UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

100 F ST., N.E.

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2011,

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM          TO         

Commission File Number	Registrants, State of Incorporation, Address, and Telephone Number	I.R.S. Employer Identification No.
001-09120	PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	22-2625848
	(A New Jersey Corporation)
	80 Park Plaza, P.O. Box 1171
	Newark, New Jersey 07101-1171
	973 430-7000
	http://www.pseg.com
001-34232	PSEG POWER LLC	22-3663480
	(A Delaware Limited Liability Company)
	80 Park Plaza—T25
	Newark, New Jersey 07102-4194
	973 430-7000
	http://www.pseg.com
001-00973	PUBLIC SERVICE ELECTRIC AND GAS COMPANY	22-1212800
	(A New Jersey Corporation)
	80 Park Plaza, P.O. Box 570
	Newark, New Jersey 07101-0570
	973 430-7000
	http://www.pseg.com

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

Registrant	Title of Each Class	Name of Each Exchange On Which Registered
Public Service Enterprise Group Incorporated	Common Stock without par value	New York Stock Exchange
PSEG Power LLC	8  5/8% Senior Notes, due 2031	New York Stock Exchange
	First and Refunding Mortgage Bonds
Public Service Electric and Gas Company	9  1/4% Series CC, due 2021	New York Stock Exchange
	6  3/4% Series VV, due 2016
	8%, due 2037
	5%, due 2037

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

Registrant	Title of Each Class
PSEG Power LLC Public Service Electric and Gas Company	Limited Liability Company Membership Interest Medium-Term Notes, Series A, B, C, D, E, F and G

(Cover continued on next page)

(Cover continued from previous page)

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

Public Service Enterprise Group Incorporated	Yes x	No ¨
PSEG Power LLC	Yes ¨	No x
Public Service Electric and Gas Company	Yes x	No ¨

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).

Public Service Enterprise Group Incorporated	Yes x	No ¨
PSEG Power LLC	Yes x	No ¨
Public Service Electric and Gas Company	Yes x	No ¨

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. ¨

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Public Service Enterprise Group Incorporated	Large accelerated filer x	Accelerated filer ¨	Non-accelerated filer ¨	Smaller reporting company ¨
PSEG Power LLC	Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer x	Smaller reporting company ¨
Public Service Electric and Gas Company	Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer x	Smaller reporting company ¨

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, 2011 was $16,495,247,274 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 31, 2012 was 506,050,478.

As of January 31, 2012, 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 2012 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 2, 2012, as specified herein.

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		30
	Segment Information		35
Item 1A.	Risk Factors		35
Item 1B.	Unresolved Staff Comments		44
Item 2.	Properties		44
Item 3.	Legal Proceedings		47
Item 4.	Mine Safety Disclosures		49
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		50
Item 6.	Selected Financial Data		52
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		53
	Overview of 2011 and Future Outlook		53
	Results of Operations		59
	Liquidity and Capital Resources		69
	Capital Requirements		74
	Off-Balance Sheet Arrangements		77
	Critical Accounting Estimates		77
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		82
Item 8.	Financial Statements and Supplementary Data		84
	Report of Independent Registered Public Accounting Firm		85
	Consolidated Financial Statements		88
	Notes to Consolidated Financial Statements
	Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies		103
	Note 2. Recent Accounting Standards		107
	Note 3. Variable Interest Entities		109
	Note 4. Discontinued Operations and Dispositions		109
	Note 5. Property, Plant and Equipment and Jointly-Owned Facilities		111
	Note 6. Regulatory Assets and Liabilities		113
	Note 7. Long-Term Investments		118
	Note 8. Financing Receivables		119
	Note 9. Available-for-Sale Securities		122
	Note 10. Goodwill and Other Intangibles		126
	Note 11. Asset Retirement Obligations (AROs)		126
	Note 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plans		127
	Note 13. Commitments and Contingent Liabilities		134
	Note 14. Schedule of Consolidated Debt		146
	Note 15. Schedule of Consolidated Capital Stock		152
	Note 16. Financial Risk Management Activities		152
	Note 17. Fair Value Measurements		159
	Note 18. Stock Based Compensation		165
	Note 19. Other Income and Deductions		170
	Note 20. Income Taxes		171
	Note 21. Earnings Per Share (EPS) and Dividends		180
	Note 22. Financial Information by Business Segment		181
	Note 23. Related-Party Transactions		183
	Note 24. Selected Quarterly Data (Unaudited)		186
	Note 25. Guarantees of Debt		187
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure		190
Item 9A.	Controls and Procedures		190
Item 9B.	Other Information		190
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		195
Item 11.	Executive Compensation		197
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		198
Item 13.	Certain Relationships and Related Transactions, and Director Independence		198
Item 14.	Principal Accounting Fees and Services		198
PART IV
Item 15.	Exhibits and Financial Statement Schedules		199
	Schedule II - Valuation and Qualifying Accounts		208
	Glossary of Terms		210
	Signatures		214
	Exhibit Index		217

i

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,” “should,” “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 13. 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:

• adverse changes in the demand for or the price of the capacity and energy that we sell into wholesale electricity markets,

• adverse changes in energy industry law, policies and regulation, including market structures and a potential shift away from competitive markets toward subsidized market mechanisms, transmission planning and cost allocation rules, including rules regarding how transmission is planned and who is permitted to build transmission in the future, and reliability standards,

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

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

• changes in nuclear regulation and/or general developments in the nuclear power industry, including various impacts from any accidents or incidents experienced at our facilities or by others in the industry, that could limit operations of our nuclear generating units,

• 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,

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

• any deterioration in our credit quality or the credit quality of our counterparties, including in our leveraged leases,

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

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

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

• delays in receipt of necessary permits and approvals for our construction and development activities,

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

• any inability to achieve, or continue to sustain, our expected levels of operating performance,

• increase in competition in energy markets in which we compete,

• challenges associated with recruitment and /or retention of a qualified workforce,

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

• changes in technology and customer usage patterns.

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 consequences to, or effects on, us or our business prospects, financial condition or results of operations that management expects. 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 apply only 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.

ii

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 210.

WHERE TO FIND MORE INFORMATION

We file annual, quarterly and special reports, proxy statements and other information with the 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 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, Inc., 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.

1

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 direct 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. Has also implemented several programs to improve efficiencies in customer energy use and increase the level of renewable generation within New Jersey.	A New Jersey limited liability company (successor to a corporation which was formed in 1989) that invests and operates through its two primary subsidiaries. Earns revenues from managing lease investments and the operation of its generation projects. Also pursuing development of 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 regulated public utility, PSE&G has continued to be a stable earnings contributor for us.

Earnings (Losses) in millions	2011			2010		2009
Power	$	1,002		$	1,136	$	1,191
PSE&G		521			359		325
Energy Holdings		(134	)		49		72
Other		18			13		6
PSEG Income from Continuing Operations	$	1,407		$	1,557	$	1,594

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

• Business Operations and Strategy

• Competitive Environment

• Employee Relations

• Regulatory Issues

• Environmental Matters

2

BUSINESS OPERATIONS AND STRATEGY

Power

Through Power, we seek to produce low-cost energy by efficiently operating our nuclear, coal, gas and oil-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:

• 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.

• 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.

• 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.

• 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 and year to year thereafter.

About 46% of PSE&G’s peak daily gas requirements is provided from Power’s firm transportation capacity, which is available every day of the year. Power satisfies the remainder of PSE&G’s requirements from storage contracts, liquefied natural gas, seasonal purchases, contract peaking supply, propane and refinery gas. Based upon availability, Power also sells gas to others.

How Power Operates

We own approximately 13,060 MW 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.

3

The map below shows the locations of our Northeast and Mid Atlantic generation facilities.

In 2011, we sold 2,000 MW of generation facilities we owned and operated in Texas. See Item 8. Financial Statements and Supplementary Data—Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies and Note 4. Discontinued Operations and Dispositions, for additional information.

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

• Generation Capacity

Our installed capacity utilizes a diverse mix of fuels: 44% gas, 28% nuclear, 18% coal, 9% 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 2011 was approximately 54,000 GWh. The following table indicates the proportionate share of generating output by fuel type.

Generation by Fuel Type	Actual 2011
Nuclear:
New Jersey facilities		38	%
Pennsylvania facilities		18	%
Fossil:
Coal:
New Jersey facilities		5	%
Pennsylvania facilities		9	%
Connecticut facilities		1	%
Oil and Natural Gas:
New Jersey facilities		22	%
New York facilities		7	%
Total		100	%

4

While overall generation has increased over the past several years, the mix by fuel type has changed slightly in recent years due to 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.

• 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 34% base load, 43% load following and 23% 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. In 2011, our base load capacity factors were as follows:

Unit	2011 Capacity Factor
Nuclear
Salem Unit 1		85.4	%
Salem Unit 2		88.0	%
Hope Creek		98.7	%
Peach Bottom Unit 2		99.2	%
Peach Bottom Unit 3		88.0	%
Coal
Keystone		75.1	%
Conemaugh		72.7	%

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

• Load Following Units typically 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.

• Peaking Units run the least amount of time and utilize higher-priced fuels. These units typically 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.

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 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 Locational Marginal Price (LMP) in congested areas, reflecting the bid prices of those higher-cost generation units.

5

The following chart depicts the merit order of dispatch in PJM Interconnection L.L.C. (PJM), where most of our generation units are located, based on illustrative historical dispatch cost. It should be noted that 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 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.

