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

(Cover continued on next page)

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

Indicate by check mark whether each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Indicate by check mark if each of the registrants is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes ¨ No x

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

Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).

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

Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether any of the registrants is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

The aggregate market value of the Common Stock of Public Service Enterprise Group Incorporated held by non-affiliates as of June 30, 2009 was $16,495,708,079 based upon the New York Stock Exchange Composite Transaction closing price.

The number of shares outstanding of Public Service Enterprise Group Incorporated’s sole class of Common Stock as of January 29, 2010 was 505,952,069.

As of January 29, 2010, Public Service Electric and Gas Company had issued and outstanding 132,450,344 shares of Common Stock, without nominal or par value, all of which were privately held, beneficially and of record by Public Service Enterprise Group Incorporated.

PSEG Power LLC and Public Service Electric and Gas Company are wholly owned subsidiaries of Public Service Enterprise Group Incorporated and each meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K. Each is filing its Annual Report on Form 10-K with the reduced disclosure format authorized by General Instruction I.

DOCUMENTS INCORPORATED BY REFERENCE

 

Part of Form 10-K of Public Service Enterprise Group Incorporated		Documents Incorporated by Reference
III		Portions of the definitive Proxy Statement for the 2010 Annual Meeting of Stockholders of Public Service Enterprise Group Incorporated, which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 8, 2010, as specified herein.

 

 

 

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TABLE OF CONTENTS

 

				Page
FORWARD-LOOKING STATEMENTS				ii
FILING FORMAT AND GLOSSARY				1
WHERE TO FIND MORE INFORMATION				1
PART I
Item 1.		Business		1
		Regulatory Issues		17
		Environmental Matters		26
		Segment Information		30
Item 1A.		Risk Factors		30
Item 1B.		Unresolved Staff Comments		38
Item 2.		Properties		39
Item 3.		Legal Proceedings		41
Item 4.		Submission of Matters to a Vote of Security Holders		44
PART II
Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		45
Item 6.		Selected Financial Data		48
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		49
		Overview of 2009 and Future Outlook		49
		Results of Operations		54
		Liquidity and Capital Resources		65
		Capital Requirements		70
		Off-Balance Sheet Arrangements		73
		Critical Accounting Estimates		73
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk		78
Item 8.		Financial Statements and Supplementary Data		80
		Report of Independent Registered Public Accounting Firm		81
		Consolidated Financial Statements		84
		Notes to Consolidated Financial Statements
		Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies		98
		Note 2. Variable Interest Entities		102
		Note 3. Recent Accounting Standards		103
		Note 4. Discontinued Operations, Dispositions and Impairments		105
		Note 5. Property, Plant and Equipment and Jointly-Owned Facilities		108
		Note 6. Regulatory Assets and Liabilities		110
		Note 7. Long-Term Investments		114
		Note 8. Available-for-Sale Securities		116
		Note 9. Goodwill and Other Intangibles		120
		Note 10. Asset Retirement Obligations (AROs)		120
		Note 11. Pension, Other Postretirement Benefits (OPEB) and Savings Plans		121
		Note 12. Commitments and Contingent Liabilities		127
		Note 13. Schedule of Consolidated Debt		141
		Note 14. Schedule of Consolidated Capital Stock and Other Securities		147
		Note 15. Financial Risk Management Activities		147
		Note 16. Fair Value Measurements		153
		Note 17. Stock Based Compensation		158
		Note 18. Other Income and Deductions		163
		Note 19. Income Taxes		164
		Note 20. Earnings Per Share (EPS) and Dividends		172
		Note 21. Financial Information by Business Segment		173
		Note 22. Related-Party Transactions		175
		Note 23. Selected Quarterly Data (Unaudited)		178
		Note 24. Guarantees of Debt		179
Item 9.		Changes In and Disagreements With Accountants on Accounting and Financial Disclosure		182
Item 9A/9A(T).		Controls and Procedures		182
Item 9B.		Other Information		182
PART III
Item 10.		Directors, Executive Officers and Corporate Governance		187
Item 11.		Executive Compensation		190
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		191
Item 13.		Certain Relationships and Related Transactions, and Director Independence		191
Item 14.		Principal Accounting Fees and Services		191
PART IV
Item 15.		Exhibits and Financial Statement Schedules		192
		Schedule II—Valuation and Qualifying Accounts		199
		Glossary of Terms		201
		Signatures		204
		Exhibit Index		207

 

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FORWARD-LOOKING STATEMENTS

Certain of the matters discussed in this report constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management’s beliefs as well as assumptions made by and information currently available to management. When used herein, the words “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “hypothetical,” “potential,” “forecast,” “project,” variations of such words and similar expressions are intended to identify forward-looking statements. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Other factors that could cause actual results to differ materially from those contemplated in any forward-looking statements made by us herein are discussed in Item 1A. Risk Factors, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A), Item 8. Financial Statements and Supplementary Data—Note 12. Commitments and Contingent Liabilities and other factors discussed in filings we make with the United States Securities and Exchange Commission (SEC). These factors include, but are not limited to:

 

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adverse changes in energy industry law, policies and regulation, including market structures and rules and reliability standards,

 

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any inability of our transmission and distribution businesses to obtain adequate and timely rate relief and regulatory approvals from federal and state regulators,

 

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changes in federal and state environmental regulations that could increase our costs or limit operations of our generating units,

 

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changes in nuclear regulation and/or developments in the nuclear power industry generally that could limit operations of our nuclear generating units,

 

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actions or activities at one of our nuclear units located on a multi-unit site that might adversely affect our ability to continue to operate that unit or other units located at the same site,

 

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any inability to balance our energy obligations, available supply and trading risks,

 

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any deterioration in our credit quality,

 

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availability of capital and credit at commercially reasonable terms and conditions and our ability to meet cash needs,

 

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any inability to realize anticipated tax benefits or retain tax credits,

 

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changes in the cost of, or interruption in the supply of, fuel and other commodities necessary to the operation of our generating units,

 

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delays or unforeseen cost escalations in our construction and development activities,

 

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increase in competition in energy markets in which we compete,

 

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adverse performance of our decommissioning and defined benefit plan trust fund investments and changes in discount rates and funding requirements, and

 

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changes in technology and increased customer conservation.

Additional information concerning these factors are set forth under Item 1A. Risk Factors.

All of the forward-looking statements made in this report are qualified by these cautionary statements and we cannot assure you that the results or developments anticipated by management will be realized, or even if realized, will have the expected consequences to, or effects on, us or our business prospects, financial condition or results of operations. Readers are cautioned not to place undue reliance on these forward-looking statements in making any investment decision. Forward-looking statements made in this report only apply as of the date of this report. While we may elect to update forward-looking statements from time to time, we specifically disclaim any obligation to do so, even if internal estimates change, unless otherwise required by applicable securities laws.

The forward-looking statements contained in this report are intended to qualify for the safe harbor provisions of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.

 

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FILING FORMAT AND GLOSSARY

This combined Annual Report on Form 10-K is separately filed by Public Service Enterprise Group Incorporated (PSEG), PSEG Power LLC (Power) and Public Service Electric and Gas Company (PSE&G). Information relating to any individual company is filed by such company on its own behalf. Power and PSE&G are each only responsible for information about itself and its subsidiaries.

Discussions throughout the document refer to PSEG and its direct operating subsidiaries, Power, PSE&G and PSEG Energy Holdings L.L.C. (Energy Holdings). Depending on the context of each section, references to “we,” “us,” and “our” relate to the specific company or companies being discussed. In addition, certain key acronyms and definitions are summarized in a glossary beginning on page 201.

WHERE TO FIND MORE INFORMATION

We file annual, quarterly and special reports, proxy statements and other information with the U.S. Securities and Exchange Commission (SEC). You may read and copy any document that we file at the Public Reference Room of the SEC at 100 F Street, N.E., Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. You may also obtain our filed documents from commercial document retrieval services, the SEC’s internet website at www.sec.gov or our website at www.pseg.com. Information contained on our website should not be deemed incorporated into or as a part of this report. Our Common Stock is listed on the New York Stock Exchange under the ticker symbol PEG. You can obtain information about us at the offices of the New York Stock Exchange, 20 Broad Street, New York, New York 10005.

PART I

 

ITEM 1.

BUSINESS

We were incorporated under the laws of the State of New Jersey in 1985 and our principal executive offices are located at 80 Park Plaza, Newark, New Jersey 07102. We conduct our business through three direct wholly owned subsidiaries, Power, PSE&G and Energy Holdings, each of which also has its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. PSEG Services Corporation (Services), our wholly owned subsidiary, provides us and these operating subsidiaries with certain management, administrative and general services at cost.

