UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of Report (Date of earliest event reported) August 29, 2005 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED (Exact name of registrant as specified in its charter)
New Jersey (State or other jurisdiction of incorporation)	001-09120 (Commission File Number)	22-2625848 (I.R.S. Employer Identification No.)
80 Park Plaza, P.O. Box 1171 Newark, New Jersey 07101-1171 (Address of principal executive offices) (Zip Code) 973-430-7000 (Registrant’s telephone number, including area code) http://www.pseg.com Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):  o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)  o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)  o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))  o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01. Other Events

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED (PSEG) CONFORMS PRESENTATION OF INFORMATION CONTAINED IN ITS 2004 ANNUAL REPORT ON FORM 10-K TO REFLECT MATTERS PREVIOUSLY DISCLOSED IN 2005 QUARTERLY REPORTS ON FORM 10-Q

THIS CURRENT REPORT ON FORM 8-K (REPORT) CONFORMS THE INFORMATION CONTAINED IN PSEG’S 2004 ANNUAL REPORT ON FORM 10-K TO THE PRESENTATION REPORTED IN ITS QUARTERLY REPORT ON FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2005. ACCORDINGLY, THIS REPORT REVISES INFORMATION PREVIOUSLY REPORTED IN PSEG’S 2004 ANNUAL REPORT ON FORM 10-K TO REFLECT THE FOLLOWING MATTERS WHICH HAVE PREVIOUSLY BEEN DISCLOSED IN REPORTS FILED UNDER THE SECURITIES EXCHANGE ACT OF 1934.

NO ATTEMPT HAS BEEN MADE IN THIS FORM 8-K TO MODIFY OR UPDATE OTHER DISCLOSURES AS PRESENTED IN THE ORIGINAL FORM 10-K EXCEPT AS REQUIRED TO REFLECT THE EFFECTS OF THOSE ITEMS AS DESCRIBED BELOW.

This Report is limited to the reclassifications to reflect the classification of the assets and results of operations of the Waterford Generation Facility as discontinued operations.  This Report reflects these changes and their impact upon Item 6. Selected Financial Data, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A. Qualitative and Quantitative Disclosures About Market Risks, Item 8. Financial Statements and Supplementary Data, and Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K as originally reported in PSEG’s 2004 Annual Report on Form 10-K. These changes have been made to maintain conformity to the reporting format presented in PSEG’s Form 10-Q for the period ended June 30, 2005. Certain reclassifications of amounts reported in prior periods have been made to conform with the current presentation.

As disclosed in PSEG’s Form 10-Q for the quarter ended June 30, 2005, on May 27, 2005, PSEG Power LLC (Power) entered into an agreement to sell its electric generation facility located in Waterford, Ohio to a subsidiary of American Electric Power Company, Inc. (AEP). Since commencing construction of the project, the dramatic increase in natural gas prices relative to the price increase of coal and the failure to receive capacity compensation for the facility caused Power to consider alternatives for the project. After reviewing the alternatives in conjunction with other strategic and financial considerations, Power concluded that the value to be received from the sale of Waterford represented a means to accelerate the realization of the plant’s value. The sale price for the facility and inventory is $220 million. In May 2005, Power recognized an estimated loss on disposal of $177 million, net of tax, for the initial write-down of its carrying amount of Waterford to its fair value less cost to sell.

Item 9.01 Financial Statements and Exhibits

Exhibit 23 Consent of Independent Registered Public Accounting Firm

TABLE OF CONTENTS

UPDATES TO 2004 FORM 10-K

		Page
FORWARD-LOOKING STATEMENTS		1
PART II
Item 6.	Selected Financial Data	2
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2
	Overview of 2004 and Future Outlook	2
	Results of Operations	8
	Liquidity and Capital Resources	23
	Capital Requirements	32
	Off-Balance Sheet Arrangements	35
	Critical Accounting Estimates	35
Item 7A.	Qualitative and Quantitative Disclosures About Market Risk	39
Item 8.	Financial Statements and Supplementary Data	47
	Report of Independent Registered Public Accounting Firm	48
	Consolidated Financial Statements	49
	Notes to Consolidated Financial Statements
	Note 1. Organization and Summary of Significant Accounting Policies	53
	Note 2. Recent Accounting Standards	60
	Note 3. Asset Retirement Obligations	66
	Note 4. Discontinued Operations, Dispositions and Acquisitions	68
	Note 5. Extraordinary Item	72
	Note 6. Asset Impairments	73
	Note 7. Regulatory Matters	73
	Note 8. Earnings Per Share	76
	Note 9. Goodwill and Other Intangibles	77
	Note 10. Long-Term Investments	78
	Note 11. Schedule of Consolidated Capital Stock and Other Securities	82
	Note 12. Schedule of Consolidated Debt	83
	Note 13. Risk Management	88
	Note 14. Commitments and Contingent Liabilities	91
	Note 15. Nuclear Decommissioning	103
	Note 16. Other Income and Deductions	104
	Note 17. Income Taxes	106
	Note 18. Pension, Other Postretirement Benefits (OPEB) and Savings Plans	111
	Note 19. Stock Options and Employee Stock Purchase Plan	116
	Note 20. Financial Information by Business Segments	118
	Note 21. Property, Plant and Equipment and Jointly-Owned Facilities	122
	Note 22. Selected Quarterly Data (Unaudited)	124
	Note 23. Related-Party Transactions	124
	Note 24. Merger Agreement	128
PART IV
	Schedule II—Valuation and Qualifying Accounts	129
	Signature	130

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,
	2004		2003		2002			2001		2000
	(Millions, where applicable)
Operating Revenues	$	10,991	$	11,135	$	8,220		$	6,883	$	6,521
Income from Continuing Operations	$	754	$	861	$	405	(A)	$	766	$	782
Net Income	$	726	$	1,160	$	235		$	764	$	770
Earnings per Share:
Income from Continuing Operations:
Basic	$	3.18	$	3.77	$	1.94	(A)	$	3.68	$	3.64
Diluted	$	3.17	$	3.76	$	1.94	(A)	$	3.68	$	3.64
Net Income:
Basic	$	3.06	$	5.08	$	1.13		$	3.67	$	3.58
Diluted	$	3.05	$	5.07	$	1.13		$	3.67	$	3.58
Dividends Declared per Share	$	2.20	$	2.16	$	2.16		$	2.16	$	2.16
As of December 31:
Total Assets	$	29,244	$	28,147	$	26,147		$	25,568	$	21,531
Long-Term Obligations(B)	$	12,975	$	12,995	$	12,291		$	10,814	$	5,869
Preferred Stock With Mandatory Redemption	$	—	$	—	$	—		$	—	$	75

______________

(A) 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 6. Asset Impairments of the Notes for further discussion.

(B) Includes capital lease obligations. The increase in 2001 is related to a $2.5 billion securitization transaction. In addition, this includes debt supporting trust preferred securities in all years presented due to the implementation of Financial Accounting Standards Board (FASB) Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities (VIE).” See Note 2. Recent Accounting Standards of the Notes.

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.

OVERVIEW OF 2004 AND FUTURE OUTLOOK

PSEG, PSE&G, Power and Energy Holdings

Merger Agreement

On December 20, 2004, PSEG entered into an agreement and plan of merger (Merger Agreement) with Exelon Corporation (Exelon), a public utility holding company registered under the Public Utility Holding Company Act of 1935 (PUHCA) which is headquartered in Chicago, Illinois, whereby PSEG will be merged with and into Exelon (Merger). Under the Merger Agreement, each share of PSEG Common Stock will be converted into 1.225 shares of Exelon Common Stock.

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PSEG and Exelon entered into the Merger Agreement with the expectation that the Merger would result in various benefits, including, among other things, cost savings and operating efficiencies. The Merger Agreement also addresses the key issues of leadership succession at PSEG with John Rowe, Exelon’s Chief Executive Officer to become Chief Executive Officer of the combined company. Achieving the anticipated benefits of the Merger is subject to a number of uncertainties, including whether the businesses of Exelon and PSEG are integrated in an efficient and effective manner, as well as general competitive factors in the market place. Failure to achieve these anticipated benefits could result in increased costs, decreases in the amount of expected revenues generated by the combined company and diversion of management’s time and energy and could have an adverse effect on the combined company’s business, financial condition, operating results and prospects.

The Merger Agreement has been unanimously approved by both companies’ boards of directors. Before the Merger may be completed, various approvals or consents must be obtained from shareholders, the Federal Energy Regulatory Commission (FERC), the Securities and Exchange Commission (SEC), the Nuclear Regulatory Commission (NRC) and various utility regulatory, antitrust and other authorities in the United States (U.S.) and in foreign jurisdictions. The governmental authorities from which these approvals are required may impose conditions on completion of the Merger or require changes to the terms of the Merger. These conditions or changes could have the effect of delaying completion of the Merger or imposing additional costs on or limiting the revenues of the combined company and/or the individual registrants following the Merger, any of which might have a material adverse effect on the combined company or the individual registrants following completion of the Merger. PSEG is committed to this proposed business combination, however, pending receipt of the various required approvals, which cannot be assured, PSEG intends to remain positioned with a viable stand-alone strategy.

On February 4, 2005, PSEG and Exelon filed for approval of the Merger with the FERC, the New Jersey Board of Public Utilities (BPU) and the Pennsylvania Public Utility Commission (PPUC). Exelon also filed a notice of the Merger with the Illinois Commerce Commission.

Although PSEG and Exelon intend to take steps to reduce any adverse effects, uncertainties relating to the Merger may impair PSEG’s and Exelon’s ability to attract, retain and motivate key personnel until the Merger is consummated and for a period of time thereafter due to uncertainty about roles with the future combined company, and could cause customers, suppliers and others that deal with PSEG and Exelon to seek to change existing business relationships. Inability to retain key employees or maintain satisfactory relationships with employees, customers or suppliers could have a material adverse impact on the operations of PSEG, Exelon and the combined company following the Merger.

It is anticipated that the regulatory approval process will be completed and the Merger will close within 12 months to 15 months after the announcement of the Merger Agreement in December 2004, subject to shareholder and regulatory approvals which cannot be assured. The Merger would create a combined company serving approximately seven million electric customers and approximately two million gas customers in Illinois, New Jersey and Pennsylvania.

PSEG and Exelon expect to incur costs associated with consummating the Merger and integrating the operations of the two companies, as well as approximately $29 million and $41 million in transaction fees for PSEG and Exelon, respectively. Preliminary estimated integration costs associated with the Merger are approximately $700 million over a period of 4 years, with approximately $400 million being incurred in the first year after completion of the Merger and approximately $150 million being incurred in the second year after completion of the Merger.

Following the Merger, approximately 50% of the combined company’s earnings and cash flow is expected to be produced by the three regulated utilities, PSE&G, Commonwealth Edison Company in northern Illinois and PECO Energy Company in southeastern Pennsylvania, and 50% by the unregulated businesses, primarily from the combined generation of Power and Exelon Generation Company LLC (Exelon Generation). After the Merger, the combined company expects to maintain its proportion of business in regulated operations while reducing the proportion in international operations. The expected strategy of the combined company would be to divest, in an orderly fashion, PSEG Global LLC’s (Global) investments that do not meet the strategic objectives of the combined company.

The Merger Agreement contains certain termination rights for both Exelon and PSEG, and further provides that, upon termination of the Merger Agreement under specified circumstances, (1) Exelon may be required to pay PSEG a termination fee of $400 million plus PSEG’s transaction expenses up to $40 million and (2) PSEG may be required to pay Exelon a termination fee of $400 million plus Exelon’s transaction expenses up to $40 million.

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Among the factors considered by the board of directors of PSEG in connection with its approvals of the Merger Agreement were the benefits as well as the risks that could result from the Merger. PSEG cannot give any assurance that these benefits will be realized within the time periods contemplated or even that they will be realized at all.

Concurrent with the Merger Agreement, PSEG Nuclear LLC (Nuclear) entered into an Operating Services Contract (OSC) with Exelon Generation, which commenced on January 17, 2005, relating to the operation of the Salem and Hope Creek nuclear generating stations. The OSC provides that Exelon Generation will provide a chief nuclear officer and other key personnel to oversee daily plant operations at the Hope Creek and Salem nuclear generating stations and to implement the Exelon operating model, which defines practices that Exelon has used to manage its own nuclear performance program. Nuclear will continue as the license holder with exclusive legal authority to operate and maintain the plants, will retain responsibility for management oversight and will have full authority with respect to the marketing of its share of the output from the facilities. Exelon Generation will be entitled to receive reimbursement of its costs in discharging its obligations, an annual operating services fee and incentive fees of up to $12 million annually based on attainment of goals relating to safety, capacity factors of the plants and operation and maintenance expenses. The OSC has a term of two years, subject to earlier termination in certain events upon prior notice, including any termination of the Merger Agreement. In the event of termination, Exelon Generation will continue to provide services under the OSC for a transition period of at least 180 days and up to two years at the election of Nuclear. This period may be further extended by Nuclear for up to an additional 12 months if Nuclear determines that additional time is necessary to complete required activities during the transition period.

Prior to the Merger, PSEG and Exelon, and their respective subsidiaries, will continue to operate as separate entities. The discussion contained in the combined MD&A that follows relates solely to the current businesses of PSEG, PSE&G, Power and Energy Holdings and their respective expectations for future financial position, results of operations and cash flows, exclusive of any potential impacts from the Merger.

On May 27, 2005, Power entered into an agreement to sell its electric generation facility located in Waterford, Ohio to a subsidiary of American Electric Power Company, Inc. (AEP). The sale price for the facility and inventory is $220 million. The proceeds, together with anticipated reduction in tax liability, are approximately $300 million, which will be used to retire debt at Power and PSEG. In May 2005, Power recognized an estimated loss on disposal of $177 million, net of tax, for the initial write-down of its carrying amount of Waterford to its fair value less cost to sell.

PSEG

PSEG’s business consists of four reportable segments, which are PSE&G, Power and the two direct subsidiaries of Energy Holdings: 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 2004 and expectations for 2005 and beyond.

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 detailed estimates of revenues, operating and maintenance expenses, capital expenditures, financing costs and other material factors for each business. 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. PSEG Management believes this monitoring and forecasting process enables it to alter operating and investment plans as conditions change.

PSEG projects earnings from Continuing Operations for 2005 of $3.15 to $3.35 per share. Included in the 2005 earnings projections are improved operations at Power’s generating facilities as compared to 2004 and margin improvements through the expiration of existing contracts and the realization of current and anticipated higher market prices. These projected improvements are expected to be partially offset by lower income from Power’s Nuclear Decommissioning Trust (NDT) Funds as compared to 2004. PSEG also expects Earnings Per Share in 2005 to be reduced by additional shares outstanding primarily due to the anticipated conversion of participating equity securities in November 2005.

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PSEG expects operating cash flows beyond 2004 to be sufficient to meet capital needs and dividend requirements and may employ any excess cash to reduce debt, invest in its businesses or increase dividends. On January 18, 2005, PSEG announced an increase in its dividend from $0.55 to $0.56 per share for the first quarter of 2005. This quarterly increase reflects an indicated annual dividend rate of $2.24 per share.

Several key factors that will drive PSEG’s future success are energy, capacity and fuel prices, performance of Power’s generating facilities, PSE&G’s ability to maintain a reasonable rate of return under its regulated rate structure and the stability of international economies for Energy Holdings. Assuming improvements in these factors over the latter part of the planning period, as discussed further below under PSE&G, Power and Energy Holdings, PSEG has a target annual earnings per share growth rate of 4% to 6% from 2005 to 2009.

PSE&G

PSE&G operates as an electric and gas public utility in New Jersey under cost-based regulation by the BPU for its distribution operations and by the FERC for its electric transmission and wholesale sales operations. Consequently, the earnings of PSE&G are largely determined by the regulation of its rates by those agencies. In February 2004, the BPU approved the results of New Jersey’s third annual basic generation service (BGS) auction process and PSE&G successfully secured contracts to provide the electricity requirements for its customers’ needs. On October 5, 2004, the BPU approved a 3% increase in PSE&G’s residential gas commodity charge to cover the higher cost of natural gas. The cost of energy supply, for both gas and electricity, is passed through from PSE&G to its customers.

In 2005, PSE&G expects Income from Continuing Operations to range from $325 million to $345 million, based on normal weather conditions, expected sales growth, productivity gains and the effects of the 2003 electric base rate case, partially offset by cost increases. In addition, as provided for in a BPU order received in July 2003 in PSE&G’s electric base rate case, PSE&G is amortizing a reserve for excess depreciation which results in an annual $64 million reduction in Depreciation and Amortization expense through December 31, 2005. The BPU’s order in this case allows PSE&G to file for a $64 million increase in electric distribution rates effective January 1, 2006, subsequent to the amortization of this reserve. Assuming a fair resolution to upcoming rate matters, expected increases in sales volumes and stable weather patterns, PSE&G expects annual earnings growth of 1% to 2% from 2005 to 2009.

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. In 2005 and beyond, PSE&G’s success will depend, 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 with an adequate return the regulatory assets it has deferred and the investments it plans to make in its electric and gas transmission and distribution system. Since PSE&G earns no margin on the commodity portion of its electric and gas sales through tariff agreements, there is no anticipated commodity price volatility for PSE&G.

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’s principal operating subsidiaries, PSEG Fossil LLC (Fossil), Nuclear and PSEG Energy Resources & Trade LLC (ER&T) are regulated by FERC. Through its subsidiaries, 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 the Super Region based on market conditions.

To reduce volatility in earnings and cash flow, 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. Power has achieved this objective through a combination of contracts related to the New Jersey BGS auctions, contracts in Pennsylvania and Connecticut and other firm sales and trading positions. Prospectively, Power intends to take advantage of the BGS auctions in New Jersey and other opportunities elsewhere in the market region to continue to meet this objective.

In February 2005, the BPU approved the results of the BGS-FP and CIEP auctions for New Jersey customers. Each bidder was limited to a third of each EDC’s total load. Power will continue to be a direct supplier of New

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Jersey EDCs under both the BGS-FP and CIEP auctions, entering into additional contracts that will begin on June 1, 2005. Power believes that its obligations under these contracts are reasonably balanced by its available supply.

A key factor in Power’s ability to achieve its objectives is its capability to operate its nuclear and fossil stations at sufficient capacity to avoid the need to purchase higher-priced electricity to satisfy its obligations. Overall, 2004 earnings were lower than originally expected primarily due to a series of factors related to its nuclear and fossil operations and recent market pricing and electric transmission congestion which resulted in the purchase of higher-priced replacement power.

In 2004, the absence of the market transition charge (MTC) revenues at Power that had been collected during the four-year transition period under New Jersey’s electric utility deregulation provisions that ended August 2003 resulted in a decrease to earnings of approximately $66 million, after-tax.

Power’s results from its nuclear operations have been negatively impacted by unanticipated, extended outages at its Hope Creek and Salem nuclear generation facilities. These outages were the result of necessary repair and maintenance work, which is expected to improve long-term operating performance. In addition, Power’s fossil operations were adversely impacted by unanticipated outages at its Hudson station and extended outages at its Mercer station. During much of 2004, the price of replacement power to satisfy Power’s contracted obligations to serve load and supply power was significantly impacted by higher than expected fuel and transmission congestion costs. Power believes that a large portion of the increased congestion costs were related to the derating of an electric transformer maintained by PSE&G, which is in the PJM Interconnection, L.L.C. (PJM) system. This transformer is being replaced, with an expected return to service in June 2005.

In addition, Power’s Waterford, Ohio and Lawrenceburg, Indiana facilities in the Midwest have experienced very low capacity factors due to oversupply conditions, and therefore have provided only modest revenues. Power cannot predict when these market conditions will improve. On May 27, 2005, Power entered into an agreement to sell its electric generation facility located in Waterford, Ohio to a subsidiary of AEP. In May 2005, Power recognized an estimated loss on disposal of $177 million, net of tax, for the initial write-down of its carrying amount of Waterford to its fair value less cost to sell.

On October 24, 2004, Power’s Hope Creek nuclear generation facility transitioned to a planned refueling outage following the unit’s shutdown on October 10, 2004 due to a steam pipe failure. Hope Creek completed its refueling outage and returned to service on January 26, 2005. In an unrelated matter in early December 2004, the two Salem nuclear generation units were taken offline due to an oil spill from a tanker in the Delaware River, near the facilities. The units, which draw river water for cooling purposes, were shut down for about two weeks to avoid intake of the spilled oil. Power anticipates that it will make a filing to seek recovery of damages and losses resulting from the oil spill. It is not possible to predict at this time what the results of this claim will be. The longer-than-planned outage at Hope Creek and an unexpected shutdown of the two Salem nuclear units resulted in additional maintenance and increased replacement power costs and Operation and Maintenance costs.

As previously discussed, Power has entered into an OSC with Exelon Generation in an attempt to improve nuclear operations. Power expects Income from Continuing Operations to range from $335 million to $385 million in 2005. The increase, as compared to 2004 earnings, is expected from anticipated improvements in Power’s nuclear and fossil operations, anticipated higher margins through the expiration of existing contracts, the realization of current and anticipated higher market prices and additional generation going into service. It is expected that these increases will be partially offset by higher Depreciation expense and lower earnings from Power’s NDT Funds.

The improvements discussed above are expected to increase Power’s earnings in the latter part of the five-year planning period. Based on these assumptions, Power expects annual earnings growth in a range of 10% to 14% from 2005 to 2009. Power’s future success as an energy provider will depend, in part, on its ability to meet its obligations under its full requirements contracts efficiently and profitably and the efficient operation of its low-cost nuclear and coal generation facilities. Power’s ability to meet its forecasts are expected to continue to be impacted by low-capacity prices due to the oversupply of electric generation capacity and the resulting competition combined with volatile prices and conditions in energy and fuel markets, including increasing commodity and transportation costs. In addition, such factors could impact liquidity in the event that Power is required to post margin related to its commodity contracts. See Note 14. Commitments and Contingent Liabilities—Guaranteed Obligations of the Notes for additional information.

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Energy Holdings

Energy Holdings, through Global, owns and operates electric generation and distribution facilities in 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 and cash flows.

During 2004, Energy Holdings generated substantial cash flows from operations and asset sales, as discussed below, which it has used to meet its scheduled debt maturity of $267 million in February 2004, repurchase approximately $41 million of its 2007 debt, reducing its next debt maturity to $309 million, and return $491 million of capital to PSEG. In addition, Energy Holdings and its subsidiaries have $199 million of cash (including cash offshore) and a $115 million receivable from PSEG as of December 31, 2004.

For 2005, Energy Holdings expects Income from Continuing Operations to range from $135 million to $155 million. The expected 2005 range exceeds the 2004 Income from Continuing Operations as stronger results from TIE, lower financing costs and the absence of foreign currency losses at Elektrocieplownia Chorzow Sp. Z o.o. (ELCHO) more than offset the loss of earnings from the sale of Meiya Power Company Limited (MPC) and the partial sale of Luz del Sur S.A. (LDS) in 2004. Energy Holdings expects annual earnings growth of 2% to 3% from 2005 to 2009. This expected earnings growth assumes a stable foreign currency environment, combined with expected improvements in earnings from TIE, due to an anticipated recovery in the Texas market, and improved earnings from Global’s facilities in Poland. It is expected that these improvements will be offset by future reductions in revenue related to the collection in January 2005 of the final payment related to the withdrawal from Eagle Point Cogeneration Partnership and the expiration of the contract for the Bridgewater, New Hampshire facility in 2007.

Global

Although Global continues to produce significant earnings and operating cash flow, the returns on its international investment portfolio have not been commensurate with the level of risk associated with international investments in developing energy markets. Such risks include the losses incurred on the abandonment of Global’s Argentine investments in 2002, the devaluation of the Brazilian Real and the corresponding decrease in earnings and cash flow from Global’s investment in Rio Grande Energia S.A. (RGE), the impact of other foreign currency fluctuations and the failure of certain counterparties to honor contracts with certain of Global’s investments. As a result, since 2003, Energy Holdings has refocused its strategy from one of accelerated growth to one that places emphasis on increasing the efficiency and returns of its existing assets and seeks to opportunistically monetize investments that may no longer have a strategic fit.

As part of this process, in 2004, Global completed (1) the sale of its investment in Carthage Power Company (CPC), a generating facility in Rades, Tunisia, for proceeds of $43 million; (2) the sale of a portion of its shares in LDS, a power distribution company in Peru, for proceeds of approximately $31 million; (3) the acquisition of all of TECO Energy Inc.’s (TECO) interests in TIE, which owns two power generation facilities in Texas, for less than $1 million, bringing Global’s ownership interest to 100%; and (4) the sale of its 50% equity interest in MPC for approximately $236 million, of which $100 million was paid in cash and the balance of approximately $136 million is in the form of a note due on March 31, 2005. In January 2005, a $38 million principal payment of this note was received. In addition, as part of this change in strategy, Global continues to limit its capital spending, while focusing on operations and improved performance of existing businesses. In 2005, the capital requirements of Global’s consolidated subsidiaries will primarily be financed from internally generated cash flow within the projects and from local sources on a non-recourse basis or limited discretionary investments by Energy Holdings.

Global’s success will depend, in part, upon its ability to mitigate risks of its international strategy. The economic and political conditions in certain countries where Global has investments present risks that may be different or more significant 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

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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.

Resources

Resources continues to focus on maintaining its current investment portfolio and does not expect to make any new investments. Resources’ objective is to produce predictable cash flows, earnings and related tax benefits while monitoring credit concerns with respect to certain lessees in its portfolio. Resources’ ability to realize tax benefits associated with its leveraged lease investments is dependent upon operating gains generated by its affiliates. In April 2004, Resources terminated its lease with Edison Mission Energy (EME) in the Collins generating facility, strengthening the credit quality of Resources’ remaining exposure with EME, resulting in a weighted average rating of the lessees in Resources’ lease portfolio of A-/A3. As a result of sales during 2004, Resources’ investment in leveraged buyout funds has been reduced from approximately $75 million as of December 31, 2003 to approximately $27 million as of December 31, 2004.

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 $1.2 billion, net of deferred taxes of $1.6 billion, as of December 31, 2004. These investments are largely concentrated in the energy industry and have some exposure to the airline industry. As of December 31, 2004, 69% of counterparties in the lease portfolio were rated investment grade by both Standard & Poors (S&P) and Moody’s. For further discussion of these leveraged leases, see Item 7A. Qualitative and Quantitative Discussion of Market Risk—Credit Risk—Resources.

RESULTS OF OPERATIONS

PSEG, PSE&G, Power and Energy Holdings

Net Income for the year ended December 31, 2004 was $726 million or $3.05 per share of common stock, diluted, based on approximately 238 million average shares outstanding. Net Income for the year ended December 31, 2003 was approximately $1.2 billion or $5.07 per share of common stock, diluted, based on approximately 229 million average shares outstanding. Included in 2003’s Net Income was a $370 million after-tax Cumulative Effect of a Change in Accounting Principle related to the adoption in 2003 of Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143). See Note 3. Asset Retirement Obligations of the Notes. 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 related to the abandoned Argentine investments and losses from operations of those assets, discontinued operations of PSEG Energy Technologies Inc. (Energy Technologies) and Tanir Bavi Power Company Private Ltd. (Tanir Bavi), a generating facility in India, and goodwill impairment charges.

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	Earnings (Losses)
	Years Ended December 31,
	2004			2003			2002
			(Millions)
PSE&G	$	346		$	247		$	205
Power		341			483			468
Energy Holdings:
Global(A)		78			121			(297	)
Resources		68			72			84
Other(B)		(10	)		(4	)		(7	)
Total Energy Holdings(A)		136			189			(220	)
Other(C)(D)		(69	)		(58	)		(48	)
PSEG Income from Continuing Operations		754			861			405
Income (Loss) from Discontinued Operations, including Gain (Loss) on Disposal(E)		(28	)		(53	)		(49	)
Extraordinary Item(F)		—			(18	)		—
Cumulative Effect of a Change in Accounting Principle(G)		—			370			(121	)
PSEG Net Income(A)	$	726		$	1,160		$	235

	Contribution to Earnings Per Share (Diluted)
	Years Ended December 31,
	2004			2003			2002
PSE&G	$	1.45		$	1.08		$	0.98
Power		1.43			2.11			2.24
Energy Holdings:
Global(A)		0.35			0.53			(1.42	)
Resources		0.29			0.31			0.40
Other(B)		(0.04	)		(0.02	)		(0.04	)
Total Energy Holdings(A)		0.60			0.82			(1.06	)
Other(C)(D)		(0.31	)		(0.25	)		(0.22	)
PSEG Income from Continuing Operations		3.17			3.76			1.94
Income (Loss) from Discontinued Operations, including Gain (Loss) on Disposal(E)		(0.12	)		(0.23	)		(0.23	)
Extraordinary Item(F)		—			(0.08	)		—
Cumulative Effect of a Change in Accounting Principle(G)		—			1.62			(0.58	)
PSEG Net Income(B)	$	3.05		$	5.07		$	1.13

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

(B) Other activities include amounts of Energy Holdings (parent company), 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) Includes pre-tax costs related to the Merger of approximately $8 million for the year ended December 31, 2004, including investment banking fees, accounting and legal fees, consulting fees for market analyses and communications costs.

9

(D) Other activities include 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).

(E) Includes Discontinued Operations of Waterford in 2004 and 2003, Energy Technologies in 2003 and 2002, CPC in 2004, 2003 and 2002, and Tanir Bavi in 2002. See Note 4. Discontinued Operations, Dispositions and Acquisitions of the Notes.

(F) Relates to a charge recorded in the second quarter of 2003 from PSE&G’s Electric Base Rate Case. See Note 5. Extraordinary Item of the Notes.

(G) 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 2. Recent Accounting Standards and Note 3. Asset Retirement Obligations of the Notes.

The $107 million, or $0.59 per share, decrease in Income from Continuing Operations for the year ended December 31, 2004, as compared to the same period in 2003, was primarily due to lower earnings at Power due to decreased load being served under the fixed-price BGS contracts, higher Operation and Maintenance costs primarily incurred for work performed during a longer-than-planned refueling outage at the Hope Creek nuclear unit, the loss of MTC revenues, which ceased effective August 1, 2003 at the end of the transition period and higher replacement power and congestion costs in 2004. Also contributing to the decrease were currency fluctuations at Global and lower earnings at Resources, primarily resulting from the termination of the Collins lease. These decreases were partially offset by improved earnings at PSE&G primarily relating to increased electric base rates.

Also contributing to the change in Net Income was Power’s Losses from Discontinued Operations of $33 million for the year ended December 31, 2004, as compared to Losses from Discontinued Operations of $9 million for the year ended December 31, 2003 and Energy Holdings’ Income from Discontinued Operations of $5 million for the year ended December 31, 2004, as compared to its Loss from Discontinued Operations of $44 million, after-tax, for the same period in 2003.

The $456 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 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 PSEG 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 Power’s Losses from Discontinued Operations of $9 million for the year ended December 31, 2003, a decrease in Energy Holdings’ Loss from Discontinued Operations, including Loss on 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 of 2004 and Future Outlook.