6

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 we operate.

7

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 can be no assurance that such prices will remain in effect or that we will be able to contract output at these forward prices.

Fuel Supply

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

• purchase of uranium (concentrates and uranium hexafluoride);

• conversion of uranium concentrates to uranium hexafluoride;

• enrichment of uranium hexafluoride; and

• fabrication of nuclear fuel assemblies.

• 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 unit uses a specific type of coal obtained from Indonesia. If the supply from Indonesia or equivalent coal from other sources was not available for this facility, our long-term operations would be adversely impacted since 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.

• 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 firm gas transportation contracts to serve our Bethlehem Energy Center (BEC) in New York.

We have 1.3 billion cubic feet-per-day of firm transportation capacity under contract to meet our obligations under the BGSS contract. On an as available basis, this firm transportation capacity may also be used to serve the gas supply needs of our generation fleet. We supplement that supply with a total storage capacity of 76 billion cubic feet.

• Oil—Oil is used as the primary fuel for one load following steam unit 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 2011 and Future Outlook and Item 8. Financial Statements and Supplementary Data -Note 13. Commitments and Contingent Liabilities.

Markets and Market Pricing

Power’s assets are located in three centralized, competitive electricity markets operated by ISO organizations all of which are subject to the regulatory oversight of the Federal Energy Regulatory Commission (FERC):

• PJM Regional Transmission Organization—PJM conducts the largest centrally dispatched energy market in North America. It serves over 60 million people, nearly 19% of the total U.S. population and

8

a peak demand of over 163,800 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. The majority of our generating stations operate in PJM.

• New York—The NYISO is the market coordinator for New York State and is 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. Our BEC station operates in New York.

• 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 28,130 MW. Our Bridgeport and New Haven stations operate in Connecticut.

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, oil 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. Over the long-term, 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 our generating units fail to function effectively or otherwise become unavailable.

Over the past few years, a decline in wholesale natural gas prices has resulted in lower electricity prices. One of the reasons for the decline in natural gas prices is greater supply from shale production. This trend has reduced margin on forward sales as we recontract our expected generation output.

In addition to energy sales, we also earn revenue from capacity payments for our generating assets. These payments are compensation for committing a portion of our capacity 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.

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.

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 2011 to May 2012	$	110.00	$	40.16
June 2012 to May 2013	$	139.73	$	51.70
June 2013 to May 2014	$	245.00	$	89.43
June 2014 to May 2015	$	136.50	$	49.82

Identical prices were set for all zones for the periods from June 2010 to May 2012 under these auctions. For all other periods the prices differ in the various areas of PJM, depending on the constraints in each area of the transmission system, with Keystone and Conemaugh receiving lower prices than the majority of our PJM generating units since there are fewer constraints in that region and our generating units in northern New Jersey usually receiving higher pricing.

9

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 the 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 may affect the capacity pricing, including but not limited to:

• changes in load and demand;

• changes in the available amounts of demand response resources;

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

• increases in transmission capability between zones;

• 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 and the other ISOs may propose over time; and

• changes driven by legislative and/or regulatory action, that permit states to subsidize local electric power generation through the consummation of standard offer capacity agreements.

For additional information on the RPM and FCM markets, 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 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 serve will vary from year to year. Pricing for the BGS contracts, including a capacity component, for recent and future periods by purchasing utility is as follows:

Load Zone ($/MWh)	2008-2011		2009-2012		2010-2013		2011-2014		2012-2015
PSE&G	$	111.50	$	103.72	$	95.77	$	94.30	$	83.88
Jersey Central Power & Light	$	114.09	$	103.51	$	95.17	$	92.56	$	81.76
Atlantic City Electric	$	116.50	$	105.36	$	98.56	$	100.95	$	85.10
Rockland Electric Company	$	120.49	$	112.70	$	103.32	$	106.84	$	92.51

A portion of our total capacity is hedged through the BGS auctions. On average, tranches won in the BGS auctions require 110 to 120 of capacity on a daily basis.

We have obtained price certainty for all of our PJM and New England capacity through May 2015 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 compared to 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

10

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 2010, as market prices declined from past years’ historic highs, there was additional incentive for more of the smaller commercial and industrial electric customers to switch. In a falling price environment, this has a negative impact on our margins, as the anticipated BGS pricing is replaced by lower spot market pricing. While this impact has been reduced as average BGS rates have declined to a level more closely resembling current market prices, customers may still see an incentive to switch to third party suppliers. We are unable to determine the degree to which this switching, or “migration,” will continue, but the impact on our results could be material.

As of February 9, 2012, we had contracted for the following percentages of our anticipated base load generation output for the next three years with modest amounts beyond 2014.

Base Load Generation	2012		2013		2014
Generation Sales		100%		85%-90%		30%-35%

Power’s strategy is to maintain certain levels of uranium in inventory and to make periodic purchases to support such levels. Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements for the three years. Power also has various long-term fuel purchase commitments for coal to support its fossil generation stations. These purchase obligations are consistent with Power’s strategy to enter into contracts for its fuel supply in comparable volumes to its sales contracts.

We take a more opportunistic approach in hedging our anticipated natural gas-fired generation. The generation from these units is less predictable, as a significant portion of these units will only dispatch when aggregate market demand has exceeded the supply provided by lower-cost units. The natural gas-fired units have historically provided a lower contribution to our margin than either the nuclear or coal units, although market price dynamics of coal and gas over the past few years have moderated this historical relationship.

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.

11

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 6.2 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.

• 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 competitive services, such as appliance repair. 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:

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

• a program to develop, own and operate solar power systems, and

• 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.

12

How PSE&G Operates

We provide network transmission and point-to-point transmission services, which are coordinated with PJM, and provide distribution service to 2.2 million electric customers and 1.8 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, our approved rates provide for a base ROE of 11.68% on existing and new transmission investment, while certain investments are entitled to earn an additional incentive rate. For more information on current transmission construction activities, see Regulatory Issues, Federal Regulation—Transmission Regulation.

Transmission Statistics
December 31, 2011			Historical Annual  Load Growth 2007-2011
Network Circuit Miles	Billing Peak (MW)
1,357		10,933		-0.3%

Distribution

Our primary business is the distribution of gas and electricity to end users in our service territory. Our load requirements were split among residential, commercial and industrial customers, as described below for 2011. 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 2011 Sales
Customer Type	Electric		Gas
Commercial		57%		36%
Residential		33%		60%
Industrial		10%		4%
Total		100%		100%

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

Electric and Gas Distribution Statistics
		December 31, 2011				Historical Annual
	Number of Customers		Electric Sales and Gas Sold and Transported		Load Growth 2007-2011
Electric		2.2 Million		42,506 GWh		-0.5%
Gas		1.8 Million		3,527 Million Therms		2.2%

13

Supply

Although commodity revenues make up almost 54% 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 are not served by 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.

PSE&G procures the supply requirements of our default service BGSS gas customers 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

Historically, there has been 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 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, including the impact of natural gas commodity prices on electricity prices such as BGS, see Item 7. MD&A.

14

Energy Holdings

Our focus at Energy Holdings is on managing our portfolio of lease investments and generation projects. Energy Holdings is also continuing to explore opportunities for additional investments in renewable generation.

Over the past several years, we have terminated all of our international leveraged leases with lessees willing to meet certain economic thresholds in order to reduce the cash tax exposure related to these leases. We have also reduced our risk by opportunistically monetizing the majority of our previous international investments. We are continuing to explore options for our remaining international investment in Venezuela as well as our projects in Hawaii and New Hampshire. In February, 2012, the California Public Utilities Commission approved the shut down of GWF Power and we anticipate recovering the remaining book value of our investment. For additional information on these generation facilities, see Item 2. Properties.

Products and Services

The majority of our remaining $881 million of domestic lease investments are energy-related leveraged leases. As of December 31, 2011, the single largest lease investment represented 38% of total lease investments.

Our leveraged 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 on 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 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 accounting principles generally accepted in the United States (GAAP), the leveraged 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, see Item 1A. Risk Factors, Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Credit Risk—Energy Holdings, Item 8. Financial Statements and Supplementary Data—Note 8. Financing Receivables and Note 13. Commitments and Contingent Liabilities.

Through Energy Holdings, we own and operate solar projects in New Jersey, Florida and Ohio totaling 29 MW. See Item 2. Properties for additional information. In January 2012, Energy Holdings also acquired an additional 25 MW solar project currently under construction in Arizona. Completion of this project is expected by the third quarter of 2012. All of the energy, capacity and environmental attributes generated by the project in the first 20 years are expected to be sold under a long-term power purchase agreement. Energy Holdings has issued guarantees of up to $71.5 million for payment of obligations related to the construction of the project. These guarantees will terminate upon successful completion of the project. The total investment for the project will be approximately $75 million.

Also, in December 2011, the Long Island Power Authority (LIPA) selected PSEG Long Island LLC (PSEG LI), a newly formed wholly owned subsidiary of Energy Holdings, to manage its electric transmission and distribution system in Long Island, New York.

15

LIPA issued a press release that it had selected us for a variety of reasons, including our proven track record of first quartile customer service and reliability, commitment to cost control, corporate culture of transparency and local decision making, technical expertise and proven environmental track record. The ten year contract will commence on January 1, 2014. As part of the management contract, PSEG LI will be expected to develop and implement a number of operational improvements to provide safe and reliable service for LIPA’s customers, increase customer satisfaction and manage the operational and maintenance costs of LIPA.

