operating Revenues		$	95			$	57		$	—
Pre-Tax (Loss) Income		$	(8	)		$	2		$	8
Net (Loss) Income		$	(1	)		$	1		$	4

The carrying amounts of the assets and liabilities of CPC as of December 31, 2003 and 2002 are summarized in the following table:

	As of December 31,

	2003			2002
	(Millions)

Current Assets		$	28		$	24
Noncurrent Assets			270			288

Total Assets		$	298		$	312

Current Liabilities		$	161		$	40
Noncurrent Liabilities			68			60
Long-Term Debt			13			141

Total Liabilities		$	242		$	241

Energy Technologies

Energy Holdings reduced the carrying value of the investments in the 11 HVAC/mechanical operating companies to their fair value less costs to sell, and recorded a loss on disposal for the year ended December 31, 2002 or $20 million, net of $11 million in taxes. During 2003, Energy Holdings re-evaluated the carrying value of Energy Technologies’ assets and liabilities and determined that market conditions required an additional write-down to fair value less cost to sell and recorded an additional loss on disposal of Energy Technologies of $9 million, net of a $3 million tax benefit. The sale of the HVAC/mechanical operating companies and Energy Technologies was complete as of September 30, 2003.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Energy Holdings has retained certain residual assets and liabilities. As of December 31, 2003, the value of these investments consisted of $60 million in assets and $25 million in liabilities. Of the $60 million in assets, approximately $39 million relates to tax assets associated with the sale of Energy Technologies’ HVAC/mechanical operating companies, with the remaining balance relating primarily to accounts receivable not sold with the HVAC/mechanical operating companies.

The revenues and results of operations of Energy Technologies for the periods ended December 31, 2003, 2002 and 2001, are displayed below:

	Years Ended December 31,

	2003			2002			2001
	(Millions)

Operating Revenues	$	68		$	378		$	441
Pre-Tax Loss	$	(18	)	$	(32	)	$	(34	)
Net Loss	$	(11	)	$	(21	)	$	(23	)

The carrying amounts of the assets and liabilities as of December 31, 2002 are summarized in the following table:

	As of December 31, 2002
	(Millions)

Current Assets		$	82
Noncurrent Assets			25

Total Assets		$	107

Current Liabilities		$	85
Noncurrent Liabilities			5
Long-Term Debt			5

Total Liabilities		$	95

Tanir Bavi

In the fourth quarter of 2002, Global sold its interest in Tanir Bavi for approximately $45 million. Global reduced the carrying value of Tanir Bavi to the contracted sales price of $45 million and recorded a loss on disposal of $14 million (after-tax of $7 million) for the year ended December 31, 2002. The facility met the criteria for classification as a component of discontinued operations and all prior periods were reclassified to conform to that presentation. The operating results of Tanir Bavi for the years ended December 31, 2002 and 2001 are summarized below.

	Years Ended December 31,

	2002			2001
	(Millions)
Operating Revenues		$	61		$	56
Pre-Tax Income		$	7		$	14
Net Income		$	5		$	7

Note 6. Extraordinary Item

PSE&G

In May 2002, PSE&G filed an Electric Base Rate Case with the BPU requesting an annual $250 million increase for its electric distribution business. In June 2003, a proposed settlement was filed with the Administrative Law Judge (ALJ) who recommended approval of the settlement to the BPU. In July

141

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2003, PSE&G received an oral decision from the BPU approving the proposed settlement with certain modifications. As a result of the oral decision and subsequent summary written order, in the second quarter of 2003, PSE&G recorded certain adjustments in connection with the resolution of various issues relating to the Final Order PSE&G received from the BPU in 1999 relating to PSE&G’s rate unbundling, stranded costs and restructuring proceedings. These amounts include a $30 million pre-tax refund to customers related to revenues previously collected in rates for nuclear decommissioning. Because this amount reflects the final accounting for PSEG’s generation-related business pursuant to the four-year transition plan mandated by the Final Order, the adjustment has been recorded as an $18 million, after-tax, Extraordinary Item as required under APB No. 30, “Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions” (APB 30) and SFAS No. 101, “Regulated Enterprises—Accounting for the Discontinuation of Application of FASB Statement No. 71”.

Note 7. Change in Accounting Principle

PSE&G and Power

In 2002, PSE&G and Power each changed its method of accounting for the classification of assets and liabilities arising from transactions related to energy trading contracts when the right of set-off exists, from a separate presentation of assets and liabilities to a net presentation. PSE&G and Power believe that the right of set-off exists when all of the following conditions are met:

•

PSE&G or Power and its respective counterparty owes the other determinable amounts;

•

PSE&G or Power have the right to set off the amount owed with the amount owed by its respective counterparty;

•

PSE&G or Power intend to set-off; and

•

the right of set-off is enforceable by law.

PSE&G and Power each believe that this change in method of accounting and classification is preferable and more closely represents the economic substance of such transactions. Additionally, this method reflects PSE&G’s and Power’s existing practice of settling amounts net and is consistent with the classification of trading revenues and trading costs on a net basis on the Consolidated Statements of Operations.

There was no effect on revenues, expenses, net income or cash flows as a result of this change. Affected amounts on the Consolidated Balance Sheets have been reclassified for all periods presented.

Note 8. Asset Impairments

Energy Holdings

In 2002, Energy Holdings determined that the carrying value of its investments in EDEERSA; 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 S.A. (CTSN) and AES Parana S.C.A. (Parana) were impaired. The combination of the year-to-date operating losses, goodwill impairment at EDEERSA, write-down of $497 million for all Argentine assets, and certain loss contingencies resulted in a pre-tax charge to earnings of $621 million ($404 million after-tax), as discussed further below. In connection with the write-down of Energy Holdings’ Argentine assets, Energy Holdings recorded a net deferred tax asset of $217 million. Energy Holdings has reviewed this deferred tax asset for recoverability and no reserve is required. For a discussion of certain contingencies related to Argentine investments, see Note 17. Commitments and Contingent Liabilities.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The tables below provide pre-tax and after-tax impacts of the various impairment charges, results of operations and accruals of loss contingencies recorded with respect to Energy Holdings’ investments in Argentina for the periods ended December 31, 2002 and 2001.

	(Pre-Tax) Years Ended December 31,					(After-Tax) Years Ended December 31,

	2002			2001		2002			2001
	(Millions)

(Losses) Earnings Before Local Taxes—EDEERSA	$	(57	)	$	19	$	(38	)	$	11
Write-down of EDEERSA		(94	)		—		(61	)		—
Write-down of Assets Held for Sale to AES		(403	)		—		(262	)		—
Loss Contingencies and Other		(11	)		—		(7	)		—
Goodwill Impairment—EDEERSA		(56	)		—		(36	)		—

Total	$	(621	)	$	19	$	(404	)	$	11

EDEERSA

In January 2002, the Argentine Federal government enacted a temporary emergency law that imposed various changes to the concession contracts in effect between electric distributors and local and federal regulators. The Province of Entre Rios enjoined in the emergency law impacting operations at EDEERSA. The Argentine government and regulators made unilateral decisions to abrogate key components of the tariff concessions related to public utilities. Such laws significantly restricted Global’s ability to control the operations of EDEERSA, as unilateral changes enacted by the government restricted Global’s ability to manage its operations to reduce the financial losses incurred as a result of such actions.

Based on actual and projected operating losses at EDEERSA and the continued economic uncertainty in Argentina, Energy Holdings determined that it was necessary to test these assets for impairment. Such impairment analyses were completed as of June 30, 2002. As a result of these analyses, Energy Holdings determined that these assets were completely impaired under SFAS 144.

In March 2003, PSEG formally and irrevocably renounced, and effectively abandoned, its entire economic and legal interest in EDEERSA. The shares were relinquished and ownership was assumed by an Argentine trust benefiting current EDEERSA employees and minority shareholders. The regulator in the Province has requested that 51% of the EDEERSA shares be transferred from the trust to the Province. The matter is pending in the courts. A representative of the labor union representing EDEERSA filed a criminal complaint against the transaction alleging that the union should have been allocated more interest in EDEERSA than the trust arrangement currently provides. Energy Holdings believes that it will have no additional exposure as a result of these legal proceedings but no assurances can be given.

Stock Purchase Agreement

During 2002, Energy Holdings determined that its minority interests in EDEN, EDES, EDELAP, CTSN and Parana were impaired and wrote them down to net realizable value. This resulted in a pre-tax charge $403 million, which was recorded in Write-down of Project Investments on the Consolidated Statement of Operations. On August 24, 2001, Global entered into a Stock Purchase Agreement with The AES Corporation (AES) to sell these investments to certain subsidiaries of AES. AES paid Global $15 million in 2002 and issued promissory notes for an additional $15 million, plus interest at 12%, maturing through July 2003. In July 2003, Energy Holdings received the final note payment from AES.

In connection with the completion of the sale, certain contingent obligations Global had with respect to the project loans relating to EDELAP were terminated by agreement with the lenders.

143

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In August 2003, the shares held by Global in the AES Parana companies were transferred to AES. In connection with the transfer, all contingent obligations Global had with respect to the project loans relating to the AES Parana project were terminated by agreement with the lenders.

Note 9. Restructuring Charges

PSE&G

In April 2003, PSE&G implemented a plan, approved by management, to reduce its work force by approximately 40 positions. These employees voluntarily elected for separation and, thus, was accounted for under SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” (SFAS 88). The cost associated with the restructuring was approximately $3 million and primarily related to termination benefits, all of which have been paid as of December 31, 2003.

Power

In 2003, Power implemented a plan, approved by management, to reduce its work force by approximately 190 positions. The plan was carried out in several phases, which included voluntary and involuntary separations being offered to both represented and non-represented employees. The major cost associated with the restructuring relates to benefits that are to be paid to the employees upon termination. The total cost estimated and recorded is approximately $14 million. The communications included sufficient detail to enable employees to determine the type and amount of benefits they would receive if they elected to be terminated. Amounts relating to voluntary separations were accounted for under SFAS 88, whereas the involuntary separations were accounted for under SFAS 146. The total cost and remaining accrual related to the restructuring charges are detailed below.

Energy Holdings

In 2002, Energy Holdings’ management approved a plan to consolidate some of its locations in order to improve the efficiency of its worldwide reporting processes and eliminate certain redundant administrative functions in North America, South America, England and India. As a result of this plan, Energy Holdings recognized a pre-tax restructuring charge of $7 million in 2002, consisting of $2 million in employee separation costs, a $3 million loss on impairment of leasehold improvements and furniture and equipment, and $2 million in facility exit costs related to subleasing certain offices. The $2 million in facility exit costs relates to the estimated difference in rents with respect to the sub-leased offices. Subsequent to the initial measurement, Energy Holdings revised its estimated cash flows related to these subleases as it was able to sublease these spaces and recognized an adjustment to the liability in 2003 for an additional $3 million.

PSEG, PSE&G, Power and Energy Holdings

The following table illustrates amounts charged against the restructuring reserve during the period ended December 31, 2003 which are included in Operation and Maintenance Expense on the Consolidated Statements of Operations:

	PSE&G				Power				Energy Holdings				Total

	(Millions)

Restructuring Accrual as of December 31, 2002		$	—			$	—			$	2			$	2
Accrued For in 2003			3				14				3				20
Total Paid in 2003			(3	)			(8	)			(1	)			(12	)

Remaining Accrual as of December 31, 2003		$	—			$	6			$	4			$	10

144

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 10. Regulatory Assets and Liabilities

PSE&G

PSE&G prepares its financial statements in accordance with the provisions of SFAS 71. 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. These costs are deferred based on rate orders issued by the BPU or the Federal Energy Regulatory Commission (FERC) or PSE&G’s experience with prior rate cases. As of December 31, 2003 and 2002, approximately 87% and 88%, respectively, of PSE&G’s regulatory assets were deferred based on written rate orders. Regulatory assets recorded on a basis other than by an issued rate order have less certainty of recovery since they can be disallowed in the future by regulatory authorities. PSE&G believes that all of its regulatory assets are probable of recovery. To the extent that collection of any regulatory assets or payments of regulatory liabilities is no longer probable, the amounts would be charged or credited to income.

PSE&G had the following regulatory assets and liabilities on the Consolidated Balance Sheets:

	As of December 31,

	2003		2002		Recovery/Refund Period
	(Millions)
Regulatory Assets
Securitized Stranded Costs	$	3,659	$	3,885		Through December 2015(1)(2)
Deferred Income Taxes		368		326		Various
OPEB-Related Costs		174		193		Through December 2012(2)
Manufactured Gas Plant Remediation Costs		123		115		Various(2)
Unamortized Loss on Reacquired Debt and Debt Expense		94		86		Over remaining debt life(1)
Underrecovered Gas Costs		53		154		Through September 2004(1)
Non-Utility Generation Transition Charge (NTC)		112		—		Through December 31, 2005(1)
Unrealized Losses on Interest Rate Swap		51		66		Through December 2015(2)
Repair Allowance Taxes		82		93		Through August 2013(1)(2)
Decontamination and Decommissioning Costs		16		22		Through December 2007(2)
Plant and Regulatory Study Costs		23		26		Through December 2021(2)
Regulatory Restructuring Costs		42		31		Through August 2013(1)(2)
Other		4		5		To be determined(1)

Total Regulatory Assets	$	4,801	$	5,002

Regulatory Liabilities
Cost of Removal	$	395	$	—		Various
Excess Depreciation Reserve		127		171		Through December 31, 2005(2)
NTC		—		27		Through December 31, 2005(1)
Societal Benefits Charges (SBC)		7		50		Through December 31, 2005(1)(2)
Other		7		4		Various(1)

Total Regulatory Liabilities	$	536	$	252

(1)

Recovered/Refunded with interest.

(2)

Recoverable/Refundable per specific rate order.

All regulatory assets and liabilities are excluded from PSE&G’s rate base unless otherwise noted. The descriptions below define certain regulatory items.

145

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Securitized Stranded Costs: This reflects deferred costs, which are being recovered through the securitization transition charge that was authorized by the BPU. Funds collected through the securitization transition charge are remitted to Transition Funding and are solely to be used for interest and principal payments on the transition bonds, and the related costs and taxes.

Deferred Income Taxes: This amount represents the portion of deferred income taxes that will be recovered through future rates, based upon established regulatory practices, which permit the recovery of current taxes. Accordingly, this regulatory asset is offset by a deferred tax liability and is expected to be recovered, without interest, over the period the underlying book-tax timing differences reverse and become current taxes.

OPEB-Related Costs: Includes costs associated with the adoption of SFAS No. 106. “Employers’ Accounting for Benefits Other Than Pensions” which were deferred in accordance with EITF Issue No. 92-12, “Accounting for OPEB Costs by Rate Regulated Enterprises.”

Manufactured Gas Plant Remediation Costs: Represents a three-year estimate of the environmental investigation and remediation program costs that are probable of recovery in future rates.

Unamortized Loss on Reacquired Debt and Debt Expense: Represents long-term debt issuance costs, premiums, discounts and losses on reacquired long-term debt.

Underrecovered Gas Costs: Represents PSE&G’s gas costs in excess of the amount included in rates and probable of recovery in the future. The current portion of the balance does not accrue interest.

NTC: This clause was established by the EDECA to account for above market costs related to non-utility generation (NUG) contracts, as approved by the BPU. Costs or benefits associated with the restructuring of these contracts are deferred. This clause also includes Basic Generation Service (BGS) costs in excess of current rates, as approved by the BPU.

Unrealized Losses on Interest Rate Swap: This represents the costs related to Transition Funding’s interest rate swap that will be recovered without interest over the life of Transition Funding’s transition bonds. This asset is offset by a derivative liability on the balance sheet.

Repair Allowance Taxes: This represents tax, interest and carrying charges relating to disallowed tax deductions for repair allowance as authorized by the BPU with recovery over 10 years effective August 1, 2003.

Decontamination and Decommissioning Costs: These costs are related to PSE&G’s portion of the obligation for nuclear decontamination and decommissioning costs of U.S. Department of Energy nuclear sites dating back prior to the generation asset transfer to Power in 2000.

Plant and Regulatory Study Costs: These are costs incurred by PSE&G required by the BPU related to current and future operations, including safety, planning, management and construction.

Regulatory Restructuring Costs: These are costs related to the restructuring of the energy industry in New Jersey through the EDECA and include such items as the system design work necessary to transition PSE&G to a transmission and distribution only company, as well as costs incurred to transfer and establish the generation function as a separate corporate entity with recovery over 10 years beginning August 1, 2003.

Other Regulatory Assets: This includes consolidated billing start up costs that have been deferred for future recovery based on a BPU order.

Cost of Removal: PSE&G collects for cost of removal liabilities, which totaled $395 million as of December 31, 2003, which was reclassified from a Cost of Removal liability to a regulatory liability pursuant to the adoption of SFAS 143. This liability is reduced as removal costs are incurred. Cost of removal is a reduction to the rate base.

Excess Depreciation Reserve: As required by the BPU in 1999, PSE&G reduced its depreciation reserve for its electric distribution assets and recorded such amount as a regulatory liability. The original liability was fully amortized in July 2003. In June 2003, PSE&G recorded an additional $155 million

146

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

liability as a result of the oral decision issued by the BPU in PSE&G’s Electric Base Rate Case. This $155 million will be amortized from August 1, 2003 through December 31, 2005.

SBC: The SBC, as authorized by the BPU and the EDECA, includes costs related to PSE&G’s electric and gas business as follows: 1) the universal service fund; 2) amortization of previous overrecovery of nuclear plant decommissioning; 3) Demand Side Management (DSM) programs; 4) social programs which include bad debt expense; 5) consumer education; 6) the New Jersey Clean Energy Program costs payable in 2004; and 7) amortization of the market transition charge (MTC) overrecovery. All components except for MTC and Clean Energy accrue interest.

Other Regulatory Liabilities: This includes the following: 1) amounts collected from customers in order for Transition Funding to obtain a AAA rating on its transition bonds; 2) amounts available to fund consumer education discounts; and 3) a retail adder was included in the BGS charges beginning on August 1, 2003. The BPU will determine the disposition of this amount in the future.

Note 11. Earnings Per Share (EPS)

PSEG

Diluted earnings per share are calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding under PSEG’s stock option plans. The following table shows the effect of these stock options on the weighted average number of shares outstanding used in calculating diluted earnings per share:

	Years Ended December 31,

	2003						2002						2001

	Basic			Diluted			Basic			Diluted			Basic			Diluted

EPS Numerator:
Earnings (Millions)
Continuing Operations	$	852		$	852		$	405		$	405		$	766		$	766
Discontinued Operations		(44	)		(44	)		(49	)		(49	)		(12	)		(12	)
Extraordinary Item		(18	)		(18	)		—			—			—			—
Cumulative Effect of a Change in Accounting Principle		370			370			(121	)		(121	)		10			10

Net Income	$	1,160		$	1,160		$	235		$	235		$	764		$	764

EPS Denominator (Thousands):
Weighted Average Common Shares Outstanding		228,222			228,222			208,647			208,647			207,737			207,737
Effect of Stock Options		—			602			—			166			—			489

Total Shares		228,222			228,824			208,647			208,813			207,737			208,226

Earnings Per Share:
Continuing Operations	$	3.73		$	3.72		$	1.94		$	1.94		$	3.68		$	3.68
Discontinued Operations		(0.19	)		(0.19	)		(0.23	)		(0.23	)		(0.06	)		(0.06	)
Extraordinary Item		(0.08	)		(0.08	)		—			—			—			—
Cumulative Effect of a Change in Accounting Principle		1.62			1.62			(0.58	)		(0.58	)		0.05			0.05

Net Income	$	5.08		$	5.07		$	1.13		$	1.13		$	3.67		$	3.67

There were approximately 5.3 million, 6.3 million and 2.2 million stock options not included in the weighted average common shares calculation used for diluted earnings per share due to their antidilutive effect for the years ended December 31, 2003, 2002 and 2001, respectively. There were approximately 9.2 million participating units not included in the weighted average common shares calculation used for diluted earnings per share due to their antidilutive effect for the years ended December 31, 2003 and 2002.

147

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 12. Long-Term Investments

PSEG, PSE&G, Power and Energy Holdings

PSEG, PSE&G, Power and Energy Holdings had the following Long-Term Investments as of December 31, 2003 and 2002:

	As of December 31,

	2003		2002
	(Millions)
Energy Holdings:
Leveraged Leases	$	2,981	$	2,844
Partnerships:
General Partnerships		25		28
Limited Partnerships		506		440

Total Partnerships		531		468

Corporate Joint Ventures		1,040		865
Securities		4		5
Other Investments(A)		27		33

Total Long-Term Investments of Energy Holdings		4,583		4,215
PSE&G(B)		131		128
Power(C)		43		78
Other Investments(D)		51		47

Total Long-Term Investments	$	4,808	$	4,468

(A)

Primarily relates to DSM investments at Resources.

(B)

Primarily relates to life insurance and supplemental benefits of $123 million and $113 million as of December 31, 2003 and 2002, respectively.

(C)

Amounts represent SO₂ and NO_x emission credits held for future use.

(D)

Amounts represent investments at PSEG (parent company), primarily related to investments in its Capital Trusts.

Energy Holdings

Leveraged Leases

Energy Holdings’ net investment, through Resources, in leveraged leases is comprised of the following elements:

	As of December 31,

	2003			2002
	(Millions)
Lease rents receivable	$	3,373		$	3,429
Estimated residual value of leased assets		1,405			1,414

		4,778			4,843
Unearned and deferred income		(1,797	)		(1,999	)

Total investments in leveraged leases		2,981			2,844
Deferred taxes		(1,563	)		(1,325	)

Net investment in leveraged leases	$	1,418		$	1,519

148

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Resources’ pre-tax income and income tax effects related to investments in leveraged leases are as follows:

	Years Ended December 31,

	2003				2002				2001
	(Millions)
Pre-tax income of leveraged leases		$	206			$	251			$	206

Income tax effect on pre-tax income of leveraged leases		$	74			$	92			$	62
Amortization of investment tax credits of leveraged leases		$	(1	)		$	(1	)		$	(1	)

Of the $45 million increase in leveraged lease income in 2002, $29 million resulted from a gain due to a recalculation of certain leveraged leases. A change in an essential assumption which affects the estimated total net income over the life of a leveraged lease requires a recalculation of the leveraged lease, from inception, using the revised information. The change in the net investment in the leveraged leases is recognized as a gain or loss in the year the assumption is changed. The change in assumption that occurred was related to a change in New Jersey tax rates applied in the leveraged lease calculations. This was due to the restructuring of Resources from a corporation to a limited liability company, which resulted in the ability to more efficiently match state tax expenses of an affiliate company with the state tax benefits associated with Resources’ lease portfolio. The remaining $16 million increase in leveraged lease income was due to additional investments in leveraged lease transactions in 2002 and 2001.

In November 2003, Resources sold its interest in Chelsea Historic Properties. Resources received net cash proceeds of $9 million, recognizing an after-tax gain of approximately $4 million. As a result of the sales of these leases, Resources will pay income taxes of approximately $3 million.

In November 2002, Resources terminated two lease transactions due to an uncured default under the lease financial covenants. Resources received cash proceeds of $183 million, recognizing an after-tax gain of $4 million. As a result of these lease terminations, Resources paid income taxes of $115 million in 2003.

Partnership Investments and Corporate Joint Ventures

Energy Holdings’ partnership investments of $531 million and $468 million as of December 31, 2003 and December 31, 2002, respectively, and corporate joint ventures of approximately $1.0 billion and $865 million as of December 31, 2003 and December 31, 2002, respectively, are those of Resources, Global and EGDC. These investments are accounted for under the equity method of accounting.

Resources also has limited partnership investments in two leveraged buyout funds, a collateralized bond obligation structure, a clean air facility and solar electric generating systems. Resources’ total investment in limited partnerships was $94 million and $118 million as of December 31, 2003 and 2002, respectively.

The leveraged buyout funds mentioned above hold publicly traded securities, which are managed by a third party. The book value of the investment in the leveraged buyout funds was $75 million and $93 million as of December 31, 2003 and December 31, 2002, respectively. The largest single investment within the funds is the investment in privately held Borden, Inc., having a book value of $28 million and $48 million as of December 31, 2003 and December 31, 2002, respectively.

Resources applies fair value accounting to investments within the funds where publicly traded market prices are available. Approximately $26 million and $24 million represent the fair value of Resources’ share of the publicly traded securities in the funds as of December 31, 2003 and December 31, 2002, respectively. For a discussion of other than temporary impairments of securities of privately held interests in certain companies held within certain leveraged buyout funds at Resources, see Note 16. Risk Management.

149

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Investments in and Advances to Affiliates

Investments in net assets of affiliated companies accounted for under the equity method of accounting by Global amounted to $1.5 billion and $1.3 billion as of December 31, 2003 and December 31, 2002, respectively. During the three years ended December 31, 2003, 2002 and 2001, the amount of dividends from these investments was $130 million, $64 million and $51 million, respectively. Global’s share of income and cash flow distribution percentages ranged from 20% to 75% as of December 31, 2003. Interest is earned on loans made to various projects. Such loans earn interest that ranged from 8% to 20% during 2003.

Global has the following equity method investments as of December 31, 2003:

Name	Location	% Owned

Texas Independent Energy
Guadalupe	TX	50	%
Odessa	TX	50	%
Kalaeloa	HI	50	%
GWF
Bay Area I	CA	50	%
Bay Area II	CA	50	%
Bay Area III	CA	50	%
Bay Area IV	CA	50	%
Bay Area V	CA	50	%
Hanford	CA	50	%
Tracy	CA	35	%
GWF Energy
Hanford-Peaker Plant	CA	75	%
Henrietta-Peaker Plant	CA	75	%
Tracy-Peaker Plant	CA	75	%
Bridgewater	NH	40	%
Conemaugh	PA	50	%
MPC
Jingyuan—Units 5 & 6	China	15	%
Tongzhou	China	40	%
Nantong	China	46	%
Jinqiao (Thermal Energy)	China	30	%
Zuojiang—Units 1, 2 & 3	China	30	%
Fushi—Units 1, 2 & 3	China	35	%
Shanghai BFG	China	33	%
Huangshi Unit I	China	25	%
Hexie	China	50	%
Mianyang—Unit 1	China	38	%
Qujing—Phase II—Unit 3	China	19	%
Kuo Kuang	Taiwan	18	%
PPN	India	20	%
Prisma
Crotone	Italy	25	%
Bando D’Argenta I	Italy	50	%
Strongoli	Italy	25	%
Turboven
Maracay	Venezuela	50	%
Cagua	Venezuela	50	%
RGE	Brazil	33	%
Chilquinta	Chile	50	%
LDS	Peru	44	%

150

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Summarized results of operations and financial position of affiliates in which Global applies the equity method of accounting are presented below:

	Foreign				Domestic			Total
					(Millions)
December 31, 2003
Condensed Statement of Operations Information
Revenue		$	1,042			$	747		$	1,789
Gross Profit		$	415			$	231		$	646
Minority Interest		$	(5	)		$	—		$	(5	)
Net Income		$	138			$	67		$	205
Condensed Balance Sheet Information
Assets:
Current Assets		$	562			$	168		$	730
Property, Plant and Equipment			1,853				1,465			3,318
Goodwill			681				50			731
Other Noncurrent Assets			473				35			508

Total Assets		$	3,569			$	1,718		$	5,287

Liabilities:
Current Liabilities		$	579			$	154		$	733
Debt*			1,075				785			1,860
Other Noncurrent Liabilities			217				124			341
Minority Interest			80				—			80

Total Liabilities			1,951				1,063			3,014
Equity			1,618				655			2,273

Total Liabilities and Equity		$	3,569			$	1,718		$	5,287

December 31, 2002
Condensed Statement of Operations Information
Revenue		$	1,022			$	516		$	1,538
Gross Profit		$	413			$	166		$	579
Minority Interest		$	(10	)		$	—		$	(10	)
Net Income		$	45			$	20		$	65
Condensed Balance Sheet Information
Assets:
Current Assets		$	494			$	110		$	604
Property, Plant and Equipment			1,597				1,193			2,790
Goodwill			586				50			636
Other Noncurrent Assets			489				24			513

Total Assets		$	3,166			$	1,377		$	4,543

Liabilities:
Current Liabilities		$	464			$	56		$	520
Debt*			868				641			1,509
Other Noncurrent Liabilities			183				72			255
Minority Interest			43				—			43

Total Liabilities			1,558				769			2,327
Equity			1,608				608			2,216

Total Liabilities and Equity		$	3,166			$	1,377		$	4,543

December 31, 2001
Condensed Statement of Operations Information
Revenue		$	972			$	473		$	1,445
Gross Profit		$	416			$	165		$	581
Minority Interest		$	(20	)		$	—		$	(20	)
Net Income		$	180			$	91		$	271

Debt is non-recourse to PSEG, Energy Holdings and Global.

151

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 13. Purchase Business Combinations/Asset Acquisitions

Power

On December 6, 2002, Power purchased Wisvest Connecticut LLC, which owned the Bridgeport Harbor Station (BHS), the New Haven Harbor Station (NHHS) and the related assets and liabilities, from Wisvest Corporation (Wisvest), a subsidiary of Wisconsin Energy Corporation. The name of Wisvest Connecticut LLC was subsequently changed to PSEG Power Connecticut LLC (Power Connecticut).

The aggregate purchase price was approximately $271 million, which consisted of approximately $269 million of cash paid to Wisvest and approximately $2 million of direct acquisition costs which were paid to third parties.

During 2003, Power finalized the allocation of the purchase price. Power Connecticut’s results of operations were reflected in the Consolidated Statements of Operations beginning December 6, 2002.

	As of December 6, 2002

	Initial Amounts Recorded			Adjustments				Final Amounts Recorded
				(Millions)
Current Assets		$	26		$	(1	)		$	25
Property, Plant and Equipment			237			(2	)			235
Intangible Assets			44			3				47

Total Assets Acquired			307			—				307
Current Liabilities			16			1				17
Noncurrent Liabilities			19			—				19

Total Liabilities Assumed			35			1				36

Net Assets Acquired		$	272		$	(1	)		$	271

Approximately $44 million of the intangible assets consisted of SO₂ allowances, which can be sold on the open market or used to offset plant emissions. These allowances have an indefinite life.