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PSEG

	For the Years Ended December 31,									2004 vs 2003					2003 vs 2002
	2004			2003			2002			Increase (Decrease)			%		Increase (Decrease)			%
	(Millions)														(Millions)
Operating Revenues	$	10,991		$	11,135		$	8,220		$	(144	)	(1	)	$	2,915		35
Energy Costs	$	6,053		$	6,387		$	3,710		$	(334	)	(5	)	$	2,677		72
Operation and Maintenance	$	2,247		$	2,117		$	1,899		$	130		6		$	218		11
Depreciation and Amortization	$	706		$	522		$	565		$	184		35		$	(43	)	(8	)
Income from Equity Method Investments	$	126		$	114		$	119		$	12		11		$	(5	)	(4	)
Other Income	$	176		$	178		$	39		$	(2	)	(1	)	$	139		356
Other Deductions	$	(91	)	$	(101	)	$	(80	)	$	(10	)	(10	)	$	21		26
Interest Expense	$	(830	)	$	(829	)	$	(819	)	$	1		—		$	10		1
Income Tax Expense	$	(469	)	$	(470	)	$	(254	)	$	(1	)	—		$	216		85
Loss from Discontinued Operations, including Loss on Disposal, net of tax	$	(28	)	$	(53	)	$	(49	)	$	(25	)	(47	)	$	4		8
Extraordinary Item, net of tax	$	—		$	(18	)	$	—		$	(18	)	(100	)	$	18		100
Cumulative Effect of a Change in Accounting Principle, net of tax	$	—		$	370		$	(121	)	$	(370	)	(100	)	$	491		406

PSEG’s results of operations are primarily comprised of the results of operations of its operating subsidiaries, PSE&G, Power and Energy Holdings, excluding changes related to intercompany transactions, which are eliminated in consolidation and certain financing costs at the parent company. For additional information on intercompany transactions, see Note 23. Related-Party Transactions of the Notes. For a discussion of the causes for the variances at PSEG in the table above, see the discussions for PSE&G, Power and Energy Holdings that follow.

PSE&G

	For the Years Ended December 31,									2004 vs 2003					2003 vs 2002
	2004			2003			2002			Increase (Decrease)			%		Increase (Decrease)			%
	(Millions)														(Millions)
Operating Revenues	$	6,972		$	6,740		$	5,919		$	232		3		$	821		14
Energy Costs	$	4,284		$	4,421		$	3,684		$	(137	)	(3	)	$	737		20
Operation and Maintenance	$	1,083		$	1,050		$	982		$	33		3		$	68		7
Depreciation and Amortization	$	523		$	372		$	409		$	151		41		$	(37	)	(9	)
Other Income	$	12		$	6		$	15		$	6		100		$	(9	)	(60	)
Other Deductions	$	(1	)	$	(1	)	$	(2	)	$	—		—		$	(1	)	(50	)
Interest Expense	$	(362	)	$	(390	)	$	(406	)	$	(28	)	(7	)	$	(16	)	(4	)
Income Tax Expense	$	(246	)	$	(129	)	$	(115	)	$	117		91		$	14		12

Operating Revenues

PSE&G has three sources of revenue: commodity revenues from the sales of energy to customers and in the PJM spot market; delivery revenues from the transmission and distribution of energy through its system; and other operating revenues from the provision of various services.

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Commodity

PSE&G makes no margin on commodity sales as the costs are passed through to customers. The difference between costs and the amount provided by customers in revenues is deferred and collected from or returned to customers in future periods. Total commodity volumes and revenues are subject to market forces. Gas commodity prices fluctuate monthly for commercial and industrial customers and annually through the Basic Gas Supply Service (BGSS) tariff for residential customers. In addition, for residential gas customers, PSE&G has the ability to adjust rates upward two additional times and downward at any time, if warranted, between annual BGSS proceedings.

Gas commodity revenues decreased $3 million for the year ended December 31, 2004, as compared to the same period in 2003, due primarily to lower sales volumes of 20%, offset by higher BGSS prices. Approximately 80% of the volume decline was due to lower sales to cogenerators and the balance was weather-related. Electric commodity prices are set at the annual BGS auction. Electric commodity revenues increased $16 million for the year ended December 31, 2004, as compared to the same period in 2003, primarily due to $249 million in increased prices offset by $233 million in lower volumes of 12% caused by migration of large customers to third-party suppliers.

Gas commodity revenues increased $660 million for the year ended December 31, 2003, as compared to the same period in 2002, due primarily to higher sales volumes of 9% and higher BGSS prices. Electric commodity revenues increased $80 million for the year ended December 31, 2003, as compared to the same period in 2002, primarily due to $217 million in increased prices offset by $137 million in lower volumes of 7% caused by migration of large customers to third-party suppliers.

Delivery

Electric delivery revenues increased $222 million for the year ended December 31, 2004, as compared to the same period in 2003. The net effect of full-year base rate increases in August 2003, combined with other annual rate adjustments in January 2004, increased revenues by $180 million. The balance of the increase was driven by higher sales volumes of 3%. Less than one percent of the sales increase was weather-related.

Gas delivery revenues decreased $24 million for the year ended December 31, 2004, as compared to the same period in 2003, primarily due to a 4% decline in residential sales due to weather. Heating degree days were 5% lower in 2004.

Gas delivery revenues increased $97 million for the year ended December 31, 2003, as compared to the same period in 2002, due to higher sales volumes of 14%, primarily due to weather. Heating degree-days were 21% higher in 2003.

Operating Expenses

Energy Costs

The $137 million decrease for the year ended December 31, 2004, as compared to the same period in 2003, was comprised of decreases of $96 million in electric costs and $41 million in gas costs. The electric decrease was caused by $262 million in lower BGS volumes due to customer migration to third-party suppliers offset by $166 million in higher prices for BGS and Non-Utility Generation (NUG) purchases. The gas decrease was caused by a $388 million or 20% decrease in sales volumes due primarily to lower sales to cogenerators offset by a $347 million or 26% increase in gas prices.

The $737 million increase for the year ended December 31, 2003, as compared to the same period in 2002, was comprised of increases of $658 million in gas costs and $79 million in electric costs. The gas increase was caused by a $527 million or 26% increase in gas prices and $131 million or 9% increase in sales volumes. The electric increase was caused by $249 million in higher prices for BGS and NUG purchases, partially offset by $170 million in lower costs due to lower BGS volumes as the result of customer migration and lower NUG volumes.

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Operation and Maintenance

The $33 million increase for 2004, as compared to the same period in 2003, was due primarily to increased Demand Side Management (DSM) amortization of $20 million, increased consumer education expenses of $24 million, an $18 million reduction in real estate tax expense in 2003 and $10 million related to a regulatory asset reserve reversal in 2003. DSM costs are deferred when incurred and amortized to expense when recovered in revenues. Offsetting the increases were decreased labor and fringe benefits of $7 million, due to lower pension costs as a result of improved fund performance, a $22 million reduction in Societal Benefits Charges (SBC) expenses and $10 million in lower shared services costs due to reduced technology spending.

The $68 million increase for the year ended December 31, 2003, as compared to the same period in 2002, was due primarily to higher labor and fringe benefit costs of $48 million, due to higher wage and incentive program costs, 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 related to the increased sales, discussed above. Partially offsetting these increases were 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.

Depreciation and Amortization

The $151 million increase for the year ended December 31, 2004, as compared to the same period in 2003, was due primarily to a $132 million reduction in amortization of an excess electric distribution depreciation reserve regulatory liability, a $30 million increase in the amortization of various regulatory assets and a $10 million increase due to increased plant in service. These increases were offset by a $16 million decrease from the use of a lower book depreciation rate for electric distribution property, which took effect in August 2003 following the conclusion of the electric base rate case, and a $6 million decrease due to plant assets transferred to an affiliate in 2003.

The $37 million decrease for the year ended December 31, 2003, as compared to the same period in 2002, was due primarily to a $52 million increase in amortization of an excess electric distribution depreciation reserve regulatory liability and an $11 million decrease from the use of a lower book depreciation rate for electric distribution property starting in August 2003 due to the rate case referred to above. These decreases were offset by increases of $13 million due to increased plant in service and $9 million due to amortization of regulatory assets related to securitization.

Other Income

The $6 million increase for the year ended December 31, 2004, as compared to the same period in 2003, was due primarily to $11 million of equity return adjustments to regulatory assets in 2003, $4 million of interest income related to an affiliate loan and other Investment Income of $3 million offset by decreased gains on excess property sales of $12 million.

The $9 million decrease for the year ended December 31, 2003, as compared to the same period in 2002, was due primarily to equity return adjustments to regulatory assets of $11 million offset by $2 million in increased gains on the disposal of various electric transmission properties.

Interest Expense

The $28 million decrease for the year ended December 31, 2004, as compared to the same period in 2003, was due primarily to lower interest on long-term debt of $37 million as a result of lower interest rates and lower levels of long-term debt outstanding, partially offset by $11 million in increased interest on affiliated loans.

The $16 million decrease for the year ended December 31, 2003, as compared to the same period in 2002, was due primarily to lower interest on long-term debt of $23 million 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 carrying charges related to certain regulatory assets.

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Income Taxes

The $117 million increase for the year ended December 31, 2004, as compared to the same period in 2003, was primarily due to higher pre-tax income combined with lower tax benefits primarily attributable to the excess depreciation reserve adjustment in 2003.

The $14 million increase for the year ended December 31, 2003, as compared to the same period in 2002, was due to higher pre-tax income, offset by tax benefits recorded in 2003 attributable to the actual filing of the 2002 tax return.

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 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 Financial Accounting Standards Board (FASB) Statement No. 71.”

Power

	For the Years Ended December 31,									2004 vs 2003					2003 vs 2002
	2004			2003			2002			Increase (Decrease)			%		Increase (Decrease)			%
				(Millions)											(Millions)
Operating Revenues	$	5,169		$	5,609		$	3,640		$	(440	)	(8	)	$	1,969		54
Energy Costs	$	3,555		$	3,750		$	1,856		$	(195	)	(5	)	$	1,894		102
Operation and Maintenance	$	954		$	911		$	773		$	43		5		$	138		18
Depreciation and Amortization	$	108		$	97		$	108		$	11		11		$	(11	)	(10	)
Other Income	$	166		$	149		$	1		$	17		11		$	148		N/A
Other Deductions	$	(55	)	$	(78	)	$	(1	)	$	(23	)	(29	)	$	77		N/A
Interest Expense	$	(113	)	$	(107	)	$	(122	)	$	6		6		$	(15	)	(12	)
Income Tax Expense	$	(209	)	$	(332	)	$	(313	)	$	(123	)	(37	)	$	19		6
Loss from Discontinued Operations, including Loss on Disposal, net of tax	$	(33	)	$	(9	)	$	—		$	24		267		$	9		100
Cumulative Effect of a Change in Accounting Principle, net of tax	$	—		$	370		$	—		$	(370	)	(100	)	$	370		100

Operating Revenues

Operating Revenues decreased by $440 million for the year ended December 31, 2004, as compared to the same period in 2003, due to decreases of $485 million in generation revenues and $5 million in trading revenues offset by an increase of $50 million in gas supply revenues.

Operating Revenues increased by $2 billion for the year ended December 31, 2003, as compared to the same period in 2002, due to increases of $646 million in generation revenues, $1.3 billion in gas supply revenues and $12 million in trading revenues.

Generation

Generation revenues decreased by $485 million for the year ended December 31, 2004, as compared to the same period in 2003, primarily due to $1.1 billion in lower revenues due to decreased load being served under the fixed-priced BGS contracts, which was partially offset by $869 million of higher revenues from new contracts and

14

higher sales into the various power pools. Additionally, the loss of MTC and NDT revenues, which amounted to $111 million and $17 million, respectively, comprised part of the decrease.

Also contributing to the decrease was the adoption of Emerging Issues Task Force (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), which requires gains and losses (realized and unrealized) on all derivative instruments within the scope of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133) to 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, which became effective on a prospective basis for transactions occurring after September 30, 2003. Since prior periods were not restated, the effect of adopting EITF 03-11 reduced Power’s Operating Revenues by approximately $174 million, with an equal reduction in Energy Costs, as compared to the same period in 2003.

Generation revenues increased by $641 million for the year ended December 31, 2003, as compared to the same period in 2002, primarily due to increased BGS related revenues of $293 million from third-party wholesale electric suppliers which commenced on August 1, 2002 and $149 million in increased revenues from two generation facilities in Connecticut acquired in 2002. Also contributing to the increase were increased MTC revenues of $13 million, increased capacity sales of $41 million and $167 million of higher revenues from new contracts and higher sales into the various power pools.

Gas Supply

Gas supply revenues increased by $50 million for the year ended December 31, 2004, as compared to the same period in 2003, primarily due to higher gas prices under the BGSS contract partially offset by decreased sales volumes mainly due to demand by PSE&G.

Gas supply revenues increased by $1.3 billion for the year ended December 31, 2003, as compared to the same period in 2002, primarily due to 2003 being the first full year of the 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.

Operating Expenses

Energy Costs

Energy Costs represent the cost of generation, which includes fuel purchases for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G.

Energy Costs decreased approximately $195 million for the year ended December 31, 2004, as compared to the same period in 2003, primarily due to a $216 million decrease in purchased power due to decreased load being served under the BGS contracts, which was offset by increased replacement power costs due to outages and higher purchased power for new contracts and a $12 million increase in gas supply costs due to higher gas prices. For additional information related to the outages at Power facilities, see the MD&A—Overview of 2004 and Future Outlook—Power. Also contributing to the decrease for the year was a reduction of approximately $174 million related to the adoption of EITF 03-11, as discussed above. Partially offsetting these decreases were higher fuel costs for generation of approximately $159 million, primarily related to higher gas prices and higher usage, including an increase of approximately $20 million related to the settlement for nuclear waste storage costs for Peach Bottom. For additional information regarding the settlement, see Note 14. Commitments and Contingent Liabilities—Nuclear Fuel Disposal of the Notes.

Energy Costs increased approximately $1.9 billion for the year ended December 31, 2003, 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

15

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. In addition, 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.

Operation and Maintenance

Operation and Maintenance expense increased $43 million for the year ended December 31, 2004, as compared to the same period in 2003, due to increased costs of $85 million related to the outages at Hope Creek, Salem and Mercer. For additional information related to the outages at Power facilities, see the MD&A—Overview of 2004 and Future Outlook—Power. This was offset by $12 million related to the settlement for nuclear waste storage costs for Peach Bottom and $10 million in lower real estate taxes and other items. Additional offsets include the absence of reorganization costs of $9 million and the lower write-down costs related to obsolete materials and supplies of $8 million. For additional information regarding the settlement, see Note 14. Commitments and Contingent Liabilities—Nuclear Fuel Disposal of the Notes.

Operation and Maintenance expense increased $138 million for the year ended December 31, 2003, as compared to the same 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 and higher nuclear refueling outage costs of $24 million. Also contributing to the increase were higher pension expense of $20 million, higher reorganization costs of $9 million and higher write-down costs related to obsolete materials and supplies of $8 million.

Depreciation and Amortization

Depreciation and Amortization expense increased $11 million for the year ended December 31, 2004, as compared to the same period in 2003, primarily due to the Lawrenceburg facility being placed into service in June 2004.

Depreciation and Amortization expense decreased $11 million for the year ended December 31, 2003, as compared to the same period in 2002. The net decrease was comprised 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.

Other Income

Other Income increased $17 million for the year ended December 31, 2004, as compared to the same period in 2003, due primarily to increased realized gains and income related to the NDT Funds.

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

Other Deductions

Other Deductions decreased by $23 million for the year ended December 31, 2004, as compared to the same period in 2003, primarily due to $28 million in lower realized losses and expenses related to the NDT Funds partially offset by a $5 million write-off of unamortized issuance costs related to the extinguishment of project financing related to Power’s Lawrenceburg facility.

Other Deductions increased by $77 million for the year ended December 31, 2003, as compared to the same period in 2002, due primarily to the recording of realized losses on the NDT Funds.

Interest Expense

Interest Expense increased by $6 million for the year ended December 31, 2004, as compared to the same period in 2003, due primarily to $4 million related to an affiliate loan and additional interest on increased levels of long-term debt outstanding.

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Interest Expense decreased by $15 million for the year ended December 31, 2003, as compared to the same period in 2002. Capitalized interest relating to various construction projects reduced interest expense by approximately $29 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 partially offset by lower interest expense on variable rate debt and other lower charges of approximately $6 million.

Income Taxes

Income taxes decreased by $140 million for the year ended December 31, 2004, as compared to the same period in 2003, due primarily to lower pre-tax income.

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

Loss from Discontinued Operations, including Loss on Disposal, net of tax

On May 27, 2005, Power reached an agreement to sell its Waterford generation facility for approximately $220 million and recognized a loss on disposal of approximately $177 million for the initial write-down of its carrying amount of Waterford to its fair value less cost to sell. It is anticipated that the transaction will close during the second half of 2005. See Note 4. Discontinued Operations, Dispositions and Acquisitions of the Notes for additional information.

Cumulative Effect of a Change in Accounting Principle

For the year ended December 31, 2003, Power recorded an after-tax benefit in the amount of $370 million due to the required remeasurement of Power’s nuclear and fossil decommissioning obligations under SFAS 143, which was adopted on January 1, 2003. See Note 3. Asset Retirement Obligations of the Notes for additional information.

Energy Holdings

	For the Years Ended December 31,									2004 vs 2003					2003 vs 2002
	2004			2003			2002			Increase (Decrease)			%		Increase (Decrease)			%
				(Millions)											(Millions)
Operating Revenues	$	1,027		$	725		$	609		$	302		42		$	116		19
Energy Costs	$	388		$	155		$	118		$	233		150		$	37		31
Operation and Maintenance	$	239		$	176		$	168		$	63		36		$	8		5
Write-down of Project Investments	$	—		$	—		$	511		$	—		—		$	(511	)	(100	)
Depreciation and Amortization	$	57		$	44		$	28		$	13		30		$	16		57
Income from Equity Method Investments	$	126		$	114		$	119		$	12		11		$	(5	)	(4	)
Other Income	$	4		$	20		$	26		$	(16	)	(80	)	$	(6	)	(23	)
Other Deductions	$	(33	)	$	(5	)	$	(77	)	$	28		560		$	(72	)	(94	)
Interest Expense	$	(255	)	$	(218	)	$	(217	)	$	37		17		$	1		—
Income Tax (Expense) Benefit	$	(48	)	$	(59	)	$	144		$	(11	)	(19	)	$	203		141

The variances in Operating Revenues, Energy Costs, Operation and Maintenance expense, Depreciation and Amortization expense and Income from Equity Method Investments were primarily attributed to Global’s acquisition of the remaining interests in TIE, thus consolidating the entity effective July 1, 2004, as compared to 2003 when Global’s ownership was accounted for under the equity method of accounting. For additional information, see Note 4. Discontinued Operations, Dispositions and Acquisitions of the Notes. The increases were also due to ELCHO placing a new generation facility in Poland in service in November 2003, a generation facility in Oman owned by Dhofar Power Company S.A.O.C. (Dhofar Power) beginning commercial operation in May 2003 and increases in ownership of Electrowina Skawina S.A (Skawina) in Poland in 2003 and 2004. The variances are also related to favorable foreign currency exchange rates and higher energy sales volumes at Sociedad Austral de Electricidad S.A. (SAESA) and a change for GWF Energy LLC (GWF Energy), which owns three generation

17

facilities in California, which was accounted for under the equity method of accounting in 2004, due to a change in ownership interest, as compared to the first nine months of 2003 and the fourth quarter of 2002 when GWF Energy was consolidated.

Operating Revenues

The increase of $302 million for the year ended December 31, 2004, as compared to the same period in 2003, was due to higher revenues at Global of $355 million, including a $247 million increase related to the consolidation of TIE, a $62 million increase from ELCHO, a $35 million increase from SAESA, a $25 million increase from Dhofar Power and a $35 million gain on the sale of MPC, partially offset by a decrease of $53 million related to GWF Energy, which was not consolidated in 2004. Offsetting the increases at Global were lower revenues at Resources of $51 million, primarily due to a loss of $31 million related to the recalculation of certain leverage leases, a loss of $11 million due to the termination of the lease investment in the Collins generating facility and normal amortization of existing leases of $10 million offset by a realized gain of $2 million related to investments in leases, partnerships and securities. See Note 10. Long-Term Investments of the Notes for additional information.

The increase of $116 million for the year ended December 31, 2003, as compared to the same period in 2002, was due to higher revenues at Global of $124 million, including a $47 million increase from Skawina, a $38 million increase from Dhofar Power, a $28 million increase from GWF Energy, which was consolidated for nine months in 2003 compared to three months in 2002, and a $19 million increase from SAESA, 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. Offsetting the increases at Global were lower revenues at Resources of $10 million, 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 these decreases 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.

Energy Costs

The increase of $233 million for the year ended December 31, 2004, as compared to the same period in 2003, was primarily due to a $192 million increase related to the consolidation of TIE and increases of $22 million, $12 million and $5 million from SAESA, ELCHO and Dhofar Power, respectively, offset by a decrease of $3 million from GWF Energy.

The increase of $37 million for the year ended December 31, 2003, as compared to the same period in 2002, was primarily due to increases of $21 million, $14 million, and $13 million from Skawina, SAESA and Dhofar Power, respectively, offset by decreases of $7 million and $5 million from EDEERSA and Electroandes S.A. (Electroandes), respectively.

Operation and Maintenance

The increase of $63 million for the year ended December 31, 2004, as compared to the same period in 2003, was primarily due to a $30 million increase related to the consolidation of TIE and increases of $12 million, $9 million, and $2 million from ELCHO, SAESA and Dhofar Power, respectively, offset by a decrease of $8 million from GWF Energy. The increase is also due to higher operating expenses of $9 million at PSEG Energy Technologies Asset Management Company L.L.C. primarily due to higher legal expenses and final asset sale settlements and $7 million at Global primarily due to the 2003 reversal of contingencies related to the Argentine write-down.

The increase of $8 million for the year ended December 31, 2003, as compared to the same period in 2002, was primarily due to increases of $19 million, $7 million, $6 million and $6 million from Skawina, Dhofar Power, GWF Energy and Electroandes, respectively, offset by decreased operation and maintenance expenses at Global of $28 million related to the abandonment of Global’s Argentine investments combined with lower labor and administrative costs.

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Write-down of Project Investments

The decrease of $511 million for the year ended December 31, 2003, as compared to the same period in 2002, was primarily due to Global’s write-down of investments in 2002, primarily in Argentina. See Note 6. Asset Impairments of the Notes.

Depreciation and Amortization

The increase of $13 million for the year ended December 31, 2004, as compared to the same period in 2003, was primarily due to a $9 million increase related to the consolidation of TIE and increases of $7 million, $5 million and $2 million from ELCHO, Dhofar Power and SAESA, respectively, offset by a decrease of $11 million from GWF Energy.

The increase of $16 million for the year ended December 31, 2003, as compared to the same period in 2002, was primarily due to increases of $8 million from both Dhofar Power and GWF Energy.

Income from Equity Method Investments

The increase of $12 million for the year ended December 31, 2004, as compared to the same period in 2003, was primarily driven by an $8 million increase related to the sale of a portion of Global’s investment in LDS, an $11 million increase related to MPC due to additional projects going into operation, and a $4 million increase related to GWF Energy, offset by an $11 million decrease related to the consolidation of TIE commencing July 1, 2004.

The decrease of $5 million for the year ended December 31, 2003, as compared to the same period in 2002, was primarily due to lower equity method income 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 Energia S.A. (Chilquinta) of $4 million. Partially offsetting this decrease were improved earnings at TIE of $14 million related to power purchase agreements (PPAs) entered into in early 2003 and improved market conditions in Texas.

Other Income

The decrease of $16 million for the year ended December 31, 2004, as compared to the same period in 2003, was primarily due to the absence in 2004 of foreign currency transaction gains of $16 million for RGE and SAESA that occurred in 2003.

The decrease of $6 million for the year ended December 31, 2003, as compared to the same period in 2002, was primarily due to the absence of favorable changes in fair value mainly relating to foreign exchange contracts held by Energy Holdings.

Other Deductions

The increase of $28 million for the year ended December 31, 2004, as compared to the same period in 2003, was primarily due to foreign currency transaction losses of $26 million and a loss on early extinguishment of debt of $3 million in 2004, offset by a $5 million favorable change in derivative fair value related to Global. The $26 million in foreign currency transaction losses was almost entirely due to the impact of the weakening U.S. Dollar relative to the Polish Zloty on Global’s investment in ELCHO. At the inception of this investment, it was determined that ELCHO is a U.S. Dollar functional currency as a portion of the long-term PPA with the Polish government is indexed to the U.S. Dollar to support the portion of ELCHO’s financing that is U.S. Dollar denominated. Since ELCHO has a U.S. Dollar functional currency, all monetary assets and liabilities that are not denominated in U.S. Dollars are marked at period-end exchange rates with changes in values recorded as gains or losses in earnings. ELCHO has significant monetary liabilities in local currency, namely Polish Zloty debt used to partially finance the construction of the plant. As a result of the strengthening of the Polish Zloty against the U.S. Dollar in 2004, there were material losses recorded on the Polish Zloty debt to reflect the greater amount of U.S. Dollars required to pay the local debt. However, the accounting model does not capture the increase in value of Polish Zlotys that will be received under the long-term PPA with the Polish government as the contract is not recorded on the balance sheet. As a result, the financial statements only reflect the losses on the Polish Zloty debt which, economically, have been more than offset by the increase in the value of the Polish Zlotys that will be received under the PPA.

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The decrease of $72 million for the year ended December 31, 2003, as compared to the same period in 2002, was largely due to a $77 million foreign currency transaction loss during 2002, which primarily related to Global’s Argentine investments.

Interest Expense

The increase of $37 million for the year ended December 31, 2004, as compared to the same period in 2003, was due to a $13 million increase related to the consolidation of TIE commencing on July 1, 2004, a $29 million increase related to ELCHO since interest was no longer capitalized as the plant became operational in the fourth quarter of 2003, and an increase in non-recourse debt at the project level with higher interest rates, offset in part by the repayment of lower interest rate debt at Energy Holdings during 2003 and 2004.

Income Taxes

The decrease of $11 million for the year ended December 31, 2004, as compared to the same period in 2003, was primarily due to lower pre-tax income and the impact of changes in certain lease forecast assumptions. In the fourth quarter of 2004, Resources revised several of its lease runs and recorded additional benefits of state tax losses generated by certain of its leases. These additional benefits resulted from changes in Resources’ forecast of state taxable income and tax liability over the relevant lease terms. This forecast was embedded in the lease reruns and led to an income tax benefit of $43 million in 2004 to reflect the cumulative benefit of this adjustment. This benefit was largely offset by the tax impact associated with a $31 million decrease in leveraged lease revenue. Future earnings will also increase by a modest amount as a result of this forecasted benefit. If Resources affiliates’ taxable earnings decreased significantly, resulting in the inability of Resources to record the benefits related to its taxable losses, it could lead to an adverse material impact to Resources’ results of operations, financial position and cash flows. See Note 17. Income Taxes of the Notes for additional information.

The increase of $203 million for the year ended December 31, 2003, as compared to the same period in 2002, was 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. See Note 6. Asset Impairments of the Notes.

Income (Loss) from Discontinued Operations, including Gain (Loss) on Disposal, net of tax

Carthage Power Company (CPC)

In May 2004, Global completed the sale of its interest in CPC for approximately $43 million in cash and recognized a gain on disposal of $5 million after-tax. Loss from Discontinued Operations for the year ended December 31, 2003 was $24 million including a $23 million estimated loss on disposal for the write-down of CPC to its fair value less cost to sell. The operating results of CPC for the year ended December 31, 2002 yielded after-tax income of approximately $1 million. See Note 4. Discontinued Operations, Dispositions and Acquisitions of the Notes for additional information.

Energy Technologies

In September 2003, Energy Holdings completed the sale of the remaining companies of Energy Technologies subsequent to recognizing a loss of $9 million, after-tax, in the first quarter of 2003. Loss from Discontinued Operations for years ended December 31, 2003 and 2002 were $11 million and $41 million, respectively, including the initial write-down in 2002. See Note 4. Discontinued Operations, Dispositions and Acquisitions of the Notes for additional information.

Tanir Bavi

In the fourth quarter of 2002, Global sold its 74% interest in Tanir Bavi, a 220 MW 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 year ended December 31, 2002 yielded after-tax income of $5 million. See Note 4. Discontinued Operations, Dispositions and Acquisitions of the Notes.

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Cumulative Effect of a Change in Accounting Principle

In 2002, Energy Holdings finalized the evaluation of the effect of adopting SFAS 142 on its recorded amount of goodwill. Under this standard, Energy Holdings 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 9. Goodwill and Other Intangibles of the Notes.

Other

To supplement the Consolidated Financial Statements presented in accordance with accounting principles generally accepted in the U.S. (GAAP), PSEG and Energy Holdings use the non-GAAP measure of Earnings Before Interest and Taxes (EBIT).

PSEG’s and Energy Holdings’ Management each reviews EBIT internally to evaluate performance and manage operations and believes that the inclusion of this non-GAAP financial measure provides consistent and comparable measures to help shareholders understand current and future operating results. PSEG and Energy Holdings urge shareholders to carefully review the GAAP financial information included as part of this Annual Report.

Global

The following table summarizes Global’s capital at risk, net contributions to EBIT and non-recourse interest in the following regions as of December 31, 2004 and 2003 and for the years ended December 31, 2004, 2003 and 2002.

	Total Capital at Risk(A)
	As of December 31, 2004			As of December 31, 2003			EBIT(B)									Non-Recourse Interest(C)
							2004			2003			2002			2004		2003		2002
							(Millions)
Region:
North America		$	427		$	423	$	98		$	117		$	122		$	13	$	2	$	—
South America			1,581			1,575		135			150			(441	)		33		27		44
Asia Pacific(D)			6			180		54			8			7			—		—		—
Europe(E)			209			285		24			22			(8	)		33		5		—
India and Oman			94			91		18			9			—			15		9		—
Global G&A—Unallocated			—			—		(31	)		(30	)		(38	)		—		—		—
Total		$	2,317		$	2,554	$	298		$	276		$	(358	)	$	94	$	43	$	44
Total Global EBIT							$	298		$	276		$	(358	)
Interest Expense								(170	)		(119	)		(118	)
Income Taxes(D)								(49	)		(23	)		178
Minority Interests								(1	)		(13	)		1
Income from Continuing Operations							$	78		$	121		$	(297	)

______________

(A) Total Capital at Risk includes Global’s gross investments and equity commitment guarantees less non-recourse debt at the project level.

(B) For investments accounted for under the equity method of accounting, includes Global’s share of net earnings, including Interest Expense and Income Taxes.

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(C) Non-recourse interest is Interest Expense on debt that is non-recourse to Global.

(D) The differences in EBIT and Capital at Risk for Asia Pacific and Income Taxes are primarily due to the sale of MPC which closed on December 31, 2004. The 2004 Capital at Risk does not include the $136 million promissory note received from the sale of MPC. See Note 4. Discontinued Operations, Dispositions and Acquisitions of the Notes.

(E) Foreign currency exchange losses at ELCHO were $28 million, $2 million, and $3 million for the years ended December 31, 2004, 2003 and 2002, respectively.

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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) 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 financial advantages, such as favorable legal liability treatment. PSEG consolidates SPEs, as applicable, in accordance with FASB Interpretation No. (FIN) 46, “Consolidation of Variable Interest Entities (VIEs)” (FIN 46). See Note 2. Recent Accounting Standards of the Notes.

The availability and cost of external capital is 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, 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.

It is expected that pursuant to the Merger Agreement, PSEG and Power will be consolidated into the combined company and all debt outstanding at PSEG and Power will be assumed by the new entities. Under the current plan, PSE&G’s and Energy Holdings’ securities will continue to be outstanding.

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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 cash flows. Non-recourse 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 include 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 and/or Energy Holdings for their respective subsidiaries. PSEG does not provide guarantees or credit support to Energy Holdings or its subsidiaries.

Operating Cash Flows

PSEG

For the year ended December 31, 2004, PSEG’s operating cash flow increased by approximately $117 million from $1.5 billion to $1.6 billion, as compared to the same period in 2003, due to net increases from its subsidiaries as discussed below.