 

As of and for the Year Ended December 31, 2009

 

 

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We are an energy company with a diversified business mix. Our operations are located primarily in the Northeastern and Mid Atlantic United States. Our business approach focuses on operational excellence, financial strength and disciplined investment. As a holding company, our profitability depends on our subsidiaries’ operating results. Below are descriptions of our principal operating subsidiaries.

 

Power		PSE&G		Energy Holdings
A Delaware limited liability company formed in 1999 that integrates its generating asset operations with its wholesale energy sales, fuel supply, energy trading and marketing and risk management functions.   Earns revenues from selling under contract or on the spot market a range of diverse products such as electricity, natural gas, capacity, emissions credits and a series of energy-related products used to optimize the operation of the energy grid.		A New Jersey corporation, incorporated in 1924, which is a franchised public utility in New Jersey. It is also the provider of last resort for gas and electric commodity service for end users in its service territory.   Earns revenues from its regulated rate tariffs under which it provides electric transmission and electric and gas distribution to residential, commercial and industrial customers in its service territory. It also offers appliance services and repairs to customers throughout its service territory.   It is implementing several programs to improve efficiencies in customer energy use and increase the level of renewable generation.		A New Jersey limited liability company (successor to a company which was incorporated in 1989) that invests and operates through its two primary subsidiaries.   Earns revenues from managing leveraged lease investments and the operation of its domestic generation projects.   Also pursuing solar and other renewable generation projects.

The majority of our earnings are derived from the operations of Power, which has contributed at least 70% of our Income from Continuing Operations over the past three years. While this part of the business has produced significant earnings over that period, its operations are subject to higher risks resulting from volatility in the energy markets. As a rate-regulated public utility, PSE&G has continued to be a stable earnings contributor for us. Earnings from Energy Holdings have significantly declined over the past few years as we sold virtually all of our investments in international projects. Energy Holdings’ earnings have also been impacted by gains and losses on its asset sales and other charges and impairments taken on its remaining investments.

 

 

Earnings (Losses) in millions		2009			2008				2007
Power		$	1,189		$	1,115			$	1,000
PSE&G			325			364				380
Energy Holdings			72			(468	)			12
Other			6			(28	)			(67	)
PSEG Income from Continuing Operations		$	1,592		$	983			$	1,325

The following is a more detailed description of our business, including a discussion of our:

 

•

Business Operations and Strategy

 

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Competitive Environment

 

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Employee Relations

 

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Regulatory Issues

 

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Environmental Matters

 

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BUSINESS

OPERATIONS AND STRATEGY

 

Power

Through Power, we seek to produce low-cost energy by efficiently operating our nuclear, coal and gas-fired generation facilities, while balancing generation production, fuel requirements and supply obligations through energy portfolio management. We use commodity contracts and financial instruments, combined with our owned generation, to cover our commitments for Basic Generation Service (BGS) in New Jersey and other bilateral supply contract agreements.

Products and Services

As a merchant generator, our profit is derived from selling a range of products and services under contract to power marketers and to others, such as investor-owned and municipal utilities, and to aggregators who resell energy to retail consumers, or in the spot market. These products and services include:

 

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Energy — the electrical output produced by generation plants that is ultimately delivered to customers for use in lighting, heating, air conditioning and operation of other electrical equipment. Energy is our principal product and is priced on a usage basis, typically in cents per kWh or dollars per MWh.

 

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Capacity —a product distinct from energy, is a market commitment that a given generation unit will be available to an Independent System Operator (ISO) for dispatch if it is needed to meet system demand. Capacity is typically priced in dollars per MW for a given sale period.

 

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Ancillary Services —related activities supplied by generation unit owners to the wholesale market, required by the ISO to ensure the safe and reliable operation of the bulk power system. Owners of generation units may bid units into the ancillary services market in return for compensatory payments. Costs to pay generators for ancillary services are recovered through charges imposed on market participants.

 

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Emissions Allowances and Congestion Credits —Emissions allowances (or credits) represent the right to emit a specific amount of certain pollutants. Allowance trading is used to control air pollution by providing economic incentives for achieving reductions in the emissions of pollutants. Congestion credits (or Financial Transmission Rights) are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly congestion price differences across a transmission path.

Power also sells wholesale natural gas, primarily through a full requirements Basic Gas Supply Service (BGSS) contract with PSE&G to meet the gas supply requirements of PSE&G’s customers. The current BGSS contract runs through March 31, 2012.

About 44% of PSE&G’s peak daily gas requirements comes from Power’s firm transportation, which is available every day of the year. Power satisfies the remainder of PSE&G’s requirements from field storage, liquefied natural gas, seasonal purchases, contract peaking supply, propane, refinery and landfill gas. Based upon availability, Power also sells gas to others.

How Power Operates

We own approximately 13,500 MWs of generation capacity located in the Northeast and Mid Atlantic regions of the U.S. in some of the country’s largest and most developed electricity markets.

 

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The map below shows the locations of Power’s Northeast and Mid Atlantic generation facilities.

We also own 2,000 MW of generation capacity in Texas which was transferred from Energy Holdings in October 2009. See Item 8. Financial Statements and Supplementary Data—Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies for additional information.

 

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For additional information on each of our generation facilities, see Item 2. Properties.

 

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Generation Capacity

Our installed capacity utilizes a diverse mix of fuels: 52% gas, 24% nuclear, 15% coal, 8% oil and 1% pumped storage. This fuel diversity helps to mitigate risks associated with fuel price volatility and market demand cycles. Our total generating output in 2009 was approximately 59,800 GWh. The following table indicates the proportionate share of generating output by fuel type.

 

 

Generation by Fuel Type		Actual 2009
Nuclear:
New Jersey facilities		35%
Pennsylvania facilities		16%
Fossil:
Coal:
New Jersey facilities		5%
Pennsylvania facilities		8%
Connecticut facilities		2%
Oil and Natural Gas:
New Jersey facilities		15%
New York facilities		6%
Texas facilities		13%
Total		100%

The generation by our coal units in 2009 was adversely affected by the relatively favorable price of natural gas as compared to coal, making it more economical to run certain of our gas units than our coal units. This caused a decrease in our coal unit production in 2009 compared to 2008. We expect our coal unit generation to increase in 2010 as compared to 2009.

 

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Generation Dispatch

Our generation units are typically characterized as serving one or more of three general energy market segments: base load; load following; and peaking, based on their operating capability and performance. On a capacity basis, our portfolio of generation assets consists of 31% base load, 50% load following and 19% peaking. This diversity helps to reduce the risk associated with market demand cycles and allows us to participate in the market at each segment of the dispatch curve.

 

¡

Base Load Units operate whenever they are available. These units generally derive revenues from energy and capacity sales. Variable operating costs are low due to the combination of highly efficient operations and the use of relatively lower cost fuels. Performance is generally measured by the unit’s “capacity factor,” or the ratio of the actual output to the theoretical maximum output. Our base load nuclear unit capacity factors were as follows:

 

 

Unit		Capacity Factor
Salem Unit 1		99.1%
Salem Unit 2		92.0%
Hope Creek		91.2%
Peach Bottom Unit 2		99.3%
Peach Bottom Unit 3		86.9%

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No assurances can be given that these capacity factors will be achieved in the future.

 

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Load Following Units operate between 20% and 80% of the time. The operating costs are higher per unit of output due to lower efficiency and/or the use of higher cost fuels such as oil, natural gas and, in some cases, coal. They operate less frequently than base load units and derive revenues from energy, capacity and ancillary services.

 

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Peaking Units run the least amount of time and utilize higher-priced fuels. These units operate less than 20% of the time. Costs per unit of output tend to be much higher than for base load units. The majority of revenues are from capacity and ancillary service sales. The characteristics of these units enable them to capture energy revenues during periods of high energy prices.

In the energy markets in which we operate, owners of power plants specify to the ISO prices at which they are prepared to generate and sell energy based on the marginal cost of generating energy from each individual unit. The ISOs will dispatch in merit order, calling on the lowest variable cost units first and dispatching progressively higher-cost units until the point that the entire system demand for power (known as the system “load”) is satisfied. Base load units are dispatched first, with load following units next, followed by peaking units. The following chart depicts the merit order of dispatch in PJM, where most of our generation units are located, based on illustrative historical dispatch cost. It should be noted that recent market price fluctuations have resulted in changes from historical norms, with lower gas prices allowing some gas generation to displace some coal generation:

The bid price of the last unit dispatched by an ISO establishes the energy market-clearing price. After considering the market-clearing price and the effect of transmission congestion and other factors, the ISO calculates the locational marginal pricing (LMP) for every location in the system. The ISO pays all units that are dispatched their respective LMP for each MWh of energy produced, regardless of their specific bid prices. Since bids generally approximate the marginal cost of production, units with lower marginal costs typically generate higher operating profits than units with comparatively higher marginal costs.