COMPETITIVE ENVIRONMENT

Power

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

• merchant generators,

• domestic and multi-national utility generators,

• energy marketers,

• banks, funds and other financial entities,

• fuel supply companies, and

• 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 load requirements. A reduction in load requirements can also be caused by economic cycles, customer migration and other 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, cost allocation and who is permitted to build transmission 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. This is now occurring in New Jersey where a new law was enacted on January 28, 2011 establishing a long-term capacity agreement pilot program (LCAPP) which provides for up to 2,000 MW of subsidized base load or mid-merit electric power generation. This bill may have the effect of artificially depressing prices in the competitive wholesale market and thus has the potential to harm competitive markets, on both a short-term and a long-term basis. Other states, such as Maryland, are also examining similar programs. The lack of consistent rules in energy markets can negatively impact the competitiveness of our plants.

Environmental issues, such as restrictions on emissions of carbon dioxide (CO₂) 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. In addition, most of our plants, which are located in the Northeast where rules are more stringent, can be at an economic disadvantage compared to our competitors in certain Midwest states. While our generation fleet is relatively low-emitting, additional restrictions could have a negative impact on certain of our units, including our coal units.

16

In addition, pressures from renewable resources could increase over time. For example, many parts of the country, including the mid-western region within the footprint of the Midwest Independent System Operator, the California ISO and the PJM region, have either implemented or are considering implementing changes to their respective regional transmission planning processes that will enable the construction of large amounts of transmission to move renewable generation to load centers. FERC has also ordered all FERC-jurisdictional regions to consider public policy requirements, such as State Renewable Portfolio Standards, in their planning processes, which could facilitate the integration of renewable resources. For additional information, see the discussion in Regulatory Issues—Federal Regulation below.

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.

Changes in the current policies for building new transmission lines, such as the proposal by FERC to eliminate contractual provisions that provide us a “right of first refusal” to construct projects in our service territory, could result in additional competition to build transmission lines in our area in the future and would allow us to seek opportunities to build in other service territories. Moreover, as discussed in Regulatory Issues—Federal Regulation below, the court’s elimination of national electric transmission corridors may impact upon future transmission build.

Construction of new subsidized local generation also has the potential to reduce the need for the construction of new transmission to transport remote generation and alleviate system constraints.

EMPLOYEE RELATIONS

As of December 31, 2011, we had approximately 9,784 employees within our subsidiaries, including 6,346 covered under collective bargaining agreements. All of our collective bargaining agreements will expire on April 30, 2013 or later. We believe we maintain satisfactory relationships with our employees.

Employees as of December 31, 2011
	Power		PSE&G		Energy Holdings		Services
Non-Union		1,207		1,250		16		965
Union		1,492		4,845		0		9
Total Employees		2,699		6,095		16		974
Number of Union Groups		3		5		N/A		1

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 and the generation and energy trading subsidiaries of Power 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 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.

17

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 criteria established by FERC. We own various QFs through Energy Holdings. QFs are subject to some, but not all, of the same FERC requirements as public utilities.

FERC also regulates Regional Transmission Operators/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

• Energy Clearing Prices

• Capacity Market Issues

• Transmission Regulation

• Compliance

Regulation of Wholesale Sales—Generation/Market Issues

• Market Power—Under FERC regulations, public utilities must receive FERC authorization to sell power in interstate commerce. They can sell power at cost-based rates or apply to FERC for authority to make market based rate (MBR) sales. For a requesting company to receive MBR authority, FERC must first make a determination that the requesting company lacks market power in the relevant markets. FERC requires that holders of MBR tariffs file an update every three years demonstrating that they continue to lack market power.

PSE&G, PSEG Energy Resources & Trade LLC, PSEG Power Connecticut, PSEG Fossil LLC and PSEG Nuclear LLC were each granted continued MBR authority from FERC in June 2011. Retention of MBR authority is important to the maintenance of our current generation business’ revenues.

• Cost-Based Reliability Must Run (RMR) Agreements—FERC has permitted public utility generation owners to enter into RMR agreements that provide cost-based compensation to a generation owner when a unit proposed for retirement is asked to continue operating for reliability purposes. In June 2011, we asked PJM to re-evaluate whether a previously approved extension of the RMR contract for Hudson 1 was necessary. In August 2011, PJM determined that such an extension was not needed and stated that it would be releasing the RMR contract. Accordingly, we filed with FERC to notify FERC that PJM had terminated RMR services from Hudson Unit 1 as of December 7, 2011. Also in September, we informed PJM that we were retiring the gas-fired load following Hudson Unit 1 as of December 8, 2011.

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 Market Issues

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

18

PJM—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 were challenged in court by various state public utility commissions, including the BPU. On February 8, 2011, the D.C. Circuit Court of Appeals issued a decision upholding the FERC orders denying this challenge to the transitional auction results. Moreover, the mechanics of RPM in PJM continue to evolve and be refined in stakeholder proceedings in which we are active, and there is currently significant discussion about the future role of demand response in the RPM market.

ISO-NE—ISO-NE’s market for installed capacity with all generators in New England provides fixed capacity payments. 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 ISO-NE continue to develop. We challenged in court the results of ISO-NE’s first forward capacity auction, arguing that our units received inadequate compensation notwithstanding the location of our resources in a constrained area. The D.C. Circuit Court of Appeals recently ruled in our favor and remanded the proceeding to FERC. We and other generators have also filed a complaint at FERC regarding ISO-NE’s capacity market design, alleging that it insufficiently reflects locational capacity values. FERC acted on the complaint, largely accepting the ISO-NE’s capacity market design; however, this ruling is being appealed.

NYISO—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.

LCAPP—In 2011, the State of New Jersey concluded that new natural-gas fired generation was needed and enacted the Long-Term Capacity Agreement Pilot Program Act (LCAPP Act) to subsidize 2,000 MW of new generation. The LCAPP Act provided that subsidies would be offered through long-term standard offer capacity agreements (SOCAs) between selected generators and the New Jersey Electric Distribution Companies (EDCs). The SOCA requires that the generator bid in and clear in the PJM RPM base residual auction in each year of the SOCA term in order to receive the subsidized payment. The SOCA requires each New Jersey EDC to provide the generators with guaranteed capacity payments funded by ratepayers, calculated as the difference between the RPM clearing price for each year of the term and the guaranteed price for each generator as set forth in its respective SOCA. The EDCs, including PSE&G, were directed to enter into fifteen-year SOCAs with three generators selected by the BPU: CPV Shore, LLC (CPV), a subsidiary of Competitive Power Ventures, Inc., Hess Newark, LLC (Hess), a subsidiary of Hess Corporation, and New Jersey Power Development LLC, a subsidiary of NRG Energy, Inc. Each of the New Jersey EDCs entered into the SOCAs as directed by the State, but did so under protest reserving their rights.

The NRG subsidiary filed a petition at the BPU claiming that there has been a material modification in PJM’s RPM that will adversely affect its performance under the SOCA and asked the BPU for relief through modifications to its SOCA. In January 2012, PSE&G received a similar notice of dispute from another of the three selected generators. In February 2012, the BPU announced that it would consider the NRG dispute in a proceeding, which will be presided over by the BPU’s president. The BPU indicated that it would encourage the CPV and Hess subsidiaries to also participate in the proceeding.

In 2011, the BPU also initiated a second proceeding, not authorized by the LCAPP Act, to consider whether there is a need for additional generation capacity in the state and whether there are rules or practices that inhibit the development of that generation in the competitive market. The BPU Staff issued written recommendations on these issues in December 2011 and recommended several options for the BPU to consider in the event that sufficient levels of new generation do not clear in the 2012 and 2013 RPM auctions. At this time, the BPU has not acted on the staff recommendations.

19

Legal challenges to the BPU’s implementation of the LCAPP Act, as well as to the constitutionality of the LCAPP Act were filed and are pending.

Maryland is also considering similar subsidies to above-market new generation. In September 2011, the Maryland Public Utility Commission (PUC) issued an order requiring its EDCs to issue a Request for Proposals (RFP) to procure up to 1,500 MW of new natural gas-fired generation located in the Southwest MAAC electrical region. The RFP would require up to a 20-year contract, with ratepayers paying the generator a fixed capacity amount and would require the generator to bid into and clear the RPM auctions (similar to the LCAPP SOCA). Developments in Maryland may influence developments in New Jersey regarding the construction of subsidized generation and impact energy and capacity prices in PJM.

The impacts of the subsidized above-market contracts on RPM auction prices were mitigated, but not eliminated, when FERC ordered certain changes to the PJM Tariff, including a Minimum Offer Price Ruling (MOPR) that would restrict new generation from bidding in RPM at less than an established minimum level established by Tariff, or a cost-based bid to the extent that the generator can demonstrate that its costs are lower than the MOPR. The BPU, the Maryland PUC and other parties have challenged the FERC’s MOPR order, and those challenges are pending.

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 certain large scale transmission investments. For additional information on our transmission rates and the annual true-ups, see Item 7. MD&A – Overview of 2011 and Future Outlook.