Energy Holdings

In June 2002, Global completed a 35% acquisition of the 590 MW (electric) and 618 MW (thermal) coal-fired Skawina CHP Plant (Skawina), located in Poland, and subsequently purchased an additional equity interest of approximately 15%, increasing its ownership to approximately 50%. The aggregate purchase price of this ownership interest was $31 million and was allocated $18 million to Current Assets, $51 million to Property, Plant and Equipment, $14 million to Current Liabilities, $9 million to Noncurrent Liabilities and $15 million to Minority Interest. In accordance with the original purchase agreement, Global increased its equity interest in Skawina to approximately 63% in August 2003. Additionally, the agreement obligates Global to offer to purchase an additional 12% from Skawina’s employees in 2004, increasing Global’s potential ownership interest to approximately 75%. For additional information, see Note 17. Commitments and Contingent Liabilities.

Prior to the fourth quarter of 2002, GWF Energy LLC (GWF Energy) was accounted for in accordance with the equity method of accounting. Pursuant to the partnership agreement, a partner is required to have at least 75% interest in the partnership to have control. During the fourth quarter of 2002, Global increased its interest in GWF Energy to 76%, acquiring control pursuant to the partnership agreement. Due to this change, Global’s investment in GWF Energy was consolidated on the Consolidated Financial Statements as of December 31, 2002 and for the three months ended December 31, 2002 and for each quarterly period thereafter through September 30, 2003. Global’s investment in GWF Energy decreased to 74.9% during the fourth quarter of 2003 and accordingly, GWF Energy was deconsolidated and recorded under the equity method of accounting as of December

152

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

31, 2003. In February 2004, Harbinger repurchased a 14.9% ownership interest from Global for approximately $14 million. See Note 17. Commitments and Contingent Liabilities for additional information.

Note 14. Schedule of Consolidated Capital Stock and Other Securities

PSEG and PSE&G

The adoption of FIN 46 required PSEG and PSE&G to deconsolidate their capital trusts. In December 2003, PSE&G redeemed $155 million of its debt obligations which required the debtholder’s redemption of the mandatorily redeemable securities. See Note 3. Recent Accounting Standards and Note 15. Schedule of Consolidated Debt.

	Outstanding Shares As of December 31, 2003		Current Redemption Price Per Share		As of December 31,

					2003			2002
					(Millions)
PSEG Common Stock (no par value)(A)
Authorized 500,000,000 shares; (outstanding as of December 31, 2002, 225,267,347 shares)		236,133,442				$	3,509		$	3,070

PSE&G Cumulative Preferred Stock(B) without Mandatory Redemption(C) $100 par value series
4.08%		146,221		103.00		$	15		$	15

4.18%		116,958		103.00			12			12
4.30%		149,478		102.75			15			15
5.05%		104,002		103.00			10			10
5.28%		117,864		103.00			12			12
6.92%		160,711		—			16			16

Total Preferred Stock without Mandatory Redemption		795,234				$	80		$	80

(A)

In 1999, PSEG’s Board of Directors authorized the repurchase of up to 30 million shares of its common stock in the open market. As of December 31, 2001, PSEG repurchased approximately 26.5 million shares of common stock at a cost of approximately $997 million. No shares were repurchased in either 2003 or 2002. The repurchased shares have been held as treasury stock or used for other corporate purposes. In October 2003, PSEG issued approximately 8.8 million shares of its common stock for $356 million. In November 2002, PSEG issued 17.25 million shares of common stock for approximately $458 million, with net proceeds of $443 million. In addition, in 2002, PSEG began issuing new shares under the Dividend Reinvestment and Stock Purchase Plan (DRASPP) and the Employee Stock Purchase Plan (ESPP), rather than purchasing them on the open market. For the years ended December 31, 2003 and December 31, 2002, PSEG issued approximately 2.1 million and 2.2 million shares for approximately $85 million and $78 million, respectively, under these plans. Total authorized and unissued shares of common stock available for issuance through PSEG’s DRASPP, ESPP and various employee benefit plans amounted to 5,588,886 as of December 31, 2003.

(B)

As of December 31, 2003, there were an aggregate of 6,704,766 shares of $100 par value and 10,000,000 shares of $25 par value Cumulative Preferred Stock, which were authorized and unissued and which, upon issuance, may or may not provide for mandatory sinking fund redemption. If dividends upon any shares of Preferred Stock are in arrears for four consecutive quarters, holders receive voting rights for the election of a majority of PSE&G’s Board of Directors and continue until all accumulated and unpaid dividends thereon have been paid, whereupon all

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153

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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such voting rights cease. There are no arrearages in cumulative preferred stock and hence currently not any voting rights for preferred shares. No preferred stock agreement contains any liquidation preferences in excess of par values or any “deemed” liquidation events.

(C)

As of December 31, 2003 and 2002, the annual dividend requirement and embedded dividend rate for PSE&G’s Preferred Stock without mandatory redemption was $3,987,867 and 5.03%, respectively for each year.

Fair Value of Preferred Securities

The estimated fair value of PSE&G’s Cumulative Preferred Stock were $70 million and $59 million as of December 31, 2003 and 2002, respectively. The estimated fair value was determined using market quotations.

Note 15.

Schedule of Consolidated Debt

Long-Term Debt

			As of December 31,

	Maturity		2003		2002
			(Millions)
PSEG
Senior Note—6.89%		2005–2009	$	245	$	245
Debt Supporting Trust Preferred Securities(A)		2007–2047		1,201		1,201
Other				16		3

Total Long-Term Debt of PSEG (Parent)			$	1,462	$	1,449

PSE&G
Debt Supporting Trust Preferred Securities(A)		2044–2046	$	—	$	160
First and Refunding Mortgage Bonds:
5.70%(F)		2003		—		64
6.875%(C)		2003		—		150
8.875%(D)		2003		—		150
5.55%(F)		2003		—		145
6.50%		2004		286		286
9.125%		2005		125		125
6.75%		2006		147		147
6.25%		2007		113		113
7.375%		2014		159		159
6.75%		2016		171		171
6.45%		2019		5		5
9.25%		2021		134		134
6.38%		2023		157		157
7.00%		2024		254		254
5.20%		2025		23		23
1.10% Auction Rate(F)		2028		64		—
6.55%		2029		93		93
6.20%		2030		88		88
6.25%		2031		104		104
5.45%		2032		50		50
6.40%		2032		100		100
1.14% Auction Rate(F)		2033		50		—
1.10% Auction Rate(F)		2033		50		—
1.15% Auction Rate(F)		2033		45		—
8.00%		2037		7		7

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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			As of December 31,

	Maturity		2003			2002
			(Millions)
5.00%		2037		8			8
Medium-Term Notes:
4.00%(E)		2008		250			—
8.16%		2009		16			16
8.10%		2009		44			44
5.125%		2012		300			300
5.00%(C)		2013		150			—
5.375%(D)		2013		300			—
7.04%		2020		9			9
7.18%		2023		5			5
7.15%		2023		34			34

Total First and Refunding Mortgage Bonds				3,341			2,941
Amounts Due Within One Year(B)				(286	)		(300	)
Net Unamortized Discount				(11	)		(14	)

Total Long-Term Debt of PSE&G (Parent)			$	3,044		$	2,787

Transition Funding (PSE&G)
Securitization Bonds:
5.74%		2007	$	171		$	300
5.98%		2008		183			183
LIBOR plus 0.30%		2011		496			496
6.45%		2013		328			328
6.61%		2015		454			454
6.75%		2016		220			220
6.89%		2017		370			370

Principal Amount Outstanding				2,222			2,351
Amounts Due Within One Year(B)				(137	)		(129	)

Total Securitization Debt of Transition Funding			$	2,085		$	2,222

Total Long-Term Debt of PSE&G			$	5,129		$	5,009

Power
Senior Notes:
6.875%		2006	$	500		$	500
7.75%		2011		800			800
6.95%		2012		600			600
5.50%(G)		2015		300			—
8.625%		2031		500			500

Total Senior Notes			$	2,700		$	2,400
Pollution Control Notes:
5.00%		2012	$	66		$	66
5.50%		2020		14			14
5.85%		2027		19			19
5.75%		2031		25			25

Total Pollution Control Notes			$	124		$	124
Net Unamortized Discount				(8	)		(8	)

Total Long-Term Debt of Power (Parent)			$	2,816		$	2,516
Non-Recourse Debt:
Variable (3.00% to 5.00%)		2005	$	800		$	800

Total Long-Term Debt of Power			$	3,616		$	3,316

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155

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(table continued from previous page)

			As of December 31,

	Maturity		2003			2002
			(Millions)
Energy Holdings (Parent)
Senior Notes:
9.125%(I)		2004	$	267		$	279
7.75%(H)		2007		350			—
8.625%		2008		507			507
10.00%		2009		400			400
8.50%		2011		544			544

Principal Amount Outstanding				2,068			1,730
Amounts Due Within One Year(B)				(267	)		—
Net Unamortized Discount and Senior Note Rate Swap				(1	)		(5	)

Total Long-Term Debt of Energy Holdings (Parent)			$	1,800		$	1,725

Global (Energy Holdings)
Non-recourse Debt:
Skawina–5.60%		2004–2005	$	3		$	—
Salalah–6.27%		2004–2018		201			131
Elcho (Chorzow)–9.550% — 13.225%		2004–2019		285			237
SAESA–3.807%		2004–2023		167			211
Electroandes–4.090%–6.438%		2005–2016		100			—
Chilquinta–5.58%–6.62%		2008–2011		161			161

Principal Amount Outstanding				917			740
Amounts Due Within One Year(B)				(33	)		(47	)

Total Long-Term Debt of Global			$	884		$	693

Resources (Energy Holdings)
8.60%–9.30%—Non-Recourse Bank Loan		2004–2020	$	32		$	22
Amounts Due Within One Year(B)				(1	)		(1	)

Total Long-Term Debt of Resources			$	31		$	21

EGDC (Energy Holdings)
8.27%—Non-recourse Mortgage		2004–2013	$	25		$	26
Amounts Due Within One Year(B)				(2	)		(1	)

Total Long-Term Debt of EGDC			$	23		$	25

PSEG Capital Corporation (Energy Holdings)
6.25% Medium-Term Notes		2003	$	—		$	252

Principal Amount Outstanding				—			252
Amounts Due Within One Year(B)				—			(252	)

Total Long-Term Debt of PSEG Capital			$	—		$	—

Total Long-Term Debt of Energy Holdings			$	2,738		$	2,464

Total PSEG Consolidated Long-Term Debt			$	12,945		$	12,238

(A)

The adoption of FIN 46 required PSEG and PSE&G to deconsolidate their capital trusts. In December 2003, PSE&G paid the trusts $155 million and offset its $5 million debt to the trusts against PSE&G’s remaining investment in conjunction with the redemption of the mandatorily redeemable securities. See Note 3. Recent Accounting Standards and Note 14. Schedule of Consolidated Capital Stock and Other Securities.

In December 2003, PSE&G Capital, L.P., a limited partnership of which PSE&G is sole general partner, redeemed all of its outstanding 8% Cumulative Monthly Income Preferred Securities, Series B at a price of $25.00 per preferred security. In December 2003, PSE&G Capital Trust II, a

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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statutory trust of which PSE&G is sole depositor, redeemed all of its outstanding 8.125% Cumulative Quarterly Income Preferred Securities, Series B at a price of $25.00 per preferred security.

As of December 31, 2003 and 2002, the annual dividend requirement of PSEG’s Trust Preferred Securities (Guaranteed Preferred Beneficial Interest in PSEG’s Subordinated Debentures) including those issued in connection with the Participating Units and their embedded costs was $103,563,284 and 8.98%. As of December 31, 2003 and 2002, the annual dividend requirement and embedded cost of the Monthly Income Preferred Securities (Guaranteed Preferred Beneficial Interest in PSE&G’s Subordinated Debentures) was $4,948,454 and 8.29%. As of December 31, 2003 and 2002, the annual dividend requirement of the Quarterly Income Preferred Securities (Guaranteed Preferred Beneficial Interest in PSE&G’s Subordinated Debentures) and their embedded costs were $7,957,475 and 8.41%.

Enterprise Capital Trust I, Enterprise Capital Trust II, Enterprise Capital Trust III, Enterprise Capital Trust IV and PSEG Funding Trust II were formed and are controlled by PSEG for the purpose of issuing Quarterly Trust Preferred Securities (Quarterly Guaranteed Preferred Beneficial Interest in PSEG’s Subordinated Debentures). The proceeds were loaned to PSEG and are evidenced by Deferrable Interest Subordinated Debentures. If and for as long as payments on the Deferrable Interest Subordinated Debentures have been deferred, or PSEG had defaulted on the indentures related thereto or its guarantees thereof, PSEG may not pay any dividends on its common and preferred stock. The Subordinated Debentures support the Preferred Securities issued by the trusts.

In September 2002, PSEG Funding Trust I issued 9.2 million Participating Units with a stated amount of $50 per unit. Each unit consists of a 6.25% trust preferred security due 2007 having a liquidation value of $50, and a stock purchase contract obligating the purchasers to purchase shares of PSEG Common Stock in an amount equal to $50 on November 16, 2005. In exchange for the obligations under the purchase contract, the purchasers will receive quarterly contract adjustment payments at the annual rate of 4.00% through the purchase date. The number of new shares to be issued on November 16, 2005 will depend upon the average closing price per share of PSEG Common Stock for the 20 consecutive trading days ending the third trading day immediately preceding November 16, 2005. Based on the formula described in the purchase contract, at that time PSEG will issue between 11,429,139 and 13,714,967 shares of its common stock. The net proceeds from the sale of the Participating Units was $446 million. In connection with the issuance of the Participating Units, PSEG recorded a $54 million reduction to equity associated with the stock purchase contracts. For additional information, see Note 22. Stock Options and Employee Stock Purchase Plan.

(B)

The aggregate principal amounts of mandatory requirements for sinking funds and maturities for each of the five years following December 31, 2003 are as follows:

			PSE&G						Energy Holdings

Year	PSEG		PSE&G		Transition Funding		Power		Energy Holdings		Global		Resources		EGDC		Total
									(Millions)
2004	$	—	$	286	$	—	$	—	$	267	$	33	$	1	$	2	$	589
2005		49		125		—		800		—		46		2		2		1,024
2006		49		147		—		500		—		45		2		2		745
2007		509		113		171		—		350		37		1		2		1,183
2008		49		250		183		—		507		104		1		2		1,096

	$	656	$	921	$	354	$	1,300	$	1,124	$	265	$	7	$	10	$	4,637

(C)

In January 2003, PSE&G issued $150 million of 5.00% Medium-Term Notes due 2013. The proceeds of this issuance were used to repay $150 million of 6.875% Series MM Mortgage Bonds which matured in January 2003.

157

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(D)

In September 2003, PSE&G issued $300 million of 5.375% Medium-Term Notes due 2013. The proceeds of this issuance were used to refinance the previously matured $150 million of Series DD Mortgage Bonds, as well as to reduce short-term debt.

(E)

In November 2003, PSE&G issued $250 million of 4.000% Medium-Term Notes due 2008. The proceeds of this issuance were used to retire $60 million and $95 million of Cumulative Monthly Income Preferred Securities and Cumulative Quarterly Income Preferred Securities, respectively, in December 2003 and to reduce short-term debt.

(F)

In December 2003, PSE&G redeemed $64 million of its 5.700% First and Refunding Mortgage Bonds, Pollution Control Series L due 2028 (Series L Bonds) and $145 million of its 5.550% First and Refunding Mortgage Bonds, Pollution Control Series N due 2033 (Series N Bonds). Each of these series of mortgage bonds serviced and secured like principal amounts of pollution control revenue refunding bonds of The Pollution Control Financing Authority of Salem County, New Jersey (Salem Authority). The Series L Bonds and the Series N Bonds were refinanced through the issuance of new series of mortgage bonds that are multi-mode and that were initially issued in a floating rate 35-day auction mode. The Series L Bonds were refinanced by the issuance of $64 million of First and Refunding Mortgage Bonds, Pollution Control Series Y due 2028, with an initial auction rate of 1.100%. The Series N Bonds were refinanced by the issuance of three separate series of mortgage bonds: $50 million First and Refunding Mortgage Bonds, Pollution Control Series Z due 2033 with an initial auction rate of 1.140%, $50 million First and Refunding Mortgage Bonds, Pollution Control Series AA due 2033 with an initial auction rate of 1.100%, and a $45.2 million First and Refunding Mortgage Bonds, Pollution Control Series AB due 2033 with an initial auction rate of 1.150%. Similarly, these new mortgage bonds service and secure like principal amounts of pollution control revenue refunding bonds of the Salem Authority.

(G)

In December 2003, Power issued $300 million of 5.500% Senior Notes due 2015. The proceeds of this issuance were used to repay intercompany debt and for general corporate purposes.

(H)

In April 2003, Energy Holdings, in a private placement, issued $350 million of its 7.75% Senior Notes due in 2007. The proceeds were used in part to repay PSEG Capital Corporation’s (PSEG Capital) remaining $252 million of 6.25% Medium-Term Notes that matured in May 2003. The remaining proceeds were used for general corporate purposes. In July 2003, Energy Holdings completed an exchange of these securities for registered securities.

(I)

In September 2003, Energy Holdings repurchased approximately $12 million of its outstanding Senior Notes that matured in February 2004, reducing that maturity to $267 million as of December 31, 2003. In February 2004, Energy Holdings redeemed the remaining $267 million of these Senior Notes at maturity.

158

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Short-Term Liquidity

PSEG, PSE&G, Power and Energy Holdings

As of December 31, 2003, PSEG and its principal subsidiaries had an aggregate of approximately $1.9 billion of committed credit facilities. Each facility is restricted to availability and use to the specific companies as listed below.

Company	Expiration Date		Total Facility		Primary Purpose	Usage as of 12/31/2003				Available Liquidity as of 12/31/2003
			(Millions)
PSEG:
364-day Credit Facility		March 2004	$	350	CP Support		$	299			$	51
5-year Credit Facility		March 2005	$	280	CP Support		$	—			$	280
3-year Credit Facility		December 2005	$	350	CP Support/ Funding/ Letters of Credit		$	10	(C)		$	340
Uncommitted Bilateral Agreement		N/A		N/A	Funding		$	—				N/A
PSE&G:
364-day Credit Facility		June 2004	$	200	CP Support		$	—			$	200
3-year Credit Facility		June 2005	$	200	CP Support		$	—			$	200
Uncommitted Bilateral Agreement		N/A		N/A	Funding		$	—				N/A
PSEG and Power:
364-day Credit Facility(A)		March 2004	$	250	CP Support/ Funding		$	—			$	250
Power:
3-year Credit Facility		August 2005	$	25	Funding/ Letters of Credit		$	19	(C)		$	6
Energy Holdings:
3-year Credit Facility (B)		October 2006	$	200	Funding/ Letters of Credit		$	56	(C)		$	144

(A)

PSEG/Power joint and several co-borrower facility

(B)

(C)

These amounts relate to letters of credit outstanding.

Energy Holdings

As of December 31, 2003, in addition to amounts outstanding under Energy Holdings’ credit facilities shown in the above table, subsidiaries of Global had $2 million of short-term non-recourse financing at the project level. As of December 31, 2003, Energy Holdings had loaned $300 million of excess cash to PSEG. For information regarding affiliate borrowings, see Note 26. Related-Party Transactions.

Fair Value of Debt

The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions as of December 31, 2003 and December 31, 2002, respectively.

	December 31, 2003				December 31, 2002

	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Millions)
Long-Term Debt:
PSEG	$	1,462	$	1,586	$	1,449	$	1,381
Energy Holdings		3,041		3,230		2,765		2,597
PSE&G		3,330		3,601		3,087		3,375
Transition Funding (PSE&G)		2,222		2,474		2,351		2,543
Power		3,616		4,034		3,316		3,372

	$	13,671	$	14,925	$	12,968	$	13,268

Because their maturities are less than one year, fair values approximate carrying amounts for cash and cash equivalents, short-term debt and accounts payable. For additional information related to interest rate derivatives, see Note 16. Risk Management.

159

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 16. Risk Management

PSEG, PSE&G, Power and Energy Holdings

The operations of PSEG, PSE&G, Power and Energy Holdings are exposed to market risks from changes in commodity prices, foreign currency exchange rates, interest rates and equity prices that could affect their results of operations and financial conditions. PSEG, PSE&G, Power and Energy Holdings manage exposure to these market risks through their regular operating and financing activities and, when deemed appropriate, hedge these risks through the use of derivative financial instruments. PSEG, PSE&G, Power and Energy Holdings 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. Each of PSEG, PSE&G, Power and Energy Holdings use derivative instruments as risk management tools consistent with their respective business plans and prudent business practices.

Derivative Instruments and Hedging Activities

Energy Trading Contracts

Power

Power actively trades energy and energy-related products, including electricity, natural gas, electric capacity, fixed transmission rights (FTRs), coal and emission allowances in the spot, forward and futures markets, primarily in the PJM Interconnection LLC (PJM), but also in the surrounding region, which extends from Maine to the Carolinas and the Atlantic Coast to Indiana and natural gas in the producing region.

Power maintains a strategy of entering into trading positions to optimize the value of its portfolio of generation assets, gas supply contracts and its electric and gas supply obligations. Power engages in physical and financial transactions in the electricity wholesale markets and executes an overall risk management strategy to mitigate the effects of adverse movements in the fuel and electricity markets. These contracts also involve financial transactions including swaps, options and futures.

Power marks its energy trading contracts to market in accordance with SFAS 133 with changes in fair value charged to the Consolidated Statement of Operations. Wherever possible, fair values for these contracts are obtained from quoted market sources. For contracts where no quoted market exists, modeling techniques are employed using assumptions reflective of current market rates, yield curves and forward prices as applicable to interpolate certain prices. The effect of using such modeling techniques is not material to Power’s financial results.

Power routinely enters into exchange-traded futures and options transactions for electricity and natural gas as part of its operations. Generally, exchange-traded futures contracts require a deposit of margin cash, the amount of which is subject to change based on market movement and in accordance with exchange rules. The aggregate amount of Power’s margin deposits as of December 31, 2003 and 2002 was approximately $36 million and $13 million, respectively.

Commodity Contracts

Power

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, market conditions and other events. Power manages its risk of fluctuations of energy price and availability through derivative instruments, such as forward purchase or sale contracts, swaps, options, futures and FTRs.

160

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Cash Flow Hedges

Power uses forward sale and purchase contracts, swaps and FTR contracts to hedge forecasted energy sales from its generation stations and to hedge related load obligations. Power also enters into swaps, options and futures transactions to hedge the price of fuel to meet its fuel purchase requirements for generation. These derivative transactions are designated and effective as cash flow hedges under SFAS 133. As of December 31, 2003 and 2002, the fair values of these hedges were $(37) million and $5 million, respectively. During the next 12 months, $17 million of unrealized losses (net of taxes) on these commodity derivatives in Accumulated OCI is expected to be reclassified to earnings. As defined in SFAS 133, hedge ineffectiveness associated with these hedges was insignificant. The maximum term of these cash flow hedges will expire in 2008.

Effective with the transfer of PSE&G’s gas contracts to Power on May 1, 2002, Power acquired all of the gas-related derivatives entered into by PSE&G. The derivatives used to hedge the forecasted purchase and sale of natural gas are designated and effective as cash flow hedges. Gains or losses from the derivatives entered into to hedge residential customer requirements are deferred and recovered from PSE&G’s customers and therefore do not affect earnings. Unrealized gains or losses on the derivatives entered to hedge commercial and industrial customer requirements are recorded to OCI. As of December 31, 2003, $4 million of losses were recorded to OCI related to gas hedges for commercial and industrial customers, all of which will be reclassed to earnings over the next twelve months. Hedge ineffectiveness associated with these hedges was insignificant. As of December 31, 2003 and 2002, the fair values of hedge instruments associated with hedging residential customer requirements were $20 million and $1 million, respectively. These hedges will mature through 2005.

Other Derivatives

Power also enters into certain other contracts which are derivatives, but do not qualify for hedge accounting under SFAS 133. Most of these contracts are used for fuel purchases for generation requirements. Therefore, the changes in fair market value of these derivative contracts are recorded in Energy Costs on the Consolidated Statements of Operations. The fair value of these instruments as of December 31, 2003 and 2002 was $7 million and $9 million.

Interest Rates

PSEG, PSE&G, Power and Energy Holdings

PSEG, PSE&G, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. PSEG’s policy is to manage interest rate risk through the use of fixed and floating rate debt and interest rate derivatives.

Fair Value Hedges

Energy Holdings

In April 2003, Energy Holdings, in a private placement, issued $350 million of 7.75% Senior Notes due in 2007. Energy Holdings used interest rate swaps to convert a portion of this fixed-rate debt into variable-rate debt. The interest rate swaps are designated and effective as fair value hedges. The fair value changes of these interest rate swaps are fully offset by the fair value changes in the underlying debt. As of December 31, 2003, the fair value of these hedges was $(1) million. There was no ineffectiveness related to these hedges.

161

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Cash Flow Hedges

PSEG, PSE&G, Power and Energy Holdings

PSEG, PSE&G, Power and Energy Holdings use interest rate swaps and other interest rate derivatives to manage their exposures to the variability of cash flows, primarily related to variable-rate debt instruments. The interest rate derivatives used are designated and effective as cash flow hedges.

The fair value changes of these derivatives are initially recorded in OCI. As of December 31, 2003, the fair value of these cash flow hedges was $(186) million, including $(16) million, $(51) million, $(7) million and $(112) million at PSEG, PSE&G, Power and Energy Holdings, respectively. The $(51) million at PSE&G is deferred and is expected to be recovered from PSE&G’s customers. As of December 31, 2002, the fair value of these cash flow hedges was $(223) million, including $(21) million, $(66) million, $(9) million and $(127) million at PSEG, PSE&G, Power and Energy Holdings, respectively. During the next 12 months, $31 million of unrealized loss (net of taxes) on interest rate derivatives accumulated in OCI is expected to be reclassified to earnings, including $4 million, $3 million and $24 million at PSEG, Power and Energy Holdings, respectively. Hedge ineffectiveness associated with these hedges was immaterial.

Other Derivatives

Energy Holdings

Foreign subsidiaries and affiliates of Energy Holdings entered into interest rate forward contracts, which effectively converted Energy Holdings’ variable rate debt to fixed rate. Changes in the fair value of these derivative instruments are recorded directly to interest expense. The fair value of these instruments as of December 31, 2003 was immaterial.

Foreign Currencies

Energy Holdings

Global is exposed to foreign currency risk and other foreign operations risk that arise from investments in foreign subsidiaries and affiliates. A key component of this risk is that some of its foreign subsidiaries and affiliates have functional currencies other than the consolidated reporting currency, the U.S. Dollar. Additionally, certain of Global’s foreign subsidiaries and affiliates have entered into monetary obligations and maintain receipts/receivables in U.S. Dollars or currencies other than their own functional currencies. Global, a U.S. Dollar functional currency entity, is primarily exposed to changes in the Brazilian Real, the Euro, the Polish Zloty, the Peruvian Nuevo Sol and the Chilean Peso. With respect to the foreign currency risk associated with the Brazilian Real, there has already been significant devaluation since the initial acquisition of these investments, which has resulted in reduced U.S. Dollar earnings and cash flows relative to initial projections. These subsidiaries and affiliates have attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust for changes in foreign exchange rates. Global also uses foreign currency forward, swap and option agreements to manage risk related to certain foreign currency fluctuations.

As of December 31, 2003, net cumulative foreign currency devaluations have reduced the total amount of Energy Holdings’ Member’s Equity by $193 million, of which $228 million was caused by the devaluation of the Brazilian Real. As of December 31, 2002, these devaluations reduced Energy Holdings’ Member’s Equity by $358 million, of which $248 million and $105 million were caused by the devaluation of the Brazilian Real and the Chilean Peso, respectively.

162

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Equity Securities

Energy Holdings

For the year ended December 31, 2003, Resources recognized a $11 million (pre-tax) loss from other than temporary impairments of non-publicly traded equity securities, which are held within its investments in certain leveraged buyout funds. For the year ended December 31, 2003, Resources has recognized a $5 million gain on the publicly traded equity securities within those funds. These gains and losses are included in Operating Revenues in the Consolidated Statements of Operations. As of December 31, 2003, Resources had investments in leveraged buyout funds of approximately $75 million, of which $26 million was comprised of public securities with available market prices and $49 million was comprised of privately-held interests in certain companies. As of December 31, 2002, Resources had investments in leveraged buyout funds of approximately $93 million, of which $24 million was comprised of public securities with available market prices and $69 million was comprised of privately held interests in certain companies.

Note 17. Commitments and Contingent Liabilities

Nuclear Insurance Coverages and Assessments

Power

Power is a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides the primary property and decontamination liability insurance at Salem Nuclear Generating Station (Salem), Hope Creek Generating Station (Hope Creek) and Peach Bottom Atomic Power Station (Peach Bottom). NEIL also provides excess property insurance through its decontamination liability, decommissioning liability and excess property policy and replacement power coverage through its accidental outage policy. NEIL policies may make retrospective premium assessments in case of adverse loss experience. Power’s maximum potential liabilities under these assessments are included in the table and notes below. Certain provisions in the NEIL policies provide that the insurer may suspend coverage with respect to all nuclear units on a site without notice if the Nuclear Regulatory Commission (NRC) suspends or revokes the operating license for any unit on that site, issues a shutdown order with respect to such unit or issues a confirmatory order keeping such unit down.

The American Nuclear Insurers (ANI) and NEIL policies both include coverage for claims arising out of acts of terrorism. Both ANI and NEIL make a distinction between certified and non-certified acts of terrorism, as defined under Terrorism Risk Insurance Act (TRIA) (Sec. 102 (1) and Sec. 102 (5)), and thus their policies respond accordingly. For non-certified acts of terrorism, ANI policies are subject to an industry aggregate limit of $300 million, subject to one reinstatement, provided the reinstatement does not exceed the balance in the Industry Credit Rating Plan (ICRP) Reserve Fund. Similarly, NEIL policies are subject to an industry aggregate limit of $3.2 billion plus any amounts available through reinsurance or indemnity for non-certified acts of terrorism. For certified acts, Power’s nuclear liability ANI and nuclear property NEIL policies will respond in the same manner as for that resulting from other covered events.