During periods when one or more parts of the transmission grid are operating at full capability, thereby resulting in a constraint on the transmission system, it may not be possible to dispatch units in merit order

 

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without violating transmission reliability standards. Under such circumstances, the ISO will dispatch higher- cost generation out of merit order within the congested area and power suppliers will be paid an increased LMP in congested areas, reflecting the bid prices of those higher-cost generation units.

This method of determining supply and pricing creates an environment in the markets such that natural gas prices often have a major impact on the price that generators will receive for their output, especially in periods of relatively strong demand. Therefore, significant changes in the price of natural gas will often translate into significant changes in the wholesale price of electricity. This can be seen in the graphs below which present historical annual spot prices and forward calendar prices as averaged over each year.

Historical data and forward prices would imply that the price of natural gas will continue to have a strong influence on the price of electricity in the primary markets in which Power operates.

The prices reflected in the tables above do not necessarily illustrate our contract prices, but they are representative of market prices at relatively liquid hubs, with nearer-term forward pricing generally resulting from more liquid markets than pricing for later years. In addition, the prices do not reflect locational differences resulting from congestion or other factors, which can be considerable. While these prices provide some perspective on past and future prices, the forward prices are highly volatile and there is no assurance that such prices will remain in effect nor that we will be able to contract output at these forward prices.

 

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Fuel Supply

 

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Nuclear Fuel Supply —To run our nuclear units we have long-term contracts for nuclear fuel. These contracts provide for:

 

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purchase of uranium (concentrates and uranium hexafluoride);

 

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conversion of uranium concentrates to uranium hexafluoride;

 

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enrichment of uranium hexafluoride; and

 

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fabrication of nuclear fuel assemblies.

 

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Coal Supply —Coal is the primary fuel for our Hudson, Mercer, Keystone, Conemaugh and Bridgeport stations. We have contracts with numerous suppliers. Coal is delivered to our units through a combination of rail, truck, barge or ocean shipments.

In order to minimize emissions levels, our Bridgeport 3 and Hudson 2 units use a specific type of coal obtained from Indonesia. If the supply from Indonesia or equivalent coal from other sources were not available for these facilities, their near-term operations would be adversely impacted. In the longer-term, additional material capital expenditures would be required to modify our Bridgeport 3 station to enable it to operate using a broader mix of coal sources. We anticipate completing the installation of pollution control equipment by the end of 2010 at our Hudson unit which will provide more flexibility in the types of coal we can use at that station.

 

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Gas Supply —Natural gas is the primary fuel for the bulk of our load following and peaking fleet. We purchase gas directly from natural gas producers and marketers. These supplies are transported to New Jersey by four interstate pipelines with whom we have contracted. In addition, we have three firm gas transportation contracts to serve both of our Texas plants and have recently contracted for a firm transportation service for our Bethlehem Energy Center (BEC) in New York.

We have 1.2 billion cubic feet-per-day of firm transportation capacity under contract to meet the primary gas supply needs of our generation fleet and our obligations under the BGSS contract. We supplement that supply with a total storage capacity of 78 billion cubic feet.

 

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Oil —Oil is used as the primary fuel for two load following steam units and nine combustion turbine peaking units and can be used as an alternate fuel by several load following and peaking units that have dual-fuel capability. Oil for operations is drawn from on-site storage and is generally purchased on the spot market and delivered by truck, barge or pipeline.

We expect to be able to meet the fuel supply demands of our customers and our own operations. However, the ability to maintain an adequate fuel supply could be affected by several factors not within our control, including changes in prices and demand, curtailments by suppliers, severe weather and other factors. For additional information, see Item 7. MD&A—Overview of 2009 and Future Outlook and Note 12. Commitments and Contingent Liabilities.

Markets and Market Pricing

Power’s assets are located in four centralized, competitive electricity markets operated by ISO organizations all of which are subject to the regulatory oversight of FERC or, in the case of ERCOT, the Texas Public Utility Commission:

 

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PJM Regional Transmission Organization —PJM conducts the largest centrally dispatched energy market in North America. It serves over 51 million people, nearly 17% of the total U.S. population and a peak demand of over 144,000 MW. The PJM Interconnection coordinates the movement of electricity through all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. All of Power’s generating stations operate in PJM, except for the BEC, Guadalupe, Odessa, Bridgeport and New Haven stations .

 

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•

New York —The NY ISO is the market coordinator for New York State and is now responsible for managing the New York Power Pool and for administering its energy marketplace. This service area has a population of about 19 million and a peak demand of over 33,900 MW. Power’s BEC station operates in New York.

 

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New England —ISO NE coordinates the movement of electricity in a region covering Maine, New Hampshire, Vermont, Massachusetts, Connecticut and Rhode Island. This service area has a population of about 14 million and a peak demand of over 28,000 MW. Power’s Bridgeport and New Haven stations operate in Connecticut.

 

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Texas —The Electric Reliability Council of Texas (ERCOT) manages the flow of electric power to Texas customers representing 85 percent of the state’s electric load and 75 percent of the Texas land area. The ERCOT service area has a population of about 22 million and a peak demand of over 63,400 MW. As the ISO for the region, ERCOT schedules power on the electric grid. Power’s Guadalupe and Odessa plants operate in ERCOT.

The price of electricity varies by location in each of these markets. Depending upon our production and our obligations, these price differentials can serve to increase or decrease our profitability.

Commodity prices, such as electricity, gas, coal and emissions, as well as the availability of our diverse fleet of generation units to produce these products, also have a considerable effect on our profitability. These commodity prices have been, and continue to be, subject to significant market volatility.

Since the majority of the power we generate has generally been sourced from lower-cost nuclear and coal units, the rise in electric prices in recent years has yielded higher margins for us. Over a longer-term horizon, the higher the forward prices are, the more attractive an environment exists for us to contract for the sale of our anticipated output. However, higher prices also increase the cost of replacement power, thereby placing us at risk should any of our generating units fail to function effectively or otherwise become unavailable.

In addition to energy sales, we also earn revenue from capacity payments for our assets in the Northeast and Mid-Atlantic U.S. These payments are compensation for committing that a portion of our capacity be available to the ISO for dispatch at its discretion. Capacity payments reflect the value to the ISO of assurance that there is sufficient generating capacity available at all times to meet system reliability and energy requirements. Currently, there is sufficient capacity in the markets in which we operate. However, in certain areas of these markets there are transmission system constraints, raising concerns about reliability and creating a more acute need for capacity. Previously, some generators, including us, announced the retirement or potential retirement of certain older generating facilities due to insufficient revenues to support their continued operation. To enable the continued availability of these facilities, in separate instances, both PJM and ISO-NE agreed to enter into Reliability-Must-Run (RMR) arrangements to compensate us for those units’ contribution to reliability.

In PJM and ISO-NE, where we operate most of our generation, the market design for capacity payments provides for a structured, forward-looking, transparent capacity pricing mechanism. This is through the Reliability Pricing Model (RPM) in PJM and the Forward Capacity Market (FCM) in ISO-NE. These mechanisms provide greater clarity regarding the value of capacity, resulting in an improved pricing signal to prospective investors in new generating facilities so as to encourage expansion of capacity to meet future market demands.

 

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The prices to be received by generating units in PJM for capacity have been set through RPM base residual auctions and depend upon the zone in which the generating unit is located. The majority of our PJM generating units are located in zones where the following prices have been set.

 

 

Delivery Year		MW-day			kW-yr
June 2008 to May 2009		$	148.80		$	54.31
June 2009 to May 2010		$	191.32		$	69.83
June 2010 to May 2011		$	174.29		$	63.62
June 2011 to May 2012		$	110.00		$	40.16
June 2012 to May 2013		$	139.73		$	51.70

The zone in which our Keystone and Conemaugh units are located has experienced fewer constraints on its transmission system, and we have received prices lower than the prices for the rest of our PJM generating assets for periods through May of 2010. This is not the case for the periods from June 2010 to May 2012 when identical prices were set for all zones. However, the most recent auction, for the 2012-2013 delivery year, once again resulted in differing prices for various areas of PJM, with Keystone and Conemaugh receiving lower prices than the majority of our PJM generating units and our generating units in northern New Jersey receiving higher pricing.

The price that must be paid by an entity serving load in the various zones is also set through these auctions. These prices can be higher or lower than the prices noted in the table above due to import and export capability to and from lower-priced areas.