• Transmission Policy Developments—In 2010, FERC initiated a Notice of Proposed Rulemaking (NOPR) proceeding to evaluate whether reforms were necessary to current transmission planning and cost allocation rules to stimulate additional transmission development. The rulemaking also addressed the issue of whether the “right of first refusal” (ROFR) contained in FERC-approved tariffs and contracts, under which incumbent transmission companies have a ROFR to build transmission located within their respective service territories, should be eliminated. On July 21, 2011, FERC issued a Final Rule (Order 1000) in this proceeding. The Final Rule, among other things (i) directs regional planners, such as PJM, to modify their planning processes to “consider transmission needs driven by public policy requirements established by state or federal laws or regulations” (ii) directs regional planners to remove the ROFR from its tariffs and agreements, subject to exceptions for certain types of projects and subject to a back-stop mechanism that may permit incumbent transmission owners to step in and build transmission if third party developers’ projects are delayed (iii) requires regional planners to develop regional cost allocation methodologies consistent with certain articulated principles, including that costs be “roughly commensurate” with project benefits and (iv) requires regional planners in neighboring regions to have a common interregional cost allocation method for new interregional facilities. We and many other parties to the proceeding have sought rehearing of the Final Rule, which remains pending. Ultimate judicial appeals are likely. PJM is about to commence a stakeholder process that will develop implementing details regarding Order 1000. An expected outcome of this Final Rule is the construction of more transmission through “public policy” planning and the opening up of transmission construction and ownership to third-party developers and to incumbents seeking to build outside of their service territories. We cannot predict the final outcome or impact on us; however, specific implementation of the Order 1000 in the various regions, including within our service territory, may expose us to competition for construction of transmission, additional regulatory considerations and potential delay with respect to future transmission projects.

We are a party to a proceeding that is pending in US District Court in New Jersey challenging the constitutionality of LCAPP and a proceeding pending in the Appellate Division in New Jersey challenging the BPU’s implementation of LCAPP.

20

• Transmission Expansion—In June 2007, PJM identified the need for the construction of the Susquehanna-Roseland line, a new 500 kV transmission line intended to maintain the reliability of the electrical grid serving New Jersey customers. PJM assigned construction responsibility for the new line to us and PPL Corporation (PPL) for the New Jersey and Pennsylvania portions of the project, respectively. The estimated cost of our portion of this construction project is $750 million, and PJM had originally directed that the line be placed into service by June 2012. 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 significant local opposition. Although the BPU has memorialized its approval in a written order and the New Jersey Department of Environmental Protection has approved construction of the portion of the project crossing the Highlands region, we have not received certain environmental approvals that are required for each of the Eastern and Western segments of the Susquehanna-Roseland line, including from the National Park Service (NPS). In November 2011, the NPS issued a draft Environmental Impact Statement (EIS) recommending a “no action” alternative that would require re-routing of the project around the affected federal park areas. We submitted comments on this draft EIS and are continuing to work with the NPS on mitigation as the agency prepares its final EIS. The NPS has also announced publicly that it intends to decide on its final preferred route in March 2012. Currently, the expected in-service date for the Eastern segment of the project is June 2014 and for the Western segment is June 2015, although further delays are possible. Delays in the construction schedule could impact the timing of expected transmission revenues.

On February 3, 2011, certain environmental groups that were parties to the BPU proceeding approving the Susquehanna-Roseland line and that appealed the BPU’s approval order filed a motion to reopen the agency record on the grounds of “changed circumstances,” including the delay in construction of the project and PJM’s issuance of a new load forecast report. On January 12, 2012, the Appellate Division denied the motion. The underlying substantive appeal of the BPU approval order remains pending.

In October 2010, PJM approved the North East Grid project, a 230 kV project running from Roseland to Hudson. This project has an expected in-service date of June 2015 with an estimated cost of construction of $895 million. The North East Grid project was approved in place of a previously approved 500 kV Branchburg-Roseland-Hudson (B-R-H) project. On October 31, 2011, we filed a petition with FERC seeking Construction Work in Progress (CWIP) in rate base, 100% abandonment cost recovery and a 100 basis point ROE adder with respect to the project. Notwithstanding protests filed by the BPU and a group of state ratepayer advocates, including the New Jersey Division of Rate Counsel (Rate Counsel), FERC granted our request for CWIP in rate base and 100% abandonment cost recovery, along with a 25 basis point ROE adder, on December 31, 2011, effective January 1, 2012.

In its Regional Transmission Expansion Plan, PJM has approved our construction of several other 230 kV transmission projects. In April 2011, we filed a petition with FERC seeking incentive rates for five of these projects (Burlington-Camden project, North Central Reliability project, the Mickleton-Gloucester-Camden project, Middlesex Switch Rack project and Bayonne-Marion project). For each of these projects, we requested inclusion of 100% of CWIP in rate base and recovery of 100% of prudently incurred abandonment costs with an effective date of June 14, 2011. In June 2011, FERC granted the requested incentives for three of the projects (Burlington-Camden, North Central Reliability and Mickleton-Gloucester-Camden) with a total estimated capital investment of $1.0 billion, representing approximately 80% of our request.

In May 2011, we filed a petition with the BPU to site the North Central Reliability project. This project, which will involve upgrading certain circuits and switching stations from 138 kV to 230 kV, is currently estimated to cost $390 million and has an in-service date of June 2014. We expect the BPU to issue a decision in the first quarter of 2012.

21

In February 2011, the United States Court of Appeals for the 9th Circuit issued a decision vacating the U.S. Department of Energy’s (DOE) 2006 Congestion Study and the two national transmission corridor designations resulting from the study, including the Mid-Atlantic Corridor which encompasses all of the State of New Jersey. FERC back-stop siting authority permits an entity building transmission to site the project at FERC under certain circumstances, including a State’s failure to act within one year. However, since this authority only attaches to transmission located within a DOE-designated corridor, FERC back-stop siting authority may not be available to companies building transmission in New Jersey, including us. The DOE is expected to issue a new Congestion Study in 2012.

• PJM Transmission Rate Design—In 2007, FERC addressed the issue of how transmission rates, paid by PJM transmission customers and ultimately paid by retail customers, should be designed in PJM. FERC ruled that the cost of new high voltage (500 kV and above) transmission facilities in PJM would be regionalized and paid for by all transmission customers on a pro-rata basis. Each share is calculated annually based upon a zone’s load ratio share within PJM. For all existing facilities, costs would be allocated using the pre-existing zonal rate design. For new lower voltage transmission facilities, costs would be allocated using a “beneficiary pays” approach. This FERC decision was subsequently upheld on rehearing but was then appealed by other parties to the United States Court of Appeals for the Seventh Circuit.

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 were denied. The case was then remanded to FERC for further proceedings. FERC has not yet issued a decision. The current allocation for new 500 kV and higher centrally-planned projects may remain in place or could be modified by FERC. PJM’s Order 1000 stakeholder proceedings may also establish cost allocation rules regarding costs for transmission facilities in PJM.

Compliance

• Reliability Standards—Congress has required FERC to put in place, through the North American Electric Reliability Council (NERC), national and regional reliability standards to ensure the reliability of the U.S. electric transmission and generation system and to prevent major system blackouts. Many reliability standards have been developed and approved. These standards apply both to reliability of physical assets interconnected to the bulk power system and to the protection of critical cyber assets. Our generation assets were audited in 2011 and our utility assets will be audited in 2012. In addition, many of our operating companies have been subject to spot audits. NERC compliance represents a significant and challenging area of compliance responsibility for us. As new standards are developed and approved, existing standards are revised and registration requirements are modified which could increase our compliance responsibilities.

Commodity Futures Trading Commission (CFTC)

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was passed in an attempt to reduce systemic risk in the financial markets thereby preventing future financial crises and market issues such as those experienced in 2008. As part of this new legislation, the SEC and the CFTC will be implementing new rules to effectuate stricter regulation over swaps and derivatives since many of the issues experienced were caused by derivative trading in connection with mortgage loans. Additionally, the Dodd-Frank Act will require many swaps and other derivative transactions to be standardized and traded on exchanges or other Derivative Clearing Organizations (DCOs).

CFTC has issued NOPRs on many of the key issues, including:

• defining swaps;

• defining swap dealers and major swap participants;

• the end-user exception from clearing requirements;

22

• position limits;

• margin requirements;

• capital requirements; and

• reporting requirements.

Exchanges and DCOs typically require full collateralization of all transactions taking place on the exchange or DCO. Although the Dodd-Frank Act specifically recognizes a commercial end user exemption from posting additional collateral in the bilateral Over the Counter swap and derivative markets, we cannot assess the exact scope of the new rules until the SEC and CFTC issue them. A broad or less than clear definition of swap dealer could result in Power being classified as a dealer, which would impose significant reporting and record-keeping requirements as well as clearing/collateral requirements on Power unless we fall under the commercial end-user exemption recognized in the Dodd-Frank Act. We believe that any regulatory change that deviates from the original intent would need to be addressed by additional legislation.

The CFTC may issue a Final Rule on the definition of a swap dealer in the next month, which is expected to include a de minimis exemption. The CFTC is scheduled to issue a Final Rule on the definition of a swap in mid-2012.

We will carefully monitor these new rules as they are developed to analyze the potential impact on our swap and derivatives transactions, including any potential increase in our collateral requirements.