The Price-Anderson Act sets the “limit of liability” for claims that could arise from an incident involving any licensed nuclear facility in the U.S. The “limit of liability” is based on the number of licensed nuclear reactors and is adjusted at least every five years based on the Consumer Price Index. The current “limit of liability” is $10.9 billion. All utilities owning a nuclear reactor, including Power, have provided for this exposure through a combination of private insurance and mandatory participation in a financial protection pool as established by the Price-Anderson Act. Under the Price- Anderson Act, each party with an ownership interest in a nuclear reactor can be assessed its share of $101 million per reactor per incident, payable at $10 million per reactor per incident per year. If the damages exceed the “limit of liability,” the President is to submit to Congress a plan for providing

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additional compensation to the injured parties. Congress could impose further revenue raising measures on the nuclear industry to pay claims. Power’s maximum aggregate assessment per incident is $317 million (based on Power’s ownership interests in Hope Creek, Peach Bottom and Salem) and its maximum aggregate annual assessment per incident is $32 million. This does not include the $11 million that could be assessed under the nuclear worker policies. Further, a decision by the U.S. Supreme Court, not involving Power, has held that the Price-Anderson Act did not preclude awards based on state law claims for punitive damages.

Power’s insurance coverages and maximum retrospective assessments for its nuclear operations are as follows:

		Total Site Coverage		Retrospective Assessments
		(Millions)
Type and Source of Coverages
Public and Nuclear Worker Liability (Primary Layer):
ANI	$	300.0	(A)		$	10.7
Nuclear Liability (Excess Layer):
Price-Anderson Act		10,562.0	(B)			316.7
Nuclear Liability Total	$	10,862.0	(C)		$	327.4
Property Damage (Primary Layer):
NEIL
Primary (Salem/Hope Creek/Peach Bottom)	$	500.0			$	19.7
Property Damage (Excess Layers):
NEIL II (Salem/Hope Creek/Peach Bottom)		600.0				8.0
NEIL Blanket Excess (Salem/Hope Creek/Peach Bottom)		1,000.0	(D)			2.9
Property Damage Total (Per Site)	$	2,100.0			$	30.6
Accidental Outage:
NEIL I (Peach Bottom)	$	245.0	(E)		$	9.3
NEIL I (Salem).		281.4	(E)			11.1
NEIL I (Hope Creek).		490.0	(E)			9.4
Replacement Power Total	$	1,016.4			$	29.8

______________

(A)

The primary limit for Public Liability is a per site aggregate limit with no potential for assessment. The Nuclear Worker Liability represents the potential liability from workers claiming exposure to the hazard of nuclear radiation. This coverage is subject to an industry aggregate limit, includes annual automatic reinstatement if the ICRP Reserve Fund exceeds $600 million, and has an assessment potential under former canceled policies.

(B)

Retrospective premium program under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. Power is subject to retrospective assessment with respect to loss from an incident at any licensed nuclear reactor in the U.S. This retrospective assessment can be adjusted for inflation every five years. The last adjustment was effective as of August 20, 2003. This retrospective program is in excess over the Public and Nuclear Worker Liability primary layers.

(C)

Limit of liability under the Price-Anderson Act for each nuclear incident.

(D)

For property limits in excess of $1.1 billion, Power participates in a Blanket Limit policy where the $1.0 billion limit is shared by Power with Amergen Energy Company, LLC and Exelon Generation Company, LLC among the Braidwood, Byron, Clinton, Dresden, La Salle, Limerick, Oyster Creek, Quad Cities, TMI-1 facilities owned by Amergen and Exelon and the Peach Bottom, Salem and Hope Creek facilities. This limit is not subject to reinstatement in the event of a loss. Participation in this program materially reduces Power’s premium and the associated potential assessment.

(footnotes continued on next page)

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(footnotes continued from previous page)

(E)

Peach Bottom has an aggregate indemnity limit based on a weekly indemnity of $2.3 million for 52 weeks followed by 80% of the weekly indemnity for 68 weeks. Salem has an aggregate indemnity limit based on a weekly indemnity of $2.5 million for 52 weeks followed by 80% of the weekly indemnity for 75 weeks. Hope Creek has an aggregate indemnity limit based on a weekly indemnity of $4.5 million for 52 weeks followed by 80% of the weekly indemnity for 71 weeks.

Old Dominion Electric Cooperative (ODEC)

PSE&G and Power

In 1995, PSE&G entered into a ten-year wholesale power contract with ODEC. The contract was transferred to Power in conjunction with the generation asset transfer in 2000. The contract provided for PSE&G to supply ODEC with capacity and energy for a bundled rate that includes a component to recover multiple transmission charges (referred to as “pancaked transmission rates”).

In November 1997, FERC issued the PJM Restructuring Order, which required PSE&G to modify its contract with ODEC to remove pancaked transmission rates. While PSE&G sought rehearing of this order, it was nonetheless required to reduce its rate to ODEC by approximately $6 million per year, effective April 1, 1998.

In 2000, FERC issued its order denying PSE&G’s request for rehearing. Thereafter, PSE&G appealed to the U.S. Court of Appeals for judicial review of the matter. On December 19, 2002, based on a court ruling, FERC reversed its November 1997 order, thereby reinstating the original contract terms. This allowed Power to collect amounts for April 1998 through December 2002 pursuant to the original contract. Power billed ODEC for this amount in January 2003. Power has been billing, recording and receiving payment on the higher rate for services provided since January 2003. ODEC is paying such increased rates currently under protest, but has refused to pay past due amounts aggregating $31 million. On October 22, 2003, FERC issued its order affirming the prices in the original contract and denying ODEC’s request for reconsideration and its request for a stay. ODEC sought rehearing of that order on November 21, 2003. Nevertheless, ODEC continues to withhold payment of the amounts due for the past period. Accordingly, on November 26, 2003, ER&T filed suit against ODEC for breach of contract in U.S. district court in Newark, New Jersey. On January 29, 2004, ODEC filed a motion to dismiss claiming that the ongoing FERC proceeding must be completed before any judicial intervention. On February 13, 2004, ER&T filed a motion for summary judgment. These motions are returnable in April 2004.

The difference in revenues between the contracted rate and the FERC-ordered reduced rate of approximately $31 million, inclusive of back interest, was recorded as Operating Revenues in the fourth quarter of 2003.

Guaranteed Obligations

Power

Power has guaranteed certain commodity related transactions for ER&T’s energy marketing activities. These guarantees were provided to counterparties in order to facilitate physical and financial agreements in gas, pipeline capacity, transportation, oil, electricity and related commodities and services. These Power guarantees support the current exposure, interest and other costs on sums due and payable by ER&T under these agreements. Guarantees offered for trading and marketing cover the granting of lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can go either direction. The face value of the guarantees outstanding as of December 31, 2003 and December 31, 2002 was $1.4 billion and $1.1 billion, respectively. In order for Power to experience a liability for the face value of the outstanding guarantees, ER&T would have to fully utilize the credit granted to it by every counterparty to whom Power has provided a guarantee and all of ER&T’s contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would

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owe money to the counterparties). The probability of all contracts at ER&T being simultaneously “out-of-the-money” is highly unlikely. For this reason, the current exposure at any point in time is a more meaningful representation of the potential liability to Power under these guarantees. The current exposure consists of the net of accounts receivable and accounts payable (AR/AP) and the forward value on open positions, less any margins posted. The current exposure from such liabilities was $228 million and $268 million as of December 31, 2003 and December 31, 2002, respectively. Of the $228 million, $167 million is recorded on Power’s Consolidated Balance Sheets as of December 31, 2003.

In addition, all supply contracts contain margin and/or other collateral requirements that, as of December 31, 2003, could require Power to post additional collateral of approximately $377 million if: a) Power were to lose its investment grade credit rating and b) all counterparties with whom Power is “out-of-the money” under such contracts, were entitled to, and called for, collateral.

As of December 31, 2003, letters of credit issued by Power were outstanding in the amount of approximately $74 million in support of various contractual obligations, environmental liabilities and to satisfy trading collateral obligations.

Power has also guaranteed equity contributions by its subsidiaries relating to its Lawrenceburg and Waterford facilities, as discussed below in New Generation and Development. Should Power lose its investment grade credit rating, it would be required to post $86 million in letters of credit for these facilities. This guarantee will be cancelled upon satisfaction of the equity commitment, which is included in Power’s anticipated capital expenditures through the second quarter 2004.

Energy Holdings

Energy Holdings and/or Global have guaranteed certain obligations of their subsidiaries or affiliates, including the successful completion, performance or other obligations related to certain projects, in an aggregate amount of approximately $180 million as of December 31, 2003. The guarantees include a $49 million standby equity commitment for Skawina, a $10 million equity commitment for Elcho and a $25 million contingent guarantee related to debt service obligations of Chilquinta. Additional guarantees consist of a $37 million leasing agreement guarantee for Prisma, $24 million of performance guarantees related to Energy Technologies that are supported by letters of credit discussed below and various other guarantees comprising the remaining $35 million.

As a result of Energy Holdings’ ratings falling below investment grade, Energy Holdings has letters of credit outstanding of approximately $10 million for certain of its equity commitments as of December 31, 2003. Under existing agreements Energy Holdings will not need to post any additional letters of credit.

In September 2003, Energy Holdings completed the sale of Energy Technologies and nearly all of its assets. However, Energy Holdings retained certain outstanding construction and warranty obligations related to ongoing construction projects previously performed by Energy Technologies. These construction obligations have performance bonds issued by insurance companies. As of December 31, 2003, there were $87 million of such bonds outstanding, of which $21 million related to uncompleted construction projects. These performance bonds are not included in the $180 million of guaranteed obligations discussed above. In January 2003, Energy Holdings provided an indemnification agreement and $31 million of letters of credit in support of Energy Technologies’ obligations. As of December 31, 2003, $24 million in letters of credit remain, including obligations relating to certain of the HVAC/mechanical operating companies that have been previously sold. These amounts are expected to decrease over time as each of the HVAC/mechanical operating companies completes the work in process.

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Environmental Matters

PSE&G and Power

Hazardous Waste

The New Jersey Department of Environmental Protection (NJDEP) adopted regulations concerning site investigation and remediation that require an ecological evaluation of potential damages to natural resources in connection with an environmental investigation of contaminated sites. These regulations may materially increase the costs of environmental investigations and remediation, where necessary, particularly at sites situated on surface water bodies. PSE&G, Power and their respective 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. PSE&G and Power do not anticipate that compliance with these regulations will have a material adverse effect on their respective financial positions, results of operations or net cash flows.

Passaic River Site

The U.S. Environmental Protection Agency (EPA) has determined that a six-mile stretch of the Passaic River in the area of Newark, New Jersey is a “facility” within the meaning of that term under Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA). PSE&G and certain of its predecessors conducted industrial operations at properties adjacent to the Passaic River facility. The operations included one operating and one former generating station and four former Manufactured Gas Plants (MGPs). PSE&G’s costs to clean up former MGPs are recoverable from utility customers through the SBC. PSE&G has sold the site of the former generating station and obtained releases and indemnities for liabilities arising out of that site in connection with the sale. The operating generating station was transferred to Power in August 2000.

In September 2003, the EPA notified 41 potentially responsible parties (PRPs), including PSE&G, that it was expanding its assessment of the Passaic River Study Area to the entire 17-mile tidal reach of the lower Passaic River. The EPA further indicated, with respect to PSE&G, that it believed that hazardous substances were being released from the Essex Generating Station, an operating electric generating station, and a former MGP located in Harrison, New Jersey, which also includes facilities for PSE&G’s ongoing gas operations. The EPA estimated that its study would require five to seven years and would cost approximately $20 million, of which it would seek to recover $10 million from the PRPs. Power assumed all environmental liabilities associated with the electric generating stations that PSE&G transferred to it, including the Essex Generating Station.

Also, in September 2003, PSEG, PSE&G and 56 other PRPs received a Directive and Notice to Insurers from the NJDEP for the PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the New Jersey Spill Act. The NJDEP alleged in the Directive that it had determined that hazardous substances had been discharged from the Essex Site and the Harrison Site. NJDEP announced in a meeting of the parties who received the directive that it had estimated the cost of interim natural resource injury restoration activities along the lower Passaic River to approximate $950 million. PSE&G and Power have indicated to both EPA and NJDEP that they are willing to work with the agencies in an effort to resolve their claims. Most of the other PRPs notified by the EPA or the NJDEP have responded similarly. None of PSEG, PSE&G or Power can predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to the Passaic River, however, such costs could be material.

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PSE&G

MGP 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 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 at this time, but experience to date indicates that at least $20 million per year could be incurred over a period of about 30 years since the inception of the program in 1988 and that the overall cost could be material. The costs for this remediation effort are recovered through SBC charges to utility customers.

As of December 31, 2003, PSE&G’s estimated net liability for remediation costs through 2006 totaled $123 million. Expenditures beyond 2006 cannot be reasonably estimated at this time and are therefore not accrued.

In September 2003, the EPA and NJDEP notified PRPs, including PSE&G, that they were expanding their assessment of the Passaic River Study Area to the entire 17-mile tidal reach of the lower Passaic River. The EPA and NJDEP both indicated that they believed that hazardous substances were being released from a former MGP located in Harrison, NJ, among other locations. For further discussion related to this matter see “Passaic River Site” above.

Power

Prevention of Significant Deterioration (PSD)/New Source Review (NSR)

In November 1999, the Federal government announced the filing of lawsuits against several companies operating power plants in the Midwest and Southeast U.S., charging that 32 coal-fired plants in ten states violated the PSD/NSR requirements of the Clean Air Act (CAA). Several states, environmental groups and public interest organizations have filed or given notice of their intent to file similar lawsuits. Generally, the PSD/NSR regulations require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets in some circumstances when those sources undergo a “major modification,” as defined in the regulations. The Federal government is seeking to order these companies to install the best available air pollution control technology at the affected plants and to pay monetary penalties of up to $27,500 for each day of continued violation.

The EPA and the NJDEP issued a demand in March 2000 under the CAA requiring information to assess whether projects completed since 1978 at the Hudson and Mercer coal-fired units were implemented in accordance with applicable PSD/NSR regulations. Power completed its response to the information request in November 2000. In January 2002, Power reached an agreement with New Jersey and the Federal government to resolve allegations of noncompliance with Federal and State of New Jersey PSD/NSR regulation. Under that agreement, over the course of 10 years, Power must install advanced air pollution controls that are designed to reduce emissions of NO_x, SO₂, particulate matter and mercury. Power also paid a $1.4 million civil penalty and has agreed to spend up to $6 million on supplemental environmental projects. The agreement resolving the NSR allegations concerning the Hudson and Mercer coal-fired units also resolved a dispute over Bergen 2 regarding the applicability of PSD requirements and allowed construction of the unit to be completed and operation to begin.

Power has recently notified the EPA and the NJDEP that it is evaluating the continued operation of the Hudson coal unit beyond 2006, in light of changes in the energy and capacity markets and increases in the cost of pollution control equipment and other necessary modifications to the unit. A decision is expected to be made in 2004 as to the Hudson unit’s continued operation. The related costs associated with these modifications have not been included in Power’s capital expenditure projections. Future environmental initiatives are expected to require reduced emissions of NO_x, SO₂, mercury, and

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possibly CO₂ from electric generating facilities. The emission reductions to be achieved are expected to assist in complying with such future requirements.

ISRA

Potential environmental liabilities related to subsurface contamination at certain generating stations have been identified as a result of compliance with ISRA, which applies to the sale of certain assets. In the second quarter of 1999, in anticipation of the transfer of PSE&G’s generation-related assets to Power, a study was conducted to identify potential environmental liabilities and PSEG had a $51 million liability as of December 31, 2003 related to these obligations, which is recorded on the Consolidated Balance Sheets.

New Generation and Development

Power and Energy Holdings

Completion of the projects discussed below, within the estimated time frames and cost estimates cannot be assured. Construction delays, cost increases and various other factors could result in changes in the operational dates or ultimate costs to complete.

Power

Through an indirect, wholly-owned subsidiary, Power is developing the Bethlehem Energy Center that will replace the Albany, NY Steam Station. Total costs for this project are expected to be approximately $500 million with expenditures to date of approximately $303 million. Construction began in 2002 with the expected completion date in 2005, at which time the existing station will be retired.

Power is constructing a generation plant in Linden, New Jersey. Total costs are estimated to be approximately $775 million with expenditures to date of approximately $621 million. Completion is expected in 2005, at which time 451 MW of existing generating capacity at the site will be retired.

Power has constructed, through an indirect, wholly-owned subsidiary, a natural gas-fired generation plant in Waterford, Ohio which achieved commercial operation in August 2003. Power is constructing, through a separate indirect, wholly-owned subsidiary, a natural gas-fired generation plant in Lawrenceburg, Indiana. Both plants combined have an estimated aggregate total cost of $1.2 billion. Expenditures on these projects are nearly complete, with approximately $372 million of the total estimated equity of $416 million invested. The $800 million remainder has been financed with non-recourse bank financing, the terms of which provide for cross collateralization of cash flows between the two projects.

In connection with these projects, ER&T entered into a five-year tolling agreement for each project pursuant to which ER&T, with support from Fossil and Power under tolling make-whole agreements, is obligated to purchase the output of these facilities. The “all-in” payment under these agreements is currently materially above market. These agreements may be terminated upon repayment of the existing financing, which currently matures in August 2005. Under the tolling make whole agreements, Fossil and Power are required under certain circumstances to make additional equity investments into Lawrenceburg and Waterford.

The Lawrenceburg facility’s commercial operation date is now expected in the first half of 2004. Power has successfully negotiated amendments to its $800 million loan agreements with the banks, which initially required the Lawrenceburg facility to achieve commercial operation by December 31, 2003.

Power also has contracts with outside parties to purchase upgraded turbines for the Salem Units 1 and 2 and to purchase upgraded turbines and complete a power uprate for Hope Creek to increase its generating capacity. The power uprate for Hope Creek is currently scheduled to be completed by 2006,

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assuming timely approval from the Nuclear Regulatory Commission (NRC). The turbine replacements are currently scheduled to be complete during planned refueling outages by 2004 for Salem Unit 1, 2006 for Hope Creek and 2008 for Salem Unit 2. Power’s aggregate estimated costs for these projects are $211 million, with expenditures to date of approximately $101 million.

Power has renegotiated certain of its contracts relating to commitments of approximately $110 million for purchases of hardware and services, for which Power would have been subject to cancellation penalties of up to $24 million. As a result of these negotiations, Power has entered into long-term contractual services agreement with a vendor who will provide the outage and service needs for certain of Power’s generating units at market rates. The contract covers approximately twenty-five years and could result in annual payments ranging from approximately $10 million to $50 million per year for services, parts and materials rendered.

Energy Holdings

California

GWF Energy, which is jointly owned by Global and Harbinger GWF LLC (Harbinger), owns and operates three peaker plants in California. In 2003, Harbinger filed an action alleging that Global wrongfully diluted Harbinger’s membership interest percentage in GWF Energy and sought an injunction to prevent Global from converting or maintaining the conversion of optional loans made to GWF Energy by Global into capital contributions and thus diluting Harbinger’s membership interest percentage. In June 2003, Global and Harbinger agreed that the issues and claims raised by Harbinger were to be resolved through arbitration. As of December 31, 2003, Global’s ownership interest in GWF Energy was approximately 74.9%. Pursuant to the arbitration in February 2004, Harbinger repurchased 14.9% interest in GWF Energy for approximately $14 million decreasing Global’s interest to 60%. The reduction in Global’s ownership interest in GWF Energy is not expected to have a material impact on Energy Holdings’ consolidated financial statements.

Poland

In 2002, Global acquired a 50% interest in the electric and thermal coal-fired Skawina plant. In accordance with the original purchase agreement, Global increased its equity interest in Skawina to approximately 63% in August 2003. Additionally, the agreement obligates Global to offer to purchase an additional 12% from Skawina’s employees in 2004, increasing Global’s potential ownership interest to approximately 75%. Global’s total equity investment is expected to be approximately $50 million. In addition, Global has approximately $49 million of equity commitment guarantees related to the modernization of the plant for environmental upgrades over an eight-year period, which could increase Global’s total equity investment to $99 million. Global expects that cash generated from Skawina’s operations will be sufficient to fund all modernization costs.

Minimum Energy Related Purchase Requirements

Power

Power purchases coal for certain of its fossil generation stations through various contracts and in the spot market. The total minimum purchase requirements included in these contracts amount to approximately $280 million through 2008.

Power has several long-term purchase contracts with uranium suppliers, converters, enrichers and fabricators to meet the currently projected fuel requirements for Salem and Hope Creek nuclear power plants. On average, Power has various multi-year requirements-based purchase commitments that total approximately $97 million per year to meet Salem’s and Hope Creek’s fuel needs, of which Power’s share is approximately $70 million per year through 2008. Power has been advised by Exelon, the co-owner and operator of Peach Bottom, that it has similar purchase contracts to satisfy the fuel

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requirements for Peach Bottom, through 2008; of which Power’s share is approximately $35 million per year.

In addition to its fuel requirements, Power has entered into various multi-year contracts for firm transportation and storage capacity for natural gas. As of December 31, 2003, the total minimum fixed cost commitments under these contracts was approximately $850 million through 2016.

BGS Supply

PSE&G and Power

Power’s objective is to enter into load serving contracts and trading positions for at least 75% of its anticipated output over an 18-month to 24-month horizon. PSE&G’s objective is to obtain all of its energy supply needs for its customers through the BGS auction. As a result of the conclusion of the BGS auction in February 2004, the contracts Power has entered into in Pennsylvania and Connecticut and other firm sales and trading positions, commitments were entered into to achieve these objectives.

Nuclear Fuel Disposal

Power

Under the Nuclear Waste Policy Act of 1982, as amended (NWPA), the Federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate disposal of spent nuclear fuel. To pay for this service, nuclear plant owners are required to contribute to a Nuclear Waste Fund at a rate of one mil ($0.001) per Kilowatt-hour (kWh) of nuclear generation, subject to such escalation as may be required to assure full cost recovery by the Federal government. Under the NWPA, the U.S. Department of Energy (DOE) was required to begin taking possession of the spent nuclear fuel by no later than 1998. The DOE has announced that it does not expect a facility for this purpose to be available earlier than 2010.

Pursuant to NRC rules, spent nuclear fuel generated in any reactor can be stored in reactor facility storage pools or in independent spent fuel storage installations located at reactors or away-from-reactor sites for at least 30 years beyond the licensed life for reactor operation (which may include the term of a revised or renewed license). The availability of adequate spent fuel storage capacity is estimated through 2011 for Salem 1, 2015 for Salem 2 and 2007 for Hope Creek. Power presently expects to construct an on-site storage facility that would satisfy the spent fuel storage needs of both Salem and Hope Creek through the end of their respective license lives. This construction will require certain regulatory approvals, the timely receipt of which cannot be assured. Exelon has advised Power that it has constructed an on-site storage facility at Peach Bottom that is now licensed and operational. This on-site storage facility will satisfy Peach Bottom’s fuel storage until at least 2014.

Exelon had previously advised Power that it had signed an agreement with the DOE applicable to Peach Bottom under which Exelon would be reimbursed for costs incurred resulting from the DOE’s delay in accepting spent nuclear fuel. Under this agreement, Power’s portion of Peach Bottom’s Nuclear Waste Fund fees have been reduced by approximately $18 million through August 31, 2002, at which point the credits were fully utilized and covered the cost of Exelon’s storage facility. In 2000, a petition was filed against the DOE in the U.S. Court of Appeals for the Eleventh Circuit, seeking to set aside the receipt of credits by Exelon. In September 2002, the Court issued an opinion upholding the challenge by the petitioners. The DOE and Exelon are required to meet and discuss alternative funding sources for the settlement credits. The Eleventh Circuit’s opinion suggests that the federal judgment fund should be available as an alternate source. On August 14, 2003, Exelon received a letter from the DOE demanding repayment of previously received credits from the Nuclear Waste Fund. The letter also demanded a total of approximately $1.5 million of accrued interest (100% share). PSEG and Power continue to believe that it is the Federal government’s obligation to pay for storage related costs due to DOE’s failure to take possession of the spent nuclear fuel. Further, PSEG and Power also believe that any current payments potentially required relating to the past Nuclear Waste Fund fees will ultimately

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be recovered and accordingly no amounts have been accrued. Exelon has advised Power that it filed suit in January 2004 in the U.S. Court of Federal Claims seeking damages caused by the DOE not taking possession of spent nuclear fuel in 1998.

In September 2001, Nuclear filed a complaint in the U.S. Court of Federal Claims seeking damages caused by the DOE not taking possession of spent nuclear fuel in 1998. No assurances can be given as to any damage recovery or the ultimate availability of a disposal facility.

In October 2001, Power filed a complaint in the U.S. Court of Federal Claims, along with a number of other plaintiffs, seeking $28 million in relief from past overcharges by the DOE for enrichment services. No assurances can be given as to any damage recovery.

Spent Fuel Pool Leakage

Power

The spent fuel pool at each Salem unit has an installed leakage collection system. This normal leakage path was recently found to be obstructed, causing concern about the extent of leakage contact with the fuel handling building’s concrete structure. Nuclear is developing a solution to maintain the design function of the leakage collection system and is investigating the extent of any structural degradation caused by the previous leakage. The investigation should take approximately one year. If any significant degradation is identified, the repair costs could be material. PSEG believes that the NRC will soon distribute an information notice on this emerging industry issue and PSEG cannot predict what further actions the NRC may take on this matter.

Elevated concentrations of tritium in the shallow groundwater near Salem Unit 1 were detected in early 2003. This information was reported to the NJDEP and the NRC, as required. Nuclear is conducting a comprehensive investigation in accordance with NJDEP site remediation regulations to determine the source and extent of the tritium in the groundwater. Currently, the source of the tritium contamination is believed to be the Salem Unit 1 Spent Fuel Pool. The investigation is ongoing and therefore the costs necessary to address this groundwater contamination issue are not known fully, however, such costs are not expected to be material.

Other

PSEG and PSE&G

ITC

As of June 1999, the Internal Revenue Service (IRS) had issued several private letter rulings that concluded that the refunding of excess deferred tax and ITC balances to utility customers was permitted only over the related assets’ regulatory lives, which were terminated upon deregulation. Based on this fact, in 1999, PSEG and PSE&G reversed the deferred tax and ITC liability relating to its generation assets that were transferred to Power and recorded a $235 million reduction as a component of the extraordinary charge recorded in 1999 due to the deregulation in New Jersey. PSE&G was directed by the BPU to seek a ruling from the IRS to determine if the ITC included in the impairment write-down of generation assets could be credited to customers without violating the tax normalization rules of the Internal Revenue Code. PSE&G filed for a private letter ruling request in 2002, which is still pending.

In January 2003, the IRS proposed for comment regulations that, if adopted, would allow utilities to elect retroactive application over periods equivalent to the ones in place prior to deregulation. While PSEG cannot predict the outcome of this matter, a requirement to refund such amounts to customers could have a material impact on PSEG’s and PSE&G’s financial condition, results of operations and net cash flows.

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PSE&G

Placement of Gas Meters

In 2003, a proposed class action lawsuit was filed against PSE&G and PSEG alleging that PSE&G’s installation of outdoor gas meters within three feet of driveways or garages at residential locations is negligent. The suit also requests the court to order PSE&G to establish a fund for the purposes of remediating the allegedly improper meter installations.

In August 2003, the Judge in the case granted PSE&G’s and the BPU’s motions to transfer the matter to the BPU to review regulatory issues within the agency’s primary jurisdiction. The case was transferred prior to the court ruling on whether the proposed class would be certified. The court retained jurisdiction over the negligence-based issues. The BPU initiated an evidentiary hearing process in the case in September 2003. In December 2003, the parties filed testimony with the BPU. Evidentiary hearings, which were scheduled for early January 2004, have been postponed to allow the parties to initiate settlement discussions. PSE&G cannot predict the ultimate outcome of this matter.

Energy Holdings

Argentina

Empresa Distribuidora La Plata S.A. (EDELAP) and AES Parana Project

During 2003, the shares formerly held by Global in EDELAP and AES Parana were transferred to AES. In connection with that transfer, certain contingent obligations of Global with respect to project loans were terminated by agreement with the lenders.

Empresa Distribuidora de Electricidad Norte (EDEN) and Empresa Distribuidora de
Electricidad Sur (EDES)

In December 2003, the shares held by Global in EDEN and in EDES were transferred to AES. In connection with these transfers, certain contingent obligations Global had with respect to the projects were transferred to the purchaser.

EDEERSA

Energy Holdings completed the process of exiting from the EDEERSA electric distribution company in the Province of Entre Rios, Argentina. In March 2003, PSEG formally and irrevocably renounced, and effectively abandoned, its entire economic and legal interest in EDEERSA. The shares were relinquished and ownership was assumed by an Argentine trust benefiting current EDEERSA employees, including all of the existing EDEERSA Class C shareholders who received their shares from the Province as part of the initial privatization process. The regulator in the Province has requested that 51% of the EDEERSA shares be transferred from the trust to the Province. The matter is pending in the courts. A representative of the labor union representing EDEERSA filed a criminal complaint against the transaction alleging that the union should have been allocated more interest in EDEERSA than the trust arrangement currently provides. Energy Holdings believes that it will have no additional exposure to these legal proceedings, but no assurances can be given.

Peru

Electroandes

In November 2002, the Peruvian Government created a subsidy in favor of the construction of the Camisea gas pipeline, in the form of a surcharge to the electric transmission tariffs paid by all end users. Two of Electroandes’ largest customers (representing about 67% of its contracted capacity) refused to pay the surcharge, thus preventing Electroandes, in its role as collection agent, from transferring the

173

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

associated funds to the beneficiaries of the surcharge. In July 2003, Electroandes made a filing with the courts to determine which party was responsible for payment of this subsidy. Subsequent to this filing, the dispute was favorably resolved with the customers and the local electric regulatory agency. Electroandes has since requested a withdrawal of its filing and expects an official conclusion from the courts on the resolution of this matter in the first quarter of 2004.