Like PJM and ISO-NE, the NYISO provides capacity payments to its generating units, but unlike these other two markets, the New York market does not provide a forward price signal beyond a six month auction period.

On a prospective basis, many factors will affect the capacity pricing, including but not limited to:

 

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changes in load and demand;

 

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changes in the available amounts of demand response resources;

 

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changes in available generating capacity (including retirements, additions, derates, forced outage rates, etc.);

 

•

increases in transmission capability between zones; and

 

•

changes to the pricing mechanism, including potentially increasing the number of zones to create more pricing sensitivity to changes in supply and demand, as well as other potential changes that PJM may propose over time.

For additional information on our collection of RMR payments in PJM and ISO-NE and the RPM and FCM proposals, see Regulatory Issues—Federal Regulation.

Hedging Strategy

In an attempt to mitigate volatility in our results, we seek to contract in advance for a significant portion of our anticipated electric output, capacity and fuel needs. We seek to sell a portion of our anticipated lower-cost nuclear and coal-fired generation over a multi-year forward horizon, normally over a period of two to three years. We believe this hedging strategy increases stability of earnings.

Among the ways in which we hedge our output are: (1) sales at PJM West and (2) BGS contracts. Sales at PJM West reflect block energy sales at the liquid PJM Western Hub and other transactions that seek to secure price certainty for our generation related products. In addition, the BGS-Fixed Price contract, a full requirements contract that includes energy and capacity, ancillary and other services, is awarded for three-year periods through an auction process managed by the New Jersey Board of Public Utilities (BPU). The volume of BGS contracts and the electric utilities that our generation operations will serve vary from year to year.

 

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Pricing for the BGS contracts for recent and future periods by purchasing utility, including a capacity component, is as follows:

 

 

Load Zone ($/MWh)		2006-2009			2007-2010			2008-2011			2009-2012			2010-2013
PSE&G		$	102.51		$	98.88		$	111.50		$	103.72		$	95.77
Jersey Central Power and Light		$	100.44		$	99.64		$	114.09		$	103.51		$	95.17
Atlantic City Electric		$	103.99		$	99.59		$	116.50		$	105.36		$	98.56
Rockland Electric Company		$	111.14		$	109.99		$	120.49		$	112.70		$	103.32

A portion of our total capacity is hedged through the BGS auctions. On average, tranches won in the BGS auctions require 100 MW to 120 MW of capacity on a daily basis.

We have obtained price certainty for all of our PJM and New England capacity through May 2013 through the RPM and FCM pricing mechanisms.

We enter into these hedges in an effort to provide price certainty for a large portion of our anticipated generation. There is, however, variability in both our actual output as well as in our hedges. Our actual output will vary based upon total market demand, the relative cost position of our units versus all units in the market and the operational flexibility of our units. Our hedge volume can also vary, depending on the type of hedge into which we have entered. The BGS auction, for example, results in a contract that provides for the supplier to serve a percentage of the default load of a New Jersey electric delivery company, that is, the load that remains after some customers have chosen to be served directly by third party suppliers. The amount of power supplied varies based on the level of the delivery company’s default load, which is affected by the number of customers who choose a third party supplier, as well as by other factors such as weather and the economy. Historically, the number of customers that have switched to third party suppliers was relatively constant, but in 2009, as market prices declined from past years’ historic highs, there has been an incentive for more of the smaller commercial and industrial electric customers to switch. In a falling price environment, this has a negative impact on Power’s margins, as the anticipated BGS pricing is replaced by lower market pricing. We are unable to determine the degree to which this switching, or ‘migration’, will continue, but the impact on our results could be material.

To support our contracted sales of energy, we entered into contracts for the future purchase and delivery of nuclear fuel and coal, which include some market-based pricing components. As of February 15, 2010, we had contracted for the following percentages of our nuclear and coal generation output and related fuel supplies for the next three years with modest amounts beyond 2012.

 

 

Nuclear and Coal Generation		2010		2011		2012
Generation Sales		90%-95%		50%-60%		15%-30%
Nuclear Fuel Purchases		100%		100%		100%
Coal Supply and Transportation Costs		95%-100%		30%-40%		5%-10%

We take a more opportunistic approach in hedging our anticipated natural gas-fired generation. The generation from these units is less predictable, as these units are generally dispatched when aggregate market demand has exceeded the supply provided by lower-cost units. The natural gas-fired units have generally provided a lower contribution to our margin than either the nuclear or coal units, although recent market price dynamics of coal and gas moderated this historical relationship for 2009.

In a changing market environment, this hedging strategy may cause our realized prices to differ materially from current market prices. In a rising price environment, this strategy normally results in lower margins than would have been the case if little or no hedging activity had been conducted. Alternatively, in a falling price environment, this hedging strategy will tend to create margins higher than those implied by the then current market.

 

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PSE&G

Our public utility, PSE&G, distributes electric energy and gas to customers within a designated service territory running diagonally across New Jersey where approximately 5.5 million people, or about 70% of the State’s population, reside.

Products and Services

Our utility operations primarily earn margins through the transmission and distribution of electricity and the distribution of gas.

 

•

Transmission —is the movement of electricity at high voltage from generating plants to substations and transformers, where it is then reduced to a lower voltage for distribution to homes, businesses and industrial customers. Our revenues for these services are based upon tariffs approved by the FERC.

 

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Distribution —is the delivery of electricity and gas to the retail customer’s home, business or industrial facility. Our revenues for these services are based upon tariffs approved by the BPU.

We also earn margins through non-tariff competitive services, such as appliance repair services. The commodity supply portion of our utility business’ electric and gas sales are managed by BGS and BGSS suppliers. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for our utility operations.

In addition to our current utility products and services, we have implemented several programs to improve efficiencies in customer energy use and increase the level of renewable generation including:

 

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a program to help finance the installation of 81 MW of solar power systems throughout our electric service area,

 

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a program to develop, own and operate 80 MW of solar power systems over four years, and

 

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a set of energy efficiency programs to encourage conservation and energy efficiency by providing energy and money saving measures directly to businesses and families.

For additional information concerning these programs and the components of our tariffs, see Regulatory Issues.

 

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How PSE&G Operates

We provide network transmission and point-to-point transmission services, which are coordinated with PJM, and provide distribution service to 2.1 million electric customers and 1.7 million gas customers in a service area that covers approximately 2,600 square miles running diagonally across New Jersey. We serve the most heavily populated, commercialized and industrialized territory in New Jersey, including its six largest cities and approximately 300 suburban and rural communities.

Transmission

We use formula rates for our existing and future transmission investments. Formula-type rates provide a method of rate recovery where the transmission owner annually determines its revenue requirements through a fixed formula which considers Operations and Maintenance expenditures, Rate Base and capital investments and applies an approved return on equity (ROE) in developing the weighted average cost of capital. Currently, approved rates provide for a ROE of 11.68% on existing and new transmission investment. FERC has also approved incentive rate treatment for two new transmission lines, which when added to the approved base ROE, will yield a ROE of 12.93% for these projects. We will also earn this ROE on Construction Work In Progress (CWIP) dollars spent on these projects.

 

 

Transmission Statistics
December 31, 2009				Historical Annual Growth 2005-2009
Network Circuit Miles		Billing Peak (MW)
1,442		9,687		0.50%

For more information on current transmission construction activities, see Regulatory Issues, Federal Regulation—Transmission Regulation.

Distribution

Our primary business is the distribution of gas and electricity to end users in our service territory. Our load requirements were split during 2009 among residential, commercial and industrial customers, described below. We believe that we have all the non-exclusive franchise rights (including consents) necessary for our electric and gas distribution operations in the territory we serve.

 

 

		% of 2009 Sales
Customer Type		Electric		Gas
Commercial		58%		36%
Residential		31%		60%
Industrial		11%		4%
Total		100%		100%

While our customer base has remained steady, electric and gas load has declined, as illustrated:

 

 

Electric and Gas Distribution Statistics
		December 31, 2009				Historical Annual Load Growth 2005-2009
		Number of Customers		Electric Sales and Gas Sold and Transported
Electric		2.1 Million		41,961 GWh		-0.6%
Gas		1.7 Million		3,500 Million Therms		-0.4%

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Supply

Although commodity revenues make up more than 60% of our revenues, we make no profit on the supply of energy since the actual costs are passed through to our customers.

All electric and gas customers in New Jersey have the ability to choose their own electric energy and/or gas supplier. However, pursuant to BPU requirements, we serve as the supplier of last resort for electric and gas customers within our service territory who have not chosen another supplier. As a practical matter, this means we are obligated to provide supply to a vast majority of residential customers and a smaller portion of commercial and industrial customers.