For the year ended December 31, 2003, PSEG’s operating cash flow increased by approximately $258 million from $1.2 billion to $1.5 billion, as compared to the same period in 2002, due to net increases from its subsidiaries as discussed below.

PSE&G

PSE&G’s operating cash flow increased approximately $95 million from $704 million to $695 million for the year ended December 31, 2004, as compared to the same period in 2003 primarily due to higher Net Income related to the increase in electric base rates, additional regulatory recoveries and lower benefit plan contributions.

PSE&G’s operating cash flow decreased approximately $223 million from $832 million to $609 million for the year ended December 31, 2003, as compared to same period in 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 decreased approximately $127 million from $624 million to $497 million for the year ended December 31, 2004, as compared to the same period in 2003 due to a decrease in Income from Continuing Operations of $166 million, primarily due to lower sales volumes and higher replacement power and maintenance costs combined with the loss of MTC revenues which ended August 1, 2003 offset by activity in the NDT Funds.

Power’s operating cash flow increased approximately $207 million from $417 million to $624 million for the year ended December 31, 2003, as compared to the same period in 2002. The 2002 operating cash flow was abnormally low, due to the purchase of 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.

Energy Holdings

Energy Holdings’ operating cash flow increased approximately $115 million from $294 million to $409 million for the year ended December 31, 2004, as compared to the same period in 2003, due primarily to a tax payment made in 2003 related to two terminated leveraged lease transactions in 2002 and sales of certain investments in the KKR leveraged buyout fund in 2004.

Energy Holdings’ operating cash flow increased approximately $186 million from $108 million to $294 million for the year ended December 31, 2003, as compared to the same period in 2002. This increase is primarily

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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 measure PSEG uses to manage the business is operating cash flows. PSEG also uses cash available to pay down recourse debt (i.e., excess cash) as a metric. Cash available to pay down recourse debt is calculated by taking PSEG’s operating cash flows, less investing activities and net dividends and adjusted for items such as securitization bond principal repayments, offshore cash activity and the impact of consolidation accounting at Energy Holdings.

In 2004, PSEG had cash available to pay down recourse debt exceeding $100 million, which was substantially supported by the monetization of assets and lease terminations by Energy Holdings with approximately $300 million in net proceeds. 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 latter part of its business plan cycle as capital expenditures are expected to decrease materially after 2005 when the current construction program at Power is completed.

Common Stock Dividends

Dividend payments on common stock for the year ended December 31, 2004 were $2.20 per share and totaled approximately $522 million. Dividend payments on common stock for the year ended December 31, 2003 were $2.16 per share and totaled approximately $493 million. Future dividends declared will be dependent upon PSEG’s future earnings, cash flows, financial requirements, alternative investment opportunities and other factors. On January 18, 2005, PSEG announced an increase in its dividend from $0.55 to $0.56 per share for the first quarter of 2005. This quarterly increase reflects an indicated annual dividend rate of $2.24 per share.

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Short-Term Liquidity

PSEG, PSE&G, Power and Energy Holdings

As of December 31, 2004, PSEG and its subsidiaries had a total of approximately $2.7 billion of committed credit facilities with approximately $1.9 billion of available liquidity under these facilities. In addition, PSEG and PSE&G have access to certain uncommitted credit facilities. PSEG had no loans outstanding and PSE&G had $15 million outstanding under these uncommitted facilities as of December 31, 2004. Each of the facilities is restricted to availability and use to the specific companies as listed below.

Company	Expiration Date	Total Facility		Primary Purpose	Usage as of 12/31/2004			Available Liquidity as of 12/31/2004
				(Millions)
PSEG:
4-year Credit Facility	April 2008	$	450	CP Support/ Funding/Letters of Credit	$	—		$	450
5-year Credit Facility	March 2005	$	280	CP Support	$	280		$	—
3-year Credit Facility	December 2005	$	350	CP Support/ Funding/Letters of Credit	$	153		$	197
Uncommitted Bilateral Agreement	N/A		N/A	Funding	$	—			N/A
Bilateral Term Loan	April 2005	$	75	Funding	$	75		$	—
Bilateral Revolver	April 2005	$	25	Funding	$	25		$	—
PSE&G:
5-year Credit Facility	June 2009	$	600	CP Support/ Funding/Letters of Credit	$	90		$	510
Uncommitted Bilateral Agreement	N/A		N/A	Funding	$	15			N/A
PSEG and Power:
3-year Credit Facility(A)	April 2007	$	600	CP Support/ Funding/Letters of Credit	$	17	(B)	$	583
Power:
3-year Credit Facility	August 2005	$	25	Funding/Letters of Credit	$	—		$	25
Bilateral Credit Facility	March 2010	$	100	Funding/Letters of Credit	$	90	(B)	$	10
Energy Holdings:
3-year Credit Facility(C)	October 2006	$	200	Funding/Letters of Credit	$	31	(B)	$	169

______________

(A) PSEG/Power co-borrower facility.

(B) These amounts relate to letters of credit outstanding.

(C) Energy Holdings/Global/Resources joint and several co-borrowed facility. PSEG

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PSEG

As noted above, S&P downgraded PSEG’s commercial paper rating on July 30, 2004. This has limited PSEG’s ability to access the commercial paper market; however, PSEG believes it has sufficient liquidity to fund its short-term cash needs. PSEG expects to renew its $280 million and $350 million credit facilities which expire in 2005.

PSE&G

In June 2004, PSE&G entered into a $600 million five-year credit facility. This facility replaced the expiring $200 million 364-day credit facility and the $200 million three-year credit facility that was to expire in June 2005.

As noted above, S&P downgraded PSE&G’s commercial paper rating on July 30, 2004. This has limited PSE&G’s ability to access the commercial paper market; however, PSE&G believes it has sufficient liquidity to fund its short-term cash needs.

Power

In October 2004, Power entered into a $100 million bilateral credit facility that expires in March 2010. This facility is available to Power for both letters of credit and funding.

As of December 31, 2004, in addition to amounts outstanding under Power’s credit facilities shown in the above table, Power had borrowed approximately $98 million from PSEG.

Power expects to renew its $25 million credit facility which expires in August 2005.

As noted above, S&P placed Power on negative outlook on July 30, 2004. Power believes it has sufficient liquidity to meet any required posting of collateral resulting from a downgrade. See Note 14. Commitments and Contingent Liabilities of the Notes for further information.

Energy Holdings

As of December 31, 2004, Energy Holdings had loaned $115 million of excess cash to PSEG. In addition, Energy Holdings and its subsidiaries had $199 million in cash, including $139 million invested offshore, as of December 31, 2004.

External Financings

PSEG

In September 2004, PSEG issued and sold $200 million of its 4.66% Series A Senior Notes due 2009 in a private placement. The proceeds were used to reduce 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, 2004, PSEG issued approximately 1.9 million shares for approximately $83 million pursuant to these plans.

PSE&G

In August 2004, PSE&G issued $104 million of its First and Refunding Mortgage Bonds, Pollution Control Series AC due 2031, $88 million of its First and Refunding Mortgage Bonds, Pollution Control Series AD due 2030 and $93 million of its First and Refunding Mortgage Bonds, Pollution Control Series AE due 2029. The proceeds were used to refund $104 million of PSE&G’s First and Refunding Mortgage Bonds, Pollution Control Series Q due 2031 and $88 million of PSE&G’s First and Refunding Mortgage Bonds, Pollution Control Series R due 2030 in August 2004 as well as $93 million of PSE&G’s First and Refunding Mortgage Bonds, Pollution Control Series S due 2029 in October 2004.

In August 2004, PSE&G issued $250 million of its Secured Medium-Term Notes Series D due 2014. The proceeds were used to redeem the remaining outstanding $254 million of PSE&G’s First and Refunding Mortgage Bonds, 7% Series SS due 2024 in September 2004.

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In June 2004, PSE&G issued $175 million two-year floating rate First and Refunding Mortgage Bonds. The interest is set quarterly at LIBOR plus 0.125%. The proceeds were primarily used to redeem $159 million of 7.375% Series TT First and Refunding Mortgage Bonds due 2014 in June 2004.

In May 2004, $286 million of PSE&G’s 6.50% Series PP First and Refunding Mortgage Bonds matured.

In addition, PSE&G paid common stock dividends totaling approximately $100 million to PSEG in 2004.

In December 2004, September 2004, June 2004 and March 2004, PSE&G Transition Funding LLC (Transition Funding) repaid approximately $39 million, $37 million, $30 million and $32 million, respectively, of its transition bonds.

Power

In October 2004, PSEG contributed approximately $300 million of equity to Power.

In March 2004, Power issued $250 million of 3.75% Senior Notes due April 2009 and $250 million of 5.00% Senior Notes due April 2014. The net proceeds of $488 million, together with other available cash, were used to fund the repayment of $800 million of project finance debt to certain of Power’s subsidiaries.

Energy Holdings

During 2004, Energy Holdings made cash distributions to PSEG totaling $491 million in the form of preference unit redemptions, preference unit distributions, ordinary unit distributions and return of capital contributed. In February 2005, Energy Holdings returned an additional $100 million of capital to PSEG in the form of an ordinary unit distribution.

During the second quarter of 2004, Energy Holdings repurchased approximately $41 million of its 7.75% Senior Notes due April 2007 at a premium of $3 million, reducing the aggregate amount of that security outstanding to $309 million.

In February 2004, Energy Holdings repaid $267 million of its 9.125% Senior Notes at maturity.

During 2004, Skawina and SAESA issued a total of approximately $15 million of non-recourse project debt.

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 (including preferred securities outstanding) 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, 2004, PSEG’s ratio of debt to capitalization (as defined above) was 57.5%. PSEG expects to continue to meet the financial covenants.

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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, 2004, PSE&G’s ratio of long-term debt to total capitalization (as defined above) was 51.4%.

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 to 1, and/or against retired Mortgage Bonds. As of December 31, 2004, PSE&G’s Mortgage coverage ratio was 5.41 to 1 and the Mortgage would permit up to approximately $1.6 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, 2004, Power’s ratio of debt to capitalization (as defined above) was 46.8%.

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 $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 1.75. As of December 31, 2004, Energy Holdings’ coverage of this covenant was 2.51. Additionally, Energy Holdings must maintain a ratio of net debt to EBITDA of less than 5.25. As of December 31, 2004, Energy Holdings’ ratio under this covenant was 4.29. 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 during any 12-month period in excess of 10% must be retained by Energy Holdings or used to repay the debt of Energy Holdings, Global or Resources.

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 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

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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 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 by PSEG or its successor.

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 or greater 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 that agreement 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 approved 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.

PSE&G is the servicer for the bonds issued by Transition Funding. If PSE&G were to lose its investment grade rating, PSE&G would be required to remit collected cash daily to the bond trustee. Currently, cash is remitted monthly.

Power

In connection with the management and optimization of Power’s asset portfolio, ER&T maintains underlying agreements that require Power, as its guarantor under performance guarantees, to satisfy certain creditworthiness standards. In the event of a deterioration of Power’s credit rating to below an investment grade rating, many of these agreements allow the counterparty to demand that ER&T provide performance assurance, generally in the form of a letter of credit or cash. As of December 31, 2004, if Power were to lose its investment grade rating and assuming all counterparties to agreements in which ER&T is “out-of-the-money” were contractually entitled to demand, and

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demanded, performance assurance, ER&T could be required to post collateral in an amount equal to approximately $701 million. Providing this credit support would increase Power’s costs of doing business and could restrict the ability of ER&T to manage and optimize Power’s asset portfolio. See Note 14. Commitments and Contingent Liabilities of the Notes.

Energy Holdings

In 2003, Energy Holdings and Global posted $44 million of letters of credit for certain of their equity commitments as a result of Energy Holdings’ ratings falling below investment grade. 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, (P) denotes a positive outlook and (WD) denotes a credit watch developing indicating that ratings could be raised or lowered. 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.

	Moody’s(A)	S&P(B)	Fitch(C)
PSEG:
Preferred Securities	Baa3	BB+(WD)	BBB–(P)
Commercial Paper	P2	A3(WD)	F2
PSE&G:
Mortgage Bonds	A3	A–(WD)	A
Cumulative Preferred Stock without Mandatory Redemption	Baa3	BB+(WD)	BBB+
Commercial Paper	P2	A3(WD)	F2
Power:
Senior Notes	Baa1	BBB(WD)	BBB(P)
Energy Holdings:
Senior Notes	Ba3(N)	BB–(N)	BB(N)

______________

(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.

On April 12, 2004, Fitch downgraded Energy Holdings’ Senior Notes rating to BB from BBB–, with a negative outlook.

On July 30, 2004, S&P placed the Corporate Credit Ratings of PSEG, PSE&G and Power on negative outlook. S&P also downgraded PSEG’s and PSE&G’s respective commercial paper ratings from A2 to A3.

On August 6, 2004, Moody’s placed Power on a negative outlook.

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On September 10, 2004, Fitch downgraded PSEG’s Preferred Securities to BBB– from BBB with a stable outlook and placed an F2 rating on PSEG’s commercial paper program. Fitch also downgraded Power’s Senior Notes to BBB from BBB+. In addition, Fitch reaffirmed its A rating on PSE&G’s Mortgage Bonds. However, Fitch downgraded PSE&G’s commercial paper program to F2 from F1.

On December 20, 2004, in conjunction with the announcement of the Merger Agreement between PSEG and Exelon, all of the rating agencies reviewed their ratings and took the following actions:

• Moody’s affirmed the ratings for PSEG, Power and Energy Holdings. Moody’s revised its outlook to stable from negative for PSEG and Power. The outlook for PSE&G remained stable and the outlook for Energy Holdings remained negative.

• S&P placed its BBB Corporate Credit Rating for PSEG, Power and PSE&G on Credit Watch with developing implications. S&P indicated that, if not for the Merger, the corporate credit ratings assigned to PSEG and its subsidiaries, other than Energy Holdings, would have been lowered to BBB– with a negative outlook. S&P lowered its outlook for Energy Holdings to negative.

• Fitch affirmed its ratings for PSEG, Power, PSE&G and Energy Holdings. Fitch revised the outlook for PSEG and Power to positive from stable. The outlook for PSE&G remained stable and Energy Holdings remained negative.

Other Comprehensive Loss (Income)

PSEG, PSE&G, Power and Energy Holdings

For the year ended December 31, 2004, PSEG, Power and Energy Holdings had Other Comprehensive Loss (Income) of $80 million, $139 million and $(62) million, respectively, due primarily to net unrealized losses on derivatives accounted for as hedges in accordance with SFAS 133, unrealized gains and losses in the NDT Funds at Power and foreign currency translation adjustments at Energy Holdings.

CAPITAL REQUIREMENTS

Forecasted Expenditures

PSEG, PSE&G, Power and Energy Holdings

It is expected that the majority of each subsidiary’s capital requirements over the next five years will come from internally generated funds. Projected construction and investment expenditures, excluding nuclear fuel purchases, for PSEG’s subsidiaries for the next five years are presented in the table below. These amounts are subject to change, based on various factors, including the possible change in strategy of the combined company following the Merger.

	2005		2006		2007		2008		2009
	(Millions)
PSE&G:
Facility Support	$	44	$	36	$	36	$	44	$	40
Environmental/Regulatory		32		51		22		21		20
Facility Replacement		183		187		184		189		198
System Reinforcement		125		122		100		92		101
New Business		147		151		156		158		162
Total PSE&G.		531		547		498		504		521
Power:
Non-Recurring (new MW and Environmental)		315		178		145		109		30
Maintenance		134		146		114		84		99
Total Power		449		324		259		193		129
Energy Holdings		120		60		40		20		30
Other		15		20		15		15		14
Total PSEG	$	1,115	$	951	$	812	$	732	$	694

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PSE&G

In 2004, PSE&G made approximately $428 million of capital expenditures, primarily for reliability of transmission and distribution systems. The $428 million does not include approximately $32 million spent on cost of removal. PSE&G projections for future capital expenditures include additions to its transmission and distribution systems to meet expected growth and to manage reliability and cost of removal expenditures. The current projections do not include investments required as a result of PJM’s approval of the Regional Transmission Expansion Plan (RTEP) in December 2004. As project scope and cost estimates develop, PSE&G will modify its current projections to include these required investments.

Power

In 2004, Power made approximately $618 million of capital expenditures (excluding $107 million for nuclear fuel), primarily related to the Bethlehem, New York (Albany) site, the Linden station in New Jersey and various other projects at Nuclear and Fossil.

In 2004, Power increased the scope of outages at the Salem and Hope Creek nuclear generating facilities to make equipment modifications. Power’s ongoing capital expenditure program for its share of the Salem, Hope Creek and Peach Bottom facilities includes approximately $669 million (including interest capitalized during construction) for 2005 through 2009 to improve operations and complete power uprates. The forecasted capital expenditures do not include potential expenditures for environmental control equipment at Power’s Keystone, Conemaugh and Hudson Stations.

Energy Holdings

Energy Holdings’ capital needs in 2005 will be limited to fulfilling existing contractual and potential contingent commitments. The balance of the forecasted expenditures relates to capital requirements of consolidated subsidiaries, which will primarily be financed from internally generated cash flow within the projects and from local sources on a non-recourse basis or limited discretionary investments by Energy Holdings. Such capital requirements include organic growth in SAESA’s service territory, the Electroandes expansion project, the majority of which is expected to be completed in 2005, and other capital improvements at Global’s consolidated subsidiaries.

In 2004, Energy Holdings incurred approximately $86 million of capital expenditures, primarily related to capital projects at SAESA, Dhofar Power and Skawina.

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

The following table reflects 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 table below does not reflect debt maturities of Energy Holdings’ 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 12. 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		$	533	$	533	$	—	$	—	$	—
PSE&G			105		105		—		—		—
Long-Term Debt Maturities
Recourse Debt Maturities
PSEG(A)			1,654		49		558		298		749
PSE&G			3,063		125		435		310		2,193
Transition Funding (PSE&G)			2,085		146		317		346		1,276
Power			3,316		—		500		250		2,566
Energy Holdings			1,756		—		309		907		540
Non-Recourse Project Financing
Energy Holdings			1,437		66		328		368		675
Interest on Recourse Debt
PSEG			102		24		44		34		—
PSE&G			2,029		158		278		260		1,333
Transition Funding (PSE&G)			852		133		237		196		286
Power			2,346		209		389		379		1,369
Energy Holdings			583		147		258		131		47
Interest on Debt Supporting Trust Preferred Securities
PSEG			1,970		101		168		108		1,593
Interest on Non-Recourse Project Financing
Energy Holdings			618		97		182		142		197
Capital Lease Obligations
PSEG			79		7		14		14		44
Power			16		1		3		3		9
Operating Leases
PSE&G			9		3		5		1		—
Services			7		1		2		2		2
Energy Related Purchase Commitments
Power			2,061		561		761		438		301
Energy Holdings			188		188		—		—		—
Total Contractual Cash Obligations		$	24,809	$	2,654	$	4,788	$	4,187	$	13,180
Standby Letters of Credit
Power		$	145	$	135	$	10	$	—	$	—
Energy Holdings			31		17		14		—		—
Guarantees and Equity Commitments
Energy Holdings			107		1		26		—		80
Total Commercial Commitments		$	283	$	153	$	50	$	—	$	80

(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 14. Commitments and Contingent Liabilities of the Notes.

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OFF-BALANCE SHEET ARRANGEMENTS

Power

Power issues guarantees in conjunction with certain of its energy trading activities. See Note 14. Commitments and Contingent Liabilities of the Notes for further discussion.

PSEG and Energy Holdings

Global has certain investments that are accounted for under the equity method in accordance with 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 Global invests, that are accounted for under the equity method have an aggregate 1.3 billion of debt on their combined, consolidated financial statements. PSEG’s pro-rata share of such debt is $563 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, 2004, Resources’ equity investment in leased assets was approximately $1.3 billion, net of deferred taxes of approximately $1.6 billion. For additional information, see Note 10. 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 assured, 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 has guaranteed certain obligations of its subsidiaries or affiliates related to certain projects. See Note 14. Commitments and Contingent Liabilities of the Notes for additional information.

CRITICAL ACCOUNTING ESTIMATES

PSEG, PSE&G, Power and Energy Holdings

Under GAAP, many accounting standards 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 determined that the following estimates are considered critical to the application of rules that relate to their respective businesses.

Accounting for Pensions

PSEG, PSE&G, Power and Energy Holdings account for pensions under SFAS No. 87, “Employers’ Accounting for Pensions” (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 2004, PSEG and its subsidiaries recorded pension expense of $102 million, compared to $147 million in 2003 and $89 million in 2002. Additionally, in 2004, PSEG and its respective subsidiaries contributed cash of approximately $96 million, compared to cash contributions of $211 million in 2003 and $240 million in 2002.

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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 2003 and 2004 net periodic pension costs were 6.75% and 6.25%, respectively. PSEG’s 2005 net periodic pension cost was developed using a discount rate of 6.00%.

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 2003 and 2004, PSEG assumed a rate of return of 9.0% and 8.75%, respectively, on PSEG’s pension plan assets. For 2005, PSEG will continue the rate of return assumption of 8.75%.

Based on the above assumptions, PSEG has estimated net period pension costs of approximately $110 million and contributions of up to $100 million in 2005. 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 6.25% discount rate for 2006 and beyond. Based on these assumptions, PSEG has estimated net period pension costs of approximately $80 million in 2006 and $70 million in 2007. 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 accumulated benefit obligation (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, 2004 Impact on Pension Benefit Obligation			Increase to Pension Expense in 2005
			(Millions)
Discount Rate	6.00%	(1%)		$	526		$	54
Rate of Return on Plan Assets	8.75%	(1%)		$	—		$	29

Accounting for Deferred Taxes

PSEG, PSE&G, Power and Energy Holdings provide for income taxes based on the liability method required by SFAS No. 109, “Accounting for Income Taxes” (SFAS 109). 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 basis, 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.

Accounting for Long-Lived Assets

SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS 144), a standard related to testing long-lived assets for impairment, was adopted on January 1, 2002. Testing under SFAS 144 consists of an undiscounted cash flow analysis to determine if an impairment existed, and, if an impairment existed, a discounted cash flow test would be performed to quantify it. This new standard is broader in that it includes discontinued operations as part of its scope. This test requires the same judgment to be employed by management in

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building assumptions related to future earnings of individual assets or an investment as is required in determining potential impairments of goodwill as discussed below.

These tests are required whenever events or circumstances indicate that an impairment may exist. Examples of potential events which could require an impairment test are when power prices become depressed for a prolonged period in a market, when a foreign currency significantly devalues or when an investment generates negative operating cash flows. Any potential impairment of investments under these circumstances is recorded as a component of operating expenses.

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 in a reporting period. The resulting revenue and expense reflect the service rendered in the calendar month.

PSE&G and Energy Holdings

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

PSE&G and certain of Global’s investments prepare their respective 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 and Global have deferred certain costs, which will be amortized over various future periods. To the extent that collection of such costs or payment of liabilities is no longer probable as a result of changes in regulation and/or PSE&G’s and Global’s competitive position, the associated regulatory asset or liability is charged or credited to income. See Note 7. Regulatory Matters of the Notes for additional information related to these and other regulatory issues.

Power

NDT Funds

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 Accumulated Other Comprehensive Income (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, as defined under SFAS 115, and related interpretive guidance, are charged against earnings rather than OCI. 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.

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Power and Energy Holdings

Accounting for Goodwill

SFAS 142 requires an entity to evaluate its goodwill for impairment at least annually or when indications of impairment exist. An impairment may exist when the carrying amount of goodwill exceeds its implied fair value.

Accounting estimates related to goodwill fair value are highly susceptible to change from period to period because they require management to make cash flow assumptions about future sales, operating costs, economic conditions and discount rates over an indefinite life. The impact of recognizing an impairment could have a material impact on financial position and results of operations.

Power and Energy Holdings perform annual goodwill impairment tests and continuously monitor the business environment in which they operate for any impairment issues that may arise. As indicated above, certain assumptions are used to arrive at a fair value for goodwill testing. Such assumptions are consistently employed and include, but are not limited to, free cash flow projections, interest rates, tariff adjustments, economic conditions prevalent in the geographic regions in which Power and Energy Holdings do business, local spot market prices for energy, foreign exchange rates and the credit worthiness of customers. If an adverse event were to occur, such an event could materially change the assumptions used to value goodwill and could result in impairments of goodwill.

PSEG and Energy Holdings

Permanent Reinvestment Strategy

As allowed under APB No. 23, “Accounting for Income Taxes — Special Areas” and SFAS 109, management has maintained a permanent reinvestment strategy as it relates to Global’s international investments. If management were to change that strategy, a deferred tax expense and deferred tax liability would be recorded to reflect the expected taxes that would need to be paid on Global’s offshore earnings. As of December 31, 2004, the undistributed foreign earnings were approximately $256 million. The determination of the amount of unrecognized U.S. Federal deferred tax liability for unrealized earnings is not practicable. The American Jobs Creation Act of 2004 (Jobs Act), as discussed further in Note 2. Recent Accounting Standards of the Notes, provides a one-year window to repatriate earnings from foreign investments and claim a special 85% dividends received tax deduction on such distributions. The range of undistributed earnings that PSEG could consider for possible repatriation under the Jobs Act is between $0 and $256 million, which would result in additional income tax expense between $0 and $15 million. On January 13, 2005, the IRS published Notice 2005-10, which discusses some of the rules that pertain to this deduction. Whether PSEG will ultimately take advantage of this provision, all or in part, depends on a number of factors, including but not limited to evaluating the impact of Notice 2005-10 and any future authoritative guidance. Management has made no change in its current intention to indefinitely reinvest accumulated earnings of its foreign subsidiaries. PSEG and Energy Holdings are currently evaluating the impacts of the entire Jobs Act, which could have a material impact on their financial condition, results of operations and cash flows.

Foreign Currency Translation

Energy Holdings’ financial statements are prepared using the U.S. Dollar as the reporting currency. In accordance with SFAS No. 52 “Foreign Currency Translation,” for foreign operations whose functional currency is deemed to be the local (foreign) currency, asset and liability accounts are translated into U.S. Dollars at current exchange rates and revenues and expenses are translated at average exchange rates prevailing during the period. Translation gains and losses (net of applicable deferred taxes) are not included in determining Net Income but are reported in OCI. Gains and losses on transactions denominated in a currency other than the functional currency are included in the results of operations as incurred.

The determination of an entity’s functional currency requires management’s judgment. It is based on an assessment of the primary currency in which transactions in the local environment are conducted, and whether the local currency can be relied upon as a stable currency in which to conduct business. As economic and business conditions change, Energy Holdings is required to reassess the economic environment and determine the appropriate functional currency. The impact of foreign currency accounting could have a material adverse impact on Energy Holdings’ financial condition, results of operation and net cash flows.

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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 Consolidated Financial Statements (Notes). 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 have 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 been significant devaluation since the initial acquisition of Global’s investment in Rio Grande Energia S.A. (RGE), which has resulted in reduced U.S. Dollar earnings and cash flows relative to initial projections. However, there have been material improvements in a number of currencies during 2003 and 2004 due to the weakness of the U.S. Dollar, that have offset some of the loss incurred because of the devaluation of the Brazilian Real. 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 transactions.

As of December 31, 2004, the devaluing Brazilian Real has resulted in a cumulative $240 million loss of value which is recorded as a $215 million after-tax charge to Other Comprehensive Income (OCI) related to Global’s equity method investments in RGE. An additional devaluation in the December 31, 2004 Brazilian Real to U.S. Dollar exchange rate of 10% would result in a $16 million change in the value of the investment in RGE and corresponding impact to OCI. If the December 31, 2004 Brazilian Real to U.S. Dollar exchange rate were to appreciate by 10%, it would result in a $20 million after-tax increase in the value of the investment in RGE.

Additionally, Global has approximately $65 million of Euro-denominated receivables related to Global’s equity method investments in Prisma which is subject to fluctuations in the U.S. Dollar to Euro exchange rate. If the December 31, 2004 Euro to U.S. Dollar exchange rate were to increase by 10%, Global would record approximately $7 million of foreign currency transaction losses. If the December 31, 2004 Euro to U.S. Dollar exchange rate were to decrease by 10%, Global would record approximately $6 million of foreign currency transaction gains.

In January 2005, Energy Holdings entered into an option to sell U.S. Dollars and buy Polish Zlotys with a notional amount equivalent to the amount of its Polish Zloty bank debt at ELCHO, a U.S. Dollar functional currency entity. As a result, if the U.S. Dollar weakens relative to the Polish Zloty, the accounting losses generated by the mark-to-market on the Polish Zloty debt would be significantly reduced by the option’s increases in value. To the extent the U.S. Dollar strengthens relative to the Polish Zloty, gains would be recorded on the Polish Zloty debt (and other monetary liabilities), and the option would expire with no value.

Global has various other foreign currency exposures related to translation adjustments. A devaluation of 10% in such foreign currencies would result in an aggregate after-tax charge to OCI of $76 million.

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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, market rules 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 demand obligations help optimize the value of owned electric generation capacity.

Normal Operations and Hedging Activities

Power enters into physical contracts, as well as financial contracts, including forwards, futures, swaps and options designed to reduce 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. 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.

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) for contracts entered into or modified and hedging relationships designated after June 30, 2003.

Trading

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. In addition, Power has non-asset based trading activities. These contracts also involve financial transactions including swaps, options and futures. These activities are marked to market in accordance with SFAS 133, its amendments and related guidance, with gains and losses recognized in earnings.

Value-at-Risk (VaR) Models

Power

Power uses VaR models to assess the market risk of its commodity businesses. The portfolio VaR 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. While Power manages its risk at the portfolio level, it also monitors separately the risk of its trading activities and other non-trading activities that receive mark-to-market accounting treatment. Non-trading VAR includes derivatives that are economic hedges that do not qualify for hedge accounting.

The VaR models used by Power are variance/covariance models adjusted for the delta of positions with a 95% one-tailed confidence level and a one-day holding period for the mark-to-market trading and non-trading activities and a 95% one-tailed confidence level with a one-week holding period for the portfolio VaR. The models assume no new positions throughout the holding periods, whereas Power actively manages its portfolio.

As of December 31, 2004 and 2003, trading VaR was approximately $2 million.

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For the Year Ended December 31, 2004	Trading VaR		Non-Trading MTM VaR
	(Millions)
95% Confidence Level, One-Day Holding Period, One-Tailed:
Period End	$	2	$	18
Average for the Period	$	2	$	13
High	$	6	$	31
Low	$	1	$	1
99% Confidence Level, One-Day Holding Period, Two-Tailed:
Period End	$	4	$	28
Average for the Period	$	4	$	20
High	$	9	$	49
Low	$	1	$	2

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. It is the policy of PSEG, PSE&G, Power and Energy Holdings 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, 2004, a hypothetical 10% change in market interest rates would result in a $1 million, $3 million and $1 million change in annual interest costs related to debt at PSEG, PSE&G and Energy Holdings, respectively. In addition, as of December 31, 2004, a hypothetical 10% change in market interest rates would result in a $9 million, $153 million, $122 million and $38 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 $2.9 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 accumulated benefit obligation (ABO) under its pension plans exceeds the fair value of its pension funds and future earnings as PSEG could be required to adjust pension expense and its assumed rate of return.

Power

Power’s NDT Funds are comprised of both fixed income and equity securities totaling $1.1 billion as of December 31, 2004. The fair value of equity securities is determined independently each month by the Trustee. As of December 31, 2004, the portfolio was comprised of approximately $678 million of equity securities and approximately $408 million in fixed income securities. The fair market value of the NDT assets will fluctuate primarily depending upon the performance of equity markets. As of December 31, 2004, a hypothetical 10% change in the equity market would impact the value of the equity securities in the NDT Funds by approximately $68 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 Funds is the Lehman Brothers Aggregate Bond Index, which currently has a duration of 4.34 years and a yield of 4.38%. The portfolio’s value will appreciate or depreciate by the duration with a 1% change in interest rates. As of December 31, 2004, a hypothetical 1% increase in interest rates would result in a decline in the market value for the fixed income portfolio of approximately $16 million.