Luz del Sur (LDS)

The Superintendencia Nacional de Administracion Tributaria (SUNAT), the governing tax authority in Peru, claimed past-due taxes for the period between 1996-1999, plus penalties and interest, resulting from an interpretation of the law that allowed LDS to restate its assets to fair market value and take advantage of the resulting higher deductions from depreciation. While LDS prevailed on this issue in arbitration proceedings that ended in December 2001, SUNAT pursued the claim in the local Tax Court. The Tax Court ordered SUNAT to rule according to the arbitration, which was favorable to LDS. The Tax Court did make a reference a provision of law, which requires consideration of the legitimacy of the business motives leading to a corporate reorganization, such as the one made by LDS and which gave rise to the original dispute. LDS believes it had legitimate business motives to reorganize when it did and management believed that it acted in accordance with the applicable law and, accordingly, LDS’s position prevailed as SUNAT agreed that this provision of law did not apply.

Further, SUNAT stated that the revaluation study, performed in 1996, was not performed correctly and is therefore invalid. It is LDS’s position that laws and regulations did not define the methodology to be used in these matters and its study was based on generally accepted practices. LDS’s total potential liability relating to this matter is approximately $55 million, of which $18 million is currently recorded as a deferred tax liability at LDS. Global’s share of the net potential liability related to the claim by SUNAT is estimated at $16 million.

In July 2003, SUNAT presented its claims before the Fiscal Court. In January 2004, the Fiscal Court ruled in favor of LDS in respect of the 1999 matter. LDS believes the 1996-1998 years will be decided consistent with this ruling.

Minimum Lease Payments

PSEG, PSE&G and Energy Holdings

PSE&G, Services and Energy Holdings lease administrative office space under various operating leases. For the years ended December 31, 2003, 2002 and 2001, PSEG’s lease expenses were approximately $10 million per year, primarily related to Energy Holdings. Total future minimum lease payments as of December 31, 2003 are:

	2004		2005		2006			2007		2008		After 2008		Total
							(Millions)
PSE&G	$	3	$	3	$	2		$	2	$	1	$	—	$	11
Services		1		1		1			1		1		3		8
Energy Holdings		8		7		6			6		5		16		48
Total PSEG	$	12	$	11	$	9		$	9	$	7	$	19	$	67

174

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Power and Services have entered into capital leases for administrative office space. The total future minimum payments and present value of these capital leases as of December 31, 2003 are:

	Services			Power
	(Millions)
2004	$	6		$	1
2005		6			1
2006		7			1
2007		7			2
2008		7			2
Thereafter		43			11
Total Minimum Lease Payments	$	76		$	18
Less: Imputed Interest		(35	)		(7	)
Present Value of net Minimum Lease Payments	$	41		$	11

Note 18. Nuclear Decommissioning Trust

Power

In accordance with NRC regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operation. As a general practice, each nuclear owner places funds in independent external trust accounts it maintains to provide for decommissioning.

For information relating to cost responsibility for nuclear decommissioning subsequent to July 31, 2003, see Note 4. Adoption of SFAS 143.

Power maintains the external master nuclear decommissioning trust previously established by PSE&G. This trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a “qualified“ fund. Contributions made into a qualified fund are tax deductible. In the most recent study the total cost of decommissioning, Power’s share of its five nuclear units was estimated at approximately $2.1 billion, including contingencies.

Power’s policy is that, except for investments tied to market indexes or other non-nuclear sector common trust funds or mutual funds (e.g., an S&P 500 mutual fund), assets of the trust shall not be invested in the securities or other obligations of PSEG or its affiliates, or its successors or assigns; and assets shall not be invested in securities of any entity owning one or more nuclear power plants.

Effective January 1, 2003, Power began accounting for the assets in the NDT Fund under SFAS 115. Power classifies investments in the NDT Fund as available-for-sale under SFAS 115. The

175

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

following tables show the fair values, gross unrealized gains and losses and amortized cost bases for the securities held in the NDT Fund.

	As of December 31, 2003
	Cost		Gross Unrealized Gains			Gross Unrealized Losses				Estimated Fair Value
	(Millions)
Equity Securities	$	447		$	186		$	(14	)		$	619
Debt Securities
Government Obligations		136			3			(1	)			138
Other Debt Securities		200			11			(5	)			206
Total Debt Securities		336			14			(6	)			344
Other Securities		25			—			(3	)			22
Total Available-for-Sale Securities	$	808		$	200		$	(23	)		$	985

	As of December 31, 2002
	Cost		Gross Unrealized Gains			Gross Unrealized Losses				Estimated Fair Value
	(Millions)
Equity Securities	$	424		$	74		$	(47	)		$	451
Debt Securities
Government Obligations		83			6			—				89
Other Debt Securities		206			9			(21	)			194
Total Debt Securities		289			15			(21	)			283
Other Securities		32			—			—				32
Total Available-for-Sale Securities	$	745		$	89		$	(68	)		$	766

	Years Ended
	December 31,
	2003		2002			2001
	(Millions)
Proceeds from Sales	$	1,229	$	491	$		589
Gross Realized Gains	$	115	$	45	$		45
Gross Realized Losses	$	64	$	62	$		52

Net realized gains of $51 million were recognized in Other Income and Other Deductions on Power’s Consolidated Statement of Operations for the year ended December 31, 2003. Net unrealized gains of $118 million were recognized in Other Comprehensive Income on Power’s Consolidated Balance Sheet as of December 31, 2003. Of the $23 million of the gross 2003 unrealized losses, $6 million have been in an unrealized loss position for less than twelve months. The available-for-sale debt securities held as of December 31, 2003, had the following maturities: $78 million less than one year, $62 million one to five years, $81 million five to ten years, $40 million ten to fifteen years, $16 million fifteen to twenty years, and $67 million over twenty years. The cost of these securities was determined on the basis of specific identification.

176

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 19. Other Income and Deductions

Other Income

	PSE&G				Power			Energy Holdings			Other(A)				Consolidated Total
	(Millions)
For the Year Ended December 31, 2003:
Interest Income		$	(7	)		$	7		$	—		$	1			$	1
Gain on Disposition of Property			11				—			—			—				11
NDT Fund Realized Gains			—				115			—			—				115
NDT Interest and Dividend Income			—				26			—			—				26
Foreign Currency Gains			—				—			16			—				16
Other			2				1			4			2				9
Total Other Income		$	6			$	149		$	20		$	3			$	178
For the Year Ended December 31, 2002:
Interest Income		$	4			$	—		$	—		$	—			$	4
Gain on Disposition of Property			10				—			—			—				10
Change in Derivative Fair Value			—				—			11			—				11
Gain on Early Retirement of Debt			—				—			14			—				14
Minority Interest			—				—			—			1				1
Other			1				1			1			(4	)			(1	)
Total Other Income		$	15			$	1		$	26		$	(3	)		$	39
For the Year Ended December 31, 2001:
Interest Income		$	88			$	—		$	—		$	(66	)		$	22
Gain on Disposition of Property			4				—			—			—				4
Other			3				—			4			—				7
Total Other Income		$	95			$	—		$	4		$	(66	)		$	33

177

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Other Deductions

	PSE&G			Power			Energy Holdings			Other(A)			Consolidated Total
	(Millions)
For the Year Ended December 31, 2003:
Donations		$	1		$	—		$	—		$	4		$	5
NDT Fund Realized Losses and Expenses			—			77			—			—			77
Minority Interest			—			—			—			13			13
Change in Derivative Fair Value			—			—			5			—			5
Other			—			1			—			—			1
Total Other Income		$	1		$	78		$	5		$	17		$	101
For the Year Ended December 31, 2002:
Donations		$	2		$	—		$	—		$	—		$	2
Foreign Currency Losses			—			—			77			—			77
Other			—			1			—			—			1
Total Other Deductions		$	2		$	1		$	77		$	—		$	80
For the Year Ended December 31, 2001:
Donations		$	3		$	—		$	—		$	—		$	3
Foreign Currency Losses			—			—			11			—			11
Change in Derivative Fair Value			—			—			3			—			3
Loss on Early Retirement of Debt			—			—			3			—			3
Other			1			—			—			—			1
Total Other Deductions		$	4		$	—		$	17		$	—		$	21

______________

(A)

Other primarily consists of activity at PSEG (parent company), Services and intercompany eliminations.

178

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 20. Income Taxes

A reconciliation of reported income tax expense with the amount computed by multiplying pre-tax income by the statutory Federal income tax rate of 35% is as follows:

	PSE&G				Power			Energy Holdings			Other			Consolidated Total
	(Millions)
2003
Net Income (Loss)		$	225		$	844		$	122		$	(31	)		$	1,160
Extraordinary Item, net of tax benefit of $12			(18	)		—			—			—				(18	)
Loss from Discontinued Operations, (Including Loss on Disposal, net of tax—$10)			—			—			(44	)		—				(44	)
Cumulative Effect of a Change in Accounting Principle, (net of tax benefit—$255)			—			370			—			—				370
Minority Interest in Earnings of Subsidiaries			—			—			(13	)		—				(13	)
Income from Continuing Operations, less Preferred Dividends			243			474			179			(31	)			865
Preferred Dividends (net)			(4	)		—			(23	)		23				(4	)
Income (Loss) from Continuing Operations excluding Minority Interest and Preferred Dividends		$	247		$	474		$	202		$	(54	)		$	869
Income Taxes:
Federal — Current			1			134			(299	)		(43	)			(207	)
Deferred			91			121			331			4				547
ITC			(2	)		—			(1	)		—				(3	)
Total Federal			90			255			31			(39	)			337
State — Current			(2	)		41			(57	)		(10	)			(28	)
Deferred			41			30			70			(1	)			140
Total State			39			71			13			(11	)			112
Foreign — Current			—			—			—			—				—
Deferred			—			—			15			—				15
Total Foreign			—			—			15			—				15
Total			129			326			59			(50	)			464
Pre-tax Income		$	376		$	800		$	261		$	(104	)		$	1,333
Tax computed at the statutory rate		$	131		$	280		$	91		$	(36	)		$	466
Increase (decrease) attributable to flow through of certain tax adjustments:
Plant Related Items			(18	)		—			—			—				(18	)
Amortization of investment tax credits			(2	)		—			(1	)						(3	)
Other			(8	)		(1	)		1			(7	)			(15	)
Tax Effects Attributable to Foreign Operations			—			—			(40	)		—				(40	)
State Income Tax (net of Federal Income Tax)			26			47			8			(7	)			74
Subtotal			(2	)		46			(32	)		(14	)			(2	)
Total income tax provisions		$	129		$	326		$	59		$	(50	)		$	464
Effective income tax rate			34.3	%		40.8	%		22.6	%		48.1	%			34.8	%

179

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	PSE&G				Power				Energy Holdings				Other				Consolidated Total
	(Millions)
2002
Net Income (Loss)		$	201			$	468			$	(413	)		$	(21	)		$	235
Loss from Discontinued Operations, (Including Loss on Disposal, net of tax—$28)			—				—				(49	)			—				(49	)
Cumulative Effect of a Change in Accounting Principle, (net of tax—$66)			—				—				(121	)			—				(121	)
Minority Interest in Earnings of Subsidiaries			—				—				1				—				1
Income from Continuing Operations, less Preferred Dividends			201				468				(244	)			(21	)			404
Preferred Dividends (net)			(4	)			—				(23	)			23				(4	)
Income (Loss) from Continuing Operations excluding Minority Interest and Preferred Dividends		$	205			$	468			$	(221	)		$	(44	)		$	408

Income Taxes:
Federal — Current			121				184				(102	)			(29	)			174
Deferred			(44	)			69				(24	)			6				7
ITC			(2	)			—				(2	)			—				(4	)
Total Federal			75				253				(128	)			(23	)			177
State — Current			17				41				(1	)			(7	)			50
Deferred			23				19				(27	)			—				15
Total State			40				60				(28	)			(7	)			65
Foreign — Current			—				—				1				—				1
Deferred			—				—				11				—				11
Total Foreign			—				—				12				—				12
Total			115				313				(144	)			(30	)			254
Pre-tax Income		$	320			$	781			$	(365	)		$	(74	)		$	662
Tax computed at the statutory rate		$	112			$	273			$	(128	)		$	(26	)		$	231
Increase (decrease) attributable to flow through of certain tax adjustments:
Plant Related Items			(15	)			—				—				—				(15	)
Amortization of investment tax credits			(2	)			—				(1	)			—				(3	)
Other			(6	)			1				(4	)			—				(9	)
Tax Effects Attributable to Foreign Operations			—				—				(2	)			—				(2	)
State Income Tax (net of Federal Income Tax)			26				39				(9	)			(4	)			52
Subtotal			3				40				(16	)			(4	)			23
Total income tax provisions		$	115			$	313			$	(144	)		$	(30	)		$	254
Effective income tax rate			35.9	%			40.1	%			39.5	%			40.5	%			38.4	%

180

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	PSE&G				Power				Energy Holdings				Other			Consolidated Total
	(Millions)
2001
Net Income (Loss)		$	230			$	394			$	154		$	(14	)		$	764
Loss from Discontinued Operations, (net of tax—$8)			—				—				(12	)		—				(12	)
Cumulative Effect of a Change in Accounting Principle, (net of tax—$8)			—				—				10			—				10
Income from Continuing Operations, less Preferred Dividends			230				394				156			(14	)			766
Preferred Dividends (net)			(5	)			—				(23	)		23				(5	)
Income (Loss) from Continuing Operations excluding Preferred Dividends		$	235			$	394			$	179		$	(37	)		$	771
Income Taxes:
Federal — Current			250				139				(106	)		(32	)			251
Deferred			(192	)			74				161			13				56
ITC			(2	)			—				(1	)		—				(3	)
Total Federal			56				213				54			(19	)			304
State — Current			42				17				9			(4	)			64
Deferred			(9	)			20				(11	)		(1	)			(1	)
Total State			33				37				(2	)		(5	)			63
Foreign — Current			—				—				1			—				1
Deferred			—				—				5			—				5
Total Foreign			—				—				6			—				6
Total			89				250				58			(24	)			373
Pre-tax Income		$	324			$	644			$	237		$	(61	)		$	1,144
Tax computed at the statutory rate		$	113			$	225			$	83			(21	)		$	400
Increase (decrease) attributable to flow through of certain tax adjustments:
Plant Related Items			(41	)			—				—			—				(41	)
Amortization of investment and energy tax credits			(2	)			—				(1	)		—				(3	)
Other			(2	)			1				(2	)		—				(3	)
Tax Effects Attributable to Foreign Operations			—				—				(19	)		—				(19	)
State Income Tax (net of Federal Income Tax)			21				24				(3	)		(3	)			39
Subtotal			(24	)			25				(25	)		(3	)			(27	)
Total income tax provisions		$	89			$	250			$	58		$	(24	)		$	373
Effective income tax rate			27.5	%			38.8	%			24.5	%		39.3	%			32.6	%

PSEG, PSE&G, Power and Energy Holdings

Each of PSEG, PSE&G, Power and Energy Holdings provide deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities irrespective of the treatment for rate-making purposes. Management believes that it is probable that the accumulated tax benefits that previously have been treated as a flow-through item to PSE&G customers will be recovered from PSE&G’s customers in the future. Accordingly, an offsetting regulatory asset was established. As of December 31, 2003, PSE&G had a deferred tax liability and an offsetting regulatory asset of $368 million representing the tax costs

181

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

expected to be recovered through rates based upon established regulatory practices which permit recovery of current taxes payable. This amount was determined using the enacted Federal income tax rate of 35% and State income tax rate of 9%.

Energy Holdings’ effective tax rate differs from the statutory Federal income tax rate of 35% primarily due to the imposition of state taxes and the fact that Global accounts for many of its foreign investments using the equity method of accounting. The foreign income taxes are a component of each PSEG and Energy Holdings’ equity in earnings rather than included as a component of the income tax provision.

The following is an analysis of deferred income taxes:

	PSE&G					Power						Energy Holdings						Other						Consolidated
	2003			2002		2003			2002			2003			2002			2003			2002			2003		2002
		(Millions)
Deferred Income Taxes
Assets:
Current (net)	$	17		$	16	$	—		$	—		$	—		$	—		$	—		$	—		$	17	$	16
Noncurrent:
Unrecovered Investment Tax Credits		19			19		—			—			—			—			—			—			19		19
Nuclear Decommissioning		—			—		—			26			—			—			—			—			—		26
SFAS 133		—			—		21			2			47			53			7			9			75		64
Other Comprehensive Income		2			122		—			58			(1	)		3			2			24			3		207
New Jersey Corporate Business Tax		189			232		102			125			(60	)		(5	)		(1	)		—			230		352
OPEB		110			99		—			—			—			—			—			—			110		99
Cost of Removal		—			—		51			51			—			—			—			—			51		51
Investment Related Adjustment		12			—		—			—			118			270			—			—			130		270
Development Fees		—			—		—			—			18			22			—			—			18		22
Foreign Currency Translation		—			—		—			—			35			39			—			—			35		39
Contractual Liabilities and Environmental Costs		—			—		35			35			—			—			—			—			35		35
Market Transition Charge		11			66		—			—			—			—			—			—			11		66
Other		(1	)		—		18			—			—			—			—			—			17		—
Total Noncurrent		342			538		227			297			157			382			8			33			734		1,250
Total Assets		359			554		227			297			157			382			8			33			751		1,266
Liabilities:
Noncurrent:
Plant Related Items		1,288			1,138		(181	)		(276	)		—			—			—			5			1,107		867
Nuclear Decommissioning		—			—		18			—			—			—			—			—			18		—
Securitization		1,414			1,502		—			—			—			—			—			—			1,414		1,502
Leasing Activities		—			—		—			—			1,509			1,298			—			—			1,509		1,298
Partnership Activities		—			—		—			—			96			66			—			—			96		66
Conservation Costs		68			10		—			—			—			—			—			—			68		10
Pension Costs		71			84		22			25			—			—			21			15			114		124
SFAS 143		—			—		337			—			—			—			—			—			337		—
Taxes Recoverable Through Future Rates (net)		156			145		—			—			—			—			—			—			156		145
Income from Foreign Operation		—			—		—			—			31			34			—			—			31		34
Other		7			39		—			(5	)		1			(1	)		5			4			13		37
Total Noncurrent		3,004			2,918		196			(256	)		1,637			1,397			26			24			4,863		4,083
Total Liabilities		3,004			2,918		196			(256	)		1,637			1,397			26			24			4,863		4,083
Summary—Accumulated Deferred Income Taxes:
Net Current Assets		17			16		—			—			—			—			—			—			17		16
Net Noncurrent Liability		2,662			2,380		(31	)		(553	)		1,480			1,015			18			(9	)		4,129		2,833
Total	$	2,645		$	2,364	$	(31	)	$	(553	)	$	1,480		$	1,015		$	18		$	(9	)	$	4,112	$	2,817

182

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 21. Pension, Other Postretirement Benefit (OPEB) and Savings Plans

PSEG

PSEG sponsors several qualified and nonqualified pension plans and other postretirement benefit plans covering PSEG’s, and its participating affiliates current and former employees who meet certain eligibility criteria.

Plan Assets

The following table provides the percentage of fair value of total plan assets for each major category of plan assets held as of the measurement date, December 31.

	As of December 31,
Investments	2003	2002
Equity Securities	63%	58%
Fixed Income Securities	29%	34%
Real Estate Asset	5%	6%
Other Investments	3%	2%
Total Percentage	100%	100%

PSEG utilizes an independent pension consultant to forecast returns, risk, and correlation of all asset classes in order to develop an optimal portfolio, which is designed to produce the maximum return opportunity per unit of risk. In 2002, PSEG’s completed its latest asset/liability study. The results from the study indicated that, in order to achieve the optimal risk/return portfolio, target allocations of 62% equity securities, 30% fixed income securities, 5% real estate investments, and 3% for other investments should be maintained. Derivative financial instruments are used by the plans investment managers primarily to rebalance the fixed income/equity allocation of the portfolio and hedge the currency risk component of the foreign investments.

The expected long-term rate of return on plan assets was 9.00% as of December 31, 2003. For 2004, the expected long-term rate of return on plan assets was reduced to 8.75%. This expected return was determined based on the study discussed above and considered the plans’ historical annualized rate of return since inception of the plan, which was an annualized return of 10.20%.

Plan Contributions

PSEG anticipates contributing approximately $90 million into its qualified pension plans for calendar year 2004.

Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Medicare Act)

The passage of the Medicare Act introduces a prescription drug benefit under Medicare, as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Certain accounting issues raised by the Medicare Act, such as the federal subsidy, are not explicitly addressed by current accounting standards. Therefore, PSEG elected to defer accounting per the implementation of the Medicare Act until official guidance is issued by the FASB. As such, the reported Accumulated Postretirement Benefit Obligation, and the net period postretirement benefit cost do not reflect the effects of the Medicare Act. The impact of this Act is expected to be an immaterial benefit. When specific authoritative guidance is issued it could require PSEG to change previously reported information.

Accumulated Benefit Obligations

The accumulated benefit obligations of all PSEG’s defined benefit pension plans as of December 31, 2003, and 2002 were $2.7 billion and $2.5 billion, respectively.

183

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides a reconciliation of the changes in the fair value of plan assets over each of the two years in the period ended December 31, 2003 and a reconciliation of the funded status at the end of both years.

Pension and Other Postretirement Benefit Plans

	Pension Benefits						Other Benefits

	2003			2002			2003			2002
	(Millions)
Change in Benefit Obligation:
Benefit Obligation at Beginning of Year	$	2,968		$	2,676		$	777		$	674
Service Cost		74			69			21			18
Interest Cost		195			188			51			47
Actuarial Loss		158			162			117			84
Benefits Paid		(160	)		(156	)		(50	)		(48	)
Plan Amendments		—			7			—			—
Business Combinations		—			22			—			2

Benefit Obligation at End of Year		3,235			2,968			916			777

Change in Plan Assets:
Fair Value of Assets at Beginning of Year		2,131			2,228			51			40
Actual Return on Plan Assets		514			(192	)		13			(3	)
Employer Contributions		211			240			63			61
Benefits Paid		(160	)		(156	)		(50	)		(48	)
Business Combinations		—			11			—			1

Fair Value of Assets at End of Year		2,696			2,131			77			51

Reconciliation of Funded Status:
Funded Status		(539	)		(837	)		(839	)		(726	)
Unrecognized Net
Transition Obligation		—			5			221			248
Prior Service Cost		94			104			—			—
(Gain) Loss		784			1,003			87			(25	)

Net Amount Recognized	$	339		$	275		$	(531	)	$	(503	)

Amounts Recognized in Statement of Financial Position:
Prepaid Benefit Cost	$	379		$	3		$	—		$	—
Accrued Cost		(67	)		(343	)		(531	)		(503	)
Intangible Asset		14			114			N/A			N/A
Accumulated Other Comprehensive Income (pre-tax)		13			501			N/A			N/A

Net Amount Recognized	$	339		$	275		$	(531	)	$	(503	)

Separate Disclosure for Pension Plans With an Accumulated Benefit Obligation in Excess of Plan Assets:
Projected Benefit Obligation at End of Year	$	86		$	2,946
Accumulated Benefit Obligation at End of Year	$	67		$	2,451
Fair Value of Assets at End of Year	$	—		$	2,113

184

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The pension benefits table above provides information relating to the funded status of all qualified and nonqualified pension plans and other postretirement benefit plans on an aggregate basis.

	Pension Benefits									Other Benefits

	2003			2002			2001			2003			2002			2001
	(Millions)
Components of Net Periodic Benefit Cost:
Service Cost	$	74		$	69		$	63		$	21		$	19		$	16
Interest Cost		195			188			182			51			47			47
Expected Return on Plan Assets		(193	)		(206	)		(211	)		(5	)		(4	)		(3	)
Amortization of Net
Transition Obligation		5			8			8			27			27			27
Prior Service Cost		17			17			16			—			—			—
(Gain)/Loss		49			13			—			(3	)		(4	)		(6	)

Net Periodic Benefit Cost	$	147		$	89		$	58		$	91		$	85		$	81

Components of Total Benefit Expense:
Net Periodic Benefit Cost	$	147		$	89		$	58		$	91		$	85		$	81
Effect of Regulatory Asset		—			—			—			19			19			19

Total Benefit Expense Including Effect of Regulatory Asset	$	147		$	89		$	58		$	110		$	104		$	100

Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31:
Discount Rate		6.75	%		7.25	%		7.50	%		6.75	%		7.25	%		7.50	%
Expected Return on Plan Assets		9.00	%		9.00	%		9.00	%		9.00	%		9.00	%		9.00	%
Rate of Compensation Increase		4.69	%		4.69	%		4.69	%		4.69	%		4.69	%		4.69	%
Weighted-Average Assumptions Used to Determine Benefit
Obligations as of December 31:
Discount Rate		6.25	%		6.75	%		7.25	%		6.25	%		6.75	%		7.25	%
Rate of Compensation Increase		4.69	%		4.69	%		4.69	%		4.69	%		4.69	%		4.69	%
Rate of Increase in Health Benefit Costs
Administrative Expense											5.00	%		5.00	%		5.00	%
Dental Costs											6.00	%		6.00	%		6.00	%
Pre-65 Medical Costs
Immediate Rate											9.00	%		9.00	%		9.50	%
Ultimate Rate											6.00	%		6.00	%		6.00	%
Year Ultimate Rate Reached											2010			2008			2008
Post-65 Medical Costs
Immediate Rate											7.00	%		7.00	%		7.50	%
Ultimate Rate											6.00	%		6.00	%		6.00	%
Year Ultimate Rate Reached											2006			2004			2004
Effect of a Change in the Assumed Rate of Increase in Health Benefit Costs:
Effect of a 1% Increase On
Total of Service Cost and Interest Cost										$	4		$	5		$	5
Postretirement Benefit Obligation										$	51		$	46		$	45
Effect of a 1% Decrease On
Total of Service Cost and Interest Cost										$	(5	)	$	(4	)	$	(4	)
Postretirement Benefit Obligation										$	(59	)	$	(39	)	$	(39	)

185

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Cash Flows

Estimated Future Benefit Payments (Reflecting Expected Future Service)

The following benefit payments, which reflect expected future service, are expected to be paid:

Year	Pension Benefits			Other Benefits
	(Millions)
2004		$	164		$	51
2005			168			53
2006			173			54
2007			178			56
2008			185			57
2009–2013			1,100			337
Total		$	1,968		$	608

401K Plans

PSEG sponsors two 401(k) plans, which are Employee Retirement Income Security Act (ERISA) defined contribution plans. Eligible represented employees of PSE&G, Power and Services participate in the PSEG Employee Savings Plan (Savings Plan), while eligible non-represented employees of PSE&G, Power, Energy Holdings and Services participate in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). Eligible employees may contribute up to 50% of their compensation to these plans. Employee contributions up to 7% for Savings Plan participants and up to 8% for Thrift Plan participants are matched with employer contributions of cash equal to 50% of such employee contributions. For periods prior to March 1, 2002, employer contributions, related to participant contributions in excess of 5% and up to 7%, were made in shares of PSEG Common Stock for Savings Plan participants. For periods prior to March 1, 2002, Employer contributions, related to participant contributions in excess of 6% and up to 8%, were made in shares of PSEG Common Stock for Thrift Plan participants. The shares for these contributions were purchased in the open market. Since that time, all Employer contributions have been made in cash. The amount expensed for Employer matching contributions to the plans was approximately $25 million, $25 million, and $24 million in 2003, 2002, and 2001, respectively.

PSE&G, Power, Energy Holdings and Services eligible employees participate in non-contributory pension and OPEB plans sponsored by PSEG and administered by Services. In addition, represented and nonrepresented employees are eligible for participation in PSEG’s two defined contribution plans described above.

PSE&G

PSE&G’s pension costs amounted to $79 million, $46 million and $30 million for the years ended December 31, 2003, 2002 and 2001, respectively. For 2003, this amount represented approximately 54% of PSEG’s total consolidated pension costs. PSE&G’s Thrift Plan and Savings Plan matching costs amounted to approximately $13 million, $13 million and $12 million for the years ended December 31, 2003, 2002 and 2001, respectively. PSE&G’s OPEB costs amounted to $100 million, $95 million and $95 million for the years ended December 31, 2003, 2002 and 2001, respectively. For 2003, this amount represented approximately 90% of PSEG’s total consolidated OPEB costs.

Power

Power’s pension costs amounted to $46 million, $26 million and $16 million for the years ended December 31, 2003, 2002 and 2001, respectively. For 2003, this amount represented approximately 31% of PSEG’s total consolidated pension costs. Power’s Thrift Plan and Savings Plan matching costs amounted to approximately $9 million, $8 million and $8 million for the years ended December 31,

186

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2003, 2002 and 2001, respectively. Power’s OPEB costs amounted to $8 million, $6 million and $4 million for the years ended December 31, 2003, 2002 and 2001, respectively. For 2003, this amount represented approximately 7% of PSEG’s total consolidated OPEB costs.

Energy Holdings

Energy Holdings’ pension costs amounted to $4 million, $2 million and $1 million for the years ended December 31, 2003, 2002 and 2001, respectively. For 2003, this amount represented approximately 3% of PSEG’s total consolidated pension costs. Energy Holdings’ Thrift Plan and Savings Plan matching costs amounted to approximately $1 million for each of the years ended December 31, 2003, 2002 and 2001. Energy Holdings OPEB costs amounted to less than $1 million for each of the years ended December 31, 2003, 2002 and 2001.

Note 22. Stock Options and Employee Stock Purchase Plan

PSEG

Stock Options

Under PSEG’s 1989 Long-Term Incentive Plan (1989 LTIP) and its 2001 Long-Term Incentive Plan (2001 LTIP), non-qualified options to acquire shares of Common Stock may be granted to officers and other key employees of PSEG, PSE&G, Power, Energy Holdings, Services and their respective subsidiaries selected by the Organization and Compensation Committee of PSEG’s Board of Directors, the plan’s administrative committee (Committee). In addition, certain key executives have received option grants under the 1989 LTIP in connection with their employment agreements. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the Committee, by delivering previously acquired shares of PSEG Common Stock. In instances where an optionee tenders shares acquired from a grant previously exercised that were held for a period of less than six months, an expense will be recorded for the difference between the fair market value at exercise date and the option price. Options are exercisable over a period of time designated by the Committee (but not prior to one year or longer than ten years from the date of grant) and are subject to such other terms and conditions as the Committee determines. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change in control. Options may not be transferred during the lifetime of a holder.