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. We received 20-year license extensions from the NRC for our Salem and Hope Creek facilities in June and July 2011, respectively. The current operating licenses of our nuclear facilities expire in the years shown below:

Unit	Year
Salem Unit 1		2036
Salem Unit 2		2040
Hope Creek		2046
Peach Bottom Unit 2		2033
Peach Bottom Unit 3		2034

In 2010, we also filed an application for an Early Site Permit for a new nuclear generating station to be located at the current site of the Salem and Hope Creek generating stations. The NRC acceptance review is complete and agency evaluation is underway. There were no petitions filed for permission to intervene. The current NRC schedule would likely result in issuance of the Early Site Permit in 2014. The Early Site Permit qualifies the site as an approved location for a new reactor for a period of 20 years but we are under no obligation to build.

As a result of events at the Fukushima Daiichi nuclear facility in Japan following the earthquake and tsunami in March 2011, the NRC will be performing additional operational and safety reviews of nuclear facilities in the United States. These reviews and the lessons learned from the events in Japan will result in additional regulation for the nuclear industry and could impact future operations and capital requirements for our facilities. We believe that our nuclear plants meet the stringent applicable design and safety specifications of the NRC.

23

In July 2011, the NRC task force submitted a report on the first 90 days of its nuclear power plant review. The report contained various recommendations to ensure plant protection, enhance accident mitigation, strengthen emergency preparedness and improve NRC program efficiency. These recommendations include proposed requirements for upgraded seismic and flooding protection, strengthening plants’ ability to deal with prolonged loss of power and development of emergency plans for events involving multiple reactors. In October 2011, the NRC staff issued a document which provides for a prioritization of the task force recommendations. In December 2011, the NRC approved the staff’s prioritization and implementation recommendations subject to a number of conditions. Among other things, the NRC advised the staff to give the highest priority to those activities that can achieve the greatest safety benefit and/or have the broadest applicability (Tier 1) and to include filtration of boiling water reactor (BWR) primary containment vents, and encouraged the staff to create requirements based on a performance-based system which allows for flexible approaches and the ability to address a diverse range of site-specific circumstances and conditions and strive to implement the requirements by 2016. The NRC and staff’s next steps are to obtain stakeholder input and issue specific requirements associated with the prioritized recommendations. The NRC is expected to provide detailed requirements for the highest priority Tier 1 safety recommendations in the first quarter of 2012 with the requirements for the remaining Tier 1 recommendations following in 2014 and 2016. The NRC is proposing to issue letters and orders to licensees and create new regulations over a six-to-52 month period to address the task force recommendations.

Separately, a petition was filed with the NRC in April 2011 seeking suspension of the operating licenses of all General Electric BWRs utilizing the Mark I containment design in the United States, including our Hope Creek and Peach Bottom units, pending completion of the NRC review. Fukushima Daiichi Units 1-4 are BWRs equipped with Mark I containments. The petition names 23 of the total 104 active commercial nuclear reactors in the United States. While we do not believe the petition will be successful, we are unable to predict the outcome of any action that the NRC may take in connection with its operational and safety reviews or any other regulatory or industry responses to the events in Japan.

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 various other states’ regulations due to our operations in those states.

Rates

Retail Gas Transportation Rates—In July 2010, as part of our gas base rate proceeding, the BPU ordered a supplemental and expedited review of certain issues related to the gas transportation rate that PSE&G charges to Power. Also in July, a complaint was filed by an independent power generator against Power at FERC related to the gas transportation rate.

On December 16, 2010, the BPU approved a settlement that resolved all remaining issues in our base rate case.

The BPU also commenced a generic proceeding to evaluate the process and standards for all utilities to provide discounts to their gas delivery customers, culminating in the issuance of an order in 2011. We, along with the other New Jersey gas utilities, filed to implement tariffs with the BPU setting forth their individual processes by which customers can obtain discounts. Our tariff remains pending at the BPU although we expect the BPU to issue an order in the first quarter of 2012.

24

Rate Adjustment Clauses—In addition to base rates, we recover certain costs from customers pursuant to mechanisms, known as adjustment clauses. These clauses permit, at set intervals, the flow-through of costs to customers related to specific programs, outside the context of base rate case proceedings. Recovery of these costs is subject to BPU approval. Costs associated with these clauses are deferred when incurred and amortized to expense when recovered in revenues. Delays in the pass-through of costs under these clauses can result in significant changes in cash flow. Our Societal Benefits Charge (SBC) and Non-utility Generation Charges (NGC) clauses are detailed in the following table:

Rate Clause	2011 Revenue		(Over) Under Recovered Balance as of December 31, 2011
	Millions
Energy Efficiency and Renewable Energy	$	200	$	8
Universal Service Fund (USF)		164		21
Social Programs		70		58
Remediation Adjustment Clause (RAC)		50		92
Total SBC		484		179
NGC		256		(5	)
Gas Weather Normalization		0		2
RGGI Recovery Charge (RRC)		37		144
Total	$	777	$	320

• 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, the RAC, which covers the costs to clean up manufactured gas plants and the 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.

• Gas Weather Normalization Clause—The purpose of this clause is to remove the gas earnings volatility caused by variations in the weather over the winter period. To the extent that the cumulative winter period is colder than normal, we refund to customers the excess margin collected as a result of the weather. To the extent that the cumulative winter period is warmer than normal, we have the opportunity to collect from customers the resulting margin shortfall.

• RRC—On October 1, 2010, we filed a petition for an increase in the RRC, seeking a revenue increase of approximately $18.7 million in electric revenue and $1.4 million in gas revenue on an annual basis. The filing sought to reset the RRC rate components for five programs including: Carbon Abatement, the Energy Efficiency Economic Stimulus Program, the Demand Response Program, Solar 4 All, and the Solar Loan II Program. These initiatives are intended to help New Jersey meet its New Jersey Energy Master Plan (EMP) goal of reducing energy consumption by 20% by 2020 and to help improve New Jersey’s economy through the creation of new jobs through the promotion of energy efficiency. In implementing these initiatives, we are allowed to recover the costs of these programs on an annual basis through a true-up mechanism.

A Decision and Order was issued by the BPU in December 2011 finalizing the 2009 Carbon Abatement Stipulated provisional rates of approximately $3.9 million on an annual basis. This Order also approved a stipulation regarding the October 2010 RRC filing which resulted in a net annual revenue increase of $18.7 million in the electric RRC rates while maintaining the gas RRC rates at the current level.

25

Recent Rate Adjustments

USF/Lifeline—The USF is an energy assistance program mandated by the BPU 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. On June 30, 2011, the State’s electric and gas utilities filed to reset the statewide rates for the USF and Lifeline programs. The filed rates were subsequently updated and approved in a written order effective November 1, 2011. The approved USF rates are set to recover $242 million on a statewide basis. Of this amount, the electric rates are set to recover $185 million and the gas rates $57 million. The rates for the Lifeline program are set to recover $49 million and $22 million for electric and gas, respectively. We earn no margin on collection of the USF and Lifeline programs, resulting in no impact on Net Income.

SBC/NGC—In August 2010, we made our 2010 annual SBC/NGC filing requesting an $85.4 million electric increase and a $17.2 million gas decrease. On February 11, 2011, we filed a stipulation of settlement with the Administrative Law Judge (ALJ). The stipulation was executed by all parties and allows us to increase electric SBC/NGC rates by $85.4 million and decrease gas SBC rates by $17.2 million, both on an annual basis. The stipulation was approved by the ALJ and adopted by the BPU by written order dated March 9, 2011, with rates effective April 1, 2011.

RAC—In November 2010, we filed a RAC 18 petition with the BPU requesting an increase in electric and gas RAC rates of approximately $3 million and $1 million, respectively. In May 2011, a settlement was signed by the parties and filed with the ALJ for the requested amounts. Also in May 2011, the ALJ issued an Initial Decision adopting the executed stipulation of the parties to the proceeding. The ALJ’s Initial Decision was approved by the BPU in June 2011. New rates were effective July 1, 2011.

In November 2011, we filed a RAC 19 petition with the BPU requesting a decrease in electric and gas RAC revenues on an annual basis of $8.9 million and $10.1 million, respectively. We are seeking an Order by April 2012 and are currently in the discovery phase of the proceeding.

Connecticut Contract for Differences—On December 1, 2011, PSEG New Haven LLC filed its first annual retail generation rate contested case seeking establishment of its first year (2012) revenue requirements of $16.7 million. As part of this process, an audit was performed by the Connecticut Public Utilities Regulatory Authority and the Office of Consumer Counsel in January 2012. Evidentiary hearings are scheduled for March 2012 with an expected Final Decision in May 2012.

Energy Supply

BGS—New Jersey’s EDCs provide two types of BGS, the default electric supply service for customers who do not have a third party supplier. The first type, which represents about 82% of PSE&G’s load requirements, provides default supply service for smaller industrial and commercial customers and residential customers at seasonally-adjusted fixed prices for a three-year term (BGS-Fixed Price). These rates change annually on June 1 and are based on the average price obtained at auctions in the current year and two prior years. The second type provides default supply for larger customers, with energy priced at hourly PJM real-time market prices for a contract term of 12 months (BGS-CIEP).

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.

26

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:

	2009		2010		2011		2012
36 Month Terms Ending		May 2012		May 2013		May 2014		May 2015	(A)
Eligible Load (MW)		2,900		2,800		2,800		2,900
$ per kWh		0.10372		0.09577		0.09430		0.08388

(A) Prices set in the February 2012 BGS Auction will be effective on June 1, 2012 when the 2009 BGS agreements expire.