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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, 2004, Resources had investments in leveraged buyout funds of approximately $27 million, all of which are public securities with available market prices. The potential change in fair value resulting from a hypothetical 10% change in quoted market prices of the publicly traded investments would amount to $3 million as of December 31, 2004.

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

Basic Generation Service (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 Board of Public Utilities (BPU) approved BGS contracts.

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’s and its subsidiaries’ financial condition, results of operations or net cash flows. As of December 31, 2004, over 88% 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 was with certain companies that supply fuel (primarily coal) to Power. Therefore, this exposure relates to the risk of a counterparty performing under its obligations rather than payment risk. As of December 31, 2004, Power’s trading operations had over 184 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. In February 2004, the BPU approved the results of the 2004 BGS auction for New Jersey customers. Power is a direct supplier of New Jersey Electric Distribution Companies (EDCs) entering into seasonally-adjusted fixed-price contracts for 12-month and 36-month periods that began on June 1, 2004. 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 New Jersey EDC making direct payment under the BGS contracts is lower than the risk under standard bilateral contracts, since the EDCs are rate-regulated entities.

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Energy Holdings

Global

Global has credit risk with respect to its counterparties to power purchase agreements (PPAs) 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 $1.2 billion, which is net of deferred taxes of $1.6 billion, as of December 31, 2004. These investments are largely concentrated in the energy industry and have some exposure to the airline industry. As of December 31, 2004, 69% 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 including United Airlines (UAL), Delta Airlines (Delta) and Northwest Airlines (Northwest). Resources leases a Boeing B767 aircraft to UAL. In December 2002, UAL filed for Chapter 11 bankruptcy protection. UAL has stated that it intends to retain and use its B767 aircraft. UAL has an additional debt obligation of $48 million associated with this aircraft which is non-recourse to Resources. Resources will work constructively with UAL to keep the leveraged lease in place. The gross invested balance of this investment as of December 31, 2004 was $21 million. In the fourth quarter of 2004, Resources entered into agreements with Delta and Northwest to extend the term of both of these leases. As part of Delta’s financial restructuring, Delta entered into a broad settlement with certain lessors and other financial stakeholders. Through this settlement, Resources agreed to extend Delta’s lease on the airplane for three years with a 25% reduction in rental payments. Resources also received shares of Delta stock through the transaction and retained its rights in the event Delta declares bankruptcy. Separately, Resources extended the lease on one of the airplanes to Northwest for two years. Each of these lessees are current on its required rental payments. The gross investment balances in Delta and Northwest as of December 31, 2004 was $5 million and $32 million, respectively. Delta is rated CC by S&P and Caa3 by Moody’s. Northwest is rated B by S&P and Caa2 by Moody’s.

Resources is the lessor of domestic generating facilities in several U.S. energy markets. As a result of rating agency actions 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 $301 million, net of deferred taxes of $398 million as of December 31, 2004.

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 was upgraded to ratings of B+ by S&P and B1 by Moody’s during 2004. 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 $107 million, net of deferred taxes of $149 million as of December 31, 2004.

Resources is the lessor/equity participant to the lease of the Powerton and Joliet power generating facilities operated by the lessee, Midwest Generation LLC (Midwest), an indirect subsidiary of Edison Mission Energy (EME). EME is the guarantor for the lease obligations. As of December 31, 2004, Resources lease investment in the Powerton and Joliet facilities was $57 million, net of taxes of $134 million. With ongoing credit problems and maturing debt during 2003, EME’s corporate credit rating was lowered to B by S&P on credit watch with negative implications in October 2003. EME successfully refinanced its debt in December 2003 through a complex plan which included new debt and bridge financing to be followed by significant offshore asset sales in 2004. In August 2004, EME’s credit rating outlook improved to B with positive implications.

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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 $116 million, net of deferred taxes of $91 million as of December 31, 2004.

Resources is a lessor/equity participant in a lease to the Midland Cogeneration Venture, LP (MCV) of a 1,500 MW natural gas-fired cogeneration facility located in Midland, Michigan. The principal partners in the limited partnership, which leases the asset, are indirect subsidiaries of CMS Energy Corporation (CMS Energy) and El Paso Energy Corporation (El Paso). S&P’s rating of the stand-alone credit quality of the facility is BB- reflecting both CMS Energy’s and El Paso’s credit deterioration, high fuel gas prices and a mismatch between coal-based energy rates and the price of natural gas fuel supply. To meet these challenges, MCV actively manages and hedges its fuel purchases and has accumulated substantial cash reserves for bondholder protection. Additionally, the partnership has negotiated and received the Michigan Public Service Commission’s approval for an operating agreement with Consumers Power to allow the facility to dispatch in a more economic manner, mitigating the fuel risk. Resources closely monitors this credit situation. The facility has been in commercial operation since 1990, successfully paying down a significant portion of its debt to date. Resources’ net investment in MCV was $21 million, net of deferred taxes of $24 million as of December 31, 2004.

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, including deferred taxes, 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, 2004, lease payments on these facilities were current and 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

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 13. Risk Management of the Notes.

The following table describes the drivers of Power’s energy trading and marketing activities and Operating Revenues included in its Consolidated Statement of Operations for the year ended December 31, 2004. 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.

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Operating Revenues

For the Year Ended December 31, 2004

	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		$	36			$	58		$	94
Origination Unrealized Gain at Inception			—				—			—
Changes in Valuation Techniques and Assumptions			—				—			—
Realization at Settlement of Contracts			(29	)			(58	)		(87	)
Total Change in Unrealized Fair Value			7				—			7
Realized Net Settlement of Transactions Subject to Mark-to-Market			29				58			87
Broker Fees and Other Related Expenses			—				(11	)		(11	)
Net Mark-to-Market Gains			36				47			83
Accrual Activities:
Accrual Activities—Revenue, Including Hedge Reclassifications			5,086				—			5,086
Total Operating Revenues		$	5,122			$	47		$	5,169

______________

(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 ABTs 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, 2004

	Normal Operations and Hedging				Trading				Total
	(Millions)
Mark-to-Market Energy Assets
Current Assets		$	24			$	144		$	168
Noncurrent Assets			19				13			32
Total Mark-to-Market Energy Assets		$	43			$	157		$	200
Mark-to-Market Energy Liabilities
Current Liabilities		$	(161	)		$	(129	)	$	(290	)
Noncurrent Liabilities			(122	)			(18	)		(140	)
Total Mark-to-Market Current Liabilities		$	(283	)		$	(147	)	$	(430	)
Total Mark-to-Market Energy Contract Net (Liabilities) Assets		$	(240	)		$	10		$	(230	)

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The following table presents the 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, 2004

	Maturities within
	2005			2006			2007			2008- 2009			Total
	(Millions)
Trading	$	8		$	(4	)	$	(4	)	$	2		$	2
Normal Operations and Hedging		(131	)		(32	)		(36	)		(33	)		(232	)
Total Net Unrealized Losses on Mark-to-Market Contracts	$	(123	)	$	(36	)	$	(40	)	$	(31	)	$	(230	)

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, Power and Energy Holdings

The following table identifies losses on cash flow hedges that are currently in Accumulated Other Comprehensive Loss, a separate component of equity. Power uses forward sale and purchase contracts, swaps and firm transmission rights (FTRs) contracts to hedge forecasted energy sales from its generation stations and its contracted supply obligations. Power also enters into swaps, options and futures transactions to hedge the price of fuel to meet its fuel purchase requirements for generation. PSEG, 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. The table also provides an estimate of the 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, 2004

	Accumulated OCI				Portion Expected to be Reclassified in next 12 months
	(Millions)
Cash Flow Hedges Included in OCI
Commodities		$	(148	)		$	(81	)
Interest Rates			(60	)			(28	)
Foreign Currency			—				—
Net Cash Flow Hedge Loss Included in OCI		$	(208	)		$	(109	)

Power

Credit Risk

The following table provides information on Power’s credit exposure, net of collateral, as of December 31, 2004. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value on open positions. 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.

46

Schedule of Credit Risk Exposure on Energy Contracts Net Assets

As of December 31, 2004

Rating	Current Exposure			Securities Held as Collateral			Net Exposure			Number of Counterparties >10%		Net Exposure of Counterparties >10%
				(Millions)								(Millions)
Investment Grade—External Rating		$	554		$	84		$	521		1		$	304
Non-Investment Grade—External Rating			24			5			20		—			—
Investment Grade—No External Rating			3			—			3		—			—
Non-Investment Grade—No External Rating			54			—			54		—			—
Total		$	635		$	89		$	598		1		$	304

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.

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.

47

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors of

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED:

We have audited the accompanying consolidated balance sheets of Public Service Enterprise Group Incorporated and subsidiaries (the “Company”) as of December 31, 2004 and 2003, 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, 2004. Our audits also included the consolidated financial statement schedule listed in the Index at 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 the standards of the Public Company Accounting Oversight Board (United States). 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, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, 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, on January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets.”

As discussed in Note 2 to the consolidated financial statements, on January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based on the criteria established in “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2005, which expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

DELOITTE & TOUCHE LLP

Parsippany, New Jersey

February 28, 2005

(August 29, 2005 as to Notes 1, 4, 7, 8, 9, 16, 17, 20, 21, and 23)

48

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF OPERATIONS

(Millions, except for share data)

	For The Years Ended December 31,
	2004			2003			2002
OPERATING REVENUES	$	10,991		$	11,135		$	8,220
OPERATING EXPENSES
Energy Costs		6,053			6,387			3,710
Operation and Maintenance		2,247			2,117			1,899
Write-down of Project Investments		–			–			511
Depreciation and Amortization		706			522			565
Taxes Other Than Income Taxes		139			136			131
Total Operating Expenses		9,145			9,162			6,816
Income from Equity Method Investments		126			114			119
OPERATING INCOME		1,972			2,087			1,523
Other Income		176			178			39
Other Deductions		(91	)		(101	)		(80	)
Interest Expense		(830	)		(829	)		(819	)
Preferred Stock Dividends		(4	)		(4	)		(4	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		1,223			1,331			659
Income Tax Expense		(469	)		(470	)		(254	)
INCOME FROM CONTINUING OPERATIONS		754			861			405
Loss from Discontinued Operations, including Gain (Loss) on Disposal, net of tax benefit of $23, $8 and $28 for the years ended 2004, 2003 and 2002, respectively		(28	)		(53	)		(49	)
INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		726			808			356
Extraordinary Item, net of tax benefit of $12 for 2003		–			(18	)		–
Cumulative Effect of a Change in Accounting Principle, net of tax (expense) benefit of ($255) and $66 for the years ended 2003 and 2002, respectively		–			370			(121	)
NET INCOME	$	726		$	1,160		$	235
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):
BASIC		236,984			228,222			208,647
DILUTED		238,286			228,824			208,813
EARNINGS PER SHARE:
BASIC
INCOME FROM CONTINUING OPERATIONS	$	3.18		$	3.77		$	1.94
NET INCOME	$	3.06		$	5.08		$	1.13
DILUTED
INCOME FROM CONTINUING OPERATIONS	$	3.17		$	3.76		$	1.94
NET INCOME	$	3.05		$	5.07		$	1.13
DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	2.20		$	2.16		$	2.16

See Notes to Consolidated Financial Statements.

49

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED BALANCE SHEETS

(Millions)

	December 31, 2004		December 31, 2003
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	279	$	452
Accounts Receivable, net of allowances of $34 and $40 in 2004 and 2003, respectively		1,621		1,551
Unbilled Revenues		340		261
Fuel		633		527
Materials and Supplies		255		224
Energy Trading Contracts		161		144
Prepayments		122		164
Restricted Funds		50		37
Assets of Discontinued Operations		511		829
Other		203		45
Total Current Assets		4,175		4,234
PROPERTY, PLANT AND EQUIPMENT		18,620		16,888
Less: Accumulated Depreciation and Amortization		(5,355)		(4,976)
Net Property, Plant and Equipment		13,265		11,912
NONCURRENT ASSETS
Regulatory Assets		5,127		4,800
Long-Term Investments		4,181		4,810
Nuclear Decommissioning Trust (NDT) Funds		1,086		985
Other Special Funds		488		470
Goodwill		530		507
Other Intangibles		100		109
Energy Trading Contracts		30		18
Other		262		302
Total Noncurrent Assets		11,804		12,001
TOTAL ASSETS	$	29,244	$	28,147
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	386	$	726
Commercial Paper and Loans		638		301
Accounts Payable		1,362		1,202
Derivative Contracts		207		103
Energy Trading Contracts		125		75
Accrued Interest		154		185
Accrued Taxes		54		13
Clean Energy Program		82		110
Liabilities of Discontinued Operations		–		242
Other		484		419
Total Current Liabilities		3,492		3,376
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		4,350		4,223
Regulatory Liabilities		545		598
Nuclear Decommissioning Liabilities		310		284
Other Postretirement Benefit (OPEB) Costs		563		532
Accrued Pension Costs		66		67
Clean Energy Program		324		–
Environmental Costs		366		144
Other		479		360
Total Noncurrent Liabilities		7,003		6,208
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 14)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt		8,414		7,921
Securitization Debt		1,939		2,085
Project Level, Non-Recourse Debt		1,371		1,738
Debt Supporting Trust Preferred Securities		1,201		1,201
Total Long-Term Debt		12,925		12,945
SUBSIDIARY’S PREFERRED SECURITIES
Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2004 and 2003 - 795,234 shares		80		80
COMMON STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 500,000,000 shares; issued 2004 - 264,128,807 shares and 2003 - 262,252,032 shares		4,569		4,490
Treasury Stock, at cost; 2004 - 26,029,740 shares; 2003 - 26,118,590 shares		(978)		(981)
Retained Earnings		2,425		2,221
Accumulated Other Comprehensive Loss		(272)		(192)
Total Common Stockholders’ Equity		5,744		5,538
Total Capitalization		18,749		18,563
TOTAL LIABILITIES AND CAPITALIZATION	$	29,244	$	28,147

See Notes to Consolidated Financial Statements.

50

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions)

	For The Years Ended December 31,
	2004			2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	726		$	1,160		$	235
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Extraordinary Item, net of tax benefit		–			18			–
(Gain) Loss on Disposal of Discontinued Operations, net of tax		(5	)		32			35
Cumulative Effect of a Change in Accounting Principle, net of tax		–			(370	)		121
Write-Down of Project Investments		–			–			511
Depreciation and Amortization		706			522			565
Amortization of Nuclear Fuel		80			89			89
Provision for Deferred Income Taxes (Other than Leases) and ITC		167			363			(117	)
Non-Cash Employee Benefit Plan Costs		217			253			187
Leveraged Lease (Income) Loss, Adjusted for Rents Received		(92	)		77			(44	)
Undistributed Earnings from Affiliates		(12	)		40			(5	)
Foreign Currency Transaction Loss (Gain)		26			(16	)		77
Unrealized Losses on Energy Contracts and Other Derivatives		(4	)		38			(35	)
Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs		80			(38	)		(19	)
(Under) Over Recovery of Societal Benefits Charge (SBC)		(158	)		4			20
Net Realized Gains and Income from NDT Fund		(105	)		(65	)		–
Gain on Sale of Investments		(79	)		(56	)		(16	)
Other Non-Cash Charges (Credits)		59			102			(15	)
Net Change in Certain Current Assets and Liabilities		21			(466	)		(20	)
Employee Benefit Plan Funding and Related Payments		(174	)		(274	)		(304	)
Proceeds from the Withdrawal of Partnership Interests and Other Distributions		126			66			54
Other		31			14			(84	)
Net Cash Provided By Operating Activities		1,610			1,493			1,235
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(1,255	)		(1,402	)		(1,620	)
Investments in Joint Ventures, Partnerships and Capital Leases		(14	)		(37	)		(227	)
Proceeds from the Sale of Investments and Return of Capital from Partnerships		438			30			388
Acquisitions, net of Cash Provided		–			–			(271	)
Restricted Cash		54			(86	)		(23	)
Other		23			–			17
Net Cash Used In Investing Activities		(754	)		(1,495	)		(1,736	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans		339			(327	)		(642	)
Issuance of Long-Term Debt		1,429			1,209			1,164
Issuance of Non-Recourse Debt		–			1,036			242
Issuance of Participating Units		–			–			457
Issuance of Common Stock		83			441			536
Issuance of Preferred Securities		–			–			174
Redemptions of Long-Term Debt		(2,309	)		(1,325	)		(971	)
Redemptions of Preferred Securities		–			(155	)		–
Cash Dividends Paid on Common Stock		(522	)		(493	)		(456	)
(Contributions from) Distributions to Minority Shareholders		(1	)		(48	)		5
Other		(49	)		(36	)		(13	)
Net Cash (Used In) Provided By Financing Activities		(1,030	)		302			496
Effect of Exhange Rate Change		1			2			(13	)
Net (Decrease) Increase in Cash and Cash Equivalents		(173	)		302			(18	)
Cash and Cash Equivalents at Beginning of Period		452			150			168
Cash and Cash Equivalents at End of Period	$	279		$	452		$	150
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid	$	104		$	(21	)	$	145
Interest Paid, Net of Amounts Capitalized	$	851		$	975		$	843

See Notes to Consolidated Financial Statements.

51

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY

(Millions)

Retained Earnings

Accumulated Other Comprehensive Loss

Common Stock

Treasury Stock

Total

Shs.

Amount

Shs.

Amount

Balance as of January 1, 2002

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)

–

–

–

–

–

(48)

(48

)

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

547

Comprehensive Income

1,707

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

$

(192)

$

5,538

Net Income

–

–

–

–

726

–

726

Other Comprehensive Income (Loss), net of tax:

Currency Translation Adjustment, net of tax $19

–

–

–

–

–

64

64

Reclassification Adjustment for Losses Included in Net Income

–

–

–

–

–

–

–

Available for Sale Securities, net of tax $29

–

–

–

–

–

(16)

(16

)

Change in Fair Value of Derivative Instruments, net of tax $(115)

–

–

–

–

–

(171)

(171

)

Reclassification Adjustments for Net Amounts included in Net Income

–

–

–

–

–

50

50

Other

–

–

–

–

–

(3)

(3

)

Minimum Pension Liability, net of tax $(3)

–

–

–

–

–

(6)

(6

)

Change in Fair Value of Equity Investments

–

–

–

–

–

2

2

Other Comprehensive Loss

(80

)

Comprehensive Income

646

Cash Dividends on Common Stock

–

–

–

–

(522)

–

(522

)

Issuance of Equity

2

83

–

–

–

–

83

Issuance Costs and Other

–

(4)

–

3

–

–

(1

)

Balance as of December 31, 2004

264

$

4,569

(26)

$

(978)

$

2,425

$

(272)

$

5,744

See Notes to Consolidated Financial Statements.

52

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).

On December 20, 2004, PSEG and Exelon Corporation (Exelon), a public utility company headquartered in Chicago, Illinois, entered into an agreement and plan of merger (Merger Agreement). For additional information, see Note 24. Merger Agreement.

PSE&G

PSE&G is an operating public utility engaged principally in the transmission and distribution of electric energy and natural gas service in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC).

PSE&G also owns PSE&G Transition Funding LLC (Transition Funding), a bankruptcy remote entity that purchased certain intangible transition property from PSE&G and issued certain transition bonds secured by such property.

Power

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: PSEG Nuclear LLC (Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC (ER&T). Nuclear and Fossil own and operate generation and generation-related facilities. ER&T is responsible for the day-to-day management of the portfolio. Fossil, Nuclear and ER&T are subject to regulation by the FERC. On May 27, 2005, Power entered into an agreement to sell its electric generation facility located in Waterford, Ohio to a subsidiary of American Electric Power Company, Inc. (AEP). The sale is subject to various regulatory approvals. It is anticipated that the transaction will close during the second half of 2005. For additional information, see Note 4. Discontinued Operations, Dispositions and Acquisitions.

Energy Holdings

Energy Holdings has two principal direct wholly-owned subsidiaries: PSEG Global LLC (Global), which owns and operates international and domestic projects engaged in the generation and distribution of energy, including independent power production facilities and electric distribution companies; and PSEG Resources LLC (Resources), which has primarily invested in energy-related leveraged leases. Energy Holdings also owns 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). For additional information relating to Energy Technologies, see Note 4. Discontinued Operations, Dispositions and Acquisitions.

Services

Services provides management and administrative services to PSEG and its subsidiaries. These include accounting, legal, communications, human resources, information technology, treasury and financial services, investor relations, stockholder services, real estate, environmental, health and safety, 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.

53

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 Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46, “Consolidation of Variable Interest Entities (VIE)” (FIN 46), as discussed in Note 2. 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 21. Property, Plant and Equipment and Jointly-Owned Facilities.

Accounting for the Effects of Regulation

PSE&G and Energy Holdings

PSE&G and certain of Global’s investments prepare their respective financial statements in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71). In general, SFAS 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (a regulatory asset) or 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 and Global have 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 and Global’s competitive positions, the associated regulatory asset or liability is charged or credited to income. Management believes that PSE&G’s and certain of Global’s transmission and distribution businesses continue to meet the requirements for application of SFAS 71. For additional information, see Note 7. Regulatory Matters.

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, 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

54

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 13. 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 and received. Power records margins from energy trading on a net basis pursuant to accounting principles generally accepted in the U.S. (GAAP). See Note 13. 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. 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. Income from these investments is recorded as a component of Operating Income. 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. For 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 10. 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 stated as a percentage of original cost of depreciable property was 3.07% for 2004, 3.30% for 2003 and 3.37% for 2002.

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 three 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.

55

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Energy Holdings

Energy Holdings calculates depreciation on property, plant and equipment under the straight-line method with estimated useful lives ranging from three 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, 2004, 2003 and 2002, combined TEFA and GRT of approximately $153 million, $152 million and $145 million, respectively, are reflected in Operating Revenues and $139 million, $136 million and $131 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 is reported in the Consolidated Statements of Operations as a reduction of interest charges. PSE&G’s average rate used for calculating AFUDC in 2004, 2003 and 2002 was 1.33%, 3.43% and 8.34%, respectively. For the years ended December 31, 2004, 2003 and 2002, PSE&G’s AFUDC amounted to $0.1 million, $0.3 million and $1 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 2004, 2003 and 2002 was 6.81%, 7.07% and 7.01%, respectively. For the years ended December 31, 2004, 2003 and 2002, Power’s IDC amounted to $111 million, $107 million and $78 million, respectively. Energy Holdings’ average rate used for calculating IDC in 2004, 2003 and 2002 was 8.37%, 8.70% and 9.06%, respectively. For the years ended December 31, 2004, 2003 and 2002, Energy Holdings’ IDC amounted to $4 million, $12 million and $13 million, respectively.

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

A business’s functional currency is the currency of the primary economic environment in which the business operates and is generally the currency in which the business generates and expends cash. In accordance with SFAS No. 52, “Foreign Currency Translation,” the assets and liabilities of foreign operations of Energy Holdings, with a functional currency other than the U.S. Dollar, are translated into U.S. Dollars at the current exchange rates in effect at the end of the reporting period. The translation differences that result from this process, and gains and losses on intercompany foreign currency transactions, which are long-term in nature and that Energy Holdings does not intend to settle in the foreseeable future, are shown in OCI as a separate component of member’s equity. U.S. deferred

56

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

taxes are not provided on translation gains and losses where Energy Holdings expects earnings of a foreign operation to be permanently reinvested. The revenue and expense accounts of such foreign operations are translated into U.S. Dollars at the average exchange rates that prevail during the period.

Gains and losses that arise from exchange rate fluctuations on monetary assets and monetary liabilities denominated in a currency other than the functional currency are included in determining Net Income. Gains and losses relating to derivatives designated as hedges of the foreign currency exposure of a net investment in foreign operations are reported in Currency Translation Adjustment, a separate component of OCI.

The determination of an entity’s functional currency requires management’s judgment. It is based on an assessment of the primary currency in which transactions in the local environment are conducted, and whether the local currency can be relied upon as a stable currency in which to conduct business. As economic and business conditions change, Energy Holdings is required to reassess the economic environment and determine the appropriate functional currency. The impact of foreign currency accounting could have a material effect on Energy Holdings’ financial statements.

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

Materials and supplies and fuel for Power and Energy Holdings are valued at the lower of average cost or market.

Property, Plant and Equipment

PSE&G

PSE&G’s additions and replacements to property, plant and equipment 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 net 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 prevent future environmental contamination or if the costs improve existing assets’ environmental safety or efficiency. All other environmental expenditures are expensed as incurred.

57

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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) Funds

Power

Prior to the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143), amounts collected from PSE&G customers that had been deposited into the NDT Funds and realized and unrealized gains and losses in the trusts were recorded as changes in the NDT Funds and as offsetting changes 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 be required to fund the NDT Funds. Therefore, deferral accounting ceased to be appropriate. Beginning January 1, 2003, realized gains and losses are recorded in earnings and unrealized gains and losses are 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 2. Recent Accounting Standards and Note 3. Asset Retirement Obligations 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 their 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.

There are several investments recorded using 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 capitalized interest and capitalized expenses. 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 was under construction, the interest accrued on such borrowings was recorded in the investment account. This is a temporary difference, as amortization of the amount of interest capitalized began upon commencement of the project. In the instance of capitalized expenses, all direct external and internal costs related to project development were capitalized once a project reached certain milestones. When the project reached financial closing, Global transferred the deferred project balance to the investment account. This is a temporary difference, as the capitalized expenses started being amortized upon commencement of the project. For additional information related to these investments, see Note 10. Long-Term Investments.

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.

58

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Deferred Project Costs and Development Costs

Power and Energy Holdings

Power and Energy Holdings capitalize all incremental and direct external and direct internal costs related to project development once a project reaches certain milestones. On Power’s Consolidated Balance Sheets, deferred project costs are recorded in Construction Work in Progress. On Energy Holdings’ Consolidated Balance Sheets, deferred project costs are recorded in Investments or Other Assets. 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. No project development commenced in 2004.

Stock Compensation

PSEG

PSEG applies Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25), and related interpretations in accounting for stock-based compensation plans. 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” (SFAS 123), there would have been an additional charge to Net Income of approximately $5 million, $8 million and $10 million in 2004, 2003 and 2002, respectively, with a $(0.02), $(0.04) and $(0.05) impact on diluted earnings per share in 2004, 2003 and 2002, 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 123 to stock-based employee compensation:

	Years Ended December 31,
	2004			2003			2002
	(Millions, except Share Data)
Net Income, as reported	$	726		$	1,160		$	235
Add: Total stock-based compensation expensed during the period, net of tax		1			—			—
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(6	)		(8	)		(10	)
Pro forma Net Income	$	721		$	1,152		$	225
Earnings per share:
Basic—as reported	$	3.06		$	5.08		$	1.13
Basic—pro forma	$	3.04		$	5.05		$	1.08
Diluted—as reported	$	3.05		$	5.07		$	1.13
Diluted—pro forma	$	3.03		$	5.03		$	1.08

See Note 2. Recent Accounting Standards and Note 8. Earnings Per Share for further information.

Basis Adjustment

PSE&G and Power

PSE&G and Power have recorded a Basis Adjustment on their Consolidated Balance Sheets related 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

59

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. Recent Accounting Standards

SFAS No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29” (SFAS 153)

PSEG, PSE&G, Power and Energy Holdings

On December 16, 2004, the FASB issued SFAS 153 which addresses the measurement of exchanges of nonmonetary assets and redefines the scope of transactions that should be measured based on the fair value of the assets exchanged. SFAS 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. PSEG, PSE&G, Power and Energy Holdings do not believe the adoption of SFAS 153 will have a material effect on their respective financial statements.

SFAS No. 151, “Inventory Costs” (SFAS 151)

PSEG, PSE&G, Power and Energy Holdings

On November 29, 2004, the FASB issued SFAS 151 which clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material. SFAS 151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. PSEG, PSE&G, Power and Energy Holdings do not believe the adoption of SFAS 151 will have a material effect on their respective financial statements.

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

PSEG, PSE&G, Power and Energy Holdings

SFAS 150, which became effective July 1, 2003, establishes standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. 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. 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities” (SFAS 146)

PSEG, PSE&G, Power and Energy Holdings

SFAS 146 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 the liability for costs 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, which was effective January 1, 2003, did not have any effect on PSEG’s, PSE&G’s, Power’s or Energy Holdings’ financial statements.

SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143)

PSEG, PSE&G, Power and Energy Holdings

Effective January 1, 2003, PSEG, PSE&G, Power and Energy Holdings each adopted SFAS 143. 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 the initial measurement, a company 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 3. Asset Retirement Obligations 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 statements 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.

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.

For additional information related to goodwill, see Note 9. Goodwill and Other Intangibles.

SFAS No. 123R, “Share-Based Payment, an amendment of SFAS No. 123 and 95” (SFAS 123R)

PSEG

In December 2004, the FASB issued SFAS 123R. SFAS 123R is a revision of SFAS 123, and supersedes APB 25 and its related implementation guidance. SFAS 123R focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS 123R is effective for the first interim or annual reporting period beginning after June 15, 2005 and requires entities to recognize stock

61

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

compensation expense for awards of equity instruments to employees based on the grant-date fair value of those awards (with limited exceptions). PSEG is currently evaluating the two methods of adoption allowed by SFAS 123, the modified-prospective transition method and the modified-retrospective transition method and has not yet determined the impact of either method on PSEG.

FASB Staff Position (FSP) 109-1, “Application of FASB Statement No. 109, “Accounting for Income Taxes”, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004” (FSP 109-1)

PSEG, Power and Energy Holdings

On December 21, 2004, the FASB issued FSP 109-1, which was effective upon issuance, to provide guidance on the application of SFAS No. 109, “Accounting for Income Taxes” (SFAS 109), to the provision within the American Jobs Creation Act of 2004 (Jobs Act) that provides a tax deduction on qualified production activities. The Jobs Act includes a tax deduction of up to 9% (when fully phased-in) of the lesser of (a) “qualified production activities income,” as defined in the Jobs Act, or (b) taxable income (after the deduction for the utilization of any net operating loss carryforwards). The tax deduction is limited to 50% of W-2 wages paid by the taxpayer. FSP 109-1 clarifies that the manufacturer’s deduction provided for under the Jobs Act should be accounted for as a special deduction in accordance with SFAS 109 and not as a tax rate reduction. The adoption of FSP 109-1 had no impact on PSEG, Power and Energy Holdings’ respective financial statements. PSEG, Power and Energy Holdings are evaluating the effect that the manufacturer’s deduction will have in subsequent years.

FSP 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004” (FSP 109-2)

PSEG and Energy Holdings

On December 21, 2004, the FASB issued FSP 109-2, which was effective upon issuance, to provide guidance on the application of the provision in the Jobs Act that allows a special one-time dividends received deduction on the repatriation of certain foreign earnings to a U.S. taxpayer, provided certain criteria are met. The Jobs Act provides a one-year window to repatriate earnings from foreign investments and claim a special 85% dividends received tax deduction on such distributions. The FASB believes that the lack of clarification of certain provisions and the timing of the enactment necessitate a practical exception to the SFAS 109 requirement to reflect the effect of a new tax law in the period of enactment, and therefore, a company is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Jobs Act on its plan for reinvestment or repatriation of foreign earnings for purposes of applying SFAS 109.