The 1989 LTIP currently provides for the issuance of up to 8,000,000 options to purchase shares of common stock. As of December 31, 2003, there were 4,232,717 options available for future grants under the 1989 LTIP.

The 2001 LTIP currently provides for the issuance of up to 15,000,000 options to purchase shares of common stock. As of December 31, 2003, there were 8,742,433 options available for future grants under the 2001 LTIP.

PSEG purchases shares on the open market to meet the exercise of stock options. The difference between the cost of the shares (generally purchased on the date of exercise) and the exercise price of the options has been reflected in Stockholders’ Equity except where otherwise discussed.

187

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Changes in common shares under option for the three fiscal years in the period ended December 31, 2003 are summarized as follows:

	2003						2002					2001
	Options			Weighted Average Exercise Price			Options		Weighted Average Exercise Price			Options		Weighted Average Exercise Price
Beginning of year		9,192,631			$	39.32	7,652,463			$	41.22	5,186,099			$	40.38
Granted		706,300				37.35	1,890,000				31.62	2,833,000				41.84
Exercised		(541,767	)			32.76	(157,332	)			36.28	(303,135	)			32.83
Canceled		(622,233	)			42.01	(192,500	)			41.94	(63,501	)			41.27
End of year		8,734,931				39.37	9,192,631				39.32	7,652,463				41.22
Exercisable at end of year		5,822,196			$	40.44	4,542,165			$	40.24	2,767,830			$	39.19
Weighted average fair value of options granted during the year					$	5.73				$	4.37				$	7.22

The following table provides information about options outstanding as of December 31, 2003:

		Options Outstanding				Options Exercisable
Range of Exercise Prices	Outstanding at December 31, 2003		Weighted Average Remaining Contractual Life	Weighted Average Exercise Price	Exercisable at December 31, 2003		Weighted Average Exercise Price
$25.03-$30.02		135,000	4.0 years	$ 29.56		135,000	$ 29.56
$30.03-$35.03		2,741,932	8.2 years	32.26		1,307,708	32.42
$35.04-$40.03		649,167	5.3 years	39.11		599,167	39.31
$40.04-$45.04		3,041,332	7.9 years	41.52		1,916,154	41.56
$45.05-$50.05		2,167,500	7.1 years	46.06		1,864,167	46.06
$25.03-$50.05		8,734,931	7.6 years	$ 39.37		5,822,196	$ 40.44

The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions used for grants in 2003, 2002 and 2001, respectively are: expected volatility of 29.68%, 30.24% and 28.22%, risk free interest rates of 2.86%, 2.82% and 4.40%, expected lives of 4.4, 4.0 years and 4.2 years. There was a dividend yield of 5.82% in 2003, 6.84% in 2002 and 5.18% in 2001.

Stock Compensation

Executive Officers

In June 1998, the Committee granted 150,000 shares of restricted common stock to a key executive. An additional 60,000 shares of restricted stock was granted to this executive in November 2001. These shares are subject to restrictions on transfer and subject to risk of forfeiture until earned by continued employment. The shares vest on a staggered schedule beginning on March 31, 2002 and become fully vested on March 31, 2007. As the shares vest, the earned compensation is recorded as compensation expense in the Consolidated Statements of Operations. The unearned compensation related to this restricted stock grant as of December 31, 2003 is approximately $2 million and is included in Stockholders’ Equity on the Consolidated Balance Sheets.

In addition, in July 2001, the Committee granted 100,000 shares of restricted common stock to another key executive. These shares are subject to restrictions on transfer and subject to risk of forfeiture until earned by continued employment. The shares vest at one-third per year and become fully vested on July 1, 2004. As the shares vest, the earned compensation is recorded as compensation expense in the Consolidated Statements of Operations. The unearned compensation related to this

188

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

restricted stock grant as of December 31, 2003 is approximately $1 million and is included in Stockholders’ Equity on the Consolidated Balance Sheets.

Outside Directors

During 2003, each director who was not an officer of PSEG or its subsidiaries and affiliates was paid an annual retainer of $40,000. Pursuant to the Compensation Plan for Outside Directors, a certain percentage, currently fifty percent, of the annual retainer is paid in PSEG Common Stock. In January 2003, PSEG amended the Compensation Plan for Outside Directors to provide for 100,000 shares of Common Stock to be used for awards to directors of PSEG who are not employees of PSEG or its subsidiaries.

PSEG also maintains a Stock Plan for Outside Directors pursuant to which directors of PSEG who are not employees of PSEG or its subsidiaries receive a restricted stock award, currently 800 shares per year, for each year of service as a director. The restrictions on the stock granted under the Stock Plan for Outside Directors provide that the shares are subject to forfeiture if the director leaves service at any time prior to the Annual Meeting of Stockholders following his or her 70th birthday. This restriction would be deemed to have been satisfied if the director’s service were terminated after a “change in control” as defined in the Plan or if the director were to die in office. PSEG also has the ability to waive this restriction for good cause shown. Restricted stock may not be sold or otherwise transferred prior to the lapse of the restrictions. Dividends on shares held subject to restrictions are paid directly to the director who has the right to vote the shares. The fair value of these shares is recorded as compensation expense in the Consolidated Statements of Operations.

Employee Stock Purchase Plan

PSEG maintains an employee stock purchase plan for all eligible employees of PSEG, PSE&G, Power, Energy Holdings and Services. Under the plan, shares of the common stock may be purchased at 95% of the fair market value through payroll deductions. Employees may purchase shares having a value not exceeding 10% of their base pay. During 2003, 2002 and 2001, employees purchased 102,532, 104,627 and 85,552 shares at an average price of $40.00, $36.41 and $44.02 per share, respectively. In June 2003, an additional 2,120,485 shares were registered for this plan. As of December 31, 2003, 2,065,521 shares were available for future issuance under this plan.

Note 23. Financial Information by Business Segment

Basis of Organization

PSEG, PSE&G, Power and Energy Holdings

The reportable segments were determined by management in accordance with SFAS No. 131, “Disclosures About Segments of an Enterprise and Related Information” (SFAS 131). These segments were determined based on how management measures the performance based on segment net income, as illustrated in the following table, and how it allocates resources to each business.

Power

Power earns revenues by selling energy, capacity and ancillary services on a wholesale basis under contract to power marketers and to load serving entities and by bidding the energy, capacity and ancillary services into the market. Power also enters into trading contracts for energy capacity, firm transmission rights, gas, emission allowances and other energy related contracts to optimize the value of its portfolio of generating assets and its electric and gas supply obligations.

189

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PSE&G

PSE&G earns revenue from its tariffs under which it provides electric transmission and electric and gas distribution services to residential, commercial and industrial customers in New Jersey. The rates charged for electric transmission are regulated by FERC while the rates charged for electric and gas distribution are regulated by the BPU. Revenues are also earned from several other activities such as sundry sales, the appliance service business, wholesale transmission services and other miscellaneous services.

Energy Holdings

Global

Global earns revenues from its investment in and operation of projects in the generation and distribution of energy, both domestically and internationally. Global has ownership interests in four distribution companies and has developed or acquired interests in electric generation facilities which sell energy, capacity and ancillary services to numerous customers. The generation plants sell power under long-term agreements as well as on a merchant basis while the distribution companies are rate-regulated enterprises.

Resources

Resources earns revenues from its passive investments in leveraged leases, limited partnerships, leveraged buyout funds and marketable securities. Over 80% of Resources’ investments are in energy industry related leveraged leases. DSM Investments were transferred to Resources on December 31, 2002 and earn revenues primarily from monthly payments from utilities, representing shared electricity savings from the installation of energy efficient equipment. Resources operates both domestically and internationally, however, revenues from all international investments are denominated in U.S. dollars.

Other

Energy Holdings’ other activities include amounts applicable to Energy Holdings (parent company), the HVAC/operating companies of Energy Technologies, which were reclassified into discontinued operations in 2002 and sold in 2003, and EGDC. The net losses primarily relate to financing and certain administrative and general costs at the Energy Holdings parent corporation.

Other

PSEG’s other activities include amounts applicable to PSEG (parent corporation), and intercompany eliminations, primarily relating to intercompany transactions between Power and PSE&G. No gains or losses are recorded on any intercompany transactions, rather, all intercompany transactions are at cost or, in the case of the BGS and Basic Gas Supply Service (BGSS) contracts between Power and PSE&G, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between Power and PSE&G, see Note 26. Related-Party Transactions. The net losses primarily relate to financing and certain administrative and general costs at the PSEG parent corporation.

190

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Information related to the segments of PSEG’s and its subsidiaries is detailed below:

	Power		PSE&G			Energy Holdings												Consolidated Total
	Power		PSE&G			Resources			Global			Other			Other			Consolidated Total
									(Millions)
For the Year Ended December 31, 2003:
Total Operating Revenues	$	5,605	$	6,740		$	238		$	476		$	11		$	(1,954	)	$	11,116
Depreciation and Amortization		102		372			5			38			1			9			527
Operating Income (Loss)		843		761			206			263			(5	)		11			2,079
Interest Income		7		(7	)		—			—			—			1			1
Net Interest Charges		114		390			96			119			3			114			836
Income (Loss) Before Income Taxes		800		376			109			158			(6	)		(121	)		1,316
Income Taxes		326		129			37			23			(1	)		(50	)		464
Income from Equity Method Investments		—		—			1			113			—			—			114
Income (Loss) From Continuing Operations		474		247			72			121			(4	)		(58	)		852
Loss from Discontinued Operations, net of tax		—		—			—			(23	)		(21	)		—			(44	)
Extraordinary Item, net of tax		—		(18	)		—			—			—			—			(18	)
Cumulative Effect of a Change in Accounting Principle, net of tax		370		—			—			—			—			—			370
Net Income (Loss)		844		229			72			98			(25	)		(58	)		1,160
Segment Earnings (Loss)		844		225			66			81			(25	)		(31	)		1,160
Gross Additions to Long-Lived Assets	$	655	$	411		$	1		$	306		$	—		$	(3	)	$	1,370
As of December 31, 2003:
Total Assets	$	7,728	$	13,136		$	3,277		$	3,814		$	366		$	(266	)	$	28,055
Investments in Equity Method Subsidiaries	$	—	$	—		$	94		$	1,472		$	4		$	—		$	1,570
For the Year Ended December 31, 2002:
Total Operating Revenues	$	3,636	$	5,919		$	248		$	352		$	9		$	(1,948	)	$	8,216
Depreciation and Amortization		108		409			5			22			1			20			565
Operating Income (Loss)		903		713			213			(300	)		(10	)		4			1,523
Interest Income		—		4			—			—			—			—			4
Net Interest Charges		122		406			98			118			1			74			819
Income (Loss) Before Income Taxes		781		320			122			(476	)		(11	)		(77	)		659
Income Taxes		313		115			38			(178	)		(4	)		(30	)		254
Income from Equity Method Investments		—		—			(1	)		120			—			—			119
Income (Loss) From Continuing Operations		468		205			84			(297	)		(7	)		(48	)		405
Loss from Discontinued Operation, net of tax		—		—			—			(9	)		(40	)		—			(49	)
Cumulative Effect of a Change in Accounting Principle, net of tax		—		—			—			(88	)		(33	)		—			(121	)
Net Income (Loss)		468		205			84			(395	)		(79	)		(48	)		235
Segment Earnings (Loss)		468		201			78			(411	)		(80	)		(21	)		235
Gross Additions to Long-Lived Assets	$	1,046	$	472		$	1		$	294		$	9		$	(35	)	$	1,787
As of December 31, 2002:
Total Assets	$	7,217	$	12,841		$	3,086		$	3,696		$	(27	)	$	(678	)	$	26,135
Investments in Equity Method Subsidiaries	$	—	$	—		$	118		$	1,210		$	4		$	—		$	1,332
For the Year Ended December 31, 2001:
Total Operating Revenues	$	2,464	$	6,091		$	240		$	204		$	10		$	(2,126	)	$	6,883
Depreciation and Amortization		95		370			4			11			—			15			495
Operating Income		787		691			211			232			(10	)		(3	)		1,908
Interest Income		—		88			—			—			—			(66	)		22
Net Interest Charges		143		458			100			81			2			(8	)		776
Income Before Income Taxes		644		324			111			135			(9	)		(66	)		1,139
Income Taxes		250		89			34			29			(5	)		(24	)		373
Income from Equity Method Investments		—		—			—			178			—			—			178
Income (Loss) From Continuing Operations		394		235			77			106			(4	)		(42	)		766
Income (Loss) from Discontinued Operations, net of tax		—		—			—			11			(23	)		—			(12	)
Cumulative Effect of a Change in Accounting Principle, net of tax		—		—			—			10			—			—			10
Net Income (Loss)		394		235			77			127			(27	)		(42	)		764
Segment Earnings (Loss)		394		230			71			110			(27	)		(14	)		764
Gross Additions to Long-Lived Assets	$	1,592	$	395		$	1		$	240		$	—		$	387		$	2,615

191

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Geographic information for PSEG is disclosed below. The foreign assets and operations noted below were made solely through Energy Holdings.

		Revenues(A)					Assets(B)

		December 31,					December 31,
		2003	2002		2001		2003		2002
		(Millions)
United States	$	10,565	$	7,736	$	6,516	$	23,457	$	22,068
Foreign Countries		551		480		367		4,598		4,067

Total	$	11,116	$	8,216	$	6,883	$	28,055	$	26,135

Identifiable assets in foreign countries include:
Chile	$	1,151	$	1,053
Netherlands		1,060		988
Peru		475		429
Tunisia		300		313
China		202		172
Oman		282		160
India		39		38
Poland		466		480
Brazil		164		108
Other		459		326


Total	$	4,598	$	4,067

__________

(A)

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.

(B)

Total assets are net of foreign currency translation adjustment of $(270) million (pre-tax) as of December 31, 2003 and $(427) million (pre-tax) as of December 31, 2002.

As of December 31, 2003, Global and Resources had approximately $3.2 billion and $1.4 billion, respectively of international assets. As of December 31, 2003, foreign assets represented 16% and 62% of PSEG’s and Energy Holdings’ consolidated assets, respectively, and the revenues related to those foreign assets contributed 5% and 76% to PSEG’s and Energy Holdings’ consolidated revenues, respectively, for the year ended December 31, 2003.

192

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 24. Property, Plant and Equipment and Jointly Owned Facilities

Information related to Property, Plant and Equipment as of December 31, 2003 and 2002 is detailed below:

	PSE&G		Power		Energy Holdings		Other		PSEG Consolidated
	(Millions)

2003
Generation:
Fossil Production	$	—	$	3,019	$	729	$	—		$	3,748
Nuclear Production		—		332		—		—			332
Nuclear Fuel in Service		—		532		—		—			532
Construction Work in Progress		—		2,020		17		—			2,037

Total Generation		—		5,903		746		—			6,649

Transmission and Distribution:
Electric Transmission		1,273		—		427		—			1,700
Electric Distribution		4,646		—		—		—			4,646
Gas Transmission		74		—		—		—			74
Gas Distribution		3,430		—		—		—			3,430
Construction Work in Progress		2		—		13		—			15
Plant Held for Future Use		20		—		—		—			20
Other		92		—		—		—			92

Total Transmission and Distribution		9,537		—		440		—			9,977

Other		256		77		176		271			780

Total	$	9,793	$	5,980	$	1,362	$	271		$	17,406


2002
Generation:
Fossil Production	$	—	$	2,467	$	358	$	—		$	2,825
Nuclear Production		—		215		—		—			215
Nuclear Fuel in Service		—		527		—		—			527
Construction Work in Progress		—		2,057		478		—			2,535

Total Generation		—		5,266		836		—			6,102

Transmission and Distribution:
Electric Transmission		1,243		—		—		—			1,243
Electric Distribution		4,446		—		320		—			4,766
Gas Transmission		74		—		—		—			74
Gas Distribution		3,271		—		—		—			3,271
Construction Work in Progress		20		—		27		—			47
Plant Held for Future Use		18		—		—		—			18
Other		91		—		—		—			91

Total Transmission and Distribution		9,163		—		347		—			9,510

Other		418		76		169		99			762

Total	$	9,581	$	5,342	$	1,352	$	99		$	16,374

PSE&G and Power

PSE&G and Power have ownership interests in and are responsible for providing their share of the necessary financing for the following jointly owned facilities. All amounts reflect the share

193

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

of PSE&G’s and Power’s jointly owned projects and the corresponding direct expenses are included in the Consolidated Statements of Operations as operating expenses.

	Ownership Interest			Plant	Accumulated Depreciation
	(Millions, where Applicable)
December 31, 2003
Power:
Coal Generating
Conemaugh	22.50	%	$	204	$	83
Keystone	22.84	%	$	167	$	62
Nuclear Generating
Peach Bottom	50.00	%	$	257	$	115
Salem	57.41	%	$	435	$	202
Nuclear Support Facilities	Various		$	41	$	16
Pumped Storage Facilities
Yards Creek	50.00	%	$	28	$	16
Merrill Creek Reservoir	13.91	%	$	2	$	—
PSE&G:
Transmission Facilities	Various		$	80	$	35
Linden SNG Plant	90.00	%	$	5	$	5
December 31, 2002
Power:
Coal Generating
Conemaugh	22.50	%	$	203	$	76
Keystone.	22.84	%	$	155	$	56
Nuclear Generating
Peach Bottom	50.00	%	$	225	$	105
Salem	57.41	%	$	324	$	177
Nuclear Support Facilities	Various		$	34	$	13
Pumped Storage Facilities
Yards Creek	50.00	%	$	28	$	16
Merrill Creek Reservoir	13.91	%	$	2	$	—
PSE&G:
Transmission Facilities	Various		$	80	$	33
Linden SNG Plant	90.00	%	$	5	$	5

Power

Power holds undivided ownership interests in the jointly owned facilities above, excluding related nuclear fuel and inventories. Power is entitled to shares of the generating capability and output of each unit equal to its respective ownership interests. Power also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. Power’s share of expenses for the jointly owned facilities is included in the appropriate expense category.

Power’s subsidiary, Nuclear, co-owns Salem and Peach Bottom with Exelon. Nuclear is the owner-operator of Salem and Exelon is the operator of Peach Bottom. A committee appointed by the co-owners reviews/approves major planning, financing and budgetary (capital and operating) decisions. Operating decisions within the above guidelines are made by the owner-operator.

Reliant Resources is a co-owner and the operator for Keystone Generating Station and Conemaugh Generating Station. A committee appointed by all co-owners makes all planning, financing and budgetary (capital and operating) decisions. Operating decisions within the above guidelines are made by Reliant Resources.

194

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Power is a co-owner in the Yards Creek Pumped Storage Generation Facility. First Energy is also a co-owner and the operator of this facility. First Energy submits separate capital and Operations and Maintenance budgets, subject to the approval of Power.

Power is a minority owner in the Merrill Creek Reservoir. Merrill Creek Reservoir is the owner-operator of this facility. The operator submits separate capital and Operations and Maintenance budgets, subject to the approval of the non-operating owners.

All owners receive revenues, Operations and Maintenance and capital allocations based on their ownership percentages. Each owner is responsible for any financing with respect to its pro rata share of capital expenditures.

Note 25. Selected Quarterly Data (Unaudited)

As discussed in Note 2. Restatement of Financial Statements, the Consolidated Financial Statements of PSEG and Energy Holdings have been restated. The unaudited quarterly data presented below and the Notes reflect the restated amounts for the current and prior periods.

The information shown below, in the opinion of PSEG, PSE&G, Power and Energy Holdings, includes all adjustments, consisting only of normal recurring accruals, necessary to fairly present such amounts.

	Calendar Quarter Ended
	March 31						June 30						September 30,						December 31,
	As Previously Reported			As Restated			As Previously Reported			As Restated			As Previously Reported			As Restated
	2003			2003			2003			2003			2003			2003			2003
	(Millions, where Applicable)
PSEG Consolidated:
Operating Revenues	$	3,364		$	3,288		$	2,419		$	2,401		$	2,805		$	2,763		$	2,664
Operating Income		695			693			420			418			534			525			443
Income from Continuing Operations		321			324			150			156			213			208			164
Loss from Discontinued Operations, including Loss on Disposal, net of tax		(15	)		(13	)		(2	)		(5	)		(3	)		(1	)		(25	)
Extraordinary Item, net of tax benefit		—			—			(18	)		(18	)		—			—			—
Cumulative Effect of a Change in Accounting Principle		370			370			—			—			—			—			—
Net Income		676			681			130			133			210			207			139
Earnings Per Share:
(Basic)
Income from Continuing Operations		1.42			1.44			0.67			0.69			0.94			0.92			0.70
Net Income		3.00			3.03			0.58			0.59			0.93			0.92			0.59
(Diluted)
Income from Continuing Operations		1.42			1.43			0.66			0.69			0.93			0.91			0.69
Net Income		3.00			3.01			0.57			0.59			0.92			0.91			0.59
Weighted Average Common Shares Outstanding:
Basic		225			225			226			226			226			226			235
Diluted		226			226			227			227			228			228			236

195

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Calendar Quarter Ended
	March 31,						June 30,						September 30,						December 31,
	As Previously Reported			As Restated			As Previously Reported			As Restated			As Previously Reported			As Restated			As Previously Reported			As Restated
	2002			2002			2002			2002			2002			2002			2002			2002
	(Millions, where Applicable)
PSEG Consolidated:
Operating Revenues	$	1,883		$	1,860		$	1,415		$	1,416		$	2,314		$	2,280		$	2,679		$	2,660
Operating Income (Loss)		541			531			(125	)		(123	)		529			529			588			586
Income (Loss) from Continuing Operations		181			172			(227	)		(228	)		207			205			255			256
Loss from Discontinued Operations, including Loss on Disposal, net of tax		(1	)		—			(37	)		(38	)		(3	)		(1	)		(10	)		(10	)
Cumulative Effect of a Change in Accounting Principle		(120	)		(121	)		—			—			—			—			—			—
Net Income (Loss)		60			51			(264	)		(266	)		204			204			245			246
Earnings Per Share:
(Basic)
Income (Loss) from Continuing Operations		0.88			0.83			(1.10	)		(1.11	)		1.00			0.99			1.18			1.19
Net Income (Loss)		0.29			0.25			(1.28	)		(1.29	)		0.99			0.99			1.14			1.14
(Diluted)
Income (Loss) from Continuing Operations		0.88			0.83			(1.10	)		(1.11	)		1.00			0.99			1.18			1.19
Net Income (Loss)		0.29			0.25			(1.28	)		(1.29	)		0.99			0.99			1.14			1.14
Weighted Average Common Shares Outstanding:
Basic		206			206			206			206			207			207			216			216
Diluted		206			206			207			207			207			207			216			216

	Calendar Quarter Ended
	March 31,				June 30,					September 30,				December 31,
	2003		2002		2003			2002		2003		2002		2003		2002
	(Millions)
PSE&G:
Operating Revenues	$	2,148	$	1,659	$	1,342		$	1,230	$	1,530	$	1,405	$	1,720	$	1,625
Operating Income		245		213		108			110		202		184		206		206
Income from Continuing Operations		101		68		22			8		69		56		55		73
Extraordinary Item, net of tax benefit		—		—		(18	)		—		—		—		—		—
Net Income		101		68		4			8		69		56		55		73
Earnings Available to PSEG		100		67		3			7		68		55		54		72

	Calendar Quarter Ended
	March 31,				June 30,				September 30,				December 31,
	2003		2002		2003		2002		2003		2002		2003		2002
		(Millions)
Power:
Operating Revenues	$	1,830	$	560	$	1,235	$	674	$	1,255	$	1,093	$	1,285	$	1,309
Operating Income		314		228		196		173		202		239		131		263
Income from Continuing Operations		177		120		109		83		110		121		78		144
Cumulative Effect of a Change in Accounting Principle		370		—		—		—		—		—		—		—
Net Income		547		120		109		83		110		121		78		144

196

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Calendar Quarter Ended
	March 31,						June 30,						September 30,					December 31,
	As Previously Reported			As Restated			As Previously Reported			As Restated			As Previously Reported			As Restated
	2003			2003			2003			2003			2003			2003		2003
	(Millions)
Energy Holdings:
Operating Revenues	$	209		$	190		$	188		$	171		$	211		$	178	$	186
Operating Income		134			132			112			110			128			118		104
Income Before Discontinued Operations and Cumulative Effect of a Change in Accounting Principle		59			62			33			39			48			43		45
Loss From Discontinued Operations, including Loss on Disposal, net of tax benefit		(15	)		(14	)		(2	)		(5	)		(3	)		—		(25	)
Net Income		44			48			31			34			45			43		20
Earnings Available to PSEG		38			42			26			28			39			38		14

	Calendar Quarter Ended
	March 31,						June 30,						September 30,					December 31,
	As Previously Reported			As Restated			As Previously Reported			As Restated			As Previously Reported			As Restated		As Previously Reported			As Restated
	2002			2002			2002			2002			2002			2002		2002			2002
	(Millions, where Applicable)
Energy Holdings:
Operating Revenues	$	136		$	128		$	133		$	133		$	187		$	163	$	205		$	185
Operating Income (Loss)		101			90			(411	)		(410	)		105			108		112			115
Income (Loss) Before Discontinued Operations and Cumulative Effect of a Change in Accounting Principle		6			(4	)		(310	)		(310	)		43			40		52			54
Income (Loss) From Discontinued Operations, including Loss on Disposal, net of tax benefit		(1	)		1			(37	)		(39	)		(3	)		—		(10	)		(11	)
Cumulative Effect of a Change in Accounting Principle		(120	)		(121	)		—			—			—			—		—			—
Net (Loss) Income		(115	)		(124	)		(347	)		(349	)		40			40		42			43
Income (Loss) Earnings Available to PSEG		(121	)		(129	)		(352	)		(355	)		34			34		36			37

Note 26. Related-Party Transactions

The majority of the following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP.

BGSS and BGS Contracts

PSE&G and Power

Effective May 1, 2002, PSE&G transferred its gas supply contracts and gas inventory requirements to Power. On the same date, PSE&G entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements.

For the years ended December 31, 2003 and 2002, Power billed PSE&G approximately $1.8 billion and $703 million, respectively, for BGSS. As of December 31, 2003 and 2002, PSE&G’s payable to Power related to the BGSS contract was approximately $268 million and $241 million, respectively.

Power billed PSE&G for the energy and capacity provided to meet its BGS requirements through July 31, 2002. Power also billed PSE&G for the MTC through July 31, 2003. For the years ended December 31, 2003 and 2002, Power billed PSE&G approximately $111 million and $1.2 billion, respectively, for the MTC and BGS. As of December 31, 2003, PSE&G did not have a payable to Power

197

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

related to these costs. As of December 31, 2002, PSE&G’s payable to Power relating to these costs was approximately $2 million.

Power was a participant in the BGS auction held in February 2003. As a result of this participation, Power entered into contracts for a ten-month period beginning August 1, 2003, to supply hourly priced energy, capacity and ancillary services to PSE&G, which in turn distributes these services to certain large industrial and commercial customers. For the year ended December 31, 2003, Power charged PSE&G approximately $30 million under this agreement. As of December 31, 2003, PSE&G’s payable to Power was approximately $9 million.

For the year ended December 31, 2002 and 2001, Power paid PSE&G for energy and capacity at the market price of approximately $77 million and $158 million, respectively, which PSE&G purchased under various NUG contracts at costs above market prices.

Affiliate Loans

PSEG and Power

As of December 31, 2003, Power had a receivable from PSEG of approximately $77 million for short-term funding needs. Interest income relating to this was immaterial. As of December 31, 2002, Power had a payable to PSEG of approximately $239 million for short-term funding needs. Interest expense related to short-term borrowings from PSEG was $2 million and $4 million for the year ended December 31, 2003 and 2002, respectively.

PSEG and Energy Holdings

As of December 31, 2003 and December 31, 2002, Energy Holdings had a note receivable due from PSEG of $300 million and $62 million, respectively, reflecting the investment of its excess cash with PSEG. Interest Income related to these borrowings were immaterial.

Equipment Purchases and Sales

Power and Energy Holdings

Global purchased equipment from Power totaling $47 million in 2002. This amount was sold at book value, thus no gain or loss was recorded on this transaction.

Energy Holdings

Operation and Maintenance and Development Fees

Global provides operating, maintenance and other services to and receives management and guaranty fees from various joint ventures and partnerships in which it is an investor. Fees related to the development and construction of certain projects are deferred and recognized when earned. Income from these services of $6 million, $3 million and $3 million were included in Operating Revenues in the Consolidated Statements of Operations for the years ended December 31, 2003, 2002, and 2001, respectively.

Affiliate Payables due to PSEG from Energy Technologies

As of December 31, 2002, Energy Technologies had recorded affiliate payable due to PSEG of $12 million. The amount was recorded as a component of Current Liabilities of Discontinued Operations on the Consolidated Balance Sheets. Energy Technologies repaid this balance during the first quarter of 2003.

198

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Loans to Texas Independent Energy, L.P. (TIE)

Global and its partner, TECO Energy, Inc. (Teco), own and operate two electric generation facilities in Texas through TIE, a 50/50 joint venture. As of December 31, 2003, Global had outstanding approximately $69 million of loans to TIE that earn interest at an annual rate of 12% and that are scheduled to be repaid in quarterly installments through 2012. For the year ended December 31, 2003 and 2002, Global recorded approximately $11 million and $10 million, respectively, of interest income related to this loan.

In March 2003, Global funded $14 million of convertible preferred equity to the two TIE projects as part of its negotiations with project lenders to amend the projects’ credit agreements. The convertible preferred equity has a 15% coupon and is convertible at Global’s option into an approximate 13% equity interest in TIE if not repaid in full by June 2004. This 13% equity interest is derived from the dilution of all existing general partners including Global and would give Global a net increase in ownership of approximately 7%.

Debt Issuance at GWF Energy

In September 2003, GWF Energy LLC (GWF Energy) issued $226 million of 6.131% senior secured notes to third parties that mature on December 30, 2011. The note proceeds were used by GWF Energy to repay a $45 million bank loan that matured on September 30, 2003, and to make distributions to its members and for general corporate purposes. GWF Energy made cash distributions to Global of approximately $137 million.