The BPU once again approved the auction process for 2012 with no significant changes to the process. However, as part of the BPU Order, the BPU Staff was directed to initiate a proceeding to review aspects of the BGS procurement process at the conclusion of the 2012 procurement, with an expected resolution by the end of May 2012.

For additional information, see Item 8. Financial Statements and Supplementary Data—Note 6. Regulatory Assets and Liabilities and Note 13. Commitments and Contingent Liabilities.

BGSS—BGSS is the mechanism approved by the BPU designed to recover all gas costs related to the supply for residential customers. BGSS filings are made annually by June 1 of each year, with an effective date of October 1. PSE&G’s revenues are matched with its costs using deferral accounting, with the goal of achieving a zero cumulative balance by September 30 of each year. In addition, we have the ability to put in place two self-implementing BGSS increases on December 1 and February 1 of up to 5% and also may reduce the BGSS rate at any time.

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.

On June 1, 2011, PSE&G made its annual BGSS filing with the BPU. The filing requested a decrease in annual BGSS revenue of $16.1 million, excluding sales and use tax, to be effective October 1, 2011. This represented a reduction of approximately 1.1% for a typical residential gas heating customer. On September 22, 2011, the BPU approved the Stipulation of the parties, which implemented the filed BGSS rate, on a provisional basis, effective October 1, 2011.

On November 21, 2011, PSE&G provided notice to the BPU of a decrease in its BGSS-Residential Gas (RSG) Commodity Charge to be effective December 1, 2011. The self-implementing rate decrease was designed to bring a projected over collected balance of $56 million to zero by the end of September 2012. The annual impact of the decrease for the average residential heating customer is approximately 4.6%. On January 18, 2012, PSE&G provided notice to the BPU of another self-implementing one-month bill credit of 15 cents per therm (including sales and use tax) for its BGSS-Residential Gas customers to be effective February 1 through February 29, 2012.

PSE&G had executed a Stipulation between the parties which would make the current provisional BGSS rate final and resolve all issues of the proceeding. The Stipulation was sent to the Office of Administrative Law and upon being signed, will be sent to the BPU.

Energy Policy

New Jersey EMP—New Jersey law requires that an EMP be developed every three years, the purpose of which is to ensure safe, secure and reasonably-priced energy supply, foster economic growth and development and protect the environment. The most recent EMP was finalized in December 2011.

27

The 2011 EMP places an emphasis on expanding in-state electricity resources and reducing energy costs. The plan also recognizes the impact of climate change and accepts the previously set goal of a 22.5% target for the renewable portfolio standard (RPS) in 2021. It also references a goal that 70% of New Jersey’s energy supplies should be from clean energy sources by 2050. To meet this goal, the plan redefines clean energy to include nuclear, natural gas and hydro power along with defined renewable sources and proposes a number of changes aimed at reducing the cost of achieving the 22.5% goal.

Specific program initiatives in the EMP include:

• construction of new combined cycle natural gas plants through the implementation of LCAPP, with the continued State challenge to FERC and PJM policies on market pricing rules in the capacity market;

• support for construction of new nuclear generation;

• changes to the solar program to reduce cost, expand opportunities, expand transparency and ensure economic and environmental benefits;

• expanded natural gas use to meet energy needs;

• development of decentralized combined heat and power;

• redesign of the delivery of state energy efficiency programs, and

• continued support for implementation of off-shore wind, without setting a specific capacity goal.

Solar Initiatives—In order to spur investment in solar power in New Jersey and meet renewable energy goals, we have undertaken two major initiatives at PSE&G.

• Solar Loans: The first program helps finance the installation of 81 MW of solar systems throughout our electric service area by providing loans to customers. The borrowers can repay the loans over a period of either 10 years (for residential customer loans) or 15 years (for non-residential customers), by providing us with solar renewable energy certificates (SRECs) or cash. The value of the SRECs towards the repayment of the loan is guaranteed to be not less than a floor price. SRECs received by us in repayment of the loan are sold through a periodic auction. Proceeds will be used to offset program costs.

The total investment of both phases of the Solar Loan Program is expected to be between $200 million and $250 million once the program is fully subscribed, projects are built and loans are closed. As of December 31, 2011, we have provided a total of $127 million in loans for 518 projects representing 38 MW.

• Solar 4 All: The second solar initiative is the Solar 4 All Program under which we are investing approximately $451 million to develop 80 MW of utility-owned solar photovoltaic (PV) systems over four years. The program consists of centralized solar systems 500kW or greater installed on PSE&G-owned property and third-party sites in our electric service territory (40 MW) and solar panels installed on distribution system poles (40 MW). We sell the energy and capacity from the systems in the PJM wholesale electricity market. In addition we sell any SRECs received from the projects through the same auction used in the loan program. Proceeds from these sales are used to offset program costs.

As of December 31, 2011, 26 MW of solar panels had been installed on approximately 120,000 distribution poles with an investment of approximately $185 million. In addition during 2011, 33 MW of centralized solar systems representing 19 projects were placed in service with an investment of approximately $160 million. An additional 6 MW is expected to be placed into service in the first quarter of 2012 and additional projects are in various stages of negotiation and development.

28

On January 18, 2012, the BPU issued an order indicating that it will conduct a proceeding to address the proposed placement of solar panels on the poles. A negative determination by the BPU could impact our ability to complete the Solar 4 All pole mounted installations.

Solar Generic Proceeding—The BPU is conducting a generic proceeding to examine whether existing utility rate-based solar programs, including ours, should be expanded, modified or discontinued once the current programs expire or the authorized level of solar installations has been achieved. Although the current programs are not expected to be affected, the proceeding will examine the costs and benefits of all of these programs. The proceeding is expected to conclude in the first quarter of 2012 with BPU Staff recommendations to the BPU, which may then be reflected in an order. We have advocated for expansion of our solar investment programs as part of this proceeding.

Capital Infrastructure Programs (CIP I and CIP II)—We have received approval from the BPU for programs that provide for accelerated investment in utility infrastructure. The goal of these accelerated capital investments is to improve the State’s economy through the creation of new jobs. The original CIP I program, approved in 2009, included 38 qualifying projects totaling $694 million of investment. In July 2011, the BPU approved CIP II which included an additional 30 qualifying projects totaling approximately $78 million and $195 million in expenditures for gas and electric, respectively. The CIP II program investments are to be completed and placed in service by December 2012.

In conjunction with the approval of CIP II, we agreed to additional base spending of approximately $96 million, excluding new business for the period 2011 through 2013.

The CIP programs require periodic filings to implement the rates to recover investment costs at which times the BPU reviews the prudency of the implementation of the programs. CIP I was completed in June 2011 and in September 2011, we filed a final CIP I petition for $60 million in revenue requirements to roll the remaining projects into base rates. An Order is expected in 2012. In November 2011, we filed our first annual recovery petition for CIP II for the period ending December 31, 2011.

LCAPP—See Federal Regulation—Capacity Market Issues above.

Storm Damage Recovery—On August 26, 2011, we filed a petition with the BPU requesting permission to defer incremental storm related costs and the opportunity to seek recovery in our next base rate proceeding. This proceeding remains pending. We have deferred approximately $29 million in incremental Operation and Maintenance (O&M) storm costs associated with Hurricane Irene. In addition, we deferred approximately $31 million in incremental O&M related to a severe October 2011 snow storm.

BPU Audits

Management/Affiliate Audit—The BPU engaged a contractor to perform a comprehensive audit with respect to the effectiveness of management and transactions among affiliates, which began in October 2009. In 2011, we received a full draft audit report, which included recommendations for changes in practices at PSE&G and its affiliates. We have provided comments back to the auditors on all chapters of the report. The BPU may enforce the recommendations in whole or in part by Order.

BPU Investigations

RRC/CIP—In January 2012, the Rate Counsel filed a letter with the BPU requesting the BPU to take prompt action to investigate certain allegations of wrong doing in PSE&G’s Solar 4 All, Energy Efficiency Economic Stimulus, and CIP I programs that were raised by three ex-employees in a lawsuit filed on December 20, 2011. At a public meeting on January 18, 2012, the BPU indicated that it would seek to obtain certain pertinent information from PSE&G prior to determining whether an investigation was warranted.

29

ENVIRONMENTAL MATTERS

Changing environmental laws and regulations significantly impact the manner in which our operations are currently conducted and impose costs on us to reduce the health and environmental impacts of our operations. 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 known 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, but may be material.

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

• air pollution control,

• climate change,

• water pollution control,

• hazardous substance liability, and

• fuel and waste disposal.

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 Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities.

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 our estimates of capital expenditures.

• New Jersey Nitrogen Oxide (NO_x) Regulation: High Electric Demand Day—In April 2009, the New Jersey Department of Environmental Protection (NJDEP) finalized revisions to NO_x emission control regulations that impose new NO_x emission reduction requirements and limits for New Jersey fossil fuel fired electric generation units. The rule will have an impact on our generation fleet, as it imposes NO_x emissions limits that require capital investment for controls or the retirement of up to 102 combustion turbines (approximately 2,000 MW) and four older New Jersey steam electric generation units (approximately 400 MW) by May 2015. We are currently evaluating our compliance options.