We procure the supply to meet our BGS obligations through two concurrent auctions authorized by the BPU for New Jersey’s total BGS requirement. These auctions take place annually in February. Results of these auctions determine which energy suppliers are authorized to supply BGS to New Jersey’s electric distribution companies (EDCs). Once validated by the BPU, electricity prices for BGS service are set.

We procure the supply requirements of our default service gas customers (BGSS) through a full requirements contract with Power. The BPU has approved a mechanism designed to recover all gas commodity costs related to BGSS for residential customers. BGSS filings are made annually by June 1 of each year, with an effective date of October 1. Any difference between rates charged under the BGSS contract and rates charged to our residential customers is deferred and collected or refunded through adjustments in future rates. Commercial and industrial customers that do not have third party suppliers are also supplied under the BGSS arrangement. These customers are charged a market based price largely determined by prices for commodity futures contracts.

Markets and Market Pricing

There continues to be significant volatility in commodity prices. Such volatility can have a considerable impact on us since a rising commodity price environment results in higher delivered electric and gas rates for customers. This could result in decreased demand for both electricity and gas, increased regulatory pressures and greater working capital requirements as the collection of higher commodity costs may be deferred under our regulated rate structure. A declining commodity price on the other hand, would be expected to have the opposite effect. For additional information see Item 7. MD&A.

Energy Holdings

With the transfer of the two Texas generation facilities to Power in October 2009 and the sale of almost all of our investments in international generation and distribution over the past few years, our focus at Energy Holdings is on managing our portfolio of leveraged lease investments and domestic generation investments. Through Energy Holdings, we are also pursuing solar and other renewable generation projects, as discussed below. For additional information on Energy Holdings generation facilities, see Item 2. Properties.

Products and Services

The majority of our $1.6 billion in leveraged lease investments are energy-related. As of December 31, 2009, the single largest lease investment represented 20% of total leveraged leases.

Our leasing portfolio is designed to provide a fixed rate of return. Leveraged lease investments involve three parties: an owner/lessor, a creditor and a lessee. In a typical leveraged lease financing, the lessor purchases an asset to be leased. The purchase price is typically financed 80% with debt provided by the creditor and the balance comes from equity funds provided by the lessor. The creditor provides long-term financing to the transaction secured by the property subject to the lease. Such long-term financing is non-recourse to the lessor and, with respect to our lease investments, is not presented in our Consolidated Balance Sheets.

The lessor acquires economic and tax ownership of the asset and then leases it to the lessee for a period of time no greater than 80% of its remaining useful life. As the owner, the lessor is entitled to depreciate the asset under applicable federal and state tax guidelines. The lessor receives income from lease payments made by the lessee during the term of the lease and from tax benefits associated with interest and depreciation deductions with respect to the leased property. Our ability to realize these tax benefits is dependent on operating gains

 

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generated by our other operating subsidiaries and allocated pursuant to the consolidated tax sharing agreement between us and our operating subsidiaries.

Lease rental payments are unconditional obligations of the lessee and are set at levels at least sufficient to service the non-recourse lease debt. The lessor is also entitled to any residual value associated with the leased asset at the end of the lease term. An evaluation of the after-tax cash flows to the lessor determines the return on the investment. Under GAAP, the lease investment is recorded net of non-recourse debt and income is recognized as a constant return on the net unrecovered investment.

For additional information on leases, including the credit, tax and accounting risks related to certain lessees, see Item 1A. Risk Factors, Item 7. MD&A—Results of Operations—Energy Holdings, Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Credit Risk—Energy Holdings and Note 12. Commitments and Contingent Liabilities.

Our domestic generation projects in California, Hawaii and New Hampshire, totaling 358 MW, are contracted under long-term Power Purchase Agreements (PPAs).

Energy Holdings has developed a 2 MW solar project in western New Jersey, currently in service, and acquired two additional solar projects of 27 MW, currently under construction in Florida and Ohio. Completion of the Florida and Ohio projects is expected by the end of 2010. The total investment for the three projects will be approximately $114 million.

In August 2008, we invested in a joint venture to license compressed air energy storage (CAES) technology. CAES technology stores energy in the form of compressed air which can later be released to generate electricity through specialized turbine equipment. This technology could be used to optimize an intermittent energy source, such as wind, by storing energy at night and releasing this stored energy during the day when customers need power. This technology can also be utilized to augment the capacity of Combined Cycle Gas Turbines, returning the units closer to their nameplate capacity when they are encountering reductions due to ambient conditions.

In October 2008, the New Jersey Office of Clean Energy (OCE) awarded a $4 million grant to a joint venture owned equally by us and an unaffiliated private developer, to advance the development of a 350 MW wind site to be located approximately 16 miles off the shore of southern New Jersey. An offshore wind site has not yet been developed and constructed in the U.S. Numerous issues, including federal and state permitting, environmental impacts, power output sale arrangements, construction approach and expected maintenance costs, will need to be resolved in order to successfully develop such a project.

COMPETITIVE ENVIRONMENT

Power

Various market participants compete with us and one another in buying and selling in wholesale power pools, entering into bilateral contracts and selling to aggregated retail customers. Our competitors include:

 

•

merchant generators,

 

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domestic and multi-national utility generators,

 

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energy marketers,

 

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banks, funds and other financial entities,

 

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fuel supply companies, and

 

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affiliates of other industrial companies.

New additions of lower cost or more efficient generation capacity could make our plants less economical in the future. Although it is not clear if this capacity will be built or, if so, what the economic impact will be, such additions could impact market prices and our competitiveness.

Our business is also under competitive pressure due to demand side management (DSM) and other efficiency efforts aimed at changing the quantity and patterns of usage by consumers which could result in a reduction in

 

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load requirements. A reduction in load requirements can also be caused by economic cycles and factors. It is also possible that advances in technology, such as distributed generation, will reduce the cost of alternative methods of producing electricity to a level that is competitive with that of most central station electric production. To the extent that additions to the transmission system relieve or reduce congestion in eastern PJM where most of our plants are located, our revenues could be adversely affected. Changes in the rules governing transmission planning or cost allocation could also impact our revenues.

We are also at risk if one or more states in which we operate should decide to turn away from competition and allow regulated utilities to own or reacquire and operate generating stations in a regulated and potentially uneconomic manner, or to encourage rate-based construction of new generating units. This has occurred in certain states. The lack of consistent rules in energy markets can negatively impact the competitiveness of our plants. Also, regional inconsistencies in environmental regulations, particularly those related to emissions, have put some of our plants which are located in the Northeast, where rules are more stringent, at an economic disadvantage compared to our competitors in certain Midwest states.

Environmental issues, such as restrictions on carbon dioxide (CO ₂ ) emissions and other pollutants, may also have a competitive impact on us to the extent that it becomes more expensive for some of our plants to remain compliant, thus affecting our ability to be a lower-cost provider compared to competitors without such restrictions. While our generation fleet is relatively low-emitting, additional restrictions could have a negative impact on certain of our units, including our coal units.

In addition, pressures from renewable resources, such as wind and solar, could increase over time, especially if government incentive programs continue to grow. For example, over the past several years, a sizable amount of wind generation capacity has been constructed in ERCOT, particularly in western Texas, which has impacted our Odessa generation facility located in that area. Given the favorable wind conditions in western Texas, these wind generation facilities are able to produce power during a substantial period of the year, resulting in an additional source of generation, especially during off-peak seasons. Numerous competitors have announced plans to build substantial amounts of new wind generation capacity in the western part of Texas, where power demand is relatively low, but there are transmission constraints in the ability to get power to the load centers. The Public Utility Commission of Texas is attempting to address the constraint issue, but it is not clear if these efforts at transmission expansion will be successful or, if so, what the economic impact will be. As a result of such potential transmission expansion, it is possible that additional amounts of wind generation may be built in ERCOT, potentially impacting market prices and our competitiveness.

PSE&G

The transmission and distribution business has minimal risks from competitors. Our transmission and distribution business is minimally impacted when customers choose alternate electric or gas suppliers since we earn our return by providing transmission and distribution service, not by supplying the commodity. The demand for electric energy and gas by customers is affected by customer conservation, economic conditions, weather and other factors not within our control.

EMPLOYEE RELATIONS

As of December 31, 2009, we had approximately 10,352 employees in the following companies, including 6,627 covered under collective bargaining agreements.

 

 

Employees as of December 31, 2009
		Power		PSE&G		Energy Holdings		Services
Non-Union		1,345		1,325		20		1,035
Union		1,561		5,057		—		9
Total Employees		2,906		6,382		20		1,044
Number of Union Groups		3		5		n/a		1

All of our collective bargaining agreements, except one will expire on April 30, 2013 or later. The one exception is an agreement at PSE&G that covers 1,218 employees. This agreement expires on April 30, 2011.