Transfer of Asset Management Group (AMG) from Energy Technologies to Resources

As of December 31, 2002, Energy Technologies contributed its equity investment in the capital stock of AMG, which includes various DSM investments to Resources. The aggregate book value, which approximated fair value, of the stock contributed was $42 million.

Changes in Capitalization

PSE&G

On January 21, 2003, PSEG contributed $170 million of equity to PSE&G. PSE&G paid a common stock dividend of approximately $200 million and $305 million to PSEG in 2003 and 2002, respectively.

Power

PSEG contributed capital of approximately $150 million and $200 million to Power during 2003 and 2002, respectively.

Services

PSE&G, Power and Energy Holdings

Services provides and bills administrative services to PSE&G, Power and Energy Holdings as follows:

	Services billed for the Years Ended December 31,				Payable to Services as of December 31,
	2003		2002		2003		2002
	(Millions)
PSE&G	$	201	$	193	$	21	$	15
Power	$	124	$	149	$	14	$	4
Energy Holdings	$	16	$	22	$	2	$	3

199

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

These transactions were properly recognized on each company’s stand-alone financial statements and were eliminated when preparing PSEG’s Consolidated Financial Statements. PSEG, PSE&G, Power and Energy Holdings believe that the costs of services provided by Services approximates market value for such services.

On July 31, 2003, the BPU approved the sale by PSE&G to Services, of certain non-operating assets related to PSE&G’s transmission and distribution operations with a net book value of approximately $53 million, together with associated rights and liabilities. The sale was completed on September 30, 2003 at net book value.

Tax Sharing Agreement

PSEG, PSE&G, Power and Energy Holdings

PSEG files a consolidated Federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits. As of December 31, 2003, PSE&G, Power and Energy Holdings had a net receivable/(payable) from/to PSEG of approximately $(105) million, $(17) million and $173 million, respectively. As of December 31, 2002, PSE&G, Power and Energy Holdings has a net payable to PSEG of approximately $113 million, $1 million and $71 million, respectively.

Note 27. Guarantees of Debt

Power has $500 million of 6.88% Senior Notes maturing in 2006, $800 million of 7.75% Senior Notes maturing in 2011, $600 million of 6.95% Senior Notes maturing in 2012, $300 million of 5.50% Senior Notes maturing in 2015 and $500 million of 8.63% Senior Notes maturing in 2031. Power also has $66 million of 5.00% Pollution Control Notes maturing in 2012, $14 million of 5.50% Pollution Control Notes maturing in 2020, $19 million of 5.85% Pollution Control Notes maturing in 2027 and $25 million of 5.75% Pollution Control Notes maturing in 2031. Each series of these Senior Notes and Pollution Control Notes is fully and unconditionally and jointly and severally guaranteed by Fossil, Nuclear and ER&T. The following table presents condensed financial information for the guarantor subsidiaries as well as Power’s non-guarantor subsidiaries as of December 31, 2003 and 2002:

	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
							(Millions)
For the Year Ended December 31, 2003:
Revenues	$	—		$	6,429		$	134		$	(958	)	$	5,605
Operating Expenses		—			5,627			93			(958	)		4,762
Operating Income		—			802			41			—			843
Equity Earnings in Subsidiaries		928			21			—			(949	)		—
Other Income		14			155			116			(136	)		149
Other Deductions		—			(78	)		—			—			(78	)
Interest Expense		(159	)		(81	)		(11	)		137			(114	)
Income Taxes		61			(327	)		(60	)		—			(326	)
Cumulative Change in Accounting Principle		—			366			4			—			370
Net Income	$	844		$	858		$	90		$	(948	)	$	844

200

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

		Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
								(Millions)
As of December 31, 2003:
Current Assets	$	3,376		$	1,910		$	122		$	(3,599	)	$	1,809
Property, Plant and Equipment, net		46			2,723			1,812			—			4,581
Investment in Subsidiaries		3,330			733			—			(4,063	)		—
Noncurrent Assets		456			1,115			69			(302	)		1,338
Total Assets	$	7,208		$	6,481		$	2,003		$	(7,964	)	$	7,728

Current Liabilities	$	1,742		$	2,839		$	168		$	(3,670	)	$	1,079
Noncurrent Liabilities		44			373			11			—			428
Note Payable—Affiliated Company		—			—			300			(300	)		—
Long-Term Debt		2,816			—			800			—			3,616
Member’s Equity		2,606			3,269			724			(3,994	)		2,605
Total Liabilities and Member’s Equity	$	7,208		$	6,481		$	2,003		$	(7,964	)	$	7,728
For the Year Ended December 31, 2003:
Net Cash Provided By (Used In) Operating Activities	$	(1,647	)	$	(132	)	$	(88	)	$	2,447		$	580
Net Cash Provided By (Used In) Investing Activities	$	1,349		$	440		$	(253	)	$	(2,285	)	$	(749	)
Net Cash Provided By (Used In) Financing Activities	$	54		$	(62	)	$	379		$	(162	)	$	209
For the Year Ended December 31, 2002:
Revenues	$	2		$	4,499		$	42		$	(907	)	$	3,636
Operating Expenses		—			3,599			41			(907	)		2,733
Operating Income		2			900			1			—			903
Equity Earnings in Subsidiaries		574			(3	)		—			(571	)		—
Other Income		—			9			—			(8	)		1
Other Deductions		—			—			—			(1	)		(1	)
Interest Expense		(180	)		(69)			118			9			(122	)
Income Taxes		72			(343)			(42	)		—			(313	)
Net Income (Loss)	$	468		$	494		$	77		$	(571	)	$	468
As of December 31, 2002:
Current Assets	$	1,329		$	2,292		$	141		$	(2,188	)	$	1,574
Property, Plant and Equipment, net		42			2,423			1,572			3			4,040
Investment in Subsidiaries		3,028			377			—			(3,405	)		—
Noncurrent Assets		230			1,349			1,313			(1,289	)		1,603
Total Assets	$	4,629		$	6,441		$	3,026		$	(6,879	)	$	7,217
Current Liabilities	$	367		$	2,604		$	499		$	(2,158	)	$	1,312
Noncurrent Liabilities		209			990			29			(78	)		1,150
Note Payable—Affiliated Company		97			1,150			—			(1,247	)		—
Long-Term Debt		2,516			—			800			—			3,316
Member’s Equity		1,440			1,697			1,698			(3,396	)		1,439
Total Liabilities and Member’s Equity	$	4,629		$	6,441		$	3,026		$	(6,879	)	$	7,217
For the Year Ended December 31, 2002:
Net Cash Provided By (Used In) Operating Activities	$	(182	)	$	738		$	298		$	(437	)	$	417
Net Cash Provided By (Used In) Investing Activities	$	(695	)	$	(1,051	)	$	(625	)	$	1,072		$	(1,299	)
Net Cash Provided By (Used In) Financing Activities	$	877		$	332		$	328		$	(638	)	$	899
For the Year Ended December 31, 2001:
Revenues	$	2		$	3,309		$	22		$	(869	)	$	2,464
Operating Expenses		—			2,524			22			(869	)		1,677
Operating Income (Loss)		2			785			—			—			787
Equity Earnings in Subsidiaries		500			(9	)		—			(491	)		—
Other Income (Loss)		—			10			—			(10	)		—
Interest Expense		(180	)		(79	)		108			8			(143	)
Income Taxes		72			(286	)		(38)			2			(250	)
Net Income (Loss)	$	394		$	421		$	70		$	(491	)	$	394
For the Year Ended December 31, 2001:
Net Cash Provided By (Used In) Operating Activities	$	313		$	1,456		$	(989	)	$	(205	)	$	575
Net Cash Provided By (Used In) Investing Activities	$	41		$	(2,394	)	$	(947	)	$	1,687		$	(1,613	)
Net Cash Provided By (Used In) Financing Activities	$	329		$	928		$	1,936		$	(2,166	)	$	1,027

201

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

PSEG

None.

PSE&G

None.

Power

None.

Energy Holdings

None.

202

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

PSEG, PSE&G, Power and Energy Holdings

PSEG, PSE&G, Power and Energy Holdings have established and maintain disclosure controls and procedures which are designed to provide reasonable assurance that material information relating to each company, including their respective consolidated subsidiaries, is made known to the Chief Executive Officer and Chief Financial Officer of each company by others within those entities. PSEG, PSE&G, Power and Energy Holdings have established a Disclosure Committee, which is made up of several key management employees and reports directly to the Chief Financial Officer and Chief Executive Officer of each company, to monitor and evaluate these disclosure controls and procedures. The Chief Financial Officer and Chief Executive Officer of each company have evaluated the effectiveness of the disclosure controls and procedures and, based on this evaluation, it was concluded that the disclosure controls and procedures for the financial statements prepared as of and for the year ended December 31, 2003 were effective in providing reasonable assurance during the period covered in these annual reports.

Internal Controls

PSEG, PSE&G, Power and Energy Holdings

In preparation for the implementation of the detailed internal control documentation and testing required by the Sarbanes-Oxley Act, PSEG, PSE&G, Power and Energy Holdings have been performing a review of internal controls related to each of their accounting and reporting processes. As a result of this review, PSEG, PSE&G, Power and Energy Holdings have made several enhancements in internal controls, including the centralization of certain operations and related accounting functions and the formalization and documentation of internal control processes and procedures.

PSEG and Energy Holdings

As a result of a Management review by Energy Holdings of the accounting for its investments at year end 2003, it was determined that the foreign currency translation impacts for RGE, one of Energy Holdings’ investments, were incorrectly recorded. Management at Energy Holdings has reviewed the accounting for each of its investments and has determined that this issue was isolated to the accounting for RGE. As a result of this error, and as discussed in further detail in Note 2. Restatement of Financial Statements of the Notes to Consolidated Financial Statements, Energy Holdings and PSEG have restated their 2003 quarterly information and 2002 and 2001 financial statements. Separately, also as part of the year end 2003 review, it was determined that there were internal control deficiencies related to the recording and review of the sale of Energy Holdings’ indirect ownership interest in CPC, which resulted in an increase in the loss recognized on the sale. As a result of an internal review of these two matters, Energy Holdings and PSEG have determined that certain significant deficiencies in their respective internal control processes existed. Specifically, such internal control deficiencies related to the design and operational effectiveness of performing investment reconciliations of foreign subsidiaries, review procedures and resource constraints. Management at Energy Holdings and PSEG have reviewed the existing internal control processes, taken various corrective actions to address each of these deficiencies and reviewed these matters with the external auditors and the Audit Committee.

PSEG, PSE&G, Power and Energy Holdings

As a result of the corrective actions taken to address the control deficiencies in internal controls at Energy Holdings and PSEG cited above, as well as the general control enhancements at PSEG, PSE&G, Power and Energy Holdings, each discussed above, there were certain significant changes in internal controls made during the most recent fiscal quarter and during the first quarter of 2004.

203

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS

Executive Officers

The Executive Officers of each of PSEG, PSE&G, Power and Energy Holdings, respectively, are set forth below, as indicated for each individual.

Name	Age as of December 31, 2003	Office	Effective Date First Elected to Present Position

E. James Ferland(1)(2)(3)(4)	61	Chairman of the Board, President and Chief Executive Officer (PSEG)	July 1986 to present
		Chairman of the Board and Chief Executive Officer (PSE&G)	July 1986 to present
		Chairman of the Board and Chief Executive Officer (Energy Holdings)	June 1989 to present
		Chairman of the Board and Chief Executive Officer (Power)	June 1999 to present
		Chairman of the Board and Chief Executive Officer (Services)	November 1999 to present

Thomas M. O’Flynn(1)(3)(4)	43	Executive Vice President and Chief Financial Officer (PSEG)	July 2001 to present
		Executive Vice President — Finance (Services)	July 2001 to present
		Executive Vice President and Chief Financial Officer (Energy Holdings)	August 2002 to present
		Executive Vice President and Chief Financial Officer (Power)	February 2002 to present
		Managing Director — Global Power and Utility Investment Banking Division Group (Morgan Stanley)	December 1997 to May 2001

Robert J. Dougherty, Jr.(1)(4)	52	President (Global)	August 2003 to present
		President and Chief Operating Officer (Energy Holdings)	January 1997 to present
		Vice President (PSEG)	March 1995 to present

Ralph Izzo(1)(2)	46	President and Chief Operating Officer (PSE&G)	October 2003 to present
		Vice President — Utility Operations (PSE&G)	June 2002 to October 2003
		Vice President — Special Projects (Services)	September 2001 to June 2002
		Vice President — Appliance Service (PSE&G)	April 2000 to September 2001
		Vice President — Corporate Planning (PSEG)	March 1998 to April 2000

R. Edwin Selover(1)(2)	58	Senior Vice President and General Counsel (PSEG)	April 2002 to present
		Vice President and General Counsel (PSEG)	April 1988 to April 2002
		Senior Vice President and General Counsel (PSE&G)	January 1988 to present
		Senior Vice President and General Counsel (Services)	November 1999 to present

Patricia A. Rado(1)(2)(3)	61	Vice President and Controller (PSEG)	April 1993 to present
		Vice President and Controller (PSE&G)	April 1993 to present

204

		Vice President and Controller (Power)	June 1999 to present
		Vice President and Controller (Services)	November 1999 to present

Robert E. Busch(1)(2)	57	President & Chief Operating Officer (Services)	April 2001 to present
		Senior Vice President-Finance and Chief Financial Officer (Services)	November 1999 to April 2001
		Senior Vice President and Chief Financial Officer (PSE&G)	March 1998 to present

Harold W. Borden Jr.(3)	59	Vice President and General Counsel (Power)	June 1999 to present
		Vice President — Law (PSE&G)	April 1995 to July 1999

Morton A. Plawner(3)	56	Treasurer (PSEG)	January 1998 to present
		Vice President and Treasurer (PSE&G)	January 1998 to present
		Vice President and Treasurer (Power)	June 1999 to present

Frank Cassidy(1)(3)	57	President and Chief Operating Officer (Power)	July 1999 to present
		President (Energy Technologies)	November 1996 to June 1999
Steven R. Teitelman(3)	57	President (ER&T)	June 1999 to present
		Vice President — Energy Resources and Trading (PSE&G)	August 1997 to August 2002

Roy A. Anderson(3)	55	President and Chief Nuclear Officer (Nuclear)	March 2003 to present
		Executive Vice President and Chief Nuclear Officer (Nuclear Management Company)	May 2001 to March 2003
		Senior Vice President, Chief Nuclear Officer, Senior Vice President — Energy Supply (Florida Power Corporation)	January 1997 to January 2001

Michael J. Thomson(3)	45	President (Fossil)	August 2003 to present
		President (Global)	January 1997 to July 2003

Eileen A. Moran(4)	49	President (Resources)	May 1990 to present
		President (EGDC)	January 1997 to present

Miriam E. Gilligan(4)	52	Vice President — Finance and Treasurer (Energy Holdings)	December 2001 to present
		Vice President (Services)	December 2001 to present
		Treasurer (Energy Holdings)	1997 to December 2001

Derek M. DiRisio(4)	39	Vice President and Controller (Energy Holdings)	June 1998 to present
		Director — Accounting Services (PSEG)	November 1997 to June 1998

(1)

Executive Officer of PSEG

(2)

Executive Officer of PSE&G

(3)

Executive Officer of Power

(4)

Executive Officer of Energy Holdings

Directors

PSEG

The information required by Item 10 of Form 10-K with respect to (i) present directors of PSEG who are nominees for election as directors at PSEG’s Annual Meeting of Stockholders to be held on April 20, 2004, and directors whose terms will continue beyond the meeting, and (ii) compliance with

205

Section 16(a) of the Securities Exchange Act of 1934, as amended, is set forth under the headings “Election of Directors” and Section 16(a) “Beneficial Ownership Reporting Compliance” in PSEG’s definitive Proxy Statement for such Annual Meeting of Stockholders, which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about March 10, 2004 and which information set forth under said heading is incorporated herein by this reference thereto.

PSE&G

CAROLINE DORSA has been a director of PSE&G since February 2003. Age 44. Director of PSEG. Has been Vice President and Treasurer of Merck & Co., Inc., Whitehouse Station, New Jersey (discovers, develops, manufactures and markets human and animal health products) since December 1996. Was Treasurer from January 1994 to November 1996 and Executive Director of the U.S. Human Health Marketing subsidiary of Merck & Co., Inc. from June 1992 to January 1994. Director of Readington Holdings, Inc.

E. JAMES FERLAND has been a director of PSE&G since July 1986. Age 61. For additional information, see Executive Officers table above.

ALBERT R. GAMPER, JR. has been a director of PSE&G since December 2000. Age 61. Director of PSEG. Has been Chairman of the Board and Chief Executive Officer of The CIT Group, Inc., Livingston, New Jersey (commercial finance company) since September 2003. Was Chairman of the Board, President and Chief Executive Officer from June 2002 to September 2003. Was President and Chief Executive Officer from February 2002 to June 2002. Was President and Chief Executive Officer of Tyco Capital Corporation from June 2001 to February 2002. Was Chairman of the Board, President and Chief Executive Officer of The CIT Group, Inc., from January 2000 to June 2001. Was President and Chief Executive Officer of The CIT Group, Inc. from December 1989 to December 1999.

CONRAD K. HARPER has been a director of PSE&G since May 1997. Age 63. Director of PSEG. Of counsel to the law firm of Simpson Thacher & Bartlett LLP, New York, New York since January 2003. Was a partner from October 1996 to December 2002 and from October 1974 to May 1993. Was Legal Adviser, US Department of State from May 1993 to June 1996. Director of New York Life Insurance Company.

Power

ROBERT E. BUSCH has been a director of Power since December 2000. For additional information, see Executive Officers table above.

FRANK CASSIDY has been a director of Power since July 1999. For additional information, see Executive Officers table above.

ROBERT J. DOUGHERTY, JR. has been a director of Power since July 1999. For additional information, see Executive Officers table above.

E. JAMES FERLAND has been a director of Power since July 1999. For additional information, see Executive Officers table above.

THOMAS M. O’FLYNN has been a director of Power since July 2001. For additional information, see Executive Officers table above.

R. EDWIN SELOVER has been a director of Power since July 1999. For additional information, see Executive Officers table above.

Energy Holdings

ROBERT E. BUSCH has been a director of Energy Holdings since December 2000. For additional information, see Executive Officers table above.

FRANK CASSIDY has been a director of Energy Holdings since January 2000. For additional information, see Executive Officers table above.

ROBERT J. DOUGHERTY, JR. has been a director of Energy Holdings since January 2000. For additional information, see Executive Officers table above.

206

E. JAMES FERLAND has been a director of Energy Holdings since June 1989. For additional information, see Executive Officers table above.

THOMAS M. O’FLYNN has been a Director of Energy Holdings since July 2001. For additional information, see Executive Officers table above.

R. EDWIN SELOVER has been a Director of Energy Holdings since January 2000. For additional information, see Executive Officers table above.

PSEG, PSE&G, Power and Energy Holdings

Code of Ethics

PSEG has adopted a code of ethics entitled Standards of Integrity (Standards) applicable to it and its subsidiaries, including PSE&G, Power and Energy Holdings. The Standards are an integral part of PSEG’s business conduct compliance program and embody the commitment of PSEG and its subsidiary companies to conduct operations in accordance with the highest legal and ethical standards. The Standards apply to all PSEG directors, employees (including PSEG’s, PSE&G’s, Power’s and Energy Holdings’ respective principal executive officer, principal financial officer, principal accounting officer or Controller and persons performing similar functions), contractors and consultants, worldwide. Each is responsible for understanding and complying with the Standards.

The Standards establish a set of common expectations for behavior that each employee must adhere to in dealings with investors, customers, fellow employees, competitors, vendors, government officials, the media and all others who may associate their words and actions with PSEG. They have been developed to provide reasonable assurance that, in conducting PSEG’s business, employees behave ethically and in accordance with the law and do not take advantage of investors, regulators or customers through manipulation, abuse of confidential information or misrepresentation of material facts.

Any amendment (other than technical, administrative or non-substantive) to or a waiver from the Standards that applies to PSEG’s, PSE&G’s, Power’s or Energy Holdings’ principal executive officer, principal financial officer, principal accounting officer or Controller, or persons performing similar functions and that relates to any element enumerated by the SEC, will be posted on PSEG’s website, www.pseg.com/investor/governance.

ITEM 11. EXECUTIVE COMPENSATION

PSEG

The information required by Item 11 of Form 10-K is set forth under the heading ‘Executive Compensation’ in PSEG’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held April 20, 2004 which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about March 10, 2004 and such information set forth under such heading is incorporated herein by this reference thereto.

PSE&G

Information regarding the compensation of the Chief Executive Officer and the four most highly compensated executive officers of PSE&G as of December 31, 2003 is set forth below. Amounts shown were paid or awarded for all services rendered to PSEG and its subsidiaries and affiliates including PSE&G.

207

Summary Compensation Table

							Long Term Compensation

			Annual Compensation				Awards						Payouts

Name and Principal Position	Year		Salary $		Bonus/Annual Incentive Award ($)(1)		Restricted Stock ($)			Options (#)(2)			LTIP Payouts ($)(3)		All Other Compensation ($)(4)

E. James Ferland		2003		1,006,227		1,440,000		0			0	(5)		0		6,002
Chairman of the Board and Chief Executive Officer		2002		971,358		713,000		0			350,000			0		6,002
		2001		962,525		1,023,000		2,248,000	(6)		350,000			400,800		51,152

R. Edwin Selover		2003		403,487		287,000		0			0	(5)		0		8,004
Senior Vice President and General Counsel		2002		388,544		125,500		0			80,000			0		8,004
		2001		367,852		225,000		0			70,000			100,200		15,597

Robert E. Busch		2003		370,610		279,000		0			0	(5)		0		8,003
Senior Vice President and Chief Financial Officer		2002		358,654		153,200		0			65,000			0		8,006
		2001		335,482		262,500		0			315,000			60,120		6,803

Ralph Izzo(7)		2003		304,051		282,800		0			250,000			0		8,003
President and Chief Operating Officer		2002		273,973		79,800		0			35,000			0		5,500
		2001		239,104		99,000		0			35,000			24,048		5,250

Patricia A. Rado		2003		227,148		102,400		0			0	(5)		0		5,509
Vice President and Controller		2002		219,178		53,600		0			25,000			0		5,593
		2001		209,835		94,500		0			25,000			24,048		6,449

(1)

Amounts awarded were earned under the Restated and Amended Management Incentive Compensation Plan and determined and paid in the following year based on individual performance and financial and operating performance of PSEG and PSE&G, including comparison to other companies.

(2)

All grants of options to purchase shares of PSEG Common Stock were non-qualified options made under the 2001Long-Term Incentive Plan (2001 LTIP). All options granted were non-tandem. Non-tandem grants are made without performance units and dividend equivalents.

(3)

Amount paid in proportion to options exercised, if any, based on value of previously granted performance units and dividend equivalents under the 1989 LTIP, each as measured during three-year period ending the year prior to the year in which payment is made. Under the 1989 LTIP, tandem grants were made with an equal number of performance units and dividend equivalents which may provide cash payments, dependent upon future financial performance of PSEG in comparison to other companies and dividend payments by PSEG, to assist recipients in exercising options granted. The tandem grant was made at the beginning of a three-year performance period and cash payment of the value of such performance units and dividend equivalents is made following such period in proportion to the options, if any, exercised at such time.

(4)

Includes employer contribution to the PSEG Thrift and Tax-Deferred Savings Plan:

	Ferland ($)		Selover ($)		Busch ($)		Izzo ($)		Rado ($)

2003		6,002		8,004		8,003		8,003		5,509
2002		6,002		8,004		8,006		8,001		5,593
2001		5,102		5,104		6,803		6,803		6,450

In addition, 2001 amounts include $46,050 for Mr. Ferland; $10,493 for Mr. Selover; and $1,093 for Mrs. Rado, respectively, representing earnings credited on compensation deferred under PSE&G’s Deferred Compensation Plan in excess of 120% of the applicable Federal long-term interest rate as prescribed under Section 1274(d) of the Internal Revenue Code.

(5)

No regular annual grants were made under the 2001 LTIP because, as noted below in “Option Grants in Last Fiscal Year (2003),” PSEG stockholders are being asked to approve the 2004 LTIP and the PSEG Organization and Compensation Committee expects to make grants with respect to 2003 following such vote.

(6)

Value as of original grant date, based on the closing price of $40.80 on the New York Stock Exchange on November 20, 2001, with respect to an award to Mr. Ferland of 60,000 shares of restricted stock, with 30,000 shares vesting in 2006 and 30,000 shares vesting in 2007. Dividends on the entire grant are paid in cash from the date of award.

(7)

Mr. Izzo was elected to his present position effective October 18, 2003.

208

Option Grants in Last Fiscal Year (2003)

	Option Grants in Last Fiscal Year

Name	Number of Securities Underlying Options Granted(1)		% of Total Options Granted to Employees in Fiscal Year		Exercise or Base Price ($/Sh)		Expiration Date		Grant Date Present Value ($)(2)


E. James Ferland		—		—		—		—		—
R. Edwin Selover		—		—		—		—		—
Robert E. Busch		—		—		—		—		—
Ralph Izzo(3)		250,000		35.4		40.77		10/18/13		1,577,500
Patricia A. Rado		—		—		—		—		—

(1)

At its Annual Meeting to be held on April 20, 2004, PSEG is requesting stockholders to approve the 2004 Long-Term Incentive Compensation Plan (2004 LTIP), a new long-term incentive compensation plan for employees. Because of this requested approval, the Organization and Compensation Committee of the Board of Directors did not make any annual long-term incentive grants to any of the named executive officers or any other officers in December 2003, pending the outcome of the stockholder vote at the 2004 Annual Meeting. If stockholders approve the 2004 LTIP, the Organization and Compensation Committee intends to make long-term incentive grants of stock options, performance shares and/or restricted stock to officers, including the executive officers, under the 2004 LTIP in an amount designed to reflect the median of the competitive market for energy services companies. If stockholders approve the 2004 LTIP, it will replace the existing 2001 LTIP approved by stockholders in 2002, and the 1989 LTIP (Prior Plans). If stockholders do not approve the 2004 LTIP, the Organization and Compensation Committee intends to continue to make grants of stock options under the Prior Plans.

(2)

Determined using the Black-Scholes model, incorporating the following material assumptions and adjustments: (a) exercise price of $40.77, equal to the fair market value of the underlying PSEG Common Stock on the date of grant; (b) an option term of ten years on all grants; (c) interest rate of 4.29% that represent the interest rates on U.S. Treasury securities on the date of grant with a maturity date corresponding to that of the option terms; (d) volatility of 29.49% calculated using daily PSEG Common Stock prices for the one-year period prior to the grant date; (e) dividend yield of 5.30% and (f) reductions of approximately 11.38% to reflect the probability of forfeiture due to termination prior to vesting, and approximately 9.53% to reflect the probability of a shortened option term due to termination of employment prior to the option expiration dates. Actual values which may be realized, if any, upon any exercise of such options, will be based on the market price of PSEG Common Stock at the time of any such exercise and thus are dependent upon future performance of PSEG Common Stock. There is no assurance that any such value realized will be at or near the value estimated by the Black-Scholes model utilized.

(3)

Granted under the 2001 LTIP with exercisability commencing October 18, 2004, October 18, 2005 and October 18, 2006, respectively, with respect to one-third of the options at each such date.

209

Aggregated Option Exercises in Last Fiscal Year (2003) and
Fiscal Year End Option Values (12/31/03)

					Number of Unexercised Options at FY-End(#)(1)				Value of Unexercised In-the-Money Options At FY-End($)(3)

Name	Shares Acquired on Exercise (#)(1)		Value Realized ($)(2)		Exercisable (#)		Unexercisable (#)		Exercisable ($)(3)		Unexercisable ($)(3)


E. James Ferland		0		0		1,115,000		350,000		6,539,836		3,238,664
R. Edwin Selover		0		0		183,334		76,666		1,098,993		730,195
Robert E. Busch		0		0		245,000		215,000		733,074		601,464
Ralph Izzo		0		0		83,000		285,000		410,811		1,081,364
Patricia A. Rado		0		0		63,001		24,999		349,451		231,324

(1)

Reflects any options granted and/or exercised through year-end (12/31/03).

(2)

Represents difference between exercise price and market price of PSEG Common Stock on date of exercise.

(3)

Represents difference at fiscal year end (12/31/03) between market price of PSEG Common Stock ($43.80) and the respective exercise prices of the options. Such amounts may not necessarily be realized. Actual values which may be realized, if any, upon any exercise of such options will be based on the market price of PSEG Common Stock at the time of any such exercise and thus are dependent upon future performance of PSEG Common Stock.

Employment Contracts and Arrangements

PSEG has entered into an employment agreement dated as of June 16, 1998 and amended as of November 20, 2001 with Mr. Ferland covering his employment as Chief Executive Officer through March 31, 2007. The Agreement provides that Mr. Ferland will be re-nominated for election as a director during his employment under the Agreement. The Agreement also provides that Mr. Ferland’s base salary, target annual incentive bonus and long term incentive bonus will be determined based on compensation practices for CEO’s of similar companies and that his annual salary will not be reduced during the term of the Agreement. The Agreement also provided for an award to him of 150,000 shares of restricted PSEG Common Stock as of June 16, 1998 and 60,000 shares of restricted PSEG Common Stock as of November 20, 2001, with 60,000 shares vesting in 2002; 20,000 shares vesting in 2003; 30,000 shares vesting in 2004; 40,000 shares vesting in 2005; 30,000 shares vesting in 2006; and 30,000 shares vesting in 2007. Any non-vested shares are forfeited upon his retirement unless the Board of Directors, in its discretion, determines to waive the forfeiture. The Agreement provides for the granting of 22 years of pension credit for Mr. Ferland’s prior service, which was awarded at the time of his initial employment.

PSEG has entered into an employment agreement with Mr. Izzo dated as of October 18, 2003 and Mr. Busch dated as of April 24, 2001, covering the respective employment of each in the position listed in the Summary Compensation Table through October 17, 2008 for Mr. Izzo and April 24, 2006 for Mr. Busch. The agreements are essentially identical and provide that the base salary, target annual incentive bonus and long-term incentive bonus will be determined based on compensation practices of similar companies and that their annual salary will not be reduced during the term of the Agreement, and awarded to Mr. Izzo 250,000 options on PSEG Common Stock, 50,000 of which vest each October 18 and expire on October 18, 2013 and awarded to Mr. Busch 250,000 options on PSEG Common Stock, 50,000 of which vest each April 24 and expire on April 24, 2011 in each case provided that the individual has remained continuously employed by PSEG through such date. The agreement for Mr. Busch also provides for the grant of additional years of credited service for retirement purposes in light of allied work experience of fifteen years.