• Connecticut NO_x Regulation—Under current Connecticut regulations, Power’s Bridgeport and New Haven facilities have been utilizing Discrete Emission Reduction Credits (DERCs) to comply with certain NOx emission limitations that were incorporated into the facilities’ operating permits. In 2010, Power negotiated new agreements with the State of Connecticut extending the continued use of DERCs for certain emission units and equipment until May 31, 2014.

• Hazardous Air Pollutants Regulation—In accordance with a court ruling, the United States Environmental Protection Agency (EPA) proposed a Maximum Achievable Control Technology (MACT) regulation in March 2011 which was finalized on December 21, 2011. This regulation includes requirements related to the reduction of mercury and other hazardous air pollutants from emissions pursuant to the CAA. The impact to our fossil generation fleet is currently being determined but we believe the back-end technology environmental controls recently installed at our Hudson and Mercer coal facilities should meet the rule’s requirements. Some additional controls could be necessary at our Connecticut facility, pending engineering evaluation. The impact to our jointly-owned coal fired generating facilities in Pennsylvania is under evaluation. In December 2011, a decision was reached to upgrade the previously planned two flue gas desulfurization scrubbers and install Selective Catalytic

30

Reduction (SCR) systems at our jointly-owned coal fired generating facility at Conemaugh in Pennsylvania. This installation is expected to be completed in the fourth quarter of 2014. PSEG’s share of this investment is approximately $147 million.

• Cross-State Air Pollution Rule (CSAPR)—On July 6, 2011, the EPA issued the final CSAPR. CSAPR limits power plant emissions of Sulfur Dioxide (SO₂) and annual and ozone season NO_x in 28 states that contribute to the ability of downwind states to attain and/or maintain current particulate matter and ozone National Ambient Air Quality Standards (NAAQS). Technical revisions to the CSAPR were finalized on February 7, 2012. The EPA increased New Jersey’s allocation of annual NOx and ozone season NOx allowances beyond what was proposed. The EPA also finalized the increase in New Jersey’s allocation of SO₂ allowances from the October proposal. The additional increases in NOx allocations are favorable to PSEG, since both PSEG and New Jersey as a whole are projected to be very tight on NOx allowances (both ozone season and annual).

On December 30, 2011, the United States Court of Appeals for the D.C. circuit issued a ruling to stay CSAPR pending judicial review. Until a final decision is reached, the court has ordered that the existing Clean Air Interstate Rule (CAIR) requirements continue temporarily. We have intervened in the CSAPR litigation along with other generating companies in support of the rule.

The continuation of CAIR affects our generating stations in Connecticut, New Jersey and New York. The purpose of CAIR is to improve Ozone and Fine Particulate (PM2.5) air quality within states that have not demonstrated achievement of the NAAQS. CAIR was implemented through a cap-and-trade program and, to date, the impact has not been material to us as the allowances allocated to our stations were sufficient. If 2012 operations are similar to those in the past three years, it is expected that the impact to operations from the temporary implementation of CAIR in 2012 will not be significant.

We continue to evaluate the impact of CSAPR on us due to many of the uncertainties that still exist regarding implementation. As we have made major capital investments over the past several years to lower the SO₂ and NO_x emissions of our fossil plants in the states affected by CSAPR (New Jersey, New York and Pennsylvania), we do not currently foresee the need to make significant additional expenditures to our generation fleet to comply with CSAPR. As such, we currently anticipate that this rule will not have a material adverse impact to our capital investment program or units’ operations.

Climate Change

• Regional Greenhouse Gas Initiative (RGGI)—In response to concerns over global climate change, some states have developed initiatives to stimulate national climate legislation through CO₂ emission reductions in the electric power industry. Ten northeastern states, including New Jersey, New York and Connecticut, originally established RGGI to cap and reduce CO₂ emissions in the region. In general, these states adopted state-specific rules to enable the RGGI regulatory mandate in each state.

Applicable 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, and 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 compliance period.

Pricing for the allowances vary based on future allowance market conditions and electric generation market conditions. For the first three-year compliance period, we have acquired sufficient allowances to compensate for CO₂ emissions from affected sources.

In May 2011, the Governor of New Jersey announced his intent to withdraw New Jersey from RGGI beginning in 2012. Therefore, our New Jersey facilities are no longer obligated to acquire CO₂ emission allowances, but our generation facilities in New York and Connecticut remain subject to RGGI.

31

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.

• CO₂ Regulation Under the CAA—In April 2010, the EPA and the National Highway Transportation Safety Board (NHTSB) jointly issued a final rule to regulate GHG emissions from certain motor vehicles (Motor Vehicle Rule). Under the CAA, the adoption of the Motor Vehicle Rule would have automatically subjected many emission sources, including ours, to CAA permitting for new facilities and major facility modifications that increase the emission of GHGs, including CO₂. However, guidance issued by the EPA in March 2010 interpreted the CAA to require permitting for GHGs at other facilities, such as ours, only when the Motor Vehicle Rule was scheduled to take effect in January 2011. In May 2010, the EPA finalized a “Tailoring Rule” that would phase in, beginning in 2011, the application of this permitting requirement to facilities such as ours. The significance of the permitting requirement is that, in cases where a new source is constructed or an existing source undergoes a major modification, the owner of the facility would need to evaluate and perhaps install best available control technology (BACT) for GHG emissions.

In November 2010, the EPA published guidance to state and local permitting authorities to undertake BACT determinations for new and modified emission sources. The guidance does not define the specific technology or technologies that should be considered BACT. The guidance does emphasize the use of energy efficiency, and specifically states that the technology of storing CO₂ under the earth, also known as carbon capture and storage, is not yet mature enough to be considered a viable alternative at this stage. The practical effect of this guidance document is unclear in the context of applying the Tailoring Rule to specific facilities. In December 2010, the EPA also announced a schedule for proposed New Source Performance Standards (NSPS) for GHGs from new and existing power plants and refineries. The EPA has missed the date for release of a draft rule. We expect the EPA to put forth draft rules for new sources early in 2012. Since a proposed rule has not been published, the outcome of the rulemaking and its significance to us cannot be predicted.

• Climate Related Legislation—The federal government may consider legislative proposals to define a national energy policy and address climate change. Proposals under consideration include, but are not limited to, provisions to establish a national clean energy portfolio standard and to establish an energy efficiency resource standard. Provisions of any new proposal may present material risks and opportunities to our businesses. The final design of any legislation will determine the impact on us, which we are not now able to reasonably estimate.

• CO₂ Litigation—In addition to legislative and regulatory initiatives, the outcome of certain legal proceedings regarding alleged impacts of global climate change not involving us could be material to the future liability of energy companies. 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 to us could be material.

32

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 and Connecticut, 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.

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 (BTA) 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 through 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. In late 2010, the EPA entered into a settlement agreement with environmental groups that established a schedule to develop a new 316(b) rule.

In April 2011, the EPA published a new proposed rule which did not establish any particular technology as the BTA (e.g. closed-cycle cooling). Instead, the proposed rule established marine life mortality standards for existing cooling water intake structures with a design flow of more than 2 million gallons per day. We reviewed the proposed rule, assessed the potential impact on our generating facilities and used this information to develop our comments to the EPA which were filed in August 2011. Although the EPA has recently stated that a revision of the proposed rule to include an alternative framework for compliance is currently being considered, if the rule were to be adopted as proposed, the impact on us would be material since the majority of our electric generating stations would be affected. We are unable to predict the outcome of this proposed rulemaking, the final form that the proposed regulations may take and the effect, if any, that they may have on our future capital requirements, financial condition or results of operations, although such impacts could be material. See Note 13. Commitments and Contingent Liabilities for additional information.

Hazardous Substance Liability

The production and delivery of electricity, the 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. Our historic operations and the operations of hundreds of other companies along the Passaic and Hackensack Rivers are alleged by federal and state agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities.

• Site Remediation—The Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and the New Jersey Spill Compensation and Control Act (Spill Act) require the remediation of discharged hazardous substances and authorize the EPA, the NJDEP and private parties to commence lawsuits to compel clean-ups or reimbursement for such remediation. The clean-ups can be more complicated and costly when the hazardous substances are in a body of water.

• Natural Resource Damages—CERCLA and the Spill Act authorize the assessment of damages against persons who have discharged a hazardous substance, causing an injury to natural resources. Pursuant to

33

the Spill Act, the NJDEP requires persons conducting remediation to characterize injuries to natural resources and to address those injuries through restoration or damages. The NJDEP adopted regulations concerning site investigation and remediation that require an ecological evaluation of potential damages to natural resources in connection with an environmental investigation of contaminated sites. The NJDEP also issued guidance to assist parties in calculating their natural resource damage liability for settlement purposes, but has stated that those calculations are applicable only for those parties that volunteer to settle a claim for natural resource damages before a claim is asserted by the NJDEP. We are currently unable to assess the magnitude of the potential financial impact of this regulatory change, although such impacts could be material.

Fuel and Waste Disposal

• Nuclear Fuel Disposal—The federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate disposal of spent nuclear fuel. To pay for this service, nuclear plant owners are required to contribute to a Nuclear Waste Fund. Under the contracts, the DOE was required to begin taking possession of the spent nuclear fuel by no later than 1998. The Nuclear Waste Policy Act of 1982 requires the DOE to perform an annual review of the Nuclear Waste Fee to determine whether that fee is set appropriately to fund the national nuclear waste disposal program. In October 2009, the DOE stated that the current fee of 1/10 cent per kWh was adequate to recover program costs. In March 2011, we joined the Nuclear Energy Institute (NEI) and fifteen other nuclear plant operators in a lawsuit seeking suspension of the Nuclear Waste Fee. The suit was filed in the U.S. Court of Appeals for the D.C Circuit.