As of December 31, 2004, Global had approximately $256 million of undistributed earnings that could be repatriated. The range of undistributed earnings that PSEG could consider for possible repatriation under the Jobs Act is between $0 and $256 million, which would result in additional income tax expense between $0 and $15 million. On January 13, 2005, the IRS published Notice 2005-10, which discusses some of the rules that pertain to this deduction. Whether PSEG will ultimately take advantage of this provision, all or in part, depends upon a number of factors including but not limited to evaluating the impact of Notice 2005-10 and any future authoritative guidance. Global has made no change in its current intention to indefinitely reinvest accumulated earnings of its foreign subsidiaries.

FASB Staff Position 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP 106-2)

PSEG, PSE&G, Power and Energy Holdings

FSP 106-2 provides guidance on the accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Drug Act) for employers who sponsor postretirement health care plans that provide prescription drug benefits. FSP 106-2 also requires those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Medicare Drug Act. The Medicare Drug Act generally permits plan sponsors that provide retiree prescription drug benefits that are “actuarially equivalent” to the benefits of Medicare Part D to be eligible for a non-taxable federal subsidy. FSP 106-2 was effective for periods beginning after June 15, 2004. PSEG selected the prospective method of adoption of FSP 106-2. Upon adoption of

62

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FSP 106-2, the subsidy reduced the accumulated postretirement benefit obligation by $45 million from $929 million to $884 million on July 1, 2004 and therefore will reduce future periodic other postretirement benefits (OPEB) expense. There was no impact from adoption on PSEG’s, PSE&G’s, Power’s or Energy Holdings’ respective financial statements.

FIN 46 (revised December 2003), “Consolidation of Variable Interest Entities” (FIN 46R)

PSEG, PSE&G, Power and Energy Holdings

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), but 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’s financial statements 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 were reclassified for comparability in accordance with FIN 46.

PSEG

PSEG’s Consolidated Balance Sheets reflect its common equity investment in the capital trusts, which were previously eliminated in consolidation resulting in recording equal amounts of additional assets and liabilities of $36 million as of December 31, 2004 and 2003. The invested cash was loaned back to PSEG in connection with the issuance of the preferred securities.

The following table displays the securities, and their original issuance amounts, held by the trusts that have now been deconsolidated.

	As of December 31,
	2004		2003
	(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	$	1,165	$	1,165

PSEG now records 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 $56 million, $56 million and $40 million for the years ended December 31, 2004, 2003 and 2002, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PSE&G

In December 2003, PSE&G redeemed its trust preferred securities. The capital trusts related to the securities were deconsolidated when FIN 46 was adopted in 2003. For PSE&G, interest expense related to these trusts totaled $13 million for each of the years ended December 31, 2003 and 2002.

In addition, PSE&G reviewed its Non-Utility Generation (NUG) contracts to determine if the entities involved were VIEs and, if so, if PSE&G was the primary beneficiary. These entities own power plants that sell their output to PSE&G, which PSE&G is contractually obligated to purchase at a variable price that correlates with certain major operating costs of the plants. As a result, PSE&G assumes some of the variability inherent in the operation of these plants.

PSE&G attempted to obtain the information necessary to conduct the analysis of the cash flow variability required under FIN 46R from two facility owners where PSE&G held a potentially significant variable interest, as defined in FIN 46R, based on the NUG contracts. The respective facility owners did not provide the information based on their respective belief that the data was competitive and proprietary. As a result, PSE&G is unable to determine whether these entities should be consolidated under FIN 46R and applies the scope exception in FIN 46R that exempts entities that conduct exhaustive unsuccessful efforts to obtain the necessary information.

PSE&G incurred Energy Costs related to these two specific NUG contracts of approximately $5 million, $7 million and $8 million for the years ended December 31, 2004, 2003 and 2002, respectively. PSE&G sells the electricity purchased under all of its NUG contracts at market prices in the PJM Interconnection, L.L.C. (PJM) spot market and recovers the difference between the variable contract price and market price through the NUG Market Transition Charge.

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 have been restated in accordance with FIN 46.

The consolidation of the real estate partnerships on the Consolidated Balance Sheets resulted in an increase of approximately $31 million in assets and liabilities. 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 about its obligations under certain guarantees that it has issued in its interim and annual financial statements. 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. 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 14. Commitments and Contingent Liabilities.

EITF Issue No. 04-1, “Accounting for Pre-existing Relationships Between the Parties to a Business Combination” (EITF 04-1)

PSEG, PSE&G, Power and Energy Holdings

EITF 04-1 reaffirms that the consummation of a business combination between two parties that have a pre-existing relationship(s) are multiple element transactions. The EITF also developed a model to address the settlement of the pre-existing relationship. This consensus is effective for business combinations consummated and goodwill impairment tests performed in reporting periods beginning after October 13, 2004. The adoption of EITF 04-1 did not have an effect on PSEG’s, PSE&G’s, Power’s or Energy Holdings’ respective financial statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

EITF Issue No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations” (EITF 03-13)

PSEG, PSE&G, Power and Energy Holdings

EITF 03-13 concluded that classification of a disposed component as a discontinued operation is appropriate only if the ongoing entity has no continuing direct cash flows (a term EITF 03-13 introduces to interpret paragraph 42(a)), and does not retain an interest, contract, or other arrangement sufficient to enable it to exert significant influence over the disposed component’s operating and financial policies after the disposal transaction (an interpretation of paragraph 42(b)). EITF 03-13 should be applied to components that are disposed of or classified as held for sale in periods beginning after December 15, 2004. PSEG, PSE&G, Power and Energy Holdings do not believe that the adoption of EITF 03-13 will have a material effect on their respective financial statements.

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 and Power

The EITF has previously discussed the income statement presentation of gains and losses on contracts held for trading purposes 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 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 Issue No. 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 costs by approximately $228 million and $5 million for the years ended December 31, 2004 and 2003, respectively.

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. 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” (EITF 03-1)

PSEG, PSE&G, Power and Energy Holdings

EITF 03-1 further defines the meaning of an “other-than-temporary impairment” and its application to debt and equity securities. Impairment occurs when the fair value of a security is less than its cost basis. When such a condition exists, the investor is required to evaluate whether the impairment is other-than-temporary as defined in EITF 03-1. When an impairment is other-than-temporary, the unrealized loss must be charged to earnings.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On September 30, 2004, the FASB issued FSP EITF 03-1-1, “Effective date of Paragraphs 10-20 of EITF Issue No. 03-1, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” (FSP EITF 03-1-1). FSP EITF 03-1-1 delayed the effective date for the measurement and recognition guidance contained in EITF 03-1 until further implementation guidance is issued.

EITF 03-1, when fully adopted, could materially impact the accounting for the investments held in Nuclear Decommissioning Trust Funds. The ultimate impact to PSEG and its subsidiaries cannot be determined until the FASB issues final guidance.

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 at January 1, 2003 qualified as derivatives under SFAS 133 and therefore continued to be marked to market. The implementation of these rules had no effect on PSEG’s or Power’s Net Income for the years ended December 31, 2004 and 2003. 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 was no significant impact on PSEG’s, PSE&G’s, Power’s and Energy Holdings’ respective financial statements as a result of the adoption of EITF 01-8.

Derivatives Implementation Group (DIG) Issues

PSEG, PSE&G, Power and Energy Holdings

DIG C15, “SFAS No. 133 Implementation Issue No. C15–Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity” (DIG C15), which became effective January 1, 2004, revised the guidance for the normal purchase and normal sales (NPNS) exception for fair value accounting for power derivatives. If the revised requirements were not met and the contract did not qualify for NPNS treatment, the contract would be considered “financial” in nature and would be marked to market, resulting in a gain or loss on the Statement of Operations. However, the derivative can be used as a hedging derivative to defer gains and losses in OCI if it meets hedge accounting requirements.

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 DIG Issue 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 financial statements.

Note 3. Asset Retirement Obligations

PSEG and Power

In the first quarter of 2003, Power completed a review of potential obligations under SFAS 143 and determined that its obligations were primarily related to the decommissioning of its nuclear power plants. Power’s

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

recorded liability for decommissioning as of December 31, 2002 was approximately $766 million and equaled the balance of its NDT Funds, as discussed below. As of January 1, 2003, this liability was recalculated under SFAS 143, and was 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 was 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
	(Millions)
PSEG
Net Income—as reported	$	1,160	$	235
Net Income—pro forma	$	790	$	221
Earnings per share:
Basic—as reported	$	5.08	$	1.13
Basic—pro forma	$	3.46	$	1.06
Diluted—as reported	$	5.07	$	1.13
Diluted—pro forma	$	3.45	$	1.06
Power
Net Income—as reported	$	844	$	468
Net Income—pro forma	$	474	$	454

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 Balance Sheets as of December 31, 2004 and 2003 are presented in the following table. These amounts were calculated using current information, current assumptions and current interest rates.

	As of December 31,
	2004			2003
	(Millions)
PSEG and Power
Beginning of Period ARO Liability		$	284	$	260
Accretion Expense			26		24
End of Period ARO Liability		$	310	$	284

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 cost of removal liabilities of approximately $418 million and $395 million recorded on its Consolidated Balance Sheets as of December 31, 2004 and 2003, respectively, which did not meet the requirements of an ARO and were therefore classified as regulatory liabilities. See Note 7. Regulatory Matters for further discussion.

Energy Holdings

Energy Holdings identified certain legal obligations that meet the criteria of SFAS 143. However, it determined that they are not material to its financial position, results of operations or net cash flows.

NDT Funds

Power

Prior to 2003, amounts collected from PSE&G customers through rates were deposited into the NDT Funds and realized and unrealized gains and losses in the trust were all recorded as changes in the NDT Funds with an offsetting charge to the nuclear decommissioning liability, pursuant to 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 Funds, and therefore deferral accounting is no longer appropriate for changes in the fair value of securities within the NDT Funds.

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 Funds, approximately $40 million of which were deemed other than temporarily impaired and recorded this amount against earnings in Cumulative Effect of a Change in an Accounting Principle in the first quarter of 2003.

As of December 31, 2004 and 2003, the fair market value of the NDT Funds was approximately $1.1 billion and $985 million, respectively. For further information regarding the NDT Funds, refer to Note 15. Nuclear Decommissioning Trust.

Note 4. Discontinued Operations, Dispositions and Acquisitions

Discontinued Operations

Power

Waterford Generation Facility (Waterford)

On May 27, 2005, Power entered into an agreement to sell its electric generation facility located in Waterford, Ohio to a subsidiary of American Electric Power Company, Inc. (AEP). Since commencing construction of the project, the dramatic increase in natural gas prices relative to the price increase of coal and the failure to receive capacity compensation for the facility caused Power to consider alternatives for the project. After reviewing the alternatives in conjunction with other strategic and financial considerations, Power concluded that the value to be received from the sale of Waterford represented a means to accelerate the realization of the plant’s value. The sale price for the facility and inventory is $220 million. The proceeds, together with anticipated reduction in tax liability, are approximately $300 million, which will be used to retire debt at Power and PSEG.

In May 2005, Power recognized an estimated loss on disposal of $177 million, net of tax, for the initial write-down of its carrying amount of Waterford to its fair value less cost to sell.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The sale is subject to various regulatory approvals. It is anticipated that the transaction will close during the second half of 2005.

Waterford’s operating results for the years ended December 31, 2004 and 2003 are summarized below:

	For the Years Ended December 31,
	2004			2003
	(Millions)
Operating Revenues	$	4		$	4
Pre-Tax Operating Loss	$	(57	)	$	(14	)
Net Loss	$	(33	)	$	(9	)

The carrying amounts of the assets of Waterford as of June 30, 2005 and December 31, 2004 are summarized in the following table:

	As of December 31,
	2004		2003
	(Millions)
Current Assets	$	4	$	13
Noncurrent Assets		507		518
Total Assets of Discontinued Operations	$	511	$	531

Energy Holdings

Carthage Power Company (CPC)

In December 2003, Global entered into a definitive purchase and sale agreement related to the sale of its majority interest in CPC, which owns and operates a power plant located in Rades, Tunisia. In May 2004, Global completed the sale of CPC for approximately $43 million in cash. The assets sold consisted primarily of accounts receivable, property, plant and equipment and other assets. The buyer also assumed certain accounts payable, accrued liabilities and debt obligations.

In December 2003, Global recognized an estimated loss on disposal of $23 million for the initial write-down of its carrying amount of CPC to its fair value less cost to sell. During the first quarter of 2004, Energy Holdings re-evaluated the carrying value of CPC’s assets and liabilities and determined that an additional write-down to fair value of $2 million was required. In May 2004, Global recognized a gain on disposal of $5 million.

69

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The operating results of CPC for the years ended December 31, 2004, 2003 and 2002 are summarized below:

	Years Ended December 31,
	2004		2003			2002
	(Millions)
Operating Revenues	$	38	$	95			$	57
Pre-Tax Income (Loss)	$	2	$	(8	)		$	2
Net Income (Loss)	$	2	$	(1	)		$	1

The carrying amounts of the assets and liabilities of CPC as of December 31, 2003 are summarized in the following table:

	As of December 31, 2003
	(Millions)
Current Assets		$	45
Noncurrent Assets			253
Total Assets		$	298
Current Liabilities		$	161
Noncurrent Liabilities			81
Total Liabilities		$	242

Energy Technologies

In June 2002, Energy Holdings adopted a plan to sell Energy Technologies, its heating, ventilating and air conditioning (HVAC)/mechanical operating companies. The HVAC/mechanical operating companies met the criteria for classification as components of Discontinued Operations. Energy Holdings reduced the carrying value of the Energy Technologies’ assets and liabilities to their fair value less costs to sell, and recorded a loss on disposal for the year ended December 31, 2002 of $20 million, net of $11 million tax benefit. During the first quarter of 2003, Energy Holdings re-evaluated the carrying value of Energy Technologies’ assets and liabilities and determined that an additional write-down to fair value of $9 million, net of a $3 million tax benefit, was required. The sale of the HVAC/mechanical operating companies and Energy Technologies was complete as of September 30, 2003.

The revenues and results of operations of Energy Technologies for the periods ended December 31, 2003 and 2002 are displayed below:

	Years Ended December 31,
	2003			2002
	(Millions)
Operating Revenues	$	68		$	378
Pre-Tax Loss	$	(18	)	$	(32	)
Net Loss	$	(11	)	$	(21	)

Tanir Bavi Power Company Private Ltd. (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, net of a $7 million tax benefit, for the year ended December 31, 2002. The facility met the criteria for classification as a component of discontinued operations. The operating results of Tanir Bavi for the year ended December 31, 2002 are summarized below.

	Year Ended December 31, 2002
	(Millions)
Operating Revenues		$	61
Pre-Tax Income		$	7
Net Income		$	5

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Dispositions

Energy Holdings

Meiya Power Company Limited (MPC)

On October 1, 2004, Global entered into an agreement to sell its 50% equity interest in MPC to BTU Power Company. The sale closed on December 31, 2004 for approximately $236 million, of which $100 million was paid in cash and the balance of approximately $136 million was provided in the form of a secured promissory note due on March 31, 2005. The sale resulted in an after-tax gain of approximately $2 million. In January 2005, a $38 million principal payment on the note was received.

Luz del Sur S.A.A. (LDS)

In April 2004, Global sold a portion of its shares in LDS in the Lima stock exchange, reducing its ownership from 44% to 38% and received gross proceeds of approximately $31 million. Global realized an after-tax gain of approximately $5 million in the second quarter of 2004 related to the LDS sale. The gain is recorded in Income from Equity Method Investments on the Consolidated Statements of Operations.

GWF Energy LLC (GWF Energy)

Prior to the fourth quarter of 2002, GWF Energy was accounted for under 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%, therefore 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 31, 2003. In February 2004, Harbinger GWF LLC (Harbinger) repurchased a 14.9% ownership interest from Global for approximately $14 million, resulting in a 60% ownership interest in GWF Energy as of December 31, 2004.

Resources

In March 2004, Resources entered into an agreement with Midwest Generation LLC, an indirect subsidiary of Edison Mission Energy (EME), to terminate its lease investment in the Collins generating facility in Illinois. In April 2004, Resources closed on the termination of the lease agreement and received gross proceeds of approximately $184 million (approximately $85 million, after-tax) that allowed it to substantially recover its investment in this lease. Resources recorded a realized loss of $11 million, after-tax, related to the termination of the lease.

In January 2004, Resources terminated two lease transactions with Qantas and China Eastern resulting from the lessees exercising their respective purchase options. Resources received aggregate gross cash proceeds of approximately $45 million (approximately $9 million, after-tax), and recorded an after-tax gain of $4 million.

In November 2003, Resources sold its interest in Chelsea Historic Properties. Resources received net cash proceeds of $9 million and recorded an after-tax gain of approximately $4 million. As a result of the sale of this lease, Resources paid 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, recorded an after-tax gain of $4 million and paid income taxes of $115 million in 2003.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Acquisitions

Energy Holdings

Texas Independent Energy, L.P. (TIE)

In June 2004, Global notified TECO Energy, Inc. (TECO) of its intent to convert a fractional amount of its preferred interest in TIE and thereby gain majority control of TIE.

In July 2004, Global signed an agreement to acquire all of TECO’s 50% equity interest in TIE for less than $1 million, which was included in cash flows used in investing activities. With this purchase, Global now owns 100% of TIE and consolidated this investment effective July 1, 2004. As a result, Energy Holdings presents approximately $630 million of Property, Plant and Equipment, $72 million of Other Assets, $461 million of Long-Term Non-Recourse Debt, and $27 million of Other Liabilities related to TIE in its Condensed Consolidated Balance Sheet as of the effective acquisition date.

The following (unaudited) pro forma consolidated results of operations of Energy Holdings have been prepared as if the acquisition of TIE had occurred at the beginning of 2002:

	Pro Forma
	For the Years Ended December 31,
	2004		2003		2002
	(Millions)
Operating Revenues	$	1,287	$	1,178	$	886
Income (Loss) Before Discontinued Operations and Cumulative Effect of a Change in Accounting Principle	$	137	$	177	$	(233	)
Net Income (Loss)	$	142	$	133	$	(403	)

The pro forma information is presented for informational purposes only and is not necessarily indicative of the results of operations that actually would have been achieved had the acquisition been consummated as of that time, nor is it intended to be a projection of future results.

Electrowina Skawina S.A. (Skawina)

In 2002, Global acquired a controlling interest in the electric and thermal coal-fired Skawina plant in Poland. In accordance with the purchase agreement, Global acquired an additional 12% from Skawina’s employees in 2004, increasing its ownership interest to approximately 75%. The transaction required an additional investment of approximately $8 million and closed in the third quarter of 2004.

Power

In 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. Wisvest Connecticut LLC was subsequently renamed PSEG Power Connecticut LLC (Power Connecticut).

The aggregate purchase price was approximately $271 million, which was included in cash flows used in investing activities. As a result, PSEG and Power consolidated approximately $235 million of Property, Plant and Equipment, $47 million of Intangible Assets, $25 million of Current Assets, and $36 million of Liabilities in 2002.

Note 5. 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 July 2003, PSE&G received an oral decision from the BPU approving a proposed settlement with certain modifications. The related Final Order was received on April 22, 2004.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 included a $30 million pre-tax refund to customers related to revenues previously collected in rates for nuclear decommissioning. Because this amount reflected the final accounting for PSEG’s generation-related business pursuant to the four-year transition plan mandated by the Final Order, the adjustment was recorded as an $18 million, after-tax, Extraordinary Item as required under 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.”

Note 6. Asset Impairments

Energy Holdings

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 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 its projects in Argentina and to manage its operations to reduce the financial losses incurred as a result of such actions.

Based on actual and projected operating losses 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.

The combination of the operating losses, goodwill impairments and write-down of $497 million for all Argentine assets for the year ended December 31, 2002, combined with certain loss contingencies resulted in a pre-tax charge to earnings of $621 million ($404 million after-tax). 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 has determined that no valuation allowance is required.

The remaining $27 million of the $217 million deferred tax asset will expire in 2007. PSEG expects to fully realize this deferred tax asset.

Note 7. Regulatory Matters

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 FERC or PSE&G’s experience with prior rate cases. As of December 31, 2004 and 2003, approximately 89% 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.

73

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PSE&G had the following regulatory assets and liabilities on the Consolidated Balance Sheets:

	As of December 31,
	2004		2003		Recovery/Refund Period
	(Millions)
Regulatory Assets
Securitized Stranded Costs	$	3,427	$	3,661	Through December 2015(1)(2)
Deferred Income Taxes		366		369	Various
Other Postretirement Benefit (OPEB)-Related Costs		154		174	Through December 2012(2)
Societal Benefits Charges (SBC)		430		—	Through December 2005(1)(2)
Manufactured Gas Plant Remediation Costs		356		123	Various(2)
Unamortized Loss on Reacquired Debt		97		79	Over remaining debt life(1)
Underrecovered Gas Costs		—		53	Through September 2004(1)(2)
Non-Utility Transition Charge (NTC)		102		112	Through December 2005(1)(2)
Unrealized Losses on Interest Rate Swap		34		51	Through December 2015(2)
Repair Allowance		76		82	Through August 2013(1)(2)
Decontamination and Decommissioning Costs		11		16	Through December 2007(2)
Asbestos Abatement Costs		11		12	Through 2020(2)
Plant and Regulatory Study Costs		21		22	Through December 2021(2)
Regulatory Restructuring Costs		38		42	Through August 2013(1)(2)
Other		4		4	To be determined(1)
Total Regulatory Assets	$	5,127	$	4,800
Regulatory Liabilities
Cost of Removal	$	418	$	395	Various
Excess Depreciation Reserve		60		127	Through December 2005(2)
Overrecovered Gas Costs		17		—	Through December 2005(1)(2)
SBC		—		19	Through December 2005(1)(2)
Other		50		57	Various(1)
Total Regulatory Liabilities	$	545	$	598

______________

(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.

Securitized Stranded Costs: This reflects deferred costs, which are being recovered through the securitization transition charge authorized by the BPU. Funds collected through the securitization transition charge are remitted to Transition Funding and are solely 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.”

74

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SBC: The SBC, as authorized by the BPU and the New Jersey Electric Discount and Energy Competition Act (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 2005 through 2008, recorded at discounted present value; 7) amortization of the market transition charge (MTC) overrecovery; and 8) the Remediation Adjustment Clause for incurred Manufactured Gas Plants (MGP) remediation expenditures. All components except for MTC and Clean Energy accrue interest.

MGP Remediation Costs: Represents the low end of the range for the remaining environmental investigation and remediation program costs that are probable of recovery in future rates.

Unamortized Loss on Reacquired Debt: Represents losses on reacquired long-term debt, which are recovered through rates over the remaining life of the debt or the life of the refinanced debt.

Overrecovered/Underrecovered Gas Costs: Represents PSE&G’s gas costs in excess or shortfall of the amount included in rates and probable of recovery or refund in the future.

NTC: This clause was established by the EDECA to account for above market costs related to 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 are being 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: 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 prior to the generation asset transfer to Power in 2000.

Asbestos Abatement Program: Represents costs incurred to remove and dispose of asbestos insulation at PSE&G’s fossil generating stations. Per a BPU order dated December 9, 1992, these costs are treated as Cost of Removal for ratemaking purposes.

Plant and Regulatory Study Costs: These are costs incurred by PSE&G and required by the BPU which are 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 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 deferred consolidated billing start-up and deferred Energy Information Control Network program costs. Both items were deferred based on BPU orders and the recovery period will be determined in future proceedings.

Cost of Removal: PSE&G accrues and collects for Cost of Removal in rates. Pursuant to the adoption of SFAS 143, the liability for Cost of Removal was reclassified as a regulatory liability. 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 liability as a result of the BPU order in PSE&G’s Electric Base Rate Case. This $155 million is being amortized from August 1, 2003 through December 31, 2005.

Other Regulatory Liabilities: This includes the following: 1) a retail adder included in the BGS charges beginning on August 1, 2003. The BPU will determine the disposition of this amount in a future proceeding; 2) Gas Margin

75

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Adjustment Cost to be returned to customers in the future; and 3) amounts collected from customers in order for Transition Funding to obtain a AAA rating on its transition bonds.

Note 8. Earnings Per Share (EPS)

PSEG

Diluted EPS is 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, upon payment of performance units and upon conversion of Participating Units. The following table shows the effect of these stock options, performance units and Participating Units on the weighted average number of shares outstanding used in calculating diluted EPS:

	Years Ended December 31,
	2004						2003						2002
	Basic			Diluted			Basic			Diluted			Basic			Diluted
EPS Numerator:
Earnings (Millions)
Continuing Operations	$	754		$	754		$	861		$	861		$	405		$	405
Discontinued Operations		(28	)		(28	)		(53	)		(53	)		(49	)		(49	)
Extraordinary Item		—			—			(18	)		(18	)		—			—
Cumulative Effect of a Change in Accounting Principle		—			—			370			370			(121	)		(121	)
Net Income	$	726		$	726		$	1,160		$	1,160		$	235		$	235
EPS Denominator (Thousands):
Weighted Average Common Shares Outstanding	236,984			236,984			228,222			228,222			208,647			208,647
Effect of Stock Options		—			464			—			602			—			166
Effect of Stock Performance Units		—			36			—			—			—			—
Effect of Participating Units		—			802			—			—			—			—
Total Shares	236,984			238,286			228,222			228,824			208,647			208,813
EPS:
Continuing Operations	$	3.18		$	3.17		$	3.77		$	3.76		$	1.94		$	1.94
Discontinued Operations		(0.12	)		(0.12	)		(0.23	)		(0.23	)		(0.23	)		(0.23	)
Extraordinary Item		—			—			(0.08	)		(0.08	)		—			—
Cumulative Effect of a Change in Accounting Principle		—			—			1.62			1.62			(0.58	)		(0.58	)
Net Income	$	3.06		$	3.05		$	5.08		$	5.07		$	1.13		$	1.13

There were approximately 2.9 million, 5.3 million and 6.3 million stock options excluded from the weighted average common shares calculation used for diluted EPS due to their antidilutive effect for the years ended December 31, 2004, 2003 and 2002, respectively.

There were approximately 9.2 million Participating Units excluded from the weighted average common shares calculation used for diluted EPS due to their antidilutive effect for the years ended December 31, 2003 and 2002.

Dividend payments on common stock for the year ended December 31, 2004 were $2.20 per share and totaled approximately $522 million. Dividend payments on common stock for the year ended December 31, 2003 were $2.16 per share and totaled approximately $493 million. Dividend payments on common stock for the year ended December 31, 2002 were $2.16 per share and totaled approximately $456 million.

76

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9. Goodwill and Other Intangibles

PSEG, Power and Energy Holdings

PSEG, Power and Energy Holdings conducted an annual review for goodwill impairment as of November 30, 2004 and concluded that goodwill was not impaired.

Power and Energy Holdings

As of December 31, 2004 and 2003, Power’s and Energy Holdings’ goodwill and pro-rata share of goodwill in equity method investments were as follows:

	As of December 31,
	2004			2003
	(Millions)
Consolidated Investments
Energy Holdings—Global
Sociedad Austral de Electricidad S.A. (SAESA)(A)		$	373		$	350
Electroandes S.A. (Electroandes)			133			133
Elektrocieplownia Chorzow Sp. Z o.o. (ELCHO)			8			8
Total Energy Holdings—Global			514			491
Power—Albany Steam Station (Albany Station)			16			16
Total PSEG Consolidated Goodwill			530			507
Pro-Rata Share of Equity Method Investments
Energy Holdings—Global
Rio Grande Energia S.A. (RGE)(A)			81			73
Chilquinta Energia S.A. (Chilquinta)(A)			178			163
LDS(B)			55			63
Kalaeloa Partners L.P. (Kalaeloa)			25			25
Pro-Rata Share of Equity Investment Goodwill			339			324
Total PSEG Goodwill		$	869		$	831

______________

(A) Changes relate to changes in foreign exchange rates.

(B) Changes primarily relate to a sale of a portion of Global’s interest in LDS in April 2004. See Note 4. Discontinued Operations, Dispositions and Acquisitions.

PSEG, PSE&G, Power and Energy Holdings

In addition to goodwill, as of December 31, 2004 and 2003, PSEG, PSE&G, Power, Energy Holdings and Services had the following recorded intangible assets:

	PSE&G			Power		Energy Holdings			Services			Consolidated Total
						(Millions)
As of December 31, 2004:
Defined Benefit Pension Plan(A)		$	2	$	3		$	3		$	4		$	12
Emissions Allowances(B)			—		40			—			—			40
Various Access Rights(A)			—		40			—			—			40
Transmission Credits(C)			—		8			—			—			8
Total Intangibles		$	2	$	91		$	3		$	4		$	100
As of December 31, 2003:
Defined Benefit Pension Plan(A)		$	2	$	3		$	4		$	5		$	14
Emissions Allowances(B)			—		49			—			—			49
Various Access Rights(A)			—		40			—			—			40
Transmission Credits(C)			—		5			—			—			5
Other(C)			—		—			1			—			1
Total Intangibles		$	2	$	97		$	5		$	5		$	109

______________

(A) Not subject to amortization.

(footnotes continued on next page)

77

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(footnotes continued from previous page)

(B) Expensed when used or sold amounting to approximately $7 million, $17 million and $3 million for the years ended December 31, 2004, 2003 and 2002, respectively.

(C) Amortized on a straight-line basis.

Note 10. 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, 2004 and 2003:

	As of December 31,
	2004		2003
	(Millions)
Energy Holdings:
Leveraged Leases	$	2,851	$	2,981
Partnerships:
General Partnerships		13		25
Limited Partnerships		206		506
Total Partnerships		219		531
Corporate Joint Ventures		894		1,041
Securities		3		5
Other Investments(A)		15		27
Total Long-Term Investments of Energy Holdings		3,982		4,585
PSE&G(B)		138		131
Power(C)		11		43
Other Investments(D)		50		51
Total Long-Term Investments	$	4,181	$	4,810

______________

(A) Primarily relates to DSM investments at Resources.

(B) Primarily relates to life insurance and supplemental benefits of $130 million and $123 million as of December 31, 2004 and 2003, respectively.

(C) Amounts represent sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emission credits held for trading purposes.

(D) Amounts represent investments at PSEG (parent company), primarily related to investments in its Capital Trusts.

 

78

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Energy Holdings

Leveraged Leases

Energy Holdings’ net investment, through Resources, in leveraged leases was comprised of the following elements:

	As of December 31,
	2004			2003
	(Millions)
Lease rents receivable (net of non-recourse debt)	$	3,094		$	3,373
Estimated residual value of leased assets		1,278			1,405
		4,372			4,778
Unearned and deferred income		(1,521	)		(1,797	)
Total investments in leveraged leases		2,851			2,981
Deferred tax liabilities		(1,623	)		(1,563	)
Net investment in leveraged leases	$	1,228		$	1,418

Resources’ pre-tax income and income tax effects related to investments in leveraged leases were as follows:

	Years Ended December 31,
	2004			2003			2002
	(Millions)
Pre-tax income of leveraged leases	$	153		$	206		$	251
Income tax effect on pre-tax income of leveraged leases	$	12		$	74		$	92
Amortization of investment tax credits of leveraged leases	$	(1	)	$	(1	)	$	(1	)

Of the $53 million decrease in pre-tax leveraged lease income in 2004 as compared to 2003, $31 million was due to a lower economic lease yield, computed for certain leases, resulting from changes in certain lease forecast assumptions pertaining to state income taxes. A change in a key assumption which effects 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. Any change in the net investment in the leveraged leases is recognized as a gain or loss in the year the assumption is changed. The remaining $22 million decrease in pre-tax leveraged lease income was primarily due to a realized loss and a reduction in leveraged lease income related to the termination of the Collins lease with Midwest Generation LLC in April 2004.