Each of the Agreements further provide that if the individual is terminated without “Cause” or resigns for “Good Reason” (as those terms are defined in each Agreement) during the term of the Agreement, the respective entire restricted stock award or the entire option award becomes vested, the

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individual will be paid a benefit of two times base salary and target bonus, and his welfare benefits will be continued for two years unless he is sooner employed. In the event such a termination occurs after a “Change in Control” (also as defined in each Agreement), the payment to the individual becomes three times the sum of salary and target bonus, continuation of welfare benefits for three years for Messrs. Ferland and Busch and two years for Mr. Izzo unless sooner reemployed, payment of the net present value of providing three years additional service under PSEG’s retirement plans, and a gross-up for excise taxes on any termination payments due under the Internal Revenue Code. The respective Agreements provide that Mr. Ferland is prohibited for two years and Messrs. Izzo and Busch are prohibited for one year from competing with and each is prohibited for two years from recruiting employees from, PSEG or its subsidiaries or affiliates, after termination of employment. Violation of these provisions requires a forfeiture of the respective restricted stock and option grant and certain benefits.

Compensation Committee Interlocks and Insider Participation

PSE&G does not have a compensation committee. Decisions regarding compensation of PSE&G’s executive officers are made by the Organization and Compensation Committee of PSEG. Hence, during 2003 the PSE&G Board of Directors did not have, and no officer, employee or former officer of PSE&G participated in any deliberations of such Board, concerning executive officer compensation.

Compensation of Directors and Certain Business Relationships

During 2003, a director who was not an officer of PSEG or its subsidiaries and affiliates, including PSE&G, was paid an annual retainer of $40,000 and a fee of $1,500 for attendance at any Board or committee meeting, inspection trip, conference or other similar activity relating to PSEG or PSE&G. Pursuant to the Compensation Plan for Outside Directors, a certain percentage, currently fifty percent, of the annual retainer is paid in PSEG Common Stock. No additional retainer is paid for service as a director of PSE&G. Each PSEG Committee Chair received an additional annual retainer of $5,000 except for the Chair of the Audit Committee, who received $10,000. In addition, each member of the Audit Committee received an additional annual retainer of $5,000.

PSEG also maintains a Stock Plan for Outside Directors pursuant to which directors who are not employees of PSEG or its subsidiaries receive shares of restricted stock for each year of service as a director. For 2003, this amount was 800 shares. Such shares held by each non-employee director are included in the table below under Item 12. Security Ownership of Certain Beneficial Owners and Management.

The restrictions on the stock granted under the Stock Plan for Outside Directors provide that the shares are subject to forfeiture if the director leaves service at any time prior to the Annual Meeting of Stockholders following his or her 70th birthday. This restriction would be deemed to have been satisfied if the director’s service were terminated after a ‘change in control’ as defined in the Plan or if the director were to die in office. PSEG also has the ability to waive these restrictions for good cause shown. Restricted stock may not be sold or otherwise transferred prior to the lapse of the restrictions. Dividends on shares held subject to restrictions are paid directly to the director and the director has the right to vote the shares.

Compensation Pursuant to Pension Plans

The table below illustrates annual retirement benefits for executive officers expressed in terms of single life annuities based on the average final compensation and service shown and retirement at age 65. A person’s annual retirement benefit is based upon a percentage that is equal to years of credited service plus 30, but not more than 75%, times average final compensation at the earlier of retirement, attainment of age 65 or death. These amounts are reduced by Social Security benefits and certain retirement benefits from other employers. Pensions in the form of joint and survivor annuities are also available.

211

Pension Plan Table

Average Final Compensation		Length of Service

		30 Years		35 Years		40 Years		45 Years

$	300,000	$	180,000	$	195,000	$	210,000	$	225,000
	400,000		240,000		260,000		280,000		300,000
	500,000		300,000		325,000		350,000		375,000
	600,000		360,000		390,000		420,000		450,000
	700,000		420,000		455,000		490,000		525,000
	800,000		480,000		520,000		560,000		600,000
	900,000		540,000		585,000		630,000		675,000
	1,000,000		600,000		650,000		700,000		750,000
	1,100,000		660,000		715,000		770,000		825,000
	1,200,000		720,000		780,000		840,000		900,000
	1,300,000		780,000		845,000		910,000		975,000
	1,400,000		840,000		910,000		980,000		1,050,000
	1,500,000		900,000		975,000		1,050,000		1,125,000

Average final compensation, for purposes of retirement benefits of executive officers, is generally equivalent to the average of the aggregate of the salary and bonus amounts reported in the Summary Compensation Table above under ‘Annual Compensation’ for the five years preceding retirement, not to exceed 150% of the average annual salary for such five year period. Messrs. Ferland, Selover, Busch, Izzo and Mrs. Rado will have accrued approximately 48, 43, 34, 36, and 29 years of credited service, respectively, as of age 65.

Power

Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

Energy Holdings

Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

PSEG

The information required by Item 12 of Form 10-K with respect to directors, executive officers and certain beneficial owners is set forth under the heading “Security Ownership of Directors, Management and Certain Beneficial Owners” in PSEG’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held April 20, 2004 which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about March 10, 2004, and such information set forth under such heading is incorporated herein by this reference thereto.

The following table indicates the securities authorized for issuance under equity compensation plans as of December 31, 2003:

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights(A)		Weighted-average exercise price of outstanding options, warrants and rights			Number of securities remaining available for future issuance under equity compensation plans

Equity Compensation plans approved by security holders		6,093,398		$	39.33		8,742,433
Equity compensation plans not approved by security holders		2,951,533		$	39.48		2,167,196

Total		9,044,931		$	39.37		10,909,629

(A)

Includes 164,000 shares granted under restricted stock agreements of certain key employees.

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For additional discussion of specific plans concerning equity-based compensation, see Note 22. Stock Options and Employee Stock Purchase Plan of the Notes, Item 11. Executive Compensation for PSE&G, above, and the information set forth under the heading “Executive Compensation” in PSEG’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held on April 20, 2004 and expected to be filed with the SEC on or about March 10, 2004, which information set forth under such heading is incorporated herein by this reference thereto.

PSE&G

All of PSE&G’s, 132,450,344 outstanding shares of Common Stock are owned beneficially and of record by PSE&G’s parent, PSEG, 80 Park Plaza, P.O. Box 1171, Newark, New Jersey.

The following table sets forth beneficial ownership of PSEG Common Stock, including options, by the directors and executive officers named below as of February 20, 2004. None of these amounts exceed 1% of the PSEG Common Stock outstanding at such date, except for the amount for all directors and executive officers as a group, which constitutes approximately 1.26%. No director or executive officer owns any of PSE&G’s Preferred Stock of any class.

Name	Amount and Nature of Beneficial Ownership

Robert E. Busch	461,920	(1)
Caroline Dorsa	2,353	(2)
E. James Ferland	1,761,921	(3)
Albert R. Gamper, Jr.	4,783	(4)
Conrad K. Harper	6,400	(5)
Ralph Izzo	369,511	(6)
Patricia A. Rado	90,879	(7)
R. Edwin Selover	271,473	(8)
All directors and executive officers as a group (8 persons)	2,969,240	(9)

(1)

Includes the equivalent of 181 shares held under PSEG Thrift and Tax-Deferred Savings Plan. Includes options to purchase 460,000 shares, 245,000 of which are currently exercisable.

(2)

Includes 1,600 shares of restricted stock awarded pursuant to the Stock Plan for Outside Directors described above in Item 11 under Compensation of Directors and Certain Business Relationships.

(3)

Includes the equivalent of 14,874 shares held under PSEG Thrift and Tax-Deferred Savings Plan. Includes options to purchase 1,465,000 shares, 1,115,000 of which are currently exercisable. Includes 130,000 shares of restricted stock, which vest as described above in Item 11. under Employment Contracts and Arrangements. Includes 80,000 shares held in a trust.

(4)

Includes 2,000 shares of restricted stock awarded pursuant to the Stock Plan for Outside Directors described above.

(5)

Includes 3,800 shares of restricted stock awarded pursuant to the Stock Plan for Outside Directors described above.

(6)

Includes the equivalent of 310 shares held under the PSEG Thrift and Tax-Deferred Savings Plan. Includes options to purchase 368,000 shares, 83,000 of which are exercisable.

(7)

Includes options to purchase 88,000 shares, 63,001 of which are currently exercisable.

(8)

Includes the equivalent of 11 shares held under the PSEG Thrift and Tax-Deferred Savings Plan. Includes options to purchase 260,000 shares, 183,334 of which are currently exercisable.

(9)

Includes the equivalent of 15,376 shares held under the PSEG Thrift and Tax-Deferred Savings Plan. Includes options to purchase 2,553,000 shares, 1,689,335 of which are currently exercisable. Includes 137,400 shares of restricted stock. Includes 80,000 shares held in a trust.

213

Power

Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

Energy Holdings

Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

PSEG

The information required by Item 13 of Form 10-K is set forth under the heading “Executive Compensation” in PSEG’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held April 20, 2004, which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about March 10, 2004. Such information set forth under such heading is incorporated herein by this reference thereto.

PSE&G

None.

Power

Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

Energy Holdings

Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

ITEM 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by Item 14 of Form 10-K is set forth under the heading “Fees Billed to PSEG by Deloitte & Touche LLP for 2003 and 2002” in PSEG’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held April 20, 2004, which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about March 10, 2004. Such information set forth under such heading is incorporated herein by this reference thereto.

PART IV

ITEM 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(A)

The following Financial Statements are filed as a part of this report:

Public Service Enterprise Group Incorporated’s Consolidated Balance Sheets as of December 31, 2003 and 2002 and the related Consolidated Statements of Operations, Cash Flows and Common Stockholders’ Equity for the three years ended December 31, 2003 on pages 100 and 101, 99, 102 and 103, respectively.

Public Service Electric and Gas Company’s Consolidated Balance Sheets as of December 31, 2003 and 2002 and the related Consolidated Statements of Operations, Cash Flows and Common Stockholder’s Equity for the three years ended December 31, 2003 on pages 106 and 107, 105, 108 and 109, respectively.

PSEG Power LLC Consolidated Balance Sheets as of December 31, 2003 and 2002 and the related Consolidated Statements of Operations, Cash Flows and Capitalization and Member’s Equity for the three years ended December 31, 2003 on pages 111, 110, 112 and 113, respectively.

214

PSEG Energy Holdings LLC Consolidated Balance Sheets as of December 31, 2003 and 2002 and the related Consolidated Statements of Operations, Cash Flows and Member’s/Common Stockholder’s Equity for the three years ended December 31, 2003 on pages 116 and 117, 115, 118 and 119, respectively.

(B)

The following documents are filed as a part of this report:

PSEG Financial Statement Schedules:

Schedule II — Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2003 (page 230).

PSE&G Financial Statement Schedules:

Schedule II — Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2003 (page 231).

Power’s Financial Statement Schedules:

Schedule II — Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2003 (page 231).

Energy Holdings’ Financial Statement Schedules:

Schedule II — Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2003 (page 232).

Schedules other than those listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.

(C)

The following documents are filed as part of this report:

LIST OF EXHIBITS

a. PSEG:

3a		Certificate of Incorporation Public Service Enterprise Group Incorporated¹

3b		By-Laws of Public Service Enterprise Group Incorporated²

3c		Certificate of Amendment of Certificate of Incorporation of Public Service Enterprise Group Incorporated, effective April 23, 1987³

3d		Amended and Restated Trust Agreement for Enterprise Capital Trust I⁴

3e		Amended and Restated Trust Agreement for Enterprise Capital Trust II⁵

3f		Amended and Restated Trust Agreement for Enterprise Capital Trust III⁶

3g		Amended and Restated Trust Agreement for PSEG Funding Trust I⁷

3h		Amended and Restated Trust Agreement for PSEG Funding Trust II⁸

4a(1)		Indenture between Public Service Enterprise Group Incorporated and First Union National Bank (now, Wachovia Bank, National Association), as Trustee, dated January 1, 1998 providing for Deferrable Interest Subordinated Debentures in Series (relating to Quarterly Preferred Securities)⁹

4a(2)		First Supplemental Indenture to Indenture dated as of January 1, 1998 between Public Service Enterprise Group Incorporated and First Union National Bank (now, Wachovia Bank, National Association), as Trustee, dated June 1, 1998 providing for the issuance of Floating Rate Deferrable Interest Subordinated Debentures, Series B (relating to Trust Preferred Securities)¹⁰

4a(3)		Second Supplemental Indenture to Indenture dated as of January 1, 1998 between Public Service Enterprise Group Incorporated and First Union National Bank (now, Wachovia Bank, National Association), as Trustee, dated July 1, 1998 providing for the issuance of Deferrable Interest Subordinated Debentures, Series C (relating to Trust Preferred Securities)¹¹

4b		Indenture dated as of November 1, 1998 between Public Service Enterprise Group Incorporated and First Union National Bank (now, Wachovia Bank, National Association) providing for the issuance of Senior Debt Securities¹²

4c		First Supplemental Indenture to Indenture dated as of November 1, 1998 between Public Service Enterprise Group Incorporated and Wachovia Bank, National Association, as Trustee, dated September 10, 2002 providing for the issuance of Senior Deferrable Notes (Senior Debt Securities)¹³

215

4d		Indenture dated as of December 17, 2002 between Public Service Enterprise Group Incorporated and Wachovia Bank, National Association providing for the issuance of Debentures in Series including 8.75% Deferrable Interest Junior Subordinated Debentures, Series D¹⁴

9		Inapplicable

10a(1)		Deferred Compensation Plan for Directors¹⁵

10a(2)		Deferred Compensation Plan for Certain Employees¹⁶

10a(3)		Limited Supplemental Benefits Plan for Certain Employees¹⁷

10a(4)		Mid Career Hire Supplemental Retirement Income Plan¹⁸

10a(5)		Retirement Income Reinstatement Plan for Non-Represented Employees¹⁹

10a(6)		1989 Long-Term Incentive Plan, as amended²⁰

10a(7)		2001 Long-Term Incentive Plan²¹

10a(8)		Restated and Amended Management Incentive Compensation Plan²²

10a(9)		Employment Agreement with E. James Ferland dated June 16, 1998²³

10a(10)		Amendment to Employment Agreement with E. James Ferland dated November 20, 2001²⁴

10a(11)		Employment Agreement with Thomas M. O’Flynn dated April 18, 2001²⁵

10a(12)		Amendment to Employment Agreement with Thomas M. O’Flynn dated December 21, 2001²⁶

10a(13)		Letter Agreement with Patricia A. Rado dated March 24, 1993²⁷

10a(14)		Employment Agreement with Ralph Izzo dated October 18, 2003²⁸

10a(15)		Employment Agreement with Frank Cassidy dated October 17, 2000²⁹

10a(16)		Employment Agreement with Robert J. Dougherty, Jr. dated October 17, 2000³⁰

10a(17)		Stock Plan for Outside Directors, as amended³¹

10a(18)		Employment Agreement with Robert E. Busch dated April 24, 2001³²

10a(19)		Employee Stock Purchase Plan³³

10a(20)		Compensation Plan for Outside Directors³⁴

10a(21)		2004 Long-Term Incentive Plan

11		Inapplicable

12		Computation of Ratios of Earnings to Fixed Charges

13		Inapplicable

14		Code of Ethics

16		Inapplicable

18		Inapplicable

21		Subsidiaries of the Registrant

22		Inapplicable

23		Independent Auditors’ Consent

24		Inapplicable

31a		Certification by E. James Ferland, pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act

31b		Certification by Thomas M. O’Flynn pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act

32a		Certification by E. James Ferland, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

216

32b

Certification by Thomas M. O’Flynn, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code


b.		PSE&G:


3a(1)		Restated Certificate of Incorporation of PSE&G³⁵

3a(2)		Certificate of Amendment of Certificate of Restated Certificate of Incorporation of PSE&G filed February 18, 1987 with the State of New Jersey adopting limitations of liability provisions in accordance with an amendment to New Jersey Business Corporation Act³⁶

3a(3)		Certificate of Amendment of Restated Certificate of Incorporation of PSE&G filed June 17, 1992 with the State of New Jersey, establishing the 7.44% Cumulative Preferred Stock ($100 Par) as a series of Preferred Stock³⁷

3a(4)		Certificate of Amendment of Restated Certificate of Incorporation of PSE&G filed March 11, 1993 with the State of New Jersey, establishing the 5.97% Cumulative Preferred Stock ($100 Par) as a series of Preferred Stock³⁸

3a(5)		Certificate of Amendment of Restated Certificate of Incorporation of PSE&G filed January 27, 1995 with the State of New Jersey, establishing the 6.92% Cumulative Preferred Stock ($100 Par) and the 6.75% Cumulative Preferred Stock — $25 Par as series of Preferred Stock³⁹

3b(1)		Copy of By-Laws of PSE&G⁴⁰

3c		Trust Agreement for PSE&G Capital Trust III⁴¹

3d		Trust Agreement for PSE&G Capital Trust IV⁴²

4a(1)		Indenture between PSE&G and Fidelity Union Trust Company (now, Wachovia Bank, National Association), as Trustee, dated August 1, 1924, securing First and Refunding Mortgage Bond⁴³

		Indentures between PSE&G and First Fidelity Bank, National Association (now, Wachovia Bank, National Association), as Trustee, supplemental to Exhibit 4a(1), dated as follows:

4a(2)		April 1, 1927⁴⁴

4a(3)		June 1, 1937⁴⁵

4a(4)		July 1, 1937⁴⁶

4a(5)		December 19, 1939⁴⁷

4a(6)		March 1, 1942⁴⁸

4a(7)		June 1, 1949⁴⁹

4a(8)		May 1, 1950⁵⁰

4a(9)		October 1, 1953⁵¹

4a(10)		May 1, 1954⁵²

4a(11)		November 1, 1956⁵³

4a(12)		September 1, 1957⁵⁴

4a(13)		August 1, 1958⁵⁵

4a(14)		June 1, 1959⁵⁶

4a(15)		September 1, 1960⁵⁷

4a(16)		August 1, 1962⁵⁸

4a(17)		June 1, 1963⁵⁹

4a(18)		September 1, 1964⁶⁰

4a(19)		September 1, 1965⁶¹

4a(20)		June 1, 1967⁶²

4a(21)		June 1, 1968⁶³

4a(22)		April 1, 1969⁶⁴


4a(23)		March 1, 1970⁶⁵

217

4a(24)		May 15, 1971⁶⁶

4a(25)		November 15, 1971⁶⁷

4a(26)		April 1, 1972⁶⁸

4a(27)		March 1, 1974⁶⁹

4a(28)		October 1, 1974⁷⁰

4a(29)		April 1, 1976⁷¹

4a(30)		September 1, 1976⁷²

4a(31)		October 1, 1976⁷³

4a(32)		June 1, 1977⁷⁴

4a(33)		September 1, 1977⁷⁵

4a(34)		November 1, 1978⁷⁶

4a(35)		July 1, 1979⁷⁷

4a(36)		September 1, 1979 (No. 1)⁷⁸

4a(37)		September 1, 1979 (No. 2)⁷⁹

4a(38)		November 1, 1979⁸⁰

4a(39)		June 1, 1980⁸¹

4a(40)		August 1, 1981⁸²

4a(41)		April 1, 1982⁸³

4a(42)		September 1, 1982⁸⁴

4a(43)		December 1, 1982⁸⁵

4a(44)		June 1, 1983⁸⁶

4a(45)		August 1, 1983⁸⁷

4a(46)		July 1, 1984⁸⁸

4a(47)		September 1, 1984⁸⁹

4a(48)		November 1, 1984 (No. 1)⁹⁰

4a(49)		November 1, 1984 (No. 2)⁹¹

4a(50)		July 1, 1985⁹²

4a(51)		January 1, 1986⁹³

4a(52)		March 1, 1986⁹⁴

4a(53)		April 1, 1986 (No. 1)⁹⁵

4a(54)		April 1, 1986 (No. 2)⁹⁶

4a(55)		March 1, 1987⁹⁷

4a(56)		July 1, 1987 (No. 1)⁹⁸

4a(57)		July 1, 1987 (No. 2)⁹⁹

4a(58)		May 1, 1988¹⁰⁰

4a(59)		September 1, 1988¹⁰¹

4a(60)		July 1, 1989¹⁰²

4a(61)		July 1, 1990 (No. 1)¹⁰³

4a(62)		July 1, 1990 (No. 2)¹⁰⁴

4a(63)		June 1, 1991 (No. 1)¹⁰⁵


4a(64)		June 1, 1991 (No. 2)¹⁰⁶

4a(65)		November 1, 1991 (No. 1)¹⁰⁷

4a(66)		November 1, 1991 (No. 2)¹⁰⁸

4a(67)		November 1, 1991 (No. 3)¹⁰⁹

218

4a(68)		February 1, 1992 (No. 1)¹¹⁰

4a(69)		February 1, 1992 (No. 2)¹¹¹

4a(70)		June 1, 1992 (No. 1)¹¹²

4a(71)		June 1, 1992 (No. 2)¹¹³

4a(72)		June 1, 1992 (No. 3)¹¹⁴

4a(73)		January 1, 1993 (No. 1)¹¹⁵

4a(74)		January 1, 1993 (No. 2)¹¹⁶

4a(75)		March 1, 1993¹¹⁷

4a(76)		May 1, 1993¹¹⁸

4a(77)		May 1, 1993 (No. 2)¹¹⁹

4a(78)		May 1, 1993 (No. 3)¹²⁰

4a(79)		July 1, 1993¹²¹

4a(80)		August 1, 1993¹²²

4a(81)		September 1, 1993¹²³

4a(82)		September 1, 1993 (No. 2)¹²⁴

4a(84)		February 1, 1994¹²⁵

4a(85)		March 1, 1994 (No. 1)¹²⁶

4a(86)		March 1, 1994 (No. 2)¹²⁷

4a(87)		May 1, 1994¹²⁸

4a(88)		June 1, 1994¹²⁹

4a(89)		August 1, 1994¹³⁰

4a(90)		October 1, 1994 (No. 1)¹³¹

4a(91)		October 1, 1994 (No. 2)¹³²

4a(92)		January 1, 1996 (No. 1)¹³³

4a(93)		January 1, 1996 (No. 2)¹³⁴

4a(94)		December 1, 1996¹³⁵

4a(95)		June 1, 1997¹³⁶

4a(96)		May 1, 1998¹³⁷

4a(97)		September 1, 2002¹³⁸

4a(98)		August 1, 2003

4a(99)		December 1, 2003 (No. 1)

4a(100)		December 1, 2003 (No. 2)

4a(101)		December 1, 2003 (No. 3)

4a(102)		December 1, 2003 (No. 4)

4b		Indenture of Trust between PSE&G and Chase Manhattan Bank (National Association) (now, JP Morgan Chase Bank, NA), as Trustee, providing for Secured Medium-Term Notes dated July 1, 1993¹³⁹


4c		Indenture dated as of December 1, 2000 between Public Service and Gas Company and First Union National Bank (now, Wachovia Bank, National Association), as Trustee, providing for Senior Debt Securities.¹⁴⁰

10a(1)		Deferred Compensation Plan for Directors¹⁵

10a(2)		Deferred Compensation Plan for Certain Employees¹⁶

10a(3)		Limited Supplemental Benefits Plan for Certain Employees¹⁷

10a(4)		Mid Career Hire Supplemental Retirement Income Plan¹⁸

10a(5)		Retirement Income Reinstatement Plan for Non-Represented Employees¹⁹

219

10a(6)		1989 Long-Term Incentive Plan, as amended²⁰

10a(7)		2001 Long-Term Incentive Plan²¹

10a(8)		Restated and Amended Management Incentive Compensation Plan²²

10a(9)		Employment Agreement with E. James Ferland, dated June 16, 1998²³

10a(10)		Amendment to Employment Agreement with E. James Ferland dated November 20, 2001²⁴

10a(11)		Letter Agreement with Patricia A. Rado dated March 24, 1993²⁷

10a(12)		Employment Agreement with Ralph Izzo dated October 18, 2003²⁸

10a(13)		Employment Agreement with Robert E. Busch dated April 24, 2001³²

10a(14)		Employee Stock Purchase Plan³³

10a(15)		Stock Plan for Outside Directors, as amended³¹

10a(16)		Compensation Plan for Outside Directors³⁴

10a(17)		2004 Long-Term Incentive Plan

11		Inapplicable

12a		Computation of Ratios of Earnings to Fixed Charges

12b		Computation of Ratios of Earnings to Fixed Charges Plus Preferred Stock Dividend Requirements

13		Inapplicable

14		Code of Ethics

16		Inapplicable

18		Inapplicable

19		Inapplicable

21a		Inapplicable

23a		Independent Auditors’ Consent

24		Inapplicable

31c		Certification by E. James Ferland, pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act

31d		Certification by Robert E. Busch pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act

32c		Certification by E. James Ferland, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

32d		Certification by Robert E. Busch, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

C. Power:

3a		Certificate of Formation of PSEG Power LLC¹⁴¹

3b		PSEG Power LLC Limited Liability Company Agreement¹⁴²

3c		Trust Agreement for PSEG Power Capital Trust I¹⁴³

3d		Trust Agreement for PSEG Power Capital Trust II¹⁴⁴

3e		Trust Agreement for PSEG Power Capital Trust III¹⁴⁵

3f		Trust Agreement for PSEG Power Capital Trust IV¹⁴⁶

3g		Trust Agreement for PSEG Power Capital Trust V¹⁴⁷

4a		Indenture dated April 16, 2001 between and among PSEG Power, PESG Fossil, PSEG Nuclear, PSEG Energy Resources & Trade and The Bank of New York and form of Subsidiary Guaranty included therein.¹⁴⁸

4b		First Supplemental Indenture, supplemental to Exhibit 4a, dated as of March 13, 2002.¹⁴⁹

10a(1)		Deferred Compensation Plan for Certain Employees¹⁶

10a(2)		Limited Supplemental Benefits Plan for Certain Employees¹⁷

10a(3)		Mid Career Hire Supplemental Retirement Income Plan¹⁸

220

10a(4)		Retirement Income Reinstatement Plan for Non-Represented Employees¹⁹

10a(5)		1989 Long-Term Incentive Plan, as amended²⁰

10a(6)		2001 Long-Term Incentive Plan²¹

10a(7)		Restated and Amended Management Incentive Compensation Plan²²

10a(8)		Employment Agreement with E. James Ferland, dated June 16, 1998²³

10a(9)		Amendment to Employment Agreement with E. James Ferland dated November 20, 2001²⁴

10a(10)		Employment Agreement with Thomas M. O’Flynn dated April 18, 2001²⁵

10a(11)		Amendment to Employment Agreement with Thomas M. O’Flynn dated December 21, 2001²⁶

10a(12)		Letter Agreement with Patricia A. Rado dated March 24, 1993²⁷

10a(13)		Employment Agreement with Frank Cassidy dated October 17, 2000²⁹

10a(14)		Employee Stock Purchase Plan³³

10a(15)		2004 Long-Term Incentive Plan

11		Inapplicable

12c		Computation of Ratio of Earnings to Fixed Charges

13		Inapplicable

14		Code of Ethics

16		Inapplicable

18		Inapplicable

19		Inapplicable

23		Independent Auditors’ Consent

24		Inapplicable

31e		Certification by E. James Ferland, pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act

31f		Certification by Thomas M. O’Flynn pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act

32e		Certification by E. James Ferland, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

32f		Certification by Thomas M. O’Flynn, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code


d. Energy Holdings:

3a		Certificate of Formation of PSEG Energy Holdings L.L.C.¹⁵⁰

3b		Certificate of Amendment to Certificate of Formation of PSEG Energy Holdings L.L.C.¹⁵¹

3c		Limited Liability Company Agreement of PSEG Energy Holdings L.L.C.¹⁵²

4a		Indenture dated October 8, 1999 between Energy Holdings and First Union National Bank (now Wachovia Bank, National Association).¹⁵³

4b		First Supplemental Indenture to Exhibit 4a between Energy Holdings and Wachovia Bank, National Association dated September 30, 2002.¹⁵⁴

10a(1)		Deferred Compensation Plan for Certain Employees¹⁶

10a(2)		Limited Supplemental Benefits Plan for Certain Employees¹⁷

10a(3)		Mid Career Hire Supplemental Retirement Income Plan¹⁸

10a(4)		Retirement Income Reinstatement Plan for Non-Represented Employees¹⁹

10a(5)		1989 Long-Term Incentive Plan, as amended²⁰

10a(6)		2001 Long-Term Incentive Plan²¹

10a(7)		Restated and Amended Management Incentive Compensation Plan²²

10a(8)		Employment Agreement with E. James Ferland, dated June 16, 1998²³

10a(9)		Amendment to Employment Agreement with E. James Ferland dated November 20, 2001²⁴

10a(10)		Employment Agreement with Thomas M. O’Flynn dated April 18, 2001²⁵

10a(11)		Amendment to Employment Agreement with Thomas M. O’Flynn dated December 21, 2001²⁶

10a(12)		Employment Agreement with Robert J. Dougherty, Jr. dated October 17, 2000³⁰

10a(13)		Employee Stock Purchase Plan³³

10a(14)		2004 Long-Term Incentive Plan

221

11		Inapplicable

12d		Computation of Ratios of Earnings to Fixed Charges

13		Inapplicable

14		Code of Ethics

16		Inapplicable

19		Inapplicable

24		Inapplicable

31g		Certification by E. James Ferland, pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act

31h		Certification by Thomas M. O’Flynn pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act

32g		Certification by E. James Ferland, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

32h		Certification by Thomas M. O’Flynn, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

(1)		Filed as Exhibit 3(a) to Registration Statement on Form S-4, No. 33-2935 and incorporated herein by this reference.

(2)		Filed as Exhibit 4.3 to Registration Statement on Form S-3, No. 333-86372 filed on April 16, 2002 and incorporated herein by this reference.