The Nuclear Waste Fee litigation is not expected to have any effect on our September 2009 settlement agreement with DOE applicable to Salem and Hope Creek under which we will be reimbursed for past and future reasonable and allowable costs resulting from the DOE delay in accepting spent nuclear fuel for permanent disposition. A similar settlement agreement was reached related to Peach Bottom in 2004.

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. We have on-site storage facilities that are expected to satisfy the storage needs of Salem 1, Salem 2, Hope Creek, Peach Bottom 2 and Peach Bottom 3 through the end of their operating licenses.

• Low Level Radioactive Waste—As a by-product of their operations, nuclear generation units produce low level radioactive waste. Such waste includes paper, plastics, protective clothing, water purification materials and other materials. These waste materials are accumulated on site and disposed of at licensed permanent disposal facilities. New Jersey, Connecticut and South Carolina have formed the Atlantic Compact, which gives New Jersey nuclear generators continued access to the Barnwell waste disposal facility which is owned by South Carolina. We believe that the Atlantic Compact will provide for adequate low level radioactive waste disposal for Salem and Hope Creek through the end of their current licenses including full decommissioning, although no assurances can be given. Low Level Radioactive Waste is periodically being shipped to the Barnwell site from Salem and Hope Creek. Additionally, there are on-site storage facilities for Salem, Hope Creek and Peach Bottom, which we believe have the capacity for at least five years of temporary storage for each facility.

• Coal Combustion Residuals (CCRs)—In June 2010, the EPA formally published a proposed rule offering three main options for the management of CCRs under the Resource Conservation and Recovery Act. One of these options regulates CCRs as a hazardous waste and the other two options are variations of a non-hazardous designation. All options communicate the EPA’s intent of ceasing wet ash transfer and instituting engineering controls on ash ponds and landfills to limit impact on human health and the environment. The outcome of the EPA rulemaking cannot be predicted. The EPA has not established a date for release of a final rule.

34

SEGMENT INFORMATION

Financial information with respect to our business segments is set forth in Note 22. Financial Information by Business Segment.

ITEM 1A.    RISK FACTORS

The following factors should be considered when reviewing our business. These factors could have a material adverse impact on our financial position, results of operations or net cash flows and could cause results to differ materially from those expressed elsewhere in this document.

The factors discussed in Item 7. MD&A may also have a material adverse effect on our results of operations and cash flows and affect the market prices for our publicly-traded securities. While we believe that we have identified and discussed the key risk factors affecting our business, there may be additional risks and uncertainties that are not presently known or that are not currently believed to be significant.

We are subject to comprehensive and evolving regulation by federal, state and local regulatory agencies that affects, or may affect, our businesses.

We are subject to regulation by federal, state and local authorities. Changes in regulation can cause significant delays in or materially affect business planning and transactions and can materially increase our costs. Regulation affects almost every aspect of our businesses, such as our ability to:

• Obtain fair and timely rate relief—Our utility’s base rates for electric and gas distribution are subject to regulation by the BPU and are effective until a new base rate case is filed and concluded. In addition, limited categories of costs such as fuel are recovered through adjustment clauses that are periodically reset to reflect current costs. Our transmission assets are regulated by FERC and costs are recovered through rates set by FERC. Inability to obtain a fair return on our investments or to timely recover material costs not included in rates would have a material adverse effect on our business.

• Obtain required regulatory approvals—The majority of our businesses operate under MBR authority granted by FERC, which has determined that our subsidiaries do not have market power and MBR rules have been satisfied. Failure to maintain MBR eligibility, or the effects of any severe mitigation measures that may be required if market power was evaluated differently in the future, could have a material adverse effect on us.

We may also require various other regulatory approvals to, among other things, buy or sell assets, engage in transactions between our public utility and our other subsidiaries, and, in some cases, enter into financing arrangements, issue securities and allow our subsidiaries to pay dividends. Failure to obtain these approvals on a timely basis could materially adversely affect our results of operations and cash flows.

• Comply with regulatory requirements—There are Federal standards, including mandatory NERC and cybersecurity standards, in place to ensure the reliability of the U. S. electric transmission and generation system and to prevent major system black-outs.

We have been, and will continue to be, periodically audited by NERC for compliance. FERC can impose penalties up to $1 million per day per violation. Further, FERC requires compliance with all of its rules and orders, including rules concerning Standards of Conduct, market behavior and anti-manipulation rules, interlocking directorate rules and cross-subsidization.

The BPU conducts periodic combined management/competitive service audits of New Jersey utilities related to affiliate standard requirements, competitive services, cross-subsidization, cost allocation and other issues. We are in the process of undergoing a management audit and an affiliate transactions audit. While we believe that we are in compliance with all applicable rules, we cannot predict the outcome of such audits.

35

We are exposed to commodity price volatility as a result of our participation in the wholesale energy markets.

The material risks associated with the wholesale energy markets known or currently anticipated that could adversely affect our operations include:

• Price fluctuations and collateral requirements—We expect to meet our supply obligations through a combination of generation and energy purchases. We also enter into derivative and other positions related to our generation assets and supply obligations. As a result, we are subject to the risk of price fluctuations that could affect our future results and impact our liquidity needs. These include:

• variability in costs, such as changes in the expected price of energy and capacity that we sell into the market;

• increases in the price of energy purchased to meet supply obligations or the amount of excess energy sold into the market;

• the cost of fuel to generate electricity; and

• the cost of emission credits and congestion credits that we use to transmit electricity.

In the markets where we operate, natural gas prices typically 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 usually translate into significant changes in the wholesale price of electricity.

Over the past few years, wholesale prices for natural gas have declined from the peak levels experienced in 2008. One of the reasons for this decline is increased shale gas production as extraction technology has improved. Lower gas prices have resulted in lower electricity prices, which has reduced our margins as nuclear and coal generation costs have not declined similarly. Over that time, generation by our coal units was also adversely affected by the relatively lower price of natural gas as compared to coal, making it sometimes more economical to run certain of our gas units than our coal units.

Natural gas prices may remain at low levels for an extended period and continue to decline if further advances in technology result in greater volumes of shale gas production.

Also, as market prices for energy and fuel fluctuate, our forward energy sale and forward fuel purchase contracts could require us to post substantial additional collateral, thus requiring us to obtain additional sources of liquidity during periods when our ability to do so may be limited. If Power were to lose its investment grade credit rating, it would be required under certain agreements to provide a significant amount of additional collateral in the form of letters of credit or cash, which would have a material adverse effect on our liquidity and cash flows. If Power had lost its investment grade credit rating as of December 31, 2011, it may have had to provide approximately $812 million in additional collateral. We may also be subject to additional collateral requirements which could be required under new rules being developed by the CFTC which are expected to be implemented in 2012.

• Our cost of coal and nuclear fuel may substantially increase—Our coal and nuclear units have a diversified portfolio of contracts and inventory that will provide a substantial portion of our fuel needs over the next several years. However, it will be necessary to enter into additional arrangements to acquire coal and nuclear fuel in the future. Market prices for coal and nuclear fuel have recently been volatile. Although our fuel contract portfolio provides a degree of hedging against these market risks, future increases in our fuel costs cannot be predicted with certainty and could materially and adversely affect liquidity, financial condition and results of operations.

While our generation runs on diverse fuels, allowing for flexibility, the mix of fuels ultimately used can impact earnings. Generation by our coal units in recent years 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.

• Third party credit risk—We sell generation output and buy fuel through the execution of bilateral contracts. These contracts are subject to credit risk, which relates to the ability of our counterparties to

36

meet their contractual obligations to us. Any failure to perform by these counterparties could have a material adverse impact on our results of operations, cash flows and financial position. In the spot markets, we are exposed to the risks of whatever default mechanisms exist in those markets, some of which attempt to spread the risk across all participants, which may not be an effective way of lessening the severity of the risk and the amounts at stake. The impact of economic conditions may also increase such risk.

We are subject to numerous Federal and state environmental laws and regulations that may significantly limit or affect our businesses, adversely impact our business plans or expose us to significant environmental fines and liabilities.

We are subject to extensive environmental regulation by Federal, state and local authorities regarding air quality, water quality, site remediation, land use, waste disposal, aesthetics, impact on global climate, natural resources damages and other matters. These laws and regulations affect the manner in which we conduct our operations and make capital expenditures. Future changes may result in significant increases in compliance costs.

Delay in obtaining, or failure to obtain and maintain, any environmental permits or approvals, or delay in or failure to satisfy any applicable environmental regulatory requirements, could:

• prevent construction of new facilities,

• prevent continued operation of existing facilities,

• prevent the sale of energy from these facilities, or

• result in significant additional costs, each of which could materially affect our business, results of operations and cash flows.

In obtaining required approvals and maintaining compliance with laws and regulations, we focus on several key environmental issues, including:

• Concerns over global climate change could result in laws and regulations to limit CO₂ emissions or other “greenhouse” gases (GHG) produced by our fossil generation facilities—Federal and state legislation and regulation designed to address global climate change through the reduction of GHG emissions could materially impact our fossil generation facilities. Legislation enacted in the states