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REGULATORY ISSUES

Federal Regulation

FERC

FERC is an independent federal agency that regulates the transmission of electric energy and gas in interstate commerce and the sale of electric energy and gas at wholesale pursuant to the Federal Power Act (FPA) and the Natural Gas Act. PSE&G, Power’s generation and energy trading subsidiaries and one subsidiary of Energy Holdings are public utilities as defined by the FPA. FERC has extensive oversight over “public utilities” as defined by the FPA. FERC approval is usually required when a “public utility” company seeks to: sell or acquire an asset that is regulated by FERC (such as a transmission line or a generating station); collect costs from customers associated with a new transmission facility; charge a rate for wholesale sales under a contract or tariff; or engage in certain mergers and internal corporate reorganizations.

FERC also regulates generating facilities known as qualifying facilities (QFs). QFs are cogeneration facilities that produce electricity and another form of useful thermal energy, or small power production facilities where the primary energy source is renewable, biomass, waste, or geothermal resources. QFs must meet certain ownership, operating and efficiency criteria established by FERC. We own various QFs through Energy Holdings. QFs are subject to many, but not all, of the same FERC requirements as public utilities.

FERC also regulates ISOs, such as PJM, and their energy and capacity markets.

For us, the major effects of FERC regulation fall into five general categories:

Regulation of Wholesale Sales—Generation/Market Issues

PSE&G and certain subsidiaries of Power and Energy Holdings have received MBR authority from FERC. Retention of MBR authority is critical to the maintenance of our generation business’ revenues.

Under MBR rules, FERC may look at sub-markets to analyze whether a company possesses market power. Applying these rules in October 2008, FERC granted PSE&G, PSEG Energy Resources & Trade LLC and PSEG Power Connecticut LLC continued MBR authority and granted both PSEG Fossil LLC and PSEG Nuclear LLC initial MBR authority. Each of these companies will be required to file for continuation of its MBR authority by the end of 2010.

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RMR treatment has enabled these units to continue to operate. Various parties have challenged the continuation of RMR payments in ISO-NE and, thus, there is risk that such payments may be terminated prior to the end of the current contract terms.

Energy Clearing Prices

Energy clearing prices in the markets in which we operate are generally based on bids submitted by generating units. Under FERC-approved rules, bids are subject to price caps and mitigation rules applicable to certain generation units. FERC rules also govern the overall design of these markets. At present, all units receive a single clearing price based on the bid of the marginal unit (i.e. the last unit that must be dispatched to serve the needs of load). These FERC rules have a direct impact on the energy prices received by our units.

Capacity Markets

PJM, NYISO, and ISO-NE each have capacity markets that have been approved by FERC.

RPM is a locational installed capacity market design for the PJM region, including a forward auction for installed capacity. Under RPM, generators located in constrained areas within PJM are paid more for their capacity as an incentive to ensure adequate supply where generation capacity is most needed. PJM’s RPM and related FERC orders establishing prices paid to us and other generators as a result of RPM’s transitional auctions are being challenged in court by various state public utility commissions, including the BPU. These legal actions remain pending. Moreover, the mechanics of RPM in PJM continue to evolve and be refined in stakeholder proceedings in which we are active.

Pursuant to a settlement that established the design of ISO-NE’s market for installed capacity and which is being implemented gradually over a four-year period that commenced in December 2006, all generators in New England began receiving fixed capacity payments that escalate gradually over the transition period. The market design consists of a forward-looking auction for installed capacity that is intended to recognize the locational value of generators on the system and contains incentive mechanisms to encourage generator availability during generation shortages. As in PJM, capacity market rules in the ISO-NE continue to develop. ISO-NE is expected to be filing soon with FERC to establish market rules for the fourth FCM auction to be held in August 2010.

NYISO operates a short-term capacity market that provides a forward price signal only for six months into the future. The NYISO capacity model recognizes only two separate zones that potentially may separate in price: New York City and Long Island. Discussions concerning potential changes to NYISO capacity markets are also ongoing.

Capacity market rules in all of these markets may change in the future.

Transmission Regulation

FERC has exclusive jurisdiction to establish the rates and terms and conditions of service for interstate transmission. We currently have FERC-approved formula rates in effect to recover the costs of our transmission facilities. Under this formula, rates are put into effect in January of each year based upon our internal forecast of annual expenses and capital expenditures. Rates are then trued up the following year to reflect actual annual expenses/capital expenditures. Our allowed ROE is 11.68% for both existing and new transmission investments, and we have received incentive rates, affording a higher ROE, for large scale transmission investments. In October 2009, PSE&G filed its 2010 transmission rates with FERC and the rates became effective January 1, 2010. On February 2, 2010 FERC issued an order accepting our filing. The update provides for approximately $23 million in increased revenues as part of our 2010 transmission rates.

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Construction of the Susquehanna-Roseland line is contingent upon obtaining all necessary federal, state, municipal and landowner permits and approvals. The construction of the line has encountered local opposition. Should the line be cancelled for reasons beyond our control, we will be entitled to recover 100% of prudently-incurred abandonment costs.

In December 2008, PJM approved another 500 kV transmission project, originating in Branchburg and ending in Hudson County, New Jersey. This project is still in the design phase and will require the receipt of numerous regulatory approvals prior to construction. In October 2009, we filed a petition with FERC seeking incentive rates for the planned project. In December 2009, FERC granted our request for incentive rate treatment. We will receive a ROE adder of 125 basis points above its base ROE, recovery of one hundred percent of Construction Work in Progress in rate base and authorization to recover 100% of all prudently-incurred development and construction costs if the project is abandoned or cancelled, in whole or in part, for reasons beyond our control. The estimated cost of the project is approximately $1.1 billion. PJM has specified a June 2013 in-service date for this project.

In October 2007, the DOE acted to designate transmission corridors within these critical congestion areas. One of the designated corridors is the Mid-Atlantic Area National Corridor which includes New Jersey, most of Pennsylvania and New York. Thus, entities seeking to build transmission within the Mid-Atlantic Area Corridor may be able to use FERC’s back-stop siting authority under certain circumstances, if necessary, to site transmission, including the Susquehanna-Roseland line. In February 2009, the United States Court of Appeals for the Fourth Circuit issued a decision that would narrow the scope of FERC’s back-stop siting authority. The United States Supreme Court has declined to review this decision. The DOE is required by statute to issue a new congestion study in 2010.

In August 2009, the Court ruled that with respect to new 500 kV and higher centrally-planned facilities, FERC had not adequately justified its decision to regionalize these costs. Certain parties sought rehearing of the Court’s decision, which requests have been denied. The case has now been remanded to FERC for further proceedings. FERC has established procedures for review of this issue. The current allocation for new 500 kV and higher centrally-planned projects may remain in place or could be modified by FERC.

Compliance

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Nuclear Regulatory Commission (NRC)

Our operation of nuclear generating facilities is subject to comprehensive regulation by the NRC, a federal agency established to regulate nuclear activities to ensure protection of public health and safety, as well as the security and protection of the environment. Such regulation involves testing, evaluation and modification of all aspects of plant operation in light of NRC safety and environmental requirements. Continuous demonstration to the NRC that plant operations meet requirements is also necessary. The NRC has the ultimate authority to determine whether any nuclear generating unit may operate. In August 2009, we submitted applications to extend the operating licenses of our Salem and Hope Creek facilities by 20 years. No parties have requested a hearing or intervention and the initial filing deadline for such a request as part of the NRC license renewal process has passed. The NRC is expected to spend up to 30 months to review our applications before making a decision. The current operating licenses of our nuclear facilities expire in the years shown below:

State Regulation

Since our operations are primarily located within New Jersey, our principal state regulator is the BPU, which oversees electric and natural gas distribution companies in New Jersey. Our utility operations are subject to comprehensive regulation by the BPU including, among other matters, regulation of retail electric and gas distribution rates and service, the issuance and sale of certain types of securities and compliance matters. BPU regulation can also have a direct or indirect impact on our power generation business as it relates to energy supply agreements and energy policy in New Jersey.

We are also subject to some state regulation in California, Connecticut, Hawaii, New Hampshire, New York, Pennsylvania and Texas due to our ownership of generation and/or transmission facilities in those states.

Rates

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SBC —The SBC is a mechanism designed to ensure recovery of costs associated with activities required to be accomplished to achieve specific government-mandated public policy determinations. The programs that are covered by the SBC (gas and electric) are energy efficiency and renewable energy programs, Manufactured Gas Plant Remediation Adjustment Charge (RAC) and the Universal Service Fund (USF). In addition, the electric SBC includes a Social Programs component. All components include interest on both over and under recoveries.