(3)		Filed as Exhibit 3(c) with Annual Report on Form 10-K for the year ended December 31, 1987, File No. 001-09120 on April 11, 1988 and incorporated herein by this reference.

(4)		Filed as Exhibit 3d with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120 on February 26, 2003 and incorporated herein by this reference.

(5)		Filed as Exhibit 3 with Quarterly Report on Form 10-Q for the Quarter ended June 30, 1998, File No. 001-09120 on August 14, 1998 and incorporated herein by this reference.

(6)		Filed as Exhibit 3(f) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120 on February 26, 2003 and incorporated herein by this reference.

(7)		Filed as Exhibit 4.3 with Current Report on Form 8-K, File No. 001-09120 on September 9, 2002 and incorporated herein by this reference.

(8)		Filed as Exhibit 3(h) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120 on February 26, 2003 and incorporated herein by this reference.

(9)		Filed as Exhibit 4(f) with Quarterly Report on Form 10-Q for the Quarter ended March 31, 1998, File No. 001-09120 on May 13, 1998 and incorporated herein by this reference.

(10)		Filed as Exhibit 4(a) with Current Report on Form 8-K, File No. 001-09120 on August 14, 1998 and incorporated herein by this reference.

(11)		Filed as Exhibit 4(b) with Current Report on Form 8-K, File No. 001-09120 on August 14, 1998 and incorporated herein by this reference.

(12)		Filed as Exhibit 4(f) with Annual Report on Form 10-K for the year ended December 31, 1998, File No. 001-09120 on February 22, 1999 and incorporated herein by this reference.

(13)		Filed as Exhibit 4(c) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120 on February 26, 2003 and incorporated herein by this reference.

(14)		Filed as Exhibit 4(d) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120 on February 26, 2003 and incorporated herein by this reference.

(15)		Filed as Exhibit 10a(1) with Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-09120, on February 25, 2000 and incorporated herein by this reference.

(16)		Filed as Exhibit 10a(2) with Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-09120, on February 25, 2000 and incorporated herein by this reference.

(footnotes continued on next page)

222

(footnotes continued from previous page)

(17)		Filed as Exhibit 10a(3) with Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-09120, on February 25, 2000 and incorporated herein by this reference.

(18)		Filed as Exhibit 10a(4) with Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-09120, on February 25, 2000 and incorporated herein by this reference.

(19)		Filed as Exhibit 10a(5) with Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-09120, on February 25, 2000 and incorporated herein by this reference.

(20)		Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the Quarter ended September 30, 2002, File No. 001-09120, on November 2, 2002 and incorporated herein by this reference.

(21)		Filed as Exhibit 10a(7) with Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-09120, on March 6, 2001 and incorporated herein by this reference.

(22)		Filed as Exhibit 10a(8) with Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-09120, on March 6, 2001 and incorporated herein by this reference.

(23)		Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the Quarter ended June 30, 1998, File No. 001-09120, on August 14, 1998 and incorporated herein by this reference.

(24)		Filed as Exhibit 10a(10) with Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-09120, on March 1, 2002 and incorporated herein by this reference.

(25)		Filed as Exhibit 10a(24) with Quarterly Report on Form 10-Q for the Quarter ended June 30, 2001, File No. 001-09120, on August 9, 2001 and incorporated herein by this reference.

(26)		Filed as Exhibit 10a(12) with Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-09120, on March 1, 2002 and incorporated herein by this reference.

(27)		Filed as Exhibit 10a(14) with Annual Report on Form 10-K for the year ended December 31, 1993, File No. 001-09120, on February 26, 1994 and incorporated herein by this reference.

(28)		File as Exhibit 10 with Quarterly Report on Form 10-Q for the Quarter ended September 30, 2003, File No. 001-09120, on October 30, 2003 and incorporated herein by this reference.

(29)		Filed as Exhibit 10a(19) with Quarterly Report on Form 10-Q for the Quarter ended September 30, 2000, File No. 001-09120, on November 13, 2000 and incorporated herein by this reference.

(30)		Filed as Exhibit 10a(20) with Quarterly Report on Form 10-Q for the Quarter ended September 30, 2000, File No. 001-09120, on November 13, 2000 and incorporated herein by this reference.

(31)		Filed as Exhibit 10a(17) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120, on February 26, 2003 and incorporated herein by this reference.

(32)		Filed as Exhibit 10a(23) with Quarterly Report on Form 10-Q for the Quarter ended June 30, 2001, File No. 001-09120, on August 9, 2001 and incorporated herein by this reference.

(33)		Filed with Registration Statement on Form S-8, File No. 333-106330 filed on June 20, 2003 and incorporated herein by this reference.

(34)		Filed as Exhibit 10a(20) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120, on February 26, 2003 and incorporated herein by this reference.

(35)		Filed as Exhibit 3(a) with Quarterly Report on Form 10-Q for the Quarter ended June 30, 1986, File No. 001-00973, on August 28, 1986 and incorporated herein by this reference.

(36)		Filed as Exhibit 3a(2) with Annual Report on Form 10-K for the year ended December 31, 1987, File No. 001-00973, on March 28, 1988 and incorporated herein by this reference.

(37)		Filed as Exhibit 3a(3) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.

(footnotes continued on next page)

223

(footnotes continued from previous page)

(38)		Filed as Exhibit 3a(4) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.

(39)		Filed as Exhibit 3a(5) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.

(40)		Filed as Exhibit 3b(1) with Quarterly Report on Form 10-Q for the Quarter ended June 30, 2000, No. 001-00973 filed on August 8, 2000 and incorporated herein by this reference.

(41)		Filed as Exhibit 3.6 to Registration Statement on Form S-3, No. 333-02763 filed on April 24, 1996 and incorporated herein by this reference.

(42)		Filed as Exhibit 3-2 to Registration Statement on Form S-3, File No. 333-76020 filed on December 27, 2001 and incorporated herein by this reference.

(43)		Filed as Exhibit 4b(1) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(44)		Filed as Exhibit 4b(2) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(45)		Filed as Exhibit 4b(3) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(46)		Filed as Exhibit 4b(4) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(47)		Filed as Exhibit 4b(5) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(48)		Filed as Exhibit 4b(6) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(49)		Filed as Exhibit 4b(7) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(50)		Filed as Exhibit 4b(8) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(51)		Filed as Exhibit 4b(9) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(52)		Filed as Exhibit 4b(10) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(53)		Filed as Exhibit 4b(11) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(54)		Filed as Exhibit 4b(12) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(55)		Filed as Exhibit 4b(13) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(56)		Filed as Exhibit 4b(14) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(57)		Filed as Exhibit 4b(15) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(58)		Filed as Exhibit 4b(16) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(59)		Filed as Exhibit 4b(17) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(footnotes continued on next page)

224

(footnotes continued from previous page)

(60)		Filed as Exhibit 4b(18) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(61)		Filed as Exhibit 4b(19) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(62)		Filed as Exhibit 4b(20) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(63)		Filed as Exhibit 4b(21) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(64)		Filed as Exhibit 4b(22) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(65)		Filed as Exhibit 4b(23) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(66)		Filed as Exhibit 4b(24) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(67)		Filed as Exhibit 4b(25) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(68)		Filed as Exhibit 4b(26) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(69)		Filed as Exhibit 4b(27) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(70)		Filed as Exhibit 4b(28) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(71)		Filed as Exhibit 4b(29) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(72)		Filed as Exhibit 4b(30) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(73)		Filed as Exhibit 4b(31) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(74)		Filed as Exhibit 4b(32) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(75)		Filed as Exhibit 4b(33) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(76)		Filed as Exhibit 4b(34) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(77)		Filed as Exhibit 4b(35) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(78)		Filed as Exhibit 4b(36) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(79)		Filed as Exhibit 4b(37) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(80)		Filed as Exhibit 4b(38) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(81)		Filed as Exhibit 4b(39) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(footnotes continued on next page)

225

(footnotes continued from previous page)

(82)		Filed as Exhibit 2 on Form 8-A, File No. 001-00973 on August 19, 1981 and incorporated herein by this reference.

(83)		Filed as Exhibit 4e with Current Report on Form 8-K, File No. 001-00973 on April 29, 1982 and incorporated herein by this reference.

(84)		Filed as Exhibit 2 on Form 8-A, File No. 001-00973 on September 17, 1982 and incorporated herein by this reference.

(85)		Filed as Exhibit 2 on Form 8-A, File No. 001-00973 on December 21, 1982 and incorporated herein by this reference.

(86)		Filed as Exhibit 4(ii) with Quarterly Report on Form 10-Q for the Quarter ended June 30, 1983, File No. 001-00973, on July 26, 1983 and incorporated herein by this reference.

(87)		Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on August 19, 1983 and incorporated herein by this reference.

(88)		Filed as Exhibit 4(ii) with Quarterly Report on Form 10-Q for the Quarter ended June 30, 1984, File No. 001-00973, on August 14, 1984 and incorporated herein by this reference.

(89)		Filed as Exhibit 4(ii) with November 12, 1984 and incorporated herein by this reference.

(90)		Filed as Exhibit 4(i) with Current Report on Form 8-K, File No. 001-00973 on January 4, 1985 and incorporated herein by this reference.

(91)		Filed as Exhibit 4(ii) with Current Report on Form 8-K, File No. 001-00973 on January 4, 1985 and incorporated herein by this reference.

(92)		Filed as Exhibit 2 on Form 8-A, File No. 001-00973 on August 2, 1985 and incorporated herein by this reference.

(93)		Filed as Exhibit 4a(51) with Annual Report on Form 10-K for the Year ended December 31, 1985, File No. 001-00973 on February 11, 1986 and incorporated herein by this reference.

(94)		Filed as Exhibit 2 on Form 8-A, File No. 001-00973 on March 28, 1986 and incorporated herein by this reference.

(95)		Filed as Exhibit 2(a) on Form 8-A, File No. 001-00973 on May 1, 1986 and incorporated herein by this reference.

(96)		Filed as Exhibit 2(b) on Form 8-A, File No. 001-00973 on May 1, 1986 and incorporated herein by this reference.

(97)		Filed as Exhibit 4a(55) to Registration Statement on Form S-3, No. 33-13209 filed on April 9, 1987 and incorporated herein by this reference.

(98)		Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on August 17, 1987 and incorporated herein by this reference.

(99)		Filed as Exhibit 4 with Quarterly Report on Form 10-Q for the Quarter ended September 30, 1987, File No. 001-00973, on November 13, 1987 and incorporated herein by this reference.

(100)		Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on May 17, 1988 and incorporated herein by this reference.

(101)		Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on September 27, 1988 and incorporated herein by this reference.

(102)		Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on July 25, 1989 and incorporated herein by this reference.

(103)		Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973 on July 25, 1990 and incorporated herein by this reference.

(footnotes continued on next page)

226

(footnotes continued from previous page)

(104)		Filed as Exhibit 4(ii) on Form 8-A, File No. 001-00973 on July 25, 1990 and incorporated herein by this reference.

(105)		Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973 on July 1, 1991 and incorporated herein by this reference.

(106)		Filed as Exhibit 4(ii) on Form 8-A, File No. 001-00973 on July 1, 1991 and incorporated herein by this reference.

(107)		Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973 on December 2, 1991 and incorporated herein by this reference.

(108)		Filed as Exhibit 4(ii) on Form 8-A, File No. 001-00973 on December 2, 1991 and incorporated herein by this reference.

(109)		Filed as Exhibit 4(iii) on Form 8-A, File No. 001-00973 on December 2, 1991 and incorporated herein by this reference.

(110)		Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973 on February 27, 1992 and incorporated herein by this reference.

(111)		Filed as Exhibit 4(ii) on Form 8-A, File No. 001-00973 on February 27, 1992 and incorporated herein by this reference.

(112)		Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973 on June 17, 1992 and incorporated herein by this reference.

(113)		Filed as Exhibit 4(ii) on Form 8-A, File No. 001-00973 on June 17, 1992 and incorporated herein by this reference.

(114)		Filed as Exhibit 4(iii) on Form 8-A, File No. 001-00973 on June 17, 1992 and incorporated herein by this reference.

(115)		Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973 on February 2, 1993 and incorporated herein by this reference.

(116)		Filed as Exhibit 4(ii) on Form 8-A, File No. 001-00973 on February 2, 1993 and incorporated herein by this reference.

(117)		Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on March 17, 1993 and incorporated herein by this reference.

(118)		Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973 on May 25, 1993 and incorporated herein by this reference.

(119)		Filed as Exhibit 4(ii) on Form 8-A, File No. 001-00973 on May 25, 1993 and incorporated herein by this reference.

(120)		Filed as Exhibit 4(iii) on Form 8-A, File No. 001-00973 on May 25, 1993 and incorporated herein by this reference.

(121)		Filed as Exhibit 4(i) with Current Report on Form 8-K, File No. 001-00973 on December 1, 1993 and incorporated herein by this reference.

(122)		Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on August 3, 1993 and incorporated herein by this reference.

(123)		Filed as Exhibit 4 with Current Report on Form 8-K, File No. 001-00973 on December 1, 1993 and incorporated herein by this reference.

(124)		Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on December 1, 1993 and incorporated herein by this reference.

(125)		Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on February 3, 1994 and incorporated herein by this reference.

(footnotes continued on next page)

227

(footnotes continued from previous page)

(126)		Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973 on March 15, 1994 and incorporated herein by this reference.

(127)		Filed as Exhibit 4(ii) on Form 8-A, File No. 001-00973 on March 15, 1994 and incorporated herein by this reference.

(128)		Filed as Exhibit 4a(87) with Quarterly Report on Form 10-Q for the Quarter ended September 30, 1994, File No. 001-00973, on November 8, 1994 and incorporated herein by this reference.

(129)		Filed as Exhibit 4a(88) with Quarterly Report on Form 10-Q for the Quarter ended September 30, 1994, File No. 001-00973, on November 8, 1994 and incorporated herein by this reference.

(130)		Filed as Exhibit 4a(89) with Quarterly Report on Form 10-Q for the Quarter ended September 30, 1994, File No. 001-00973, on November 8, 1994 and incorporated herein by this reference.

(131)		Filed as Exhibit 4a(90) with Quarterly Report on Form 10-Q for the Quarter ended September 30, 1994, File No. 001-00973, on November 8, 1994 and incorporated herein by this reference.

(132)		Filed as Exhibit 4a(91) with Quarterly Report on Form 10-Q for the Quarter ended September 30, 1994, File No. 001-00973, on November 8, 1994 and incorporated herein by this reference.

(133)		Filed as Exhibit 4a(2) on Form 8-A, File No. 001-00973 on January 26, 1996 and incorporated herein by this reference.

(134)		Filed as Exhibit 4a(3) on Form 8-A, File No. 001-00973 on January 26, 1996 and incorporated herein by this reference.

(135)		Filed as Exhibit 4a(94) with Annual Report on Form 10-K for the Year ended December 31, 1996, File No. 001-00973 on February 27, 1997 and incorporated herein by this reference.

(136)		Filed as Exhibit 4a(2) on Form 8-A, File No. 001-00973 on June 17, 1997 and incorporated herein by this reference.

(137)		Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on May 15, 1998 and incorporated herein by this reference.

(138)		Filed as Exhibit 4a(97) with Annual Report on Form 10-K for the Year ended December 31, 2002, File No. 001-00973 on February 25, 2003 and incorporated herein by this reference.

(139)		Filed as Exhibit 4 with Current Report on Form 8-K, File No. 001-00973 on December 1, 1993 and incorporated herein by this reference.

(140)		Filed as Exhibit 4.6 to Registration Statement on Form S-3, No. 333-76020 filed on December 27, 2001 and incorporated herein by this reference.

(141)		Filed as Exhibit 3.1 to Registration Statement on Form S-4, No. 333-69228 filed on October 5, 2001 and incorporated herein by this reference.

(142)		Filed as Exhibit 3.2 to Registration Statement on Form S-4, No. 333-69228 filed on October 5, 2001 and incorporated herein by this reference.

(143)		Filed as Exhibit 3.6 to Registration Statement on Form S-3, No. 333-105704 filed on May 30, 2003 and incorporated herein by this reference.

(144)		Filed as Exhibit 3.7 to Registration Statement on Form S-3, No. 333-105704 filed on May 30, 2003 and incorporated herein by this reference.

(145)		Filed as Exhibit 3.8 to Registration Statement on Form S-3, No. 333-105704 filed on May 30, 2003 and incorporated herein by this reference.

(footnotes continued on next page)

228

(footnotes continued from previous page)

(146)		Filed as Exhibit 3.9 to Registration Statement on Form S-3, No. 333-105704 filed on May 30, 2003 and incorporated herein by this reference.

(147)		Filed as Exhibit 3.10 to Registration Statement on Form S-3, No. filed 333-105704 on May 30, 2003 and incorporated herein by this reference.

(148)		Filed as Exhibit 4.1 to Registration Statement on Form S-4, No. 333-69228 filed on October 5, 2001 and incorporated herein by this reference.

(149)		Filed as Exhibit 4.7 with Quarterly Report on Form 10-Q for the Quarter ended March 31, 2002, File No. 001-49614, on May 15, 2002 and incorporated herein by this reference.

(150)		Filed as Exhibit 3 with Current Report on Form 8-K, File No. 000-32503 on October 4, 2002 and incorporated herein by this reference.

(151)		Filed as Exhibit 3.1 with Current Report on Form 8-K, File No. 000-32503 on October 4, 2002 and incorporated herein by this reference.

(152)		Filed as Exhibit 3.2 with Current Report on Form 8-K, File No. 000-32503 on October 4, 2002 and incorporated herein by this reference.

(153)		Filed as Exhibit 4.1 to Registration Statement on Form S-4, No. 333-95697 filed on January 28, 2000 and incorporated herein by this reference.

(154)		Filed as Exhibit 4 with Current Report on Form 8-K, File No. 000-32503 on October 4, 2002 and incorporated herein by this reference.

(D)

The following reports on Form 8-K were filed during the last quarter of 2003 and the 2004 period covered by this report under Item 5:

PSEG:

Items Reported		Date of Report
Items 5 and 9		October 22, 2003
Items 5 and 12		February 2, 2004

PSE&G:

Items Reported		Date of Report
Items 5 and 9		October 22, 2003
Items 5 and 12		February 2, 2004

Power:

Items Reported		Date of Report
Items 5 and 9		October 22, 2003
Items 5 and 12		February 2, 2004

Energy Holdings:

Items Reported		Date of Report
Items 5 and 9		October 22, 2003
Items 5 and 12		February 2, 2004

229

SCHEDULE II

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
Schedule II—Valuation and Qualifying Accounts
Years Ended December 31, 2003—December 31, 2001

Column A	Column B			Column C								Column D				Column E
				Additions

Description	Balance at Beginning of Period			Charged to cost and expenses				Charged to other accounts - describe				Deductions - describe				Balance at End of Period

2003:
Allowance for Doubtful Accounts		$	47		$	52			$	—			$	59	(A)(E)		$	40
Materials and Supplies Valuation Reserve			5			11	(I)			—				1	(B)			15
Other Reserves			12			—				2	(G)			—				14
Other Valuation Allowances			28			8				—				12	(E)(F)			24
2002:
Allowance for Doubtful Accounts		$	40		$	58			$	—			$	51	(A)(H)		$	47
Materials and Supplies Valuation Reserve			2			2				1	(C)			—				5
Other Reserves			2			10	(D)			—				—				12
Other Valuation Allowances			29			2				—				3	(E)(F)			28
2001:
Allowance for Doubtful Accounts		$	41		$	45			$	—			$	46	(A)		$	40
Materials and Supplies Valuation Reserve			11			—				—				9	(B)			2
Other Reserves			4			—				—				2	(D)			2
Other Valuation Allowances			41			—				—				12	(E)			29

(A)

Accounts Receivable/Investments written off.

(B)

Reduced reserve to appropriate level and to remove obsolete inventory.

(C)

Acquired two Connecticut electric generating stations.

(D)

Includes various liquidity, credit and bad debt reserves.

(E)

Valuation allowances consolidated in connection with the acquisition of SAESA.

(F)

Recorded in connection with the sales of certain properties held by EGDC.

(G)

Includes fuel reserve related to Connecticut acquisition.

(H)

Reclassified to Discontinued Operations.

(I)

Increased reserve due to obsolescence, excess and damaged items.

230

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
Schedule II—Valuation and Qualifying Accounts
Years Ended December 31, 2003—December 31, 2001

Column A	Column B			Column C						Column D				Column E
				Additions

Description	Balance at Beginning of Period			Charged to cost and expenses			Charged to other accounts - describe			Deductions - describe				Balance at End of Period

	(Millions)
2003:
Allowance for Doubtful Accounts		$	32		$	46		$	—		$	44	(A)		$	34
2002:
Allowance for Doubtful Accounts		$	38		$	43		$	—		$	49	(A)		$	32
2001:
Allowance for Doubtful Accounts		$	39		$	45		$	—		$	46	(A)		$	38

(A)

Accounts Receivable/Investments written off.

PSEG POWER LLC
Schedule II — Valuation and Qualifying Accounts
Years Ended December 31, 2003 — December 31, 2001

Column A	Column B			Column C								Column D				Column E
				Additions

Description	Balance at Beginning of Period			Charged to cost and expenses				Charged to other accounts - describe				Deductions - describe				Balance at End of Period

	(Millions)
2003:
Materials and Supplies Valuation Reserve		$	5		$	11	(E)		$	—			$	1	(A)		$	15
Other Reserves			12			—			$	2	(D)			—				14
2002:
Materials and Supplies Valuation Reserve		$	2		$	2			$	1	(B)		$	—			$	5
Other Reserves			2			10	(C)			—				—				12
2001:
Materials and Supplies Valuation Reserve		$	11		$	—			$	—			$	9	(A)		$	2
Other Reserves			4			—				—				2	(C)			2

(A)

Reduced reserve to appropriate level and removed obsolete inventory.

(B)

Acquired two Connecticut electric generation stations.

(C)

Includes various liquidity, credit and bad debt reserves.

(D)

Includes fuel reserve related to Connecticut acquisition.

(E)

Increased reserve due to obsolescence, excess and damaged items.

231

PSEG ENERGY HOLDINGS LLC
Schedule II—Valuation and Qualifying Accounts
Years Ended December 31, 2003—December 31, 2001

Column A	Column B			Column C							Column D				Column E
				Additions

Description	Balance at Beginning of Period			Charged to cost and expenses				Charged to other accounts- describe			Deductions- describe				Balance at End of Period
	(millions)
2003:
Allowance for Doubtful Accounts		$	15		$	6			$	—		$	15	(A)		$	6
Other Valuation Allowances			28			8				—			12	(A)(B)			24
2002:
Allowance for Doubtful Accounts		$	2		$	15	(C)		$	—		$	2	(D)		$	15
Other Valuation Allowances			29			2				—			3	(A)(B)			28
2001:
Allowance for Doubtful Accounts		$	2		$	—			$	—		$	—			$	2
Other Valuation Allowances			41			—				—			12	(A)			29

(A)

Valuation allowances consolidated in connection with the acquisition of SAESA.

(B)

Recorded in connection with the sales of certain properties held by EGDC, $1 million and $2 million in 2003 and 2002, respectively.

(C)

Reserve established for Accounts Receivable in Argentina.

(D)

Reclassified to Discontinued Operations.

232

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

	PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

	By	/s/ E. JAMES FERLAND

		E. James Ferland Chairman of the Board, President and Chief Executive Officer

Date: February 25, 2004

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

Signature	Title	Date


/s/ E. JAMES FERLAND	Chairman of the Board,	February 25, 2004
	President and Chief Executive Officer and Director (Principal Executive Officer)
E. James Ferland

/s/ THOMAS M. O’FLYNN	Executive Vice President and Chief	February 25, 2004
	Financial Officer (Principal Financial Officer)
Thomas M. O’Flynn	Financial Officer (Principal Financial Officer)

/s/ PATRICIA A. RADO	Vice President and Controller	February 25, 2004
	(Principal Accounting Officer)
Patricia A. Rado

/s/ CAROLINE DORSA	Director	February 25, 2004

Caroline Dorsa

/s/ ERNEST H. DREW	Director	February 25, 2004

Ernest H. Drew

/s/ ALBERT R. GAMPER, JR.	Director	February 25, 2004

Albert R. Gamper, Jr.

/s/ CONRAD K. HARPER	Director	February 25, 2004

Conrad K. Harper

/s/ WILLIAM V. HICKEY	Director	February 25, 2004

William V. Hickey

/s/ SHIRLEY ANN JACKSON	Director	February 25, 2004

Shirley Ann Jackson

/s/ THOMAS A. RENYI	Director	February 25, 2004

Thomas A. Renyi

/s/ RICHARD J. SWIFT	Director	February 25, 2004

Richard J. Swift

233

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

	PUBLIC SERVICE ELECTRIC AND GAS COMPANY

	By	/s/ RALPH IZZO

		Ralph Izzo President and Chief Operating Officer

Date: February 25, 2004

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

Signature	Title	Date


/s/ E. JAMES FERLAND	Chairman of the Board and Chief	February 25, 2004
	Executive Officer and Director
E. James Ferland	(Principal Executive Officer)

/s/ ROBERT E. BUSCH	Senior Vice President—Finance and	February 25, 2004
	Chief Financial Officer
Robert E. Busch	(Principal Financial Officer)

/s/ PATRICIA A. RADO	Vice President and Controller	February 25, 2004
	(Principal Accounting Officer)
Patricia A. Rado

/s/ CAROLINE DORSA	Director	February 25, 2004

Caroline Dorsa

/s/ ALBERT R. GAMPER, JR.	Director	February 25, 2004

Albert R. Gamper, Jr.

/s/ CONRAD K. HARPER	Director	February 25, 2004

Conrad K. Harper

234

SIGNATURES

	PSEG POWER LLC

	By	/s/ FRANK CASSIDY

		Frank Cassidy President and Chief Operating Officer

Date: February 25, 2004

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

Signature	Title	Date


/s/ E. JAMES FERLAND	Chairman of the Board and	February 25, 2004
	Chief Executive Officer and Director
E. James Ferland	(Principal Executive Officer)

/s/ THOMAS M. O’FLYNN	Executive Vice President and Chief	February 25, 2004
	Financial Officer and Director
Thomas M. O’Flynn	(Principal Financial Officer)

/s/ PATRICIA A. RADO	Vice President and Controller	February 25, 2004
	(Principal Accounting Officer)
Patricia A. Rado

/s/ ROBERT E. BUSCH	Director	February 25, 2004

Robert E. Busch

/s/ FRANK CASSIDY	Director	February 25, 2004

Frank Cassidy

/s/ ROBERT J. DOUGHERTY, JR.	Director	February 25, 2004

Robert J. Dougherty, Jr.

/s/ R. EDWIN SELOVER	Director	February 25, 2004

R. Edwin Selover

235

SIGNATURES

	PSEG ENERGY HOLDINGS LLC

	By	/s/ ROBERT J. DOUGHERTY, JR.

		Robert J. Dougherty, Jr. President and Chief Operating Officer

Date: February 25, 2004

Signature	Title	Date


/s/ E. JAMES FERLAND	Chairman of the Board and	February 25, 2004
	Chief Executive Officer and Director
E. James Ferland	(Principal Executive Officer)

/s/ THOMAS M. O’FLYNN	Executive Vice President and	February 25, 2004
	Chief Financial Officer and Director
Thomas M. O’Flynn	(Principal Financial Officer)

/s/ DEREK M. DIRISIO	Vice President and Controller	February 25, 2004
	(Principal Accounting Officer)
Derek M. DiRisio

/s/ ROBERT E. BUSCH	Director	February 25, 2004

Robert E. Busch

/s/ FRANK CASSIDY	Director	February 25, 2004

Frank Cassidy

/s/ ROBERT J. DOUGHERTY, JR.	Director	February 25, 2004

Robert J. Dougherty, Jr.

/s/ R. EDWIN SELOVER	Director	February 25, 2004

R. Edwin Selover

236

The following documents are filed as a part of this report:

PSEG:

Exhibit 10a(21): 2004 Long-Term Incentive Plan

Exhibit 12: Computation of Ratios of Earnings to Fixed Charges

Exhibit 14: Code of Ethics

Exhibit 21: Subsidiaries of the Registrant

Exhibit 23: Independent Auditors’ Consent

Exhibit 31a: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934

Exhibit 31b: Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934

Exhibit 32a: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

Exhibit 32b: Certification by Thomas M. O’Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

PSE&G:

Exhibit 4a(98): Supplemental Indenture dated August 1, 2003 to Mortgage Indenture

Exhibit 4a(99): Supplemental Indenture dated December 1, 2003 (No. 1) to Mortgage Indenture

Exhibit 4a(100): Supplemental Indenture dated December 1, 2003 (No. 2) to Mortgage Indenture

Exhibit 4a(101): Supplemental Indenture dated December 1, 2003 (No. 3) to Mortgage Indenture

Exhibit 4a(102): Supplemental Indenture dated December 1, 2003 (No. 4) to Mortgage Indenture

Exhibit 10a(17): 2004 Long-Term Incentive Plan

Exhibit 12a: Computation of Ratios of Earnings to Fixed Charges

Exhibit 12b: Computation of Ratios of Earnings to Fixed Charges Plus Preferred Stock Dividend Requirements

Exhibit 14: Code of Ethics

Exhibit 21a: Subsidiaries of Registrant

Exhibit 23a: Independent Auditors’ Consent

Exhibit 31c: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934

Exhibit 31d: Certification by Robert E. Busch Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934

Exhibit 32c: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

Exhibit 32d: Certification by Robert E. Busch Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

237

Power:

Exhibit 10a(15): 2004 Long-Term Incentive Plan

Exhibit 12c: Computation of Ratios of Earnings to Fixed Charges

Exhibit 14: Code of Ethics

Exhibit 23b: Independent Auditors’ Consent

Exhibit 31e: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934

Exhibit 31f: Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934

Exhibit 32e: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

Exhibit 32f: Certification by Thomas M. O’Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

Energy Holdings:

Exhibit 10a(14): 2004 Long-Term Incentive Plan

Exhibit 12d: Computation of Ratios of Earnings to Fixed Charges

Exhibit 14: Code of Ethics

Exhibit 31g: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934

Exhibit 31h: Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934

Exhibit 32g: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

Exhibit 32h: Certification by Thomas M. O’Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

238