Of the $45 million decrease in pre-tax leveraged lease income in 2003 as compared to 2002, $29 million resulted from a gain recognized in 2002 due to a recalculation of certain leveraged leases. The change in assumption that occurred was related to a change in New Jersey tax rates due to the restructuring of Resources from a corporation to a limited liability company in 2002. This change allowed Resources to more efficiently match state tax expenses of an affiliate company with the state tax benefits associated with its lease portfolio. The remaining $16 million decrease in pre-tax leveraged lease income was due to the termination of two leveraged leases in November 2002.

Partnership Investments and Corporate Joint Ventures

Energy Holdings’ partnership investments of $219 million and $531 million as of December 31, 2004 and 2003, respectively, and corporate joint ventures of approximately $894 million and $1 billion as of December 31, 2004 and 2003, 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 $41 million and $94 million as of December 31, 2004 and 2003, respectively.

79

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The leveraged buyout funds mentioned above hold publicly-traded securities as of December 31, 2004. The book value of the investment in the leveraged buyout funds was $27 million and $75 million as of December 31, 2004 and 2003, respectively.

Resources applies fair value accounting to investments within the funds where publicly-traded market prices are available. Approximately $27 million and $26 million represent the fair value of Resources’ share of the publicly traded securities in the funds as of December 31, 2004 and 2003, 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 13. Risk Management.

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 billion and $1.5 billion as of December 31, 2004 and 2003, respectively. During the three years ended December 31, 2004, 2003 and 2002, the amount of dividends from these investments was $89 million, $130 million and $64 million, respectively. Global’s share of income and cash flow distribution percentages ranged from 25% to 60% as of December 31, 2004. Interest is earned on loans made to various projects. Such loans earn interest that ranged from 6% to 12% during 2004.

As of December 31, 2004, Global’s recorded investment in equity method subsidiaries was approximately $1 billion as compared to approximately $770 million of underlying equity in net assets of such investments. The difference primarily relates to an approximate $160 million investment in a foreign subsidiary which is classified as an equity investment on Global’s financial statements and recorded as a loan on the equity method subsidiary. Investment classification is appropriate due to its long-term investment nature. The difference is also related to a $65 million Euro-denominated receivable from a foreign subsidiary included in Global’s investment in equity method subsidiaries.

Global had the following equity method investments as of December 31, 2004:

Name	Location	% Owned
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 L.P.	CA	50%
Tracy	CA	35%
GWF Energy Hanford-Peaker Plant	CA	60%
Henrietta-Peaker Plant	CA	60%
Tracy-Peaker Plant	CA	60%
Bridgewater	NH	40%
Conemaugh	PA	50%
Prisma 2000 S.p.A. (Prisma) Crotone	Italy	25%
Bando D’Argenta I	Italy	50%
Strongoli	Italy	25%
Turboven Maracay	Venezuela	50%
Cagua	Venezuela	50%
RGE	Brazil	32%
Chilquinta	Chile	50%
LDS	Peru	38%

80

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Summarized results of operations and financial position of affiliates in which Global applied the equity method of accounting are presented below:

	Foreign			Domestic		Total
	(Millions)
December 31, 2004
Statement of Operations Information
Revenue	$	1,397		$	537	$	1,934
Gross Profit	$	510		$	130	$	640
Minority Interest	$	7		$	—	$	7
Net Income	$	148		$	46	$	194
Balance Sheet Information
Assets:
Current Assets	$	419		$	89	$	508
Property, Plant and Equipment		1,612			627		2,239
Goodwill		716			50		766
Other Noncurrent Assets		240			34		274
Total Assets	$	2,987		$	800	$	3,787
Liabilities:
Current Liabilities	$	374		$	78	$	452
Debt*		1,024			293		1,317
Other Noncurrent Liabilities		188			43		231
Minority Interest		65			—		65
Total Liabilities		1,651			414		2,065
Equity		1,336			386		1,722
Total Liabilities and Equity	$	2,987		$	800	$	3,787
December 31, 2003
Statement of Operations Information
Revenue	$	1,042		$	747	$	1,789
Gross Profit	$	415		$	231	$	646
Minority Interest	$	(5	)	$	—	$	(5	)
Net Income	$	138		$	67	$	205
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
Statement of Operations Information
Revenue	$	1,022		$	516	$	1,538
Gross Profit	$	413		$	166	$	579
Minority Interest	$	(10	)	$	—	$	(10	)
Net Income	$	45		$	20	$	65

______________

* Debt is non-recourse to PSEG, Energy Holdings and Global.

81

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The differences in the results of operations and the financial position as of and for the year ended December 31, 2004, as compared to the same period in 2003, was due to: (1) the sale of a portion of its shares in LDS reducing its ownership from 44% to 38% in April 2004; (2) the acquisition of all of TECO’s interests in TIE, bringing Global’s ownership interest to 100% and therefore consolidating the entity as of July 1, 2004; (3) the sale of its 50% equity interest in MPC in December 2004; and (4) the change in accounting for Global’s investment is PPN Power Generating Company Limited (PPN) from the equity method of accounting to the cost method in June 2004. See Note 4. Discontinued Operations, Dispositions and Acquisitions.

Global also has investments in certain companies in which it does not have the ability to exercise significant influence. Such investments are accounted for under the cost method. As of December 31, 2004 and 2003, the carrying value of these investments aggregated $46 million and $7 million, respectively. The primary reason for the increase in 2004 as compared to 2003 is the change in accounting for Global’s investment in PPN to the cost method in June 2004. Global did not test these investments for impairment in 2004 since there were no identified events or changes in circumstances that would have an adverse effect on the fair value of these investments.

Note 11. Schedule of Consolidated Capital Stock and other Securities

PSEG and PSE&G

	Outstanding Shares As of December 31, 2004	Current Redemption Price Per Share		Book Value As of December 31
				2004		2003
				(Millions)
PSEG Common Stock (no par value)(A)Authorized 500,000,000 shares; (outstanding as of December 31, 2003, 236,133,442 shares)	238,099,067			$	3,591	$	3,509
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 October 2003, PSEG issued approximately 8.8 million shares of its common stock for $356 million. In November 2002, PSEG issued 17.3 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, 2004, 2003 and 2002, PSEG issued approximately 1.9 million, 2.1 million and 2.2 million shares, respectively, for approximately $83 million, $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 approximately 3.2 million shares as of December 31, 2004.

(B) As of December 31, 2004, there was an aggregate of approximately 6.7 million shares of $100 par value and 10 million 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 such voting rights cease. There are no arrearages in cumulative preferred stock and hence currently no 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, 2004 and 2003, the annual dividend requirement and the embedded dividend rate for PSE&G’s Preferred Stock without mandatory redemption was approximately $4 million and 5.03%, respectively, for each year.

82

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Fair Value of Preferred Securities

The estimated fair value of PSE&G’s Cumulative Preferred Stock was $73 million and $70 million as of December 31, 2004 and 2003, respectively. The estimated fair value was determined using market quotations.

Note 12. Schedule of Consolidated Debt

Long-Term Debt

		As of December 31,
	Maturity	2004			2003
		(Millions)
PSEG
Senior Note—6.89%	2005–2009	$	245		$	245
Senior Note—4.66%(C)	2009		200			—
Debt Supporting Trust Preferred Securities(A)	2007–2047		1,201			1,201
Other			8			16
Principal Amount Outstanding			1,654			1,462
Amounts Due Within One Year(B)			(49	)		—
Total Long-Term Debt of PSEG (Parent)		$	1,605		$	1,462
PSE&G
First and Refunding Mortgage Bonds:
6.50%(G)	2004	$	—		$	286
9.125%	2005		125			125
6.75%	2006		147			147
LIBOR plus 0.125%(E)(N)	2006		175			—
6.25%	2007		113			113
7.375%(E)	2014		—			159
6.75%	2016		171			171
6.45%	2019		5			5
9.25%	2021		134			134
6.38%	2023		157			157
7.00%(D)	2024		—			254
5.20%	2025		23			23
1.10% Auction Rate(N)	2028		64			64
6.55%(F)	2029		—			93
1.38% Auction Rate(F)(N)	2029		93			—
6.20%(F)	2030		—			88
1.38% Auction Rate(F)(N)	2030		88			—
6.25%(F)	2031		—			104
1.40% Auction Rate(F)(N)	2031		104			—
5.45%	2032		50			50
6.40%	2032		100			100
1.14% Auction Rate(N)	2033		50			50
1.10% Auction Rate(N)	2033		50			50
1.15% Auction Rate(N)	2033		45			45
8.00%	2037		7			7
5.00%	2037		8			8
Medium-Term Notes:
4.00%	2008		250			250
8.16%	2009		16			16
8.10%	2009		44			44
5.125%	2012		300			300
5.00%	2013		150			150
5.375%	2013		300			300
5.00%(D)	2014		250			—
7.04%	2020		9			9

(table continued on next page)

83

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(table continued from previous page)

		As of December 31,
	Maturity	2004			2003
		(Millions)
7.18%	2023		5			5
7.15%	2023		34			34
Principal Amount Outstanding			3,067			3,341
Amounts Due Within One Year(B)			(125	)		(286	)
Net Unamortized Discount			(4	)		(11	)
Total Long-Term Debt of PSE&G (Parent)		$	2,938		$	3,044
Transition Funding (PSE&G)
Securitization Bonds:
5.74%(M)	2007	$	34		$	171
5.98%	2008		183			183
6.29%	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			2,085			2,222
Amounts Due Within One Year(B)			(146	)		(137	)
Total Securitization Debt of Transition Funding		$	1,939		$	2,085
Total Long-Term Debt of PSE&G		$	4,877		$	5,129
Power
Senior Notes:
6.875%	2006	$	500		$	500
3.75%(H)	2009		250			—
7.75%	2011		800			800
6.95%	2012		600			600
5.00%(H)	2014		250			—
5.50%	2015		300			300
8.625%	2031		500			500
Total Senior Notes		$	3,200		$	2,700
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)		$	3,316		$	2,816
Non-Recourse Debt:
Variable (3.00% to 5.00%)(H)	2005	$	—		$	800
Total Long-Term Debt of Power		$	3,316		$	3,616
Energy Holdings (Parent)
Senior Notes:
9.125%(I)	2004	$	—		$	267
7.75%(J)	2007		309			350
8.625%	2008		507			507
10.00%	2009		400			400
8.50%	2011		544			544
Principal Amount Outstanding			1,760			2,068
Amounts Due Within One Year(B)			—			(267	)
Net Unamortized Discount and Senior Note Rate Swap			(4	)		(1	)
Total Long-Term Debt of Energy Holdings (Parent)		$	1,756		$	1,800

(table continued on next page)

84

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(table continued from previous page)

		As of December 31,
	Maturity	2004			2003
		(Millions)
Global (Energy Holdings)
Non-Recourse Debt:
Skawina–5.60%	2004–2005	$	17		$	3
Dhofar Power–6.27%	2004–2018		195			201
ELCHO (Chorzow)–9.550%–13.225%	2004–2019		305			285
SAESA–3.807%	2004–2023		167			167
TIE (Odessa)–4.3125%–8.000%(K)	2007		227			—
TIE (Guadalupe)–4.3125%–8.000%(K)(L)	2009		207			—
Electroandes–5.880%–6.438%	2005–2016		103			100
Chilquinta–5.58%–6.62%	2008–2011		162			161
Principal Amount Outstanding			1,383			917
Amounts Due Within One Year(B)			(62	)		(33	)
Total Long-Term Debt of Global		$	1,321		$	884
Resources (Energy Holdings)
8.60%–9.30%—Non-Recourse Bank Loan	2004–2020	$	31		$	32
Amounts Due Within One Year(B)			(2	)		(1	)
Total Long-Term Debt of Resources		$	29		$	31
EGDC (Energy Holdings)
8.27%—Non-Recourse Mortgage	2004–2013	$	23		$	25
Amounts Due Within One Year(B)			(2	)		(2	)
Total Long-Term Debt of EGDC		$	21		$	23
Total Long-Term Debt of Energy Holdings		$	3,127		$	2,738
Total PSEG Consolidated Long-Term Debt		$	12,925		$	12,945

______________

(A) As of each of the years ended December 31, 2004 and 2003, 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 approximately $104 million and 8.98%.

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 buy 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 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

(footnotes continued on next page)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(footnotes continued from previous page)

will issue between 11.4 million and 13.7 million 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 19. 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, 2004 are as follows:

			PSE&G							Energy Holdings
Year	PSEG		PSE&G		Transition Funding			Power		Energy Holdings		Global		Resources			EGDC		Total
										(Millions)
2005	$	49	$	125		$	146	$	—	$	—	$	62		$	2	$	2	$	386
2006		49		322			—		500		—		60			2		2		935
2007		509		113			34		—		309		261			1		2		1,229
2008		49		250			183		—		507		130			1		2		1,122
2009		249		60			—		250		400		230			2		3		1,194
	$	905	$	870		$	363	$	750	$	1,216	$	743		$	8	$	11	$	4,866

______________

(C) In September 2004, PSEG issued and sold $200 million of its 4.66% Series A Senior Notes due 2009 in a private placement. The proceeds were used to reduce short-term debt.

(D) In August 2004, PSE&G issued $250 million of 5.00% Medium-Term Notes due 2014. The proceeds of this issuance were used to redeem the remaining outstanding $254 million of PSE&G’s First and Refunding Mortgage Bonds, 7% Series SS due 2024 in September 2004.

(E) In June 2004, PSE&G issued $175 million of floating rate First and Refunding Mortgage Bonds due 2006. The interest is set quarterly at LIBOR plus 0.125%. The proceeds were primarily used to redeem $159 million of 7.375% Series TT First and Refunding Mortgage Bonds due 2014 in June 2004.

(F) In August 2004, PSE&G issued $104 million of its First and Refunding Mortgage Bonds, Pollution Control Series AC due 2031; $88 million of its First and Refunding Mortgage Bonds, Pollution Control Series AD due 2030; and $93 million of its First and Refunding Mortgage Bonds, Pollution Control Series AE due 2029. The proceeds were used to refund $104 million of PSE&G’s First and Refunding Mortgage Bonds, Pollution Control Series Q due 2031, $88 million of PSE&G’s First and Refunding Mortgage Bonds, Pollution Control Series R due 2030 in August 2004; and $93 million of PSE&G’s First and Refunding Mortgage Bonds, Pollution Control Series S due 2029 in October 2004.

(G) In May 2004, $286 million of PSE&G’s 6.50% Series PP First and Refunding Mortgage Bonds matured.

(H) In March 2004, Power issued $250 million of 3.75% Senior Notes due April 2009 and $250 million of 5.00% Senior Notes due April 2014. The net proceeds of $488 million, together with other available cash, were used to fund the repayment of $800 million of project finance debt of certain of Power’s subsidiaries.

(I) In February 2004, Energy Holdings repaid $267 million of its 9.125% Senior Notes at maturity.

(J) During the second quarter of 2004, Energy Holdings repurchased approximately $41 million of its 7.75% Senior Notes due April 2007 at a premium of $3 million, reducing the aggregate amount of that security outstanding to $309 million.

(K) In July 2004, Global signed an agreement to acquire all of TECO Energy Inc.’s 50% equity interest in TIE for less than $1 million. With this purchase, Global now owns 100% of TIE and consolidated this investment effective July 1, 2004. As a result, Energy Holdings presents approximately $434 million of Long-Term Non-Recourse Debt on its Consolidated Balance Sheet as of December 31, 2004.

(L) In October 2004, Global invested approximately $20 million in TIE which was primarily used to reduce the Non-Recourse Long-Term Debt related to the Guadalupe project. The maturity date of the remaining debt of approximately $207 million associated with the project was extended from April 2006 to December 2009.

(M) In December 2004, September 2004, June 2004 and March 2004, Transition Funding repaid approximately $38 million, $37 million, $30 million and $32 million, respectively, of its transition bonds.

(N) As of December 31, 2004, variable interest rates were 2.66%, 1.75%, 1.80%, 1.85%, 1.80%, 1.80%, 1.80%, 1.80%, respectively.

86

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Short-Term Liquidity

PSEG, PSE&G, Power and Energy Holdings

As of December 31, 2004, PSEG and its principal subsidiaries had an aggregate of approximately $2.7 billion of committed credit facilities. Each facility is restricted as to availability and use to the specific companies as listed below.

Company	Expiration Date	Total Facility		Primary Purpose	Usage as of 12/31/2004			Available Liquidity as of 12/31/2004
		(Millions)
PSEG:
4-year Credit Facility	April 2008	$	450	Commercial Paper (CP) Support/ Funding/ Letters of Credit	$	—		$	450
5-year Credit Facility	March 2005	$	280	CP Support	$	280		$	—
3-year Credit Facility	December 2005	$	350	CP Support/ Funding/ Letters of Credit	$	153		$	197
Uncommitted Bilateral Agreement	N/A		N/A	Funding	$	—			N/A
Bilateral Term Loan	April 2005	$	75	Funding	$	75		$	—
Bilateral Revolver	April 2005	$	25	Funding	$	25		$	—
PSE&G:
5-year Credit Facility	June 2009	$	600	CP Support/ Funding/ Letters of Credit	$	90		$	510
Uncommitted Bilateral Agreement	N/A		N/A	Funding	$	15			N/A
PSEG and Power:
3-year Credit Facility(A)	April 2007	$	600	CP Support/Funding/ Letters of Credit	$	17	(B)	$	583
Power:
3-year Credit Facility	August 2005	$	25	Funding/ Letters of Credit	$	—		$	25
Bilateral Credit Facility	March 2010	$	100	Funding/ Letters of Credit	$	90	(B)	$	10
Energy Holdings:
3-year Credit Facility(C)	October 2006	$	200	Funding/ Letters of Credit	$	31	(B)	$	169

______________

(A) PSEG/Power joint and several co-borrower facility.

(B) These amounts relate to letters of credit outstanding.

(C) Energy Holdings/Global/Resources joint and several co-borrower facility.

Energy Holdings

As of December 31, 2004, Energy Holdings had loaned $115 million of excess cash to PSEG. For information regarding affiliate borrowings, see Note 23. 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, 2004 and 2003, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	December 31, 2004				December 31, 2003
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Millions)
Long-Term Debt:
PSEG	$	1,654	$	1,817	$	1,462	$	1,586
Energy Holdings		3,193		3,389		3,041		3,230
PSE&G		3,063		3,209		3,330		3,601
Transition Funding (PSE&G)		2,085		2,272		2,222		2,474
Power		3,316		3,714		3,616		4,034
	$	13,311	$	14,401	$	13,671	$	14,925

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 13. Risk Management.

Note 13. 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 gains or losses on the assets, liabilities or anticipated transactions exposed to such market risks. Each of PSEG, PSE&G, Power and Energy Holdings uses derivative instruments as risk management tools consistent with its respective business plan 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, firm transmission rights (FTRs), coal, oil, weather derivatives and emission allowances in the spot, forward and futures markets, primarily in 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 positions to optimize the value of its portfolio and reduce earnings volatility 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 seeking 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 derivative energy trading contracts to market in accordance with SFAS 133, as amended, 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.

88

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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, transmission availability 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.

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. These derivative transactions are designated and effective as cash flow hedges under SFAS 133, as amended. As of December 31, 2004, the fair value of these hedges was $(248) million, $(145) million after-tax. As of December 31, 2003, the fair value of these hedges was $(37) million, $(22) million after-tax. During the next 12 months, $81 million of unrealized losses (after-tax) on these commodity derivatives in Accumulated Other Comprehensive Loss is expected to be reclassified to earnings. Ineffectiveness associated with these hedges, as defined in SFAS 133, was immaterial. The expiration date of the longest dated cash flow hedge is in 2008.

Other Derivatives

Power also enters into certain other contracts that are derivatives, but do not qualify for hedge accounting under SFAS 133. Most of these contracts are used for fuel purchases for generation requirements and for electricity purchases for contractual sales obligations. Therefore, the changes in fair market value of these derivative contracts are recorded in Energy Costs or Operating Revenues, as appropriate, on the Consolidated Statements of Operations. The net fair value of these instruments as of December 31, 2004 and 2003 was $14 million and $7 million, respectively.

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

PSEG and Power

In March 2004, Power issued $250 million of 3.75% Senior Notes due April 2009. PSEG used an interest rate swap to convert Power’s fixed-rate debt into variable-rate debt. The interest rate swap is designated and effective as a fair value hedge. The fair value changes of the interest rate swap are fully offset by the fair value changes in the underlying debt. As of December 31, 2004, the fair value of the hedge was $(3) million and there was no ineffectiveness related to the hedge.

Energy Holdings

In April 2003, Energy Holdings issued $350 million of 7.75% Senior Notes due in 2007. Energy Holdings used interest rate swaps to convert $200 million 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

89

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

by the fair value changes in the underlying debt. As of December 31, 2004 and 2003, the fair value of these hedges was $(3) million and $(1) million, respectively, and there was no ineffectiveness related to these hedges.

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, 2004, the fair value of these cash flow hedges was $(145) million, including $(11) million, $(34) million and $(100) million at PSEG, PSE&G and Energy Holdings, respectively. 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 $(34) million and $(51) million at PSE&G as of December 31, 2004 and 2003, respectively, is not included in Accumulated Other Comprehensive Loss and is deferred as a Regulatory Asset and expected to be recovered from PSE&G’s customers. During the next 12 months, $28 million of unrealized losses (net of taxes) on interest rate derivatives in Accumulated Other Comprehensive Loss is expected to be reclassified to earnings, including $7 million and $21 million at PSEG and Energy Holdings, respectively. As of December 31, 2004, hedge ineffectiveness associated with these hedges was not material.

Other Derivatives

Energy Holdings

Foreign subsidiaries and affiliates of Energy Holdings have entered into interest rate forward contracts, which effectively converted variable-rate debt to fixed-rate debt. Since these contracts have not been designated as cash flow or fair value hedges, 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, 2004 and 2003 was not material.

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 its risks is that some of its foreign subsidiaries and affiliates have functional currencies other than the consolidated reporting currency, the U.S. Dollar. Additionally, Global and certain of its 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. Changes in valuation of these currencies can impact the value of Global’s investments, as well as its ability to service locally funded debt obligations. With respect to the foreign currency risk associated with the Brazilian Real, there has already been significant devaluation since the initial acquisition of that investment in 1997, which has resulted in reduced U.S. Dollar earnings and cash flows relative to initial projections. Global has 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, 2004, net cumulative foreign currency devaluations had reduced the total amount of Energy Holdings’ Member’s Equity by $116 million. This decrease was primarily due to the devaluation of the Brazilian Real in 1999. During 2004, as the U.S. Dollar weakened against many currencies, Global’s equity increased by $75 million. As of December 31, 2003, net cumulative foreign currency devaluations had reduced the total amount of Energy Holdings’ Member’s Equity by $193 million, including $228 million caused by the devaluation of the Brazilian Real.

In November 2004, Energy Holdings entered into foreign currency call options in order to hedge the majority of its 2005 expected earnings denominated in Brazilian Reais, Chilean Pesos and Peruvian Nuevo Soles. These

90

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

options are not considered hedges for accounting purposes under SFAS 133 and, as a result, changes in their fair value are recorded directly to earnings.

Equity Securities

Energy Holdings

For the year ended December 31, 2004, Resources recognized a $13 million (pre-tax) loss related to non-publicly traded equity securities and an $11 million (pre-tax) gain on publicly traded equity securities, which are held within its investments in certain venture capital and leveraged buyout funds. For the year ended December 31, 2003, Resources had an $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 and a $5 million (pre-tax) gain on the publicly traded equity securities. In September 2004, Resources received cash distributions totaling approximately $26 million from the sale of some of its investments in KKR’s leveraged buyout fund. As a result of this sale and sales earlier in the year, Resources’ investment in leveraged buyout funds has been reduced to approximately $27 million as of December 31, 2004, all of which is comprised of public securities with available market prices. 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.

Note 14. 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 Nuclear 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 the Terrorism Risk Insurance Act (TRIA), 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 reinstatement at ANI discretion. 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 similarly to 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 $10.8 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 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,

91

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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		10,461.0	(B)			316.7
Nuclear Liability Total	$	10,761.0	(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				6.2
NEIL Blanket Excess (Salem/Hope Creek/Peach Bottom)		1,000.0	(D)			6.6
Property Damage Total (Per Site)	$	2,100.0			$	32.5
Accidental Outage:
NEIL I (Peach Bottom)	$	245.0	(E)		$	9.7
NEIL I (Salem)		281.4	(E)			10.8
NEIL I (Hope Creek)		490.0	(E)			8.9
Replacement Power Total	$	1,016.4			$	29.4

______________

(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 that is subject to reinstatement at ANI discretion and has an assessment potential under former canceled policies.

(B) Retrospective premium program under the Price-Anderson Act 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 (Exelon Generation) 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)

92

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(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.

Guaranteed Obligations

Power

Power has unconditionally guaranteed payment by its subsidiary, ER&T, in certain commodity-related transactions in the ordinary course of business. These payment guarantees were provided to counterparties in order to obtain credit under physical and financial agreements in gas, pipeline capacity, transportation, oil, electricity and related commodities and services. These Power payment 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 lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction. The face value of the guarantees outstanding as of December 31, 2004 and 2003 was $1.6 billion and $1.4 billion, respectively. In order for Power to incur 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 were terminated, Power would 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 and the forward value on open positions, less any margins posted. The current exposure from such liabilities was $507 million and $228 million as of December 31, 2004 and 2003, respectively. Of the $507 million exposure, $193 million was recorded on Power’s Consolidated Balance Sheet as of December 31, 2004. Of the $228 million exposure, $167 million is recorded on Power’s Consolidated Balance Sheet as of December 31, 2003. The increase in exposure as of December 31, 2004, as compared to December 31, 2003, is partially due to the inclusion of an additional year of BGS exposure that commenced in February 2004. BGS exposure is not marked to market and therefore this exposure is not included on the Consolidated Balance Sheets.

Power is subject to collateral calls related to commodity contracts. As of December 31, 2004, Power had recorded margin (cash) paid of approximately $23 million. An increase in energy prices causes a commensurate increase in collateral requirements for Power. As of December 31, 2004, if Power had lost its investment grade credit rating, there was a potential for approximately $701 million of additional collateral calls for those counterparties with whom Power was “out-of-the-money” under such contracts and where those counterparties were entitled to and had called for collateral. Extreme market events, like the daily price movements in natural gas and power experienced recently, can significantly impact these requirements. As of December 31, 2004, Power had recorded margin received of approximately $68 million.

As of December 31, 2004, letters of credit issued by Power were outstanding in the amount of approximately $145 million in support of various contractual obligations, environmental liabilities and to satisfy trading collateral obligations.

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 $138 million and $180 million as of December 31, 2004 and 2003, respectively. As of December 31, 2004 and 2003, the guarantees of payment include $26 million and $49 million, respectively, for a standby equity commitment for Skawina in Poland expiring in August 2007 and a $25 million contingent guarantee related to debt service obligations of Chilquinta in Chile expiring in 2011. Additional guarantees consist of a $35 million and $37 million leasing agreement guarantee for Prisma in Italy as of December 31, 2004 and 2003, respectively, $13 million and $24 million of performance and payment guarantees related to Energy Technologies as of December 31, 2004 and 2003, respectively, that are supported by letters of credit that expire in May 2005, and

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various other guarantees comprising the remaining $39 million and $45 million as of December 31, 2004 and 2003, respectively, expiring through 2010.

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 for which exposure is adequately supported by the outstanding letters of credit described above. As of December 31, 2004, there were $30 million of such bonds outstanding, which are related to uncompleted construction projects. These performance bonds are not included in the $138 million of guaranteed obligations discussed above.

In addition to the amounts discussed above, certain subsidiaries of Energy Holdings also have contingent obligations related to their respective projects, which are non-recourse to Energy Holdings and Global.

Environmental Matters

PSEG, PSE&G and Power

Hazardous Substances

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 substantially increase the costs of environmental investigations and necessary remediation, particularly at sites situated on surface water bodies. PSE&G, Power and 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. However, neither PSE&G nor Power anticipate that compliance with these regulations will have a material adverse effect on its respective financial position, results of operations or net cash flow.

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 the 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 (Essex Site, one former generating station and four former 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 the site in connection with the sale. The Essex Site was transferred to Power in August 2000. Power assumed any environmental liabilities of PSE&G associated with the electric generating stations that PSE&G transferred to it, including the Essex Site.

In 2003, the EPA notified 41 potentially responsible parties (PRPs), including PSE&G and Power, 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 Site and a former MGP located in Harrison, New Jersey (Harrison Site), which also includes facilities for PSE&G’s ongoing gas operations. The EPA has estimated that its study would require five to eight years to complete and would cost approximately $20 million, of which it would seek to recover $10 million from the PRPs, including PSE&G and Power. Power is evaluating recoverability of any disbursed amounts from its insurance carriers.

Also, in 2003, PSEG, PSE&G and 56 other PRPs received a Directive and Notice to Insurers from the NJDEP that directed 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 Compensation and Control 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. The NJDEP announced 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 the EPA and NJDEP that they are willing to work with the agencies in an effort to resolve their respective claims and, along with approximately 40 other PRPs, have executed an

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agreement with the EPA that provides for sharing the costs of the study between the government organizations and the PRPs. PSEG, PSE&G and Power cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to the Passaic River or natural resource damages. However, such costs could be material.

PSE&G

MGP Remediation Program

PSE&G is currently working with the NJDEP under a program to assess, investigate and remediate environmental conditions at PSE&G’s former MGP sites (Remediation Program). To date, 38 sites have been identified as sites requiring some level of remedial action. The Remediation Program is periodically reviewed, and the estimated costs are revised by PSE&G based on regulatory requirements, experience with the program and available remediation technologies. Since the inception of the program in 1988 through December 31, 2004, PSE&G had expenditures of approximately $294 million.

During the fourth quarter of 2004, PSE&G refined the detailed site estimates, and determined that total Remediation Program costs could range between $650 million and $685 million. No amount within the range was considered to be most likely. Therefore, $356 million was accrued at December 31, 2004, which represents the difference between the low end of the total program cost estimate of $650 million and the total incurred costs through December 31, 2004 of $294 million. Of this amount, approximately $47 million was recorded in Other Current Liabilities and $309 million was reflected in Other Noncurrent Liabilities. The costs associated with the MGP Remediation Program have historically been recovered through the SBC charges to PSE&G ratepayers. As such, a $356 million Regulatory Asset was also recorded.

Costs for the MGP Remediation Program were approximately $34 million in 2004. PSE&G anticipates spending $47 million in 2005, $35 million in 2006, and an average of $26 million per year through 2016.

New Jersey Clean Energy Program

The BPU has approved a new funding requirement for each New Jersey utility applicable to Renewable Energy and Energy Efficiency programs for the years 2005 to 2008. The sum of PSE&G’s electric and gas funding requirement for 2005 is $82 million and grows to $137 million in 2008 for a four-year total of $406 million. A liability for PSE&G’s funding requirement has been recorded at discounted present value with an offsetting regulatory asset.

Power

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

The PSD/NSR regulations, promulgated under the Clean Air Act (CAA), 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 companies allegedly not in compliance with the PSD/NSR regulations to install the best available control technology at the affected plants and to pay monetary penalties of up to approximately $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-burning units were implemented in accordance with applicable PSD/NSR regulations. Power completed its response to the requests for information and, in January 2002, reached an agreement with New Jersey and the Federal government to resolve allegations of noncompliance with PSD/NSR regulations. Under that agreement, over the course of 10 years, Power has agreed to install advanced air pollution controls that are designed to reduce emissions of NO_x, SO₂, particulate matter and mercury. The estimated cost of the program as of December 31, 2004 includes approximately $110 million for installation of selective catalytic reduction systems (SCRs) at Mercer, of which approximately $92 million has been spent, as well as approximately $300 million to $350 million at the Hudson unit and $150 million to $200 million for other pollution control equipment at Mercer to be installed by December 31, 2012. Power also paid a $1.4 million civil penalty and has agreed to spend up to $6 million on supplemental environmental projects. The

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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 operations to commence.