NGC —The NGC recovers the above market costs associated with the long-term power purchase contracts with non-utility generators approved by the BPU.

Recent Rate Adjustments

USF/Lifeline — The USF is an energy assistance program mandated by the BPU under state law to provide payment assistance to low-income customers. The Lifeline program is a separately mandated energy assistance program to provide payment assistance to elderly and disabled customers. In October 2009, revised rates were put in place. Our USF rates will recover $75 million and $38 million for electric and gas, respectively. Our Lifeline rates will recover $29 million and $16 million for electric and gas, respectively. We earn no margin on the collection of the USF or Lifeline programs, resulting in no impact on Net Income.

SBC/NGC —In February 2009, we filed a petition requesting a decrease in our electric SBC/NGC rates of $18.9 million and an increase in gas SBC rates of $3.7 million. In July 2009, a revision was filed requesting an increase in SBC/NGC rates of $104 million and $15 million for electric and gas, respectively. The electric increase was due to increased non-utility generation (NUG) contract costs. We expect an initial decision from the Administrative Law Judge in March and a BPU order in April 2010. No assurances can be provided as to the outcome of these proceedings.

RAC — In November 2009, we filed a RAC 17 petition with the BPU requesting an increase in electric and gas RAC rates of approximately $13.4 million and $10.5 million, respectively. This matter was transferred to the Office of Administrative Law.

Energy Supply

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All of New Jersey’s EDCs jointly procure the supply to meet their BGS obligations through two concurrent auctions authorized each year by the BPU for New Jersey’s total BGS requirement. These auctions take place annually in February. Results of these auctions determine which energy suppliers provide BGS to New Jersey’s EDCs. PSE&G earns no margin on the provision of BGS.

PSE&G’s total BGS-Fixed Price eligible load is expected to be approximately 8,500 MW. Approximately one-third of this load is auctioned each year for a three-year term. Current pricing is as follows:

In December 2009, the BPU decided that, after the 2010 BGS auction, it would hold a technical conference to consider enhancements to the BGS auction. Any action taken in response to that hearing is likely to be implemented for the BGS auctions in 2011 or future years. The BPU may address many issues, including the impact of potential development of incremental generation in New Jersey. No assurances can be provided as to the outcome of these proceedings.

For additional information, see Item 8. Financial Statements and Supplementary Data—Note 6. Regulatory Assets and Liabilities and Note 12. Commitments and Contingent Liabilities.

PSE&G has a full requirements contract through March 2012 with Power to meet the supply requirements of default service gas customers. Power charges PSE&G for gas commodity costs which PSE&G recovers from customers. Any difference between rates charged by Power under the BGSS contract and rates charged to PSE&G’s residential customers are deferred and collected or refunded through adjustments in future rates. PSE&G earns no margin on the provision of BGSS.

In May 2009, PSE&G made its annual BGSS filing with the BPU. The filing requested a decrease in annual BGSS revenue of $133 million, excluding Sales and Use Tax, to be effective October 1, 2009. This represents a reduction of approximately 7% for a typical residential gas heating customer. The BPU approved the new lower BGSS rate on September 16, 2009 and it became effective immediately.

Energy Policy

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We have approval from the BPU to implement several programs addressing different components of the EMP goals to improve efficiencies in customer use and increase the level of renewable generation in New Jersey.

The total investment of both phases of the Solar Loan Program will be approximately $248 million once the program is fully subscribed, projects are built and loans are closed. As of December 31, 2009, we have provided $43 million in loans for 53 projects representing 11.6 MW.

The second solar initiative is the Solar 4 All Program that was approved by the BPU in July 2009. Under this program, we are investing approximately $515 million to develop 80 MW of utility-owned solar photovoltaic (PV) systems over four years. The program consists of systems 500kW or greater installed on PSE&G-owned property (25 MW), solar panels installed on distribution system poles (40 MW) and PV systems installed on third-party sites in our electric service territory (15 MW). We will sell the energy and capacity from the systems in the PJM wholesale electricity market. In addition we will sell the SRECs received from the projects through the same auction used in the loan program. Proceeds from these sales will be used to offset program costs.

As of December 31, 2009, 1 MW of solar panels had been installed on distribution poles. On January 6, 2010, we announced that we had entered into contracts with four developers for 12 MW of solar capacity to be developed on land we own in Edison, Linden, Trenton and Hamilton. The projects represent an investment of approximately $50 million. Construction is expected to start this spring pending receipt of all approvals.

In July 2009, the BPU approved a portion of our program that focuses on air conditioning load control in the residential and small commercial customer segments. The investment represents $65.3 million with a target of 150 MW to be achieved. The remaining portion of our filing is awaiting further action by the BPU, but no timetable has been established to complete the proceeding. As of December 31, 2009, we had installed approximately 1.2 MW.

Also in 2008, the BPU directed each of the State’s electric utilities to administer a one-year program designed to develop an additional 600 MW of DR resources. The utilities’ role was to collect funding through rates and make payments to Curtailable Service Providers who signed up the new or incremental DR resources. The incentive was set by the BPU at $22.50/MW-day with a statewide budget of $4.9 million. Our share was set at 59.54%, or 195 MW, with a budget of $3.4 million. Funding for the program, called the Demand Response Working Group Modified Program, was

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collected through a component of the Regional Greenhouse Gas Initiative (RGGI) Adjustment Clause in 2009. We anticipate paying approximately $1.1 million in February 2010 for the 132 MW verified by PJM.

The energy efficiency initiatives target multiple customer segments. Subprograms provide energy audits and incentives for energy retrofit services to homes and small businesses in Urban Enterprise Zone municipalities, multi-family buildings, hospitals, data centers and governmental entities. Other initiative components include funding for new technologies and demonstration projects, and a program to encourage non-residential customers to reduce energy use through improvements in the operation and maintenance of their facilities.

In April 2009, the BPU approved a settlement agreement which identified 38 qualifying projects totaling $694 million. These projects are expected to create more than 900 new jobs. We received the BPU’s written order effective May 1, 2009, which provides increases of $7 million for electric and $12 million for gas rates annually. Under the program, new Capital Adjustment Charges (CAC) will provide for immediate recovery of a return on program expenditures plus depreciation of the assets. The CAC will be adjusted each January based on forecasted program expenditures and will be subject to deferred accounting. The rates are subject to annual adjustments based on actual expenditures and market conditions.

In November 2009, PSE&G made a filing in the above-referenced matter, requesting approximately $35 million for electric and $17 million for gas in revenue, on an annual basis for a combined total of $52 million. Compared to the existing BPU approved CAC rates, the resultant total net annual revenue impact on the electric and gas customers is a $33 million increase over the 2009 rates. In December 2009, the BPU approved a stipulation to reset the CAC effective January 1, 2010.

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BPU Audits

The BPU has statutory authority to conduct periodic audits of our utility’s operations and our compliance with applicable affiliate rules and competition standards. The BPU has begun conducting its periodic combined management/competitive service audits of PSE&G.

ENVIRONMENTAL MATTERS

Environmental laws and regulations significantly impact the manner in which our operations are currently conducted and impose costs on us to address the environmental impacts of historical operations that may have been in full compliance with the requirements in effect at the time those operations were conducted. To the extent that environmental requirements are more stringent and compliance more costly in certain states where we operate compared to other states that are part of the same market, such rules may impact our ability to compete within that market. Due to evolving environmental regulations, it is difficult to project future costs of compliance and their impact on competition. Capital costs of complying with current pollution control requirements are included in our estimate of construction expenditures in Item 7. MD&A—Capital Requirements. The costs of compliance associated with any new requirements that may be imposed by future regulations are not known and are not included in capital expenditures, but may be material.

Areas of environmental regulation may include, but are not limited to:

For additional information related to environmental matters, including anticipated expenditures for installation of pollution control equipment, hazardous substance liabilities and fuel and waste disposal costs, see Item 1A. Risk Factors, Item 3. Legal Proceedings and Note 12. Commitments and Contingent Liabilities.

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Air Pollution Control

Our facilities are subject to federal regulation under the Clean Air Act (CAA) which requires controls of emissions from sources of air pollution and imposes record keeping, reporting and permit requirements. Our facilities are also subject to requirements established under state and local air pollution laws.

Title V of the CAA requires all major sources such as our generation facilities to obtain and keep current an operating permit. The costs of compliance associated with any new requirements that may be imposed and included in these permits in the future could be material and are not included in capital expenditures, but may be material.

