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Public Service Enterprise Group 8-K 2005

Documents found in this filing:

  1. 8-K
  2. Ex-23
  3. Ex-23

 

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.

 

2

 



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.

 

3

 



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.

 

4

 



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

 

5

 



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.

 

6

 



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

 

7

 



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.

 

8

 



 

 

 

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.

 

10

 



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.

 

11

 



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.

 

12

 



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.

 

13

 



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.

 

16

 



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.

 

18

 



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.

 

19

 



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.

 

20

 



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.

 

21

 



(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.

 

22

 



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.

 

23

 



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

 

24

 



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.

 

25

 



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

 

26

 



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.

 

27

 



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.

 

28

 



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

 

29

 



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

 

30

 



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.

 

31

 



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

 

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