Power has notified the EPA and the NJDEP that it is evaluating the continued operation of the Hudson coal unit in light of changes in the energy and capacity markets, increases in the cost of pollution control equipment and other necessary modifications to the unit. These and other factors impacting the power industry identified to the agencies continue to cast doubts on the appropriateness of making the necessary investments and Power’s ability to complete the work at this time. A decision has not yet been made as to the Hudson unit’s continued operation beyond the December 31, 2006 deadline for installation of pollution control equipment. The related costs associated with the pollution control modifications for the Hudson unit have not been included in Power’s capital expenditure projections.

ISRA

Potential environmental liabilities related to subsurface contamination at certain generating stations have been identified. In the second quarter of 1999, in anticipation of the transfer of PSE&G’s generation-related assets to Power, a study was conducted pursuant to ISRA, which applies to the sale of certain assets. PSEG had a $51 million liability as of December 31, 2004 related to these obligations, which is recorded on the Consolidated Balance Sheets.

New Generation and Development

Power

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 is constructing the Bethlehem Energy Center, which will replace the Albany Station. Total costs for this project are expected to be approximately $551 million with expenditures to date of approximately $496 million (including IDC of $52 million). Construction began in 2002 with the expected completion date in mid-2005, at which time the existing station will be retired.

Power is constructing a natural gas-fired generation plant in Linden, New Jersey. Power is replacing the tubes in both steam turbine condensers due to corrosion that was detected. Power anticipates that construction will be completed in the second quarter of 2006. Including the replacement of the tubes, the total costs are currently estimated at approximately $1 billion with expenditures to date of approximately $880 million (including IDC of $135 million).

Power also has contracts with outside parties to purchase upgraded turbines for Salem Units 1 and 2 and to purchase upgraded turbines and complete a power uprate for Hope Creek to modestly increase its generating capacity. Salem Unit 2 completed Phase I of its turbine replacement during its Fall 2003 refueling outage and gained 24 MW, primarily due to the replacement. Phase II of the replacement is currently scheduled for 2008 and is anticipated to increase capacity by 26 MW. Salem Unit 1 completed its turbine replacement during its Spring 2004 refueling outage and gained 63 MW, primarily due to the replacement. Phase I of Hope Creek’s turbine replacement was completed in January 2005 and is anticipated to increase capacity by 10 MW. Phase II is expected to be completed in 2006 and along with the power uprate is expected to add 125 MW. This schedule for completion of Hope Creek’s power uprate in 2006, which depends on timely approval from the NRC, is currently being reevaluated. Power’s expenditures to date approximate $183 million (including IDC of $13 million) with an aggregate estimated share of total costs for these projects of $250 million (including IDC of $22 million). Timing, costs and results of these projects is dependant on timely completion of work, timely approval from the NRC and various other factors.

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Power has entered into a long-term contractual services agreement with a vendor to provide the outage and service needs for certain of Power’s generating units at market rates. The contract covers approximately 25 years and could result in annual payments ranging from approximately $10 million to $50 million for services, parts and materials rendered.

Energy Holdings

Electroandes

There is a 35 MW expansion project on an existing hydro station under development at Electroandes. The project is expected to be placed into service in 2007 at a total cost of $27 million. The project is being financed with cash and non-recourse debt at Electroandes.

BGS and Basic Gas Supply Service (BGSS)

PSE&G and Power

PSE&G is required to obtain all of its basic generation energy supply needs through the New Jersey BGS auctions for its customers that are not served by a third-party supplier. PSE&G has entered into contracts with Power, as well as with third-party suppliers, to purchase BGS for PSE&G’s anticipated load requirements. In addition, PSE&G has a full requirements natural gas contract for gas supply with Power under which Power will provide PSE&G with its BGSS requirements into 2007.

The BPU permits recovery of the cost of hedging up to 115 billion cubic feet of PSE&G’s residential gas supply annually through the BGSS tariff. Power has hedged approximately 75% to 80% of the allowed residential volume for the current winter season (2004/05) at an average price of $5.78 per decatherm (dth). For the upcoming 2005 summer season, approximately 50% to 55% of the allowed residential volume has been hedged at an average price of $5.84 per dth. Approximately 35% to 40% of the allowed residential volume has been hedged for next winter season (2005/06) at an average price of $6.76 per dth. As of December 31, 2004 and 2003, the fair value of the contracts was approximately $25 million and $47 million, respectively. PSE&G has recorded an intercompany receivable from Power related to the fair market value of the contract with an offsetting Regulatory Liability. Power has recorded a derivative asset with an offsetting intercompany payable to PSE&G.

Power

Power’s objective is to enter into load serving supply contracts and trading positions for at least 75% of its anticipated output over an 18-month to 24-month horizon. As part of this objective, Power has entered into contracts to directly supply PSE&G and other New Jersey Electric Distribution Companies (EDC) with a portion of their BGS requirements, through the New Jersey BGS auction process. In addition to the BGS related contracts, Power has entered into firm supply contracts with EDCs in Pennsylvania, Connecticut and Maryland, as well as other firm sales and trading positions and commitments.

Minimum Fuel Purchase Requirements

Power

Power purchases coal and oil for certain of its fossil generation stations through various long-term commitments. The total minimum purchase requirements included in these commitments amount to approximately $851 million through 2009.

Power has various multi-year requirements-based purchase commitments that total approximately $87 million per year to meet Salem’s and Hope Creek’s nuclear fuel needs, of which Power’s share is approximately $63 million per year through 2010. Power has been advised by Exelon Generation, the co-owner and operator of Peach Bottom, that it has similar purchase contracts to satisfy the fuel requirements for Peach Bottom through 2010, of which Power’s share is approximately $23 million per year.

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In addition to its fuel requirements, Power has entered into various multi-year contracts for firm transportation and storage capacity for natural gas, primarily to meet its gas supply obligations to PSE&G. As of December 31, 2004, the total minimum requirements under these contracts were approximately $627 million through 2016.

These purchase obligations are in keeping with Power’s objective to enter into load serving supply contracts and trading positions for at least 75% of its anticipated output over an 18-month to 24-month horizon and to enter into contracts for its fuel supply in comparable volumes.

Energy Holdings

TIE’s Guadalupe and Odessa plants committed to purchase fuel under gas supply agreements. As of December 31, 2004, Guadalupe and Odessa had fuel purchase commitments totaling $188 million. These supply contracts are expected to cover 43% of anticipated output during 2005.

Operating Services Contract (OSC)

Power

Nuclear has entered into an OSC with Exelon Generation, which commenced on January 17, 2005, relating to the operation of the Salem and Hope Creek nuclear generating stations. The OSC provides that Exelon Generation will provide a chief nuclear officer and other key personnel to oversee daily plant operations at the Hope Creek and Salem nuclear generating stations and to implement the Exelon operating model, which defines practices that Exelon has used to manage its own nuclear performance program. Nuclear will continue as the license holder with exclusive legal authority to operate and maintain the plants, will retain responsibility for management oversight and will have full authority with respect to the marketing of its share of the output from the facilities. Exelon Generation will be entitled to receive reimbursement of its costs in discharging its obligations, an annual operating services fee and incentive fees of up to $12 million annually based on attainment of goals relating to safety, capacity factors of the plants and operation and maintenance expenses. The OSC has a term of two years, subject to earlier termination in certain events upon prior notice, including any termination of the Merger Agreement. In the event of termination, Exelon Generation will continue to provide services under the OSC for a transition period of at least 180 days and up to two years at the election of Nuclear. This period may be further extended by Nuclear for up to an additional 12 months if Nuclear determines that additional time is necessary to complete required activities during the transition period.

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 such 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). Adequate spent fuel storage capacity is estimated to be available through 2011 for Salem 1, 2015 for Salem 2 and 2007 for Hope Creek. Power has commenced construction of an on-site storage facility that will satisfy the spent fuel storage needs of both Salem and Hope Creek through the end of their current respective license lives. Exelon Generation has advised Power that it has a licensed and operational on-site storage facility at Peach Bottom that will satisfy Peach Bottom’s spent fuel storage requirements until at least 2014.

Exelon Generation had previously advised Power that it had signed an agreement with the DOE, applicable to Peach Bottom, under which Exelon Generation would be reimbursed for costs incurred resulting from the DOE’s delay in accepting spent nuclear fuel for permanent storage. Under this agreement, Power’s portion of Peach

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Bottom’s Nuclear Waste Fund fees were reduced by approximately $18 million through August 31, 2002, at which point credits were fully utilized and covered the cost of Exelon Generation’s onsite storage facility. In September 2002, the U.S. Court of Appeals for the Eleventh Circuit issued an opinion upholding a petition seeking to set aside the receipt of these credits by Exelon Generation. On August 14, 2003, Exelon Generation 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). In August 2004, Exelon Generation advised Nuclear that it reached a settlement with the U.S. Department of Justice, under which Exelon Generation will be reimbursed for costs associated with the storage of spent nuclear fuel at the Peach Bottom facility, a portion of which will be paid to Nuclear as a co-owner of Peach Bottom. Future costs incurred resulting from DOE delays in accepting spent fuel will be reimbursed annually until the DOE fulfills its obligation to accept spent nuclear fuel. In addition, Exelon Generation and Nuclear are required to reimburse the DOE for the previously received credits from the Nuclear Waste Fund, plus lost earnings. Under this settlement, Power received approximately $27 million for its share of previously incurred storage costs for Peach Bottom, $22 million of which was used for the required reimbursement to the Nuclear Waste Fund. As a result of this settlement, Power reversed approximately $12 million of previously capitalized plant-related costs and recognized an increase of $7 million to Operating Expenses in 2004.

In September 2001, Power filed a complaint in the U.S. Court of Federal Claims (Court) seeking damages caused by the DOE not taking possession of spent nuclear fuel in 1998. On October 14, 2004, an order to show cause was issued regarding whether the Court has jurisdiction over the matter. Power responded to this order in November 2004. On January 31, 2005, the Judge dismissed the breach-of-contract claims of Power and three other utilities. Power moved for reconsideration at the Court of Federal Claims and jointly petitioned for permission to appeal the January 31, 2005 order to the U.S. Court of Appeals for the Federal Circuit. No assurances can be given as to any damage recovery or the ultimate availability of a disposal facility.

Spent Fuel Pool

Power

The spent fuel pool at each Salem unit has an installed leakage collection system. This normal leakage path was found to be obstructed, causing concern about the extent of leakage contact with the fuel handling building’s concrete structure. Power 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 leakage. The investigation should take approximately one year. If any significant degradation is identified, the repair costs could be material. The NRC issued Information Notice 2004-05 in March 2004 concerning this emerging industry issue and Power 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. Power conducted a comprehensive investigation in accordance with NJDEP site remediation regulations to determine the source and extent of the tritium in the groundwater. Power is conducting remedial pilot studies and received approval of a remedial action workplan from the NJDEP in November 2004 for the proposed remedy. The costs necessary to address this groundwater contamination issue have not been determined, however, such costs are not expected to be material.

Other

PSEG, PSE&G, Power and Energy Holdings

Merger Agreement

In connection with the merger agreement with Exelon Generation, there are certain commitments and contingencies relating to termination fees and operating service contracts. See Note 24. Merger Agreement for further information.

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PSEG and PSE&G

Investment Tax Credits (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 New Jersey’s electric industry restructuring. Based on this fact, PSEG and PSE&G reversed the deferred tax and ITC liability relating to PSE&G’s generation assets that were transferred to Power and recorded a $235 million reduction of the extraordinary charge in 1999 due to the restructuring of the utility industry 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 a private letter ruling request with the IRS in 2002, which is still pending.

In 2003, the IRS proposed regulations for comment 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 adverse impact on PSEG’s and PSE&G’s financial condition, results of operations and net cash flows.

PSEG and Energy Holdings

Leveraged Lease Investments

In 1996 through 2002, PSEG, through its indirect wholly-owned subsidiary, Resources, entered into a number of leveraged leasing transactions in the ordinary course of PSEG’s business. The IRS is likely to argue that certain of those transactions are of a type that it has announced its intention to challenge, and PSEG understands that similar transactions entered into by other companies have been the subject of review and challenge by the IRS. As of December 31, 2004, Resources’ total gross investment in such transactions was approximately $1.3 billion. The IRS is presently reviewing the tax returns of PSEG and its subsidiaries for tax years 1997 through 2000, years when Resources entered into these transactions. The IRS is aware of these lease transactions and has requested information and documents associated with them. To date, the IRS has not proposed to disallow any deductions claimed relative to these transactions, but may propose such disallowances in the future. If the tax benefits associated with the lease transactions were successfully challenged by the IRS, PSEG would be assessed interest and possibly penalties in addition to any underpayments of tax. During the time period of 1997 through 2000, these transactions reduced current tax liabilities of PSEG by approximately $240 million and during the subsequent time period of 2001 though 2004, these and similar transactions reduced the current tax liabilities of PSEG by approximately $301 million. Interest that would be assessed on these potential deficiencies, if associated deductions were disallowed, would be approximately $100 million through December 31, 2004. It is presently unclear the extent to which the IRS will seek to disallow deductions associated with lease transactions, if at all, and, if it were to do so, the extent to which any such challenge would be successful. If deductions associated with these transactions entered into by PSEG were successfully challenged by the IRS, it could have a material adverse impact on PSEG’s and Energy Holdings financial position, results of operations and net cash flows and could impact future returns on these transactions. PSEG believes that its tax position related to these transactions is proper based on applicable statutes, regulations and case law, and believes that it should prevail with respect to an IRS challenge, if presented, although no assurances can be given.

The FASB is currently considering a modification to GAAP for leveraged leases. Under present GAAP, a tax settlement with the IRS that results merely in a change in the timing of tax liabilities would not require an accounting repricing of the lease investment. As such, income from the lease would continue to accrue at the original economic yield computed for the lease and there would be no write-down of the lease investment.

A modification currently being considered by the FASB could require a lease to be repriced in the event a change in the timing of tax liabilities has a significant impact on the economic yield of the lease and to be retested to determine if it qualifies for leveraged lease accounting. If this or a similar modification were to be adopted by the FASB, a successful challenge by the IRS to the tax treatment of the leases referred to above, or a settlement with the IRS, could trigger a lease repricing. Further, such a successful challenge or settlement may cause the lease to fail to qualify for leveraged lease accounting. It is presently unclear what modifications, if any, will be adopted by the

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FASB, the timing of any such modification and the effect of any such modification on the operating results or financial position of PSEG or Energy Holdings.

PSEG and PSE&G

Placement of Gas Meters

In 2003, a proposed class action lawsuit was filed against PSE&G and PSEG in the Superior Court of New Jersey 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 requested the court to order PSE&G to establish a fund for the purpose of remediating the allegedly improper meter installations. In June 2004, the parties to the lawsuit entered into a settlement in which PSE&G committed to enhance the protection of certain identified outdoor gas meter sets over a three-year period. PSE&G anticipates that the cost of such work will not be material. As a result of this settlement, the claims were dismissed with prejudice.

Energy Holdings

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 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 requested a withdrawal of its filing, which was granted during the first quarter of 2004, effectively putting an end to the issue.

RGE

The governing tax authority in Brazil has claimed past due taxes from RGE plus penalties and interest for the periods 1998 to 2004 primarily related to claims that the goodwill tax amortization period used by RGE for several years resulted in higher than allowed tax deductions. Global’s share of the maximum claim amount related to these tax issues is approximately $30 million. RGE believes it has valid legal defenses to these claims, although no assurances can be given.

LDS

The Superintendencia Nacional de Administracion Tributaria (SUNAT), the governing tax authority in Peru, has claimed past due taxes for the period between 1999-2001, plus penalties and interest, resulting from an interpretation of the law that allowed LDS to restate its assets to fair market value for tax purposes and take advantage of the resulting higher tax deductions from depreciation. SUNAT also claimed past due taxes, penalties and interest for the 1996-1998 periods related to this issue.

SUNAT claimed that the revaluation appraisal, performed in 1994, was not performed correctly and was 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 and the only constraint was not to exceed market value. Global’s share of the net unrecorded potential liability related to the claim by SUNAT is estimated at $8 million. LDS has not accepted the SUNAT valuation, but has challenged SUNAT’s study that included no value for large components of LDS’s system and under valued other components in LDS’s view. The Fiscal Court ruled on December 7, 2004 and notified LDS on January 4, 2005 that a decision could not be based on the SUNAT studies and ordered another valuation study to be performed by Consejo Nacional de Tasaciones (CONATA), a Government Agency in Peru. LDS believes that it will prevail, however, no assurances can be given as to the ultimate outcome of this matter.

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Dhofar Power Company S.A.O.C. (Dhofar Power)

Since commencing operations in Oman in May 2003, Dhofar Power has experienced a number of service interruptions, including four service interruptions in the first half of 2004, which resulted from a combination of force majeure events and breaches of general warranties of the contractors that installed equipment at Dhofar Power. The Concession Agreement includes a provision for penalties to be paid in some circumstances to the Government of Oman for certain types of service interruptions. Dhofar Power and the Government of Oman are in dispute regarding both the applicability and extent of any such penalties arising from the service interruptions in question here. Dhofar Power and the Government of Oman are pursuing alternative dispute resolution and it is expected that the matter will be resolved in 2005. Dhofar Power believes that cash retentions, letters of credit and a guarantee bond provided by the contractors should be sufficient to cover the potential penalty claims.

Dhofar Power and the Government of Oman are in a disagreement on the calculation of certain monthly allowances to be paid to the Dhofar Power to compensate for enhancements and extensions of the transmission and distribution system in Salalah. Dhofar Power maintains that, according to the Concession Agreement, these allowances should be calculated based on actual contracted value of the services executed and the Government of Oman maintains that they should be calculated based on the lower estimated executed value. Dhofar Power is accruing this revenue at the values it calculated according to contract terms. Dhofar Power and the Government of Oman are pursuing alternative dispute resolution and it is expected that the matter will be resolved within the next 12 months. In the event the Government of Oman prevails, the annual loss of revenue to Dhofar Power would be approximately $0.6 million (at current exchange rate) for 15 years from December 28, 2003.

Minimum Lease Payments

PSEG, PSE&G, Services and Energy Holdings

PSE&G, Services and Energy Holdings lease administrative office space under various operating leases. For the years ended December 31, 2004, 2003 and 2002, PSEG’s lease expenses were approximately $10 million per year, primarily related to Energy Holdings. Total future minimum lease payments as of December 31, 2004 are:

	2005			2006			2007			2008			2009			After 2009			Total
	(Millions)
PSE&G		$	3		$	3		$	2		$	1		$	—		$	—		$	9
Services			1			1			1			1			1			2			7
Energy  Holdings			3			2			2			2			2			4			15
Total PSEG		$	7		$	6		$	5		$	4		$	3		$	6		$	31

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, 2004 are:

	Services				Power
	(Millions)
2005		$	7			$	1
2006			7				1
2007			7				2
2008			7				2
2009			7				2
Thereafter			44				9
Total Minimum Lease Payments		$	79			$	17
Less: Imputed Interest			(41	)			(5	)
Present Value of Net Minimum Lease Payments		$	38			$	12

102

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 15. Nuclear Decommissioning

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 3. Asset Retirement Obligations.

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. In the most recent study of the total cost of decommissioning, Power’s share related to 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 Funds under SFAS 115. Power classifies investments in the NDT Funds as available-for-sale under SFAS 115. The following tables show the fair values, gross unrealized gains and losses and amortized cost bases for the securities held in the NDT Funds.

	As of December 31, 2004
	Cost		Gross Unrealized Gains			Gross Unrealized Losses				Estimated Fair Value
	(Millions)
Equity Securities	$	488		$	200		$	(8	)		$	680
Debt Securities
Government Obligations		166			4			(1	)			169
Other Debt Securities		172			8			(2	)			178
Total Debt Securities		338			12			(3	)			347
Other Securities		59			1			(1	)			59
Total Available-for-Sale Securities	$	885		$	213		$	(12	)		$	1,086

	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

103

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Years Ended December 31,
	2004		2003		2002
	(Millions)
Proceeds from Sales	$	2,637	$	1,229	$	491
Gross Realized Gains	$	126	$	115	$	45
Gross Realized Losses	$	43	$	64	$	62

Net realized gains of $83 million were recognized in Other Income and Other Deductions on Power’s Consolidated Statement of Operations for the year ended December 31, 2004. Net unrealized gains of $101 million were recognized in OCI on Power’s Consolidated Balance Sheet as of December 31, 2004. Of the $12 million of the gross 2004 unrealized losses, $8 million has been in an unrealized loss position for less than twelve months. The available-for-sale debt securities held as of December 31, 2004, had the following maturities: $45 million less than one year, $70 million one to five years, $126 million five to 10 years, $31 million 10 to 15 years, $12 million 15 to 20 years, and $63 million over 20 years. The cost of these securities was determined on the basis of specific identification.

The fair value of securities in an unrealized loss position as of December 31, 2004 was approximately $172 million. The unrealized losses were primarily caused by interest rate movements and fluctuations in the market. Based on Power’s evaluations and its ability and intent to hold such investments for a reasonable period of time sufficient for an projected recovery of fair value, Power does not consider these investments to be other-than-temporarily impaired as of December 31, 2004.

Note 16. Other Income and Deductions

Other Income

	PSE&G				Power		Energy Holdings			Other(A)				Consolidated Total
	(Millions)
For the Year Ended December 31, 2004:
Interest Income		$	10		$	9		$	—		$	—			$	19
NDT Fund Realized Gains			—			126			—			—				126
NDT Interest and Dividend Income			—			28			—			—				28
Other			2			3			4			(6	)			3
Total Other Income		$	12		$	166		$	4		$	(6	)		$	176
For the Year Ended December 31, 2003:
Interest Income		$	(7	)	$	8		$	—		$	3			$	4
Gain on Disposition of Property			12			—			—			—				12
NDT Fund Realized Gains			—			115			—			—				115
NDT Interest and Dividend Income			—			26			—			—				26
Foreign Currency Gains			—			—			16			—				16
Other			1			—			4			—				5
Total Other Income		$	6		$	149		$	20		$	3			$	178
For the Year Ended December 31, 2002:
Interest Income		$	4		$	1		$	—		$	—			$	5
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			(4	)			(2	)
Total Other Income		$	15		$	1		$	26		$	(3	)		$	39

104

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Other Deductions

	PSE&G			Power		Energy Holdings			Other(A)			Consolidated Total
	(Millions)
For the Year Ended December 31, 2004:
Donations		$	1	$	—		$	—		$	—		$	1
NDT Fund Realized Losses and Expenses			—		49			—			—			49
Loss on Disposition of Property			—		1			—			—			1
Loss on Early Retirement of Debt			—		—			3			—			3
Foreign Currency Losses			—		—			27			—			27
Minority Interest			—		—			—			1			1
Change in Derivative Fair Value			—		—			3			—			3
Other			—		5			—			1			6
Total Other Deductions		$	1	$	55		$	33		$	2		$	91
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 Deductions		$	1	$	78		$	5		$	17		$	101
For the Year Ended December 31, 2002:
Donations		$	2	$	1		$	—		$	—		$	3
Foreign Currency Losses			—		—			77			—			77
Total Other Deductions		$	2	$	1		$	77		$	—		$	80

______________

(A) Other primarily consists of activity at PSEG (parent company), Services and intercompany eliminations.

 

105

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 17. 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)
2004
Net Income (Loss)	$	342		$	308		$	125		$	(49	)		$	726
Gain from Discontinued Operations, (Including Gain on Disposal)		—			(33	)		5			—				(28	)
Minority Interest in Earnings of Subsidiaries		—			—			(1	)		—				(1	)
Income from Continuing Operations, less Preferred Dividends		342			341			121			(49	)			755
Preferred Dividends (net)		(4	)		—			(16	)		16				(4	)
Income (Loss) from Continuing Operations excluding Minority Interest and Preferred Dividends	$	346		$	341		$	137		$	(65	)		$	759
Income Taxes:
Federal—Current		255			27			(92	)		(35	)			155
Deferred		(67	)		136			164			3				236
ITC		(3	)		—			(1	)		—				(4	)
Total Federal		185			163			71			(32	)			387
State—Current		72			19			4			—				95
Deferred		(11	)		27			(40	)		(2	)			(26	)
Total State		61			46			(36	)		(2	)			69
Foreign—Deferred		—			—			13			—				13
Total Foreign		—			—			13			—				13
Total		246			209			48			(34	)			469
Pre-tax Income	$	592		$	550		$	185		$	(99	)		$	1,228
Tax computed at the statutory rate	$	207		$	193		$	65		$	(35	)		$	430
Increase (decrease) attributable to flow through of certain tax adjustments:
Plant Related Items		5			—			—			—				5
Amortization of investment tax credits		(3	)		—			(1	)		—				(4	)
Tax Reserves		—			(18	)		17			—				(1	)
Other		(3	)		4			(1	)		2				2
Lease Rate Differential		—			—			(8	)		—				(8	)
State Income Tax (net of Federal Income Tax)		40			30			(24	)		(1	)			45
Subtotal		39			16			(17	)		1				39
Total income tax provisions	$	246		$	209		$	48		$	(34	)		$	469
Effective income tax rate		41.6	%		38.0	%		25.9	%		34.3	%			38.2	%

106

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	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		(18	)		—			—			—				(18	)
Loss from Discontinued Operations, (Including Loss on Disposal, net of tax benefit—$8)		—			(9	)		(44	)		—				(53	)
Cumulative Effect of a Change in Accounting
Principle, (net of tax expense—$255)		—			370			—			—				370
Minority Interest in Earnings of Subsidiaries		—			—			(13	)		—				(13	)
Income from Continuing Operations, less Preferred Dividends		243			483			179			(31	)			874
Preferred Dividends (net)		(4	)		—			(23	)		23				(4	)
Income (Loss) from Continuing Operations excluding Minority Interest and Preferred Dividends	$	247		$	483		$	202		$	(54	)		$	878
Income Taxes:
Federal—Current		1			140			(299	)		(43	)			(201	)
Deferred		91			120			331			4				546
ITC		(2	)		—			(1	)		—				(3	)
Total Federal		90			260			31			(39	)			342
State—Current		(2	)		42			(57	)		(10	)			(27	)
Deferred		41			30			70			(1	)			140
Total State		39			72			13			(11	)			113
Foreign—Deferred		—			—			15			—				15
Total Foreign		—			—			15			—				15
Total		129			332			59			(50	)			470
Pre-tax Income	$	376		$	815		$	261		$	(104	)		$	1,348
Tax computed at the statutory rate	$	131		$	285		$	91		$	(36	)		$	471
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			48			8			(7	)			75
Subtotal		(2	)		47			(32	)		(14	)			(1	)
Total income tax provisions	$	129		$	332		$	59		$	(50	)		$	470
Effective income tax rate		34.3	%		40.7	%		22.6	%		48.0	%			34.8	%

107

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 benefit—$28)		—			—			(49	)		—				(49	)
Cumulative Effect of a Change in Accounting Principle, (net of tax benefit—$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		99			182			(102	)		(25	)			154
Deferred		(22	)		71			(24	)		2				27
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	%

108

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2004, PSE&G had a regulatory asset of $366 million representing the tax costs 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 investments using the equity method of accounting. As allowed under APB 23, “Accounting for Income Taxes—Special Areas” and SFAS 109, Management has maintained a permanent reinvestment strategy as it relates to Global’s international investments. If Management were to change that strategy, a deferred tax expense and deferred tax liability would need to be recorded to reflect the expected taxes that would need to be paid on Global’s offshore earnings. As of December 31, 2004, undistributed foreign earnings were approximately $256 million. The determination of the amount of unrecognized U.S. Federal deferred income tax liability for undistributed earnings is not practicable.

The Jobs Act, as discussed further in Note 2. Recent Accounting Standards, provides a one-year window to repatriate earnings from foreign investments and claim a special 85% dividends received tax deduction on such distributions. The range of undistributed earnings that PSEG could consider for possible repatriation under the Jobs Act is between $0 and $256 million, which would result in additional income tax expense between $0 and $15 million. On January 13, 2005 the IRS published Notice 2005-10, which discusses some of the rules that pertain to this deduction. Whether PSEG will ultimately take advantage of this provision, all or in part, depends on a number of factors including but not limited to evaluating the impact of Notice 2005-10 and any future authoritative guidance. Management has made no change in its current intention to indefinitely reinvest accumulated earnings of its foreign subsidiaries. PSEG and Energy Holdings are currently evaluating the impacts of the entire Act, which could have a material impact on their financial condition, results of operations and cash flows.

As of December 31, 2004, there is a capital loss carryforward of $78 million which will expire by 2007 unless utilized by PSEG. Since PSEG expects to fully realize this amount, no valuation allowance is necessary.

109

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following is an analysis of deferred income taxes:

	PSE&G					Power						Energy Holdings						Other						Consolidated
	2004		2003			2004			2003			2004			2003			2004			2003			2004		2003
	(Millions)
Deferred Income Taxes
Assets:
Current (net)	$	19	$	17		$	—		$	—		$	—		$	—		$	—		$	—		$	19	$	17
Noncurrent:
Unrecovered Investment Tax Credits		18		19			—			—			—			—			—			—			18		19
SFAS 133		—		—			100			15			33			47			8			7			141		69
Other Comprehensive Income		2		2			—			—			—			(1	)		2			2			4		3
New Jersey Corporate Business Tax		182		189			75			102			(42	)		(60	)		—			(1	)		215		230
OPEB		129		110			—			—			—			—			(2	)		—			127		110
Cost of Removal		—		—			51			51			—			—			—			—			51		51
Conservation Costs		30		—			—			—			—			—			—			—			30		—
Investment Related Adjustment		—		12			—			—			32			118			—			—			32		130
Development Fees		—		—			—			—			17			18			—			—			17		18
Foreign Currency Translation		—		—			—			—			31			35			—			—			31		35
Contractual Liabilities and Environmental Costs		—		—			35			35			—			—			—			—			35		35
Market Transition Charge		11		11			—			—			—			—			—			—			11		11
Other		—		(1	)		—			18			23			—			4			—			27		17
Total Noncurrent		372		342			261			221			94			157			12			8			739		728
Total Assets		391		359			261			221			94			157			12			8			758		745
Liabilities:
Noncurrent:
Plant Related Items		1,382		1,295			(82	)		(155	)		—			—			2			—			1,302		1,140
Nuclear Decommissioning		—		—			74			18			—			—			—			—			74		18
Securitization		1,323		1,414			—			—			—			—			—			—			1,323		1,414
Leasing Activities		—		—			—			—			1,564			1,509			—			—			1,564		1,509
Partnership Activities		—		—			—			—			48			96			—			—			48		96
Conservation Costs		—		68			—			—			—			—			—			—			—		68
Energy Clause Recoveries		33		—			—			—			—			—			—			—			33		—
Pension Costs		77		75			19			(3	)		—			—			23			17			119		89
SFAS 143		—		—			325			337			—			—			—			—			325		337
Taxes Recoverable Through Future Rates (net)		155		156			—			—			—			—			—			—			155		156
Income from Foreign Operations		—		—			—			—			63			31			—			—			63		31
Other		5		18			16			2			—			1			—			5			21		26
Total Noncurrent		2,975		3,026			352			199			1,675			1,637			25			22			5,027		4,884
Total Liabilities		2,975		3,026			352			199			1,675			1,637			25			22			5,027		4,884
Summary—Accumulated Deferred Income Taxes:
Net Current Assets		19		17			—			—			—			—			—			—			19		17
Net Noncurrent Liability		2,603		2,684			91			(22	)		1,581			1,480			13			14			4,288		4,156
Total	$	2,584	$	2,667		$	91		$	(22	)	$	1,581		$	1,480		$	13		$	14		$	4,269	$	4,139
ITC		50		53			6			7			6			7			—			—			62		67
Current Portion of FAS 109 Transferred		19		17			—			—			—			—			—			—			19		17
Total Deferred Income Taxes and ITC	$	2,653	$	2,737		$	97		$	(15	)	$	1,587		$	1,487		$	13		$	14		$	4,350	$	4,223

110

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 18. Pension, Other Postretirement Benefits (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	2004	2003
Equity Securities	64%	63%
Fixed Income Securities	28%	29%
Real Estate Assets	5%	5%
Other Investments	3%	3%
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 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 8.75% as of December 31, 2004. For 2005, the expected long-term rate of return on plan assets will remain at 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 plans, which was an annualized return of 10.3%.