The U.S. Environmental Protection Agency (EPA) further regulated SO ₂ and NOx by enacting the final Clean Air Interstate Rule (CAIR). In this rule, the EPA identified 28 states and the District of Columbia as contributing significantly to the levels of fine particulates and/or eight-hour ozone air quality in states downwind of those states identified by EPA. New Jersey, New York, Pennsylvania, Texas and Connecticut were among the states the EPA listed as contributing to downwind particulate and eight-hour ozone air quality. Based on state obligations to address interstate transport of air pollutants under the CAA, the EPA had proposed a two-phased emission reduction of both NO _x and SO ₂ , which are precursors to both particulate matter emissions and ozone air quality. Under CAIR, both NO _x and SO ₂ are regulated under two phases, which correspond to the emissions levels expected to be obtained by certain dates during those phases. Phase 1of CAIR was scheduled to begin in 2009 for emissions of NO _x and 2010 for emissions of SO _2. Phase 2 of CAIR for NOx and SO ₂ emissions were scheduled to begin in 2015. The EPA is recommending that the program be implemented through a cap-and-trade program, although states are not required to proceed in this manner.

CAIR was challenged by a variety of states, environmental groups and industry groups. In December 2008, the U.S. Court of Appeals for the District of Columbia Circuit remanded CAIR back to the EPA to fix what the Court identified as the flaws within CAIR. The existing CAIR will remain in effect until the EPA issues new rules.

Based upon the remand order, the NO _x trading program commenced in 2009. It is anticipated that, in aggregate, we will be net buyers of annual NO _x allowances but will likely be allocated sufficient allowances to satisfy Ozone season NO _x emissions. At recent market prices of annual NO _x allowances, the cost of our estimated shortfall requirement of 3,000 allowances would be approximately $10 million. The future direction of the market is unclear due to the recent court rulings. The final cost of compliance is uncertain due to market instability.

The SO ₂ part of CAIR was initiated on January 1, 2010, and the financial impact to us is anticipated to be minimal due to the surplus allowances banked from the acid rain program that can be used to satisfy CAIR obligations. CAIR redesign is expected to be proposed in the second quarter of 2010. The impacts of this redesign cannot be determined at this time.

Water Pollution Control

The Federal Water Pollution Control Act (FWPCA) prohibits the discharge of pollutants to U.S. waters from point sources, except pursuant to a National Pollutant Discharge Elimination System (NPDES) permit issued by the EPA or by a state under a federally authorized state program. The FWPCA authorizes the imposition of technology-based and water quality-based effluent limits to regulate the discharge of pollutants into surface waters and ground waters. The EPA has delegated authority to a number of state agencies, including those in New Jersey, New York, Connecticut and Texas, to administer the NPDES program through state acts. We also have ownership interests in facilities in other jurisdictions that have their own laws and implement regulations to control discharges to their surface waters and ground waters that directly govern our facilities in those jurisdictions.

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In addition to regulating the discharge of pollutants, the FWPCA regulates the intake of surface waters for cooling. The use of cooling water is a significant part of the generation of electricity at steam-electric generating stations. Section 316(b) of the FWPCA requires that cooling water intake structures reflect the best technology available for minimizing adverse environmental impact. The impact of regulations under Section 316(b) can be significant, particularly at steam-electric generating stations which do not have closed cycle cooling, in other words, the use of cooling towers to recycle water for cooling purposes. The installation of cooling towers at an existing generating station can impose significant engineering challenges and significant costs, which can affect the economic viability of a particular plant.

For additional information, see Item 8. Financial Statements and Supplementary Data—Note 12. Commitments and Contingent Liabilities.

Hazardous Substance Liability

The production and delivery of electricity, distribution of gas and, formerly, the manufacture of gas, results in various by-products and substances classified by federal and state regulations as hazardous. These regulations may impose liability for damages to the environment from hazardous substances, including obligations to conduct environmental remediation of discharged hazardous substances as well as monetary payments, regardless of the absence of fault and the absence of any prohibitions against the activity when it occurred, as compensation for injuries to natural resources.

Fuel and Waste Disposal

Spent nuclear fuel generated in any reactor can be stored in reactor facility storage pools or in Independent Spent Fuel Storage Installations located at reactors or away-from reactor sites for at least 30 years beyond the licensed life for the reactor. We have an on-site storage facility that is expected to satisfy the storage needs of Salem 1, Salem 2 and Hope Creek through the end of their current licenses as well as storage needs over the units’ anticipated 20 year license extensions. Exelon Generation has advised us that it has an on-site storage facility that will satisfy Peach Bottom’s storage requirements until at least 2014.

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Climate Change

In response to concerns over global climate change, some states have developed initiatives to stimulate national climate legislation through CO ₂ emission reductions in the electric power industry. Ten Northeastern states, including New Jersey, New York and Connecticut, have established RGGI intended to cap and reduce CO ₂ emissions in the region. In general, these states adopted state-specific rules to enable the RGGI regulatory mandate in each state.

States’ rules make allowances available through a regional auction whereby generators may acquire allowances that are each equal to one ton of CO2 emissions. Generators are required to submit an allowance for each ton emitted over a three year period (e.g. 2009, 2010, 2011). Allowances are available through the auction or through secondary markets and are required to be submitted to states by March 2012 for the first period.

Pricing for the allowances will vary based on future allowance market conditions, electric generation market conditions and the possibility of a national greenhouse gas program that may or may not supplant RGGI.

New Jersey also adopted the Global Warming Response Act in 2007, which calls for stabilizing its greenhouse gas emissions to 1990 levels by 2020, followed by a further reduction of greenhouse emissions to 80% below 2006 levels by 2050. To reach this goal, the NJDEP, the BPU, other state agencies and stakeholders are required to evaluate methods to meet and exceed the emission reduction targets, taking into account their economic benefits and costs.

Concurrently, the federal government is considering several bills to define a national energy policy and address climate change. Bills under consideration include provisions to establish a national renewable energy portfolio standard, to establish an energy efficiency resource standard and to implement a cap-and-trade program to reduce greenhouse gas emissions. Provisions contained within these bills may present material risks and opportunities to our businesses. Ultimately, the final design of the federal climate change bill—specifically with regard to the stringency and integrity of the carbon cap, the design of price control mechanisms, rules governing the use of offsets, how emissions allowances are allocated and provisions for preemption of State, regional, and EPA programs—will determine the impact of the legislation on us. We will not be able to reasonably estimate these impacts until final legislation is passed.

The EPA has issued an endangerment finding for greenhouse gas emissions, and is in the process of defining how it will apply Preventions of Significant Deterioration (PSD)/ Best Available Control Technology (BACT) requirements for greenhouse gas emissions at new and or modified sources. The scope and stringency of these requirements will determine their impact to the electric power industry and us.

For additional information on various activities at the federal level during 2009 related to addressing global climate change, see Item 7. MD&A—Overview of 2009 and Future Outlook.

The outcome of global climate change initiatives cannot be determined; however, adoption of stringent CO ₂ emissions reduction requirements in the Northeast, including the potential allocation of allowances to our facilities and the prices of allowances available through auction, could materially impact our operations. The financial impact of a requirement to purchase allowances for emissions of CO ₂ would be greatest on coal-fired generating units because they typically have the highest CO ₂ emission rate and therefore, need to purchase the most allowances. Gas-fired units would require fewer allowances and nuclear units would not need any allowances.

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Any addition of CO ₂ limit requirements under a national program could impose an additional financial impact on our fossil generation activities beyond that imposed by existing state and regional programs. It is premature to determine the positive or negative financial impact of a future federal climate change program because it is difficult to determine the effect of such program on the dispatch of our electric generation units compared to the dispatch of other power generating companies, particularly those which may have a larger carbon footprint.

While there would be increased costs relating to these evolving regulations, the efforts to reduce greenhouse gases could lead to increased opportunities associated with renewable generation and other alternative fuels. Moreover, to the extent that a carbon charge applies to gas and coal generation, we could experience higher margin from the sale of energy produced by our nuclear facilities. However, it is premature to attempt to quantify the possible costs and other implications of our generation facilities.

In addition to legislative and regulatory initiatives, the outcome of certain legal proceedings not involving our companies could be material in the future liability of energy companies on alleged impacts of global climate change. Litigation has been commenced by individuals, local governments and interest groups alleging that various industries, including various energy companies, emitted greenhouse gases causing global climate change that resulted in a variety of damages. If relevant Federal or state common law were to develop that imposed liability upon those that emit greenhouse gases for alleged impacts of greenhouse gas emissions, such potential liability could be material.

SEGMENT INFORMATION

Financial information with respect to our business segments is set forth in Note 21. Financial Information by Business Segment.