Plan Contributions

PSEG anticipates contributing approximately $83 million into its qualified pension plans for calendar year 2005.

Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Medicare Act)

For information relating to the accounting impacts of the Medicare Act, see Note 2. Recent Accounting Standards.

Accumulated Benefit Obligations

The accumulated benefit obligations of all PSEG’s defined benefit pension plans as of December 31, 2004 and 2003 were $3.0 billion and $2.7 billion, respectively.

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, 2004 and a reconciliation of the funded status at the end of both years.

111

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Pension and Other Postretirement Benefit Plans

	Pension Benefits						Other Benefits
	2004			2003			2004			2003
	(Millions)
Change in Benefit Obligation:
Benefit Obligation at Beginning of Year	$	3,235		$	2,968		$	916		$	777
Service Cost		82			74			22			21
Interest Cost		197			195			55			51
Actuarial Loss		216			158			47			117
Benefits Paid		(178	)		(160	)		(52	)		(50	)
Benefit Obligation at End of Year		3,552			3,235			988			916
Change in Plan Assets:
Fair Value of Assets at Beginning of Year		2,696			2,131			77			51
Actual Return on Plan Assets		306			514			10			13
Employer Contributions		96			211			66			63
Benefits Paid		(178	)		(160	)		(52	)		(50	)
Fair Value of Assets at End of Year		2,920			2,696			101			77
Reconciliation of Funded Status:
Funded Status		(632	)		(539	)		(887	)		(839	)
Unrecognized Net
Transition Obligation		—			—			194			221
Prior Service Cost		71			94			—			—
Loss		894			784			131			87
Net Amount Recognized	$	333		$	339		$	(562	)	$	(531	)
Amounts Recognized in Statement of Financial Position:
Prepaid Benefit Cost	$	383		$	379		$	—		$	—
Accrued Cost		(82	)		(67	)		(562	)		(531	)
Intangible Asset		11			14			N/A			N/A
Accumulated Other Comprehensive Income (pre-tax)		21			13			N/A			N/A
Net Amount Recognized	$	333		$	339		$	(562	)	$	(531	)
Separate Disclosure for Pension Plans With an Accumulated Benefit Obligation in Excess of Plan Assets:
Projected Benefit Obligation at End of Year	$	91		$	86
Accumulated Benefit Obligation at End of Year	$	81		$	67
Fair Value of Assets at End of Year	$	—		$	—

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. The nonqualified pension plans are partially funded with Rabbi Trusts. In accordance with SFAS 87, the plan assets in the table above do not include the assets held in the Rabbi Trusts. The fair value of these assets are included on the Consolidated Balance Sheets. For additional information, see Rabbi Trusts, below.

112

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Pension Benefits									Other Benefits
	2004			2003			2002			2004			2003			2002
	(Millions)
Components of Net Periodic Benefit Cost:
Service Cost	$	82		$	74		$	69		$	22		$	21		$	19
Interest Cost		197			195			188			55			51			47
Expected Return on Plan Assets		(231	)		(193	)		(206	)		(7	)		(5	)		(4	)
Amortization of Net Transition Obligation		—			5			8			27			27			27
Prior Service Cost		16			17			17			—			—			—
Loss/(Gain)		38			49			13			—			(3	)		(4	)
Net Periodic Benefit Cost	$	102		$	147		$	89		$	97		$	91		$	85
Components of Total Benefit Expense:
Net Periodic Benefit Cost	$	102		$	147		$	89		$	97		$	91		$	85
Effect of Regulatory Asset		—			—			—			19			19			19
Total Benefit Expense Including Effect of Regulatory Asset	$	102		$	147		$	89		$	116		$	110		$	104
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31:
Discount Rate		6.25	%		6.75	%		7.25	%		6.25	%		6.75	%		7.25	%
Expected Return on Plan Assets		8.75	%		9.00	%		9.00	%		8.75	%		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		6.00	%		6.25	%		6.75	%		6.00	%		6.25	%		6.75	%
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											10.00	%		9.00	%		9.00	%
Ultimate Rate											5.00	%		6.00	%		6.00	%
Year Ultimate Rate Reached											2010			2009			2008
Post-65 Medical Costs Immediate Rate											11.00	%		7.00	%		7.00	%
Ultimate Rate											5.00	%		6.00	%		6.00	%
Year Ultimate Rate Reached											2011			2005			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		$	4		$	5
Postretirement Benefit Obligation										$	57		$	51		$	46
Effect of a 1% Decrease On
Total of Service Cost and Interest Cost										$	(3	)	$	(5	)	$	(4	)
Postretirement Benefit Obligation										$	(50	)	$	(59	)	$	(39	)

113

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)
2005	$	174		$	65
2006		179			65
2007		184			68
2008		190			71
2009		197			74
2010 - 2014		1,121			391
Total	$	2,045		$	734

Rabbi Trusts

PSEG maintains certain unfunded, nonqualified benefit plans for which certain assets have been set aside in grantor trusts commonly known as “Rabbi Trusts” to provide supplemental retirement and deferred compensation benefits to certain of its and its subsidiaries’ key employees and directors.

Effective January 1, 2003, PSEG began accounting for the assets in the Rabbi Trusts under SFAS 115. PSEG classifies investments in the Rabbi Trusts as available-for-sale under SFAS 115. The following tables show the fair values, gross unrealized gains and losses and amortized cost bases for the securities held in the Rabbi Trusts.

	As of December 31, 2004
	Cost		Gross Unrealized Gains			Gross Unrealized Losses			Estimated Fair Value
	(Millions)
Equity Securities	$	11		$	1		$	—		$	12
Debt Securities
Government Obligations		57			—			—			57
Other Debt Securities		26			—			—			26
Total Debt Securities		83			—			—			83
Other Securities		11			—			—			11
Total Available-for-Sale Securities	$	105		$	1		$	—		$	106

	As of December 31, 2003
	Cost		Gross Unrealized Gains			Gross Unrealized Losses			Estimated Fair Value
	(Millions)
Equity Securities	$	9		$	2		$	—		$	11
Debt Securities
Government Obligations		72			1			—			73
Other Debt Securities		—			—			—			—
Total Debt Securities		72			1			—			73
Other Securities		9			—			—			9
Total Available-for-Sale Securities	$	90		$	3		$	—		$	93

114

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Years Ended December 31,
	2004		2003		2002
	(Millions)
Proceeds from Sales	$	95	$	15	$	74
Gross Realized Gains	$	3		—		—
Gross Realized Losses	$	1	$	—	$	—

Net realized gains of $2 million were recognized in Other Income and Other Deductions on PSEG’s Consolidated Statement of Operations for the year ended December 31, 2004. Net unrealized gains of $1 million were recognized in OCI on PSEG’s Consolidated Balance Sheet as of December 31, 2004. The available-for-sale debt securities held as of December 31, 2004, had the following maturities: $12 million less than one year, $25 million one to five years, $18 million five to 10 years, $7 million 10 to 15 years, $4 million 15 to 20 years, and $26 million over 20 years. The cost of these securities was determined on the basis of specific identification.

The estimated fair value of the Rabbi Trusts related to PSEG, PSE&G, Power and Energy Holdings are detailed as follows:

	As of December 31,
	2004		2003
	(Millions)
PSE&G	$	49	$	45
Power		20		15
Energy Holdings		9		9
Services		28		24
Total	$	106	$	93

401(k) 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 paid for Employer matching contributions to the plans for PSEG, PSE&G, Power and Energy Holdings are detailed as follows:

	Thrift Plan and Savings Plan
	Years Ended December 31,
	2004		2003		2002
	(Millions)
PSE&G	$	15	$	13	$	13
Power		8		9		8
Energy Holdings		1		1		1
Services		3		2		3
Total Employer matching contributions	$	27	$	25	$	25

115

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PSEG, PSE&G, Power and Energy Holdings

Eligible employees of PSE&G, Power, Energy Holdings and Services 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. Pension costs and OPEB costs for PSEG, PSE&G, Power and Energy Holdings are detailed as follows:

	Pension Benefits						Other Benefits
	Years Ended December 31,						Years Ended December 31,
	2004		2003		2002		2004		2003		2002
	(Millions)
PSE&G	$	52	$	79	$	46	$	104	$	100	$	95
Power		31		46		26		9		8		6
Energy Holdings		2		4		2		—		—		—
Services		17		18		15		3		2		3
Total Benefit Expense	$	102	$	147	$	89	$	116	$	110	$	104

Note 19. Stock Options and Employee Stock Purchase Plan

PSEG

Stock Options

As approved at the Annual Meeting of Stockholders in 2004, PSEG’s 2004 Long-Term Incentive Plan (2004 LTIP) replaced prior Long-Term Incentive Plans (the 1989 LTIP and 2001 LTIP). The 2004 LTIP is a broad-based equity compensation program that provides for grants of various long-term incentive compensation awards, such as qualified and non-qualified stock options, stock appreciation rights, performance shares and restricted stock.

Under the 2004 LTIP, non-qualified options to acquire shares of PSEG 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). There were approximately 12.9 million shares of Common Stock available for future grants under the prior plans, and those shares were made available under the 2004 LTIP. Approval of the 2004 LTIP did not increase the number of shares available for use in long-term incentive compensation. Grants of stock options with respect to approximately 7.1 million shares of Common Stock remain outstanding under the prior plans.

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 10 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.

As of December 31, 2004, there were 12.4 million shares available for future awards under the 2004 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.

116

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Changes in common shares under option for the three fiscal years in the period ended December 31, 2004 are summarized as follows:

	2004				2003				2002
	Options		Weighted Average Exercise Price		Options		Weighted Average Exercise Price		Options		Weighted Average Exercise Price
Beginning of year	8,734,931		$	39.37	9,192,631		$	39.32	7,652,463		$	41.22
Granted	863,700			43.87	706,300			37.35	1,890,000			31.62
Exercised	(1,539,966	)		38.49	(541,767	)		32.76	(157,332	)		36.28
Canceled	(367,763	)		41.26	(622,233	)		42.01	(192,500	)		41.94
End of year	7,690,902		$	39.97	8,734,931		$	39.37	9,192,631		$	39.32
Exercisable at end of year	5,612,528		$	40.05	5,822,196		$	40.44	4,542,165		$	40.24
Weighted average fair value of options granted during the year			$	6.58			$	5.73			$	4.37

The following table provides information about options outstanding as of December 31, 2004:

	Options Outstanding					Options Exercisable
Range of Exercise Prices	Outstanding at December 31, 2004	Weighted Average Remaining Contractual Life		Weighted Average Exercise Price		Exercisable at December 31, 2004	Weighted Average Exercise Price
$25.03 - $30.02	115,000		3.0	$	29.56	115,000	$	29.56
$30.03 - $35.03	2,141,733		7.4		32.18	1,421,825		32.14
$35.04 - $40.03	388,500		4.0		39.31	388,500		39.31
$40.04 - $45.04	2,932,169		7.4		41.74	2,048,203		41.46
$45.05 - $50.05	2,113,500		6.5		46.09	1,639,000		46.06
$25.03 - $50.05	7,690,902		6.9	$	39.97	5,612,528	$	40.05

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 2004, 2003 and 2002, respectively: expected volatility of 26.74%, 29.68% and 30.24%, risk free interest rates of 3.09%, 2.86% and 2.82%, expected lives of 4.0 years, 4.4 years and 4.0 years. There was a weighted average dividend yield of 5.00% in 2004, 5.82% in 2003 and 6.84% in 2002.

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, 2004 was approximately $1 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 were fully vested on July 1, 2004.

117

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

During the second quarter of 2004, 94,400 shares of restricted PSEG Common Stock were granted under the 2004 LTIP to certain key executives. These shares are subject to restrictions on transfer and subject to risk of forfeiture until vested by continued employment. The shares vest on a staggered schedule beginning on December 31, 2004 and become fully vested on December 31, 2006. The unearned compensation related to these restricted stock grants as of December 31, 2004 was approximately $3 million and is included in Common Stockholders’ Equity on the Consolidated Balance Sheets.

In addition, 94,400 performance units were granted to certain key executives, which provide for payment in shares of PSEG Common Stock within 45 days of January 1, 2007 based on achievement of certain financial goals. The performance units are credited with dividend equivalents in an amount equal to dividends paid on PSEG Common Stock up until January 1, 2007. As of December 31, 2004, approximately 92,203 performance units were outstanding.

Outside Directors

During 2004, 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 50%, 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 1,000 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 PSEG 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 2004, 2003 and 2002, employees purchased 85,766, 102,532 and 104,627 shares at an average price of $42.51, $40.00 and $36.41 per share, respectively. As of December 31, 2004, 1,965,809 shares were available for future issuance under this plan.

Note 20. 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 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 energy, capacity and ancillary services into the markets for these products. Power also enters into trading contracts for energy, capacity, firm transmission rights, gas,

118

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

emission allowances and other energy related contracts to optimize the value of its portfolio of generating assets and its electric and gas supply obligations.

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. Revenues include revenues of consolidated investments.

Resources

Resources earns revenues from its passive investments in leveraged leases, limited partnerships, leveraged buyout funds and marketable securities. Over 86% 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 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 23. Related-Party Transactions. The net losses primarily relate to financing and certain administrative and general costs at the PSEG parent corporation.

119

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Information related to the segments of PSEG and its subsidiaries is detailed below:

							Energy Holdings												Consolidated Total
	Power			PSE&G			Resources			Global			Other			Other
	(Millions)
For the Year Ended December 31, 2004:
Total Operating Revenues	$	5,169		$	6,972		$	187		$	831		$	9		$	(2,177	)	$	10,991
Depreciation and Amortization		108			523			5			52			—			18			706
Income from Equity Method Investments		—			—			1			125			—			—			126
Operating Income (Loss)		552			943			154			328			(13	)		8			1,972
Interest Income		9			10			—			—			—			—			19
Net Interest Charges		113			362			81			170			4			100			830
Income (Loss) Before Income Taxes		550			592			71			128			(14	)		(104	)		1,223
Income Taxes		209			246			4			49			(5	)		(34	)		469
Income (Loss) From Continuing Operations		341			346			68			78			(10	)		(69	)		754
(Loss) Income from Discontinued Operations, net of tax		(33	)		—			—			5			—			—			(28)
Net Income (Loss)		308			346			68			83			(10	)		(69	)		726
Segment Earnings (Loss)		308			342			65			69			(9	)		(49	)		726
Gross Additions to Long-Lived Assets	$	725		$	428		$	11		$	89		$	—		$	16		$	1,269
As of December 31, 2004:
Total Assets	$	8,607		$	13,586		$	2,999		$	4,144		$	52		$	(144	)	$	29,244
Investments in Equity Method Subsidiaries	$	—		$	—		$	41		$	1,075		$	—		$	—		$	1,116
For the Year Ended December 31, 2003:
Total Operating Revenues	$	5,609		$	6,740		$	238		$	476		$	11		$	(1,939	)	$	11,135
Depreciation and Amortization		97			372			5			38			1			9			522
Income from Equity Method Investments		—			—			1			113			—			—			114
Operating Income (Loss)		851			761			206			263			(5	)		11			2,087
Interest Income		8			(7	)		—			—			—			3			4
Net Interest Charges		107			390			96			119			3			114			829
Income (Loss) Before Income Taxes		815			376			109			157			(5	)		(121	)		1,331
Income Taxes		332			129			37			23			(1	)		(50	)		470
Income (Loss) From Continuing Operations		483			247			72			121			(4	)		(58	)		861
Loss from Discontinued Operations, net of tax		(9	)		—			—			(23	)		(21	)		—			(53	)
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	$	699		$	411		$	1		$	306		$	1		$	21		$	1,439
As of December 31, 2003:
Total Assets	$	7,744		$	13,177		$	3,278		$	3,818		$	368		$	(238	)	$	28,147
Investments in Equity Method Subsidiaries	$	—		$	—		$	94		$	1,233		$	4		$	—		$	1,331
For the Year Ended December 31, 2002:
Total Operating Revenues	$	3,640		$	5,919		$	248		$	352		$	9		$	(1,948	)	$	8,220
Depreciation and Amortization		108			409			5			22			1			20			565
Income from Equity Method Investments		—			—			(1	)		120			—			—			119
Operating Income (Loss)		903			713			213			(300	)		(10	)		4			1,523
Interest Income		1			4			—			—			—			—			5
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 (Loss) From Continuing Operations		468			205			84			(297	)		(7	)		(48	)		405
Loss from Discontinued Operations, 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		$	447		$	32		$	294		$	14		$	14		$	1,847

120

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Geographic information for PSEG is disclosed below. The foreign assets and operations noted below relate solely to Energy Holdings.

	Revenues						Assets(A)
	December 31,						December 31,
	2004		2003		2002		2004		2003
	(Millions)
United States	$	10,341	$	10,588	$	7,740	$	24,960	$	23,542
Foreign Countries		655		551		480		4,284		4,605
Total	$	10,996	$	11,139	$	8,220	$	29,244	$	28,147

Identifiable assets in foreign countries include:

Chile	$	1,279	$	1,151
Netherlands		1,113		1,060
Poland		511		473
Peru		449		475
Tunisia		—		300
China(B)		—		202
Oman		269		282
Brazil		178		164
Other		485		498
Total	$	4,284	$	4,605

______________

(A) Total assets are net of foreign currency translation adjustment of $(129) million (after-tax) as of December 31, 2004 and $(193) million (after-tax) as of December 31, 2003.

(B) Does not include the $136 million promissory note received from the sale of MPC. See Note 4. Discontinued Operations, Dispositions and Acquisitions.

As of December 31, 2004, Global and Resources had approximately $2.9 billion and $1.4 billion, respectively, of international assets. As of December 31, 2004, foreign assets represented 15% and 60% of PSEG’s and Energy Holdings’ consolidated assets, respectively, and the revenues related to those foreign assets contributed 6% and 67% to PSEG’s and Energy Holdings’ consolidated revenues, respectively, for the year ended December 31, 2004.

121

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 21. Property, Plant and Equipment and Jointly-Owned Facilities

Information related to Property, Plant and Equipment as of December 31, 2004 and 2003 is detailed below:

	PSE&G		Power		Energy Holdings		Other		PSEG Consolidated
	(Millions)
2004
Generation:
Fossil Production	$	—	$	3,324	$	1,359	$	—		$	4,683
Nuclear Production		—		399		—		—			399
Nuclear Fuel in Service		—		500		—		—			500
Construction Work in Progress		—		1,787		52		—			1,839
Total Generation		—		6,010		1,411		—			7,421
Transmission and Distribution:
Electric Transmission		1,299		—		—		—			1,299
Electric Distribution		4,840		—		464		—			5,304
Gas Transmission		74		—		—		—			74
Gas Distribution		3,592		—		—		—			3,592
Construction Work in Progress		20		—		38		—			58
Plant Held for Future Use		21		—		—		—			21
Other		68		—		—		—			68
Total Transmission and Distribution		9,914		—		502		—			10,416
Other		245		63		171		304			783
Total	$	10,159	$	6,073	$	2,084	$	304		$	18,620
2003
Generation:
Fossil Production	$	—	$	2,511	$	719	$	—		$	3,230
Nuclear Production		—		332		—		—			332
Nuclear Fuel in Service		—		532		—		—			532
Construction Work in Progress		—		2,020		17		—			2,037
Total Generation		—		5,395		736		—			6,131
Transmission and Distribution:
Electric Transmission		1,273		—		—		—			1,273
Electric Distribution		4,646		—		427		—			5,073
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	$	5,472	$	1,352	$	271		$	16,888

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 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.

122

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Ownership Interest		Plant		Accumulated Depreciation
			(Millions)
December 31, 2004
Power:
Coal Generating
Conemaugh	22.50	%	$	208		$	90
Keystone	22.84	%	$	170		$	69
Nuclear Generating
Peach Bottom	50.00	%	$	248		$	112
Salem	57.41	%	$	482		$	192
Nuclear Support Facilities	Various		$	65		$	19
Pumped Storage Facilities
Yards Creek	50.00	%	$	28		$	18
Merrill Creek Reservoir	13.91	%	$	1		$	—
PSE&G:
Transmission Facilities	Various		$	80		$	36
Linden SNG Plant	90.00	%	$	5		$	5
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

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 Generation. Nuclear is the owner-operator of Salem and Exelon Generation 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.

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.

123

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 22. Selected Quarterly Data (Unaudited)

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,
	2004			2003			2004			2003			2004			2003			2004			2003
	(Millions, where applicable)
PSEG Consolidated:
Operating Revenues	$	3,228		$	3,291		$	2,285		$	2,403		$	2,747		$	2,776		$	2,731		$	2,665
Operating Income		670			693			339			418			614			528			349			448
Income from Continuing Operations		282			324			127			156			251			211			94			170
(Loss)/Gain from Discontinued Operations, including Loss on Disposal, net of tax		(11	)		(13	)		(3	)		(5	)		(7	)		(4	)		(7	)		(31	)
Extraordinary Item, net of tax benefit		—			—			—			(18	)		—			—			—			—
Cumulative Effect of a Change in Accounting Principle		—			370			—			—			—			—			—			—
Net Income		271			681			124			133			244			207			87			139
Earnings Per Share:
(Basic)
Income from Continuing Operations		1.19			1.44			0.54			0.69			1.06			0.93			0.39			0.71
Net Income		1.15			3.02			0.52			0.59			1.03			0.91			0.36			0.56
(Diluted)
Income from Continuing Operations		1.18			1.43			0.54			0.69			1.06			0.93			0.39			0.71
Net Income		1.14			3.01			0.52			0.59			1.03			0.91			0.36			0.56
Weighted Average Common Shares Outstanding:
Basic		236			225			237			226			237			226			238			235
Diluted		239			226			238			227			238			228			239			236

Note 23. 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, BGS and MTC

PSE&G and Power

Effective May 1, 2002, 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 additional information about the BGSS contract, see Note 14. Commitments and Contingent Liabilities.

124

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. For additional information about the BGS contracts, see Note 14. Commitments and Contingent Liabilities. In addition to BGS, Power collected an MTC charge from PSE&G until the end of the four-year transition period on July 31, 2003. The amounts Power charged to PSE&G for BGSS, BGS and MTC are presented below:

	Billings for the Years Ended December 31,
	2004		2003		2002
	(Millions)
BGS	$	359	$	30	$	1,071
BGSS	$	1,784	$	1,785	$	582
MTC	$	—	$	111	$	98

As of December 31, 2004 and 2003, Power had net receivables from PSE&G of approximately $357 million and $266 million, respectively, primarily related to the BGS and BGSS billings.

In addition, as of December 31, 2004 and 2003, PSE&G had a receivable from Power of approximately $25 million and $47 million, respectively, related to gas supply hedges Power entered into for BGSS. For additional information, see Note 14. Commitments and Contingent Liabilities.

Services

PSE&G, Power and Energy Holdings

Services provides and bills administrative services to PSE&G, Power and Energy Holdings. In addition, PSE&G, Power and Energy Holdings have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies. The billings for administrative services and payables are presented below:

	Administrative Services billed for the Years Ended December 31,						Payable to Services as of December 31,
	2004		2003		2002		2004		2003
	(Millions)
PSE&G	$	208	$	201	$	193	$	38	$	74
Power	$	150	$	124	$	149	$	23	$	22
Energy Holdings	$	18	$	16	$	22	$	2	$	2

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 approximate market value for such services.

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.

125

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PSE&G, Power and Energy Holdings had (payables to) receivables from PSEG related to taxes as follows:

	(Payable to) Receivable from PSEG as of December 31,
	2004			2003
	(Millions)
PSE&G	$	(45	)	$	(83	)
Power	$	9		$	(15	)
Energy Holdings	$	19		$	173

Affiliate Loans and Advances

PSEG and Power

As of December 31, 2004, Power had a payable to PSEG of approximately $98 million for short-term funding needs. As of December 31, 2003, Power had a receivable from PSEG of approximately $77 million for short-term funding needs. Interest Income and Interest Expense relating to these short term funding activities was immaterial.

PSEG and Energy Holdings

As of December 31, 2004 and 2003, Energy Holdings had a note receivable due from PSEG of $115 million and $300 million, respectively, reflecting the investment of its excess cash with PSEG. Interest Income related to these borrowings was immaterial.

PSE&G and Services

As of December 31, 2004 and 2003, PSE&G had advanced working capital to Services of approximately $33 million and $26 million, respectively. These amounts are included in Other Noncurrent Assets on PSE&G’s Consolidated Balance Sheets.

Power and Services

As of December 31, 2004 and 2003, Power had advanced working capital to Services of approximately $17 million and $12 million, respectively. These amounts are included in Other Noncurrent Assets on Power’s Consolidated Balance Sheets.

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 $100 million, $200 million and $305 million to PSEG in 2004, 2003 and 2002, respectively.

Power

PSEG contributed capital of approximately $300 million, $150 million and $200 million to Power during 2004, 2003 and 2002, respectively.

Energy Holdings

During 2004, Energy Holdings made cash distributions to PSEG totaling $491 million in the form of preference unit redemptions, preference unit distributions, ordinary unit distributions and return of capital contributed. In February 2005, Energy Holdings returned an additional $100 million of capital to PSEG in the form of an ordinary unit distribution.

126

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Asset 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.

PSE&G and 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.

Power and Services

During the year ended December 31, 2004, Power sold certain maintenance facilities to Services at net book value, resulting in proceeds of approximately $4 million.

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 $7 million, $6 million and $3 million was included in Operating Revenues in the Consolidated Statements of Operations for the years ended December 31, 2004, 2003, and 2002, respectively.

Other

PSEG and PSE&G

As of December 31, 2004 and 2003, PSE&G had receivables from PSEG of approximately $14 million and $6 million, respectively, related to amounts that PSEG had collected on PSE&G’s behalf.

PSEG and Power

As of December 31, 2004 and 2003, Power had receivables from PSEG of approximately $4 million and $1 million, respectively, related to amounts that PSEG had collected on Power’s behalf.

PSE&G and Energy Holdings

As of December 31, 2003, PSE&G had a receivable from Energy Holdings of approximately $2 million.

Global

As of December 31, 2004, Global had loans outstanding with its affiliates of approximately $68 million, including $24 million of accrued interest related to its projects in Italy.

127

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 24. Merger Agreement

On December 20, 2004, PSEG and Exelon Corporation (Exelon), a public utility holding company registered under PUHCA which is headquartered in Chicago, Illinois, entered into an agreement and plan of merger (the Merger Agreement) whereby PSEG will be merged with and into Exelon (the Merger). Under the Merger Agreement, each share of PSEG common stock will be converted into 1.225 shares of Exelon common stock.

The Merger Agreement contains certain termination rights for both PSEG and Exelon, and further provides that, upon termination of the Merger Agreement under specified circumstances, (1) Exelon may be required to pay PSEG a termination fee of $400 million plus PSEG’s transaction expenses up to $40 million and (2) PSEG may be required to pay Exelon a termination fee of $400 million plus Exelon’s transaction expenses up to $40 million.

The Merger Agreement has been unanimously approved by both companies’ boards of directors but is contingent upon, among other things, the approval by shareholders of both companies, antitrust clearance and a number of regulatory approvals or reviews by federal and state energy authorities. The parties have made some of the regulatory filings to obtain necessary regulatory approvals. It is anticipated that this approval process will be completed and the Merger will close within 12 months to 15 months after the announcement of the Merger Agreement in December 2004. Concurrent with the Merger Agreement, PSEG adopted the Key Executive Severance Plan of PSEG (Severance Plan) and adopted the Retention Program for Key Employees of PSEG (Retention Program).

Severance Plan

The Severance Plan provides change in control severance benefits to certain elected officers of PSEG whose employment is terminated without “cause” or who resign their employment for “good reason” within two years after a change in control, which would include the consummation of the Merger. Under the Severance Plan, the majority of the participants, if they are terminated without “cause” or resign his or her employment for “good reason” within two years after a change in control, will receive (1) a pro rata bonus based on the participant’s target annual incentive compensation, (2) two times the sum of the participant’s salary and target incentive bonus, (3) accelerated vesting of equity-based awards, (4) a lump sum payment equal to the actuarial equivalent of the participant’s benefits under all of PSEG’s retirement plans in which the participant participates calculated as though the participant remained employed for two years beyond the date his or her employment terminates less the actuarial equivalent of such benefits on the date his or her employment terminates, (5) two years continued welfare benefits (the first 18 months of which will be provided through PSEG-paid COBRA continuation coverage), (6) one year of PSEG-paid outplacement services and (7) vesting of any compensation previously deferred. Under the Severance Plan, one participant will receive the same benefits as the other participants, except that the applicable multiplier for salary and target incentive bonus, retirement plan accruals and continuation of welfare benefits is three years instead of two.

Retention Program

The Retention Program, effective as of December 20, 2004, provides for payments to be made to certain key employees of PSEG who remain employed from the date of execution of the Merger Agreement through the date that is 90 days after the consummation of the Merger. The amount of a participant’s retention payment may not be less than 40% or more than 150% of the participant’s annual base salary. Retention payments under the Retention Program may not exceed $10 million in the aggregate.

PSEG will pay the first installment, equal to half of a participant’s total retention payment, within 60 days after the first anniversary of the date of execution of the Merger Agreement. PSEG will pay the participant’s remaining retention payment on the business day following the date that is 90 days after the consummation of the Merger. No participant whose employment terminates for any reason other than involuntary termination without “cause” will receive any subsequent installment of the retention payment. A participant whose employment is terminated without “cause” on or prior to the consummation of the Merger will be treated as if he or she remained employed through the date that is 90 days after the consummation of the Merger for all purposes under the Retention Program.

128

SCHEDULE II

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

Schedule II—Valuation and Qualifying Accounts

Years Ended December 31, 2004—December 31, 2002

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)
2004:
Allowance for Doubtful Accounts	$	40	$	47		$	—		$	53	(A)(K)	$	34
Materials and Supplies Valuation Reserve		15		—			—			6	(B)		9
Other Reserves		14		—			—			5	(B)		9
Other Valuation Allowances		24		—			—			10	(F)		14
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		17	(D)(J)		2	(G)		17	(L)		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

______________

(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, $10 million, $1 million and $2 million in 2004, 2003 and 2002, respectively.

(G) Includes fuel reserve related to Connecticut acquisition.

(H) Reclassified to Discontinued Operations.

(I) Increased reserve due to obsolescence, excess and damaged items.

(J) Reserve established for coal ash disposal costs.

(K) Valuation allowances reversed in connection with PETAMC Acccounts Receivable settlement.

(L) Includes amounts related to Enron settlement.

129

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. 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

(Registrant)

By:	/s/ Patricia A. Rado
	Patricia A. Rado Vice President and Controller (Principal Accounting Officer)

Date: August 29, 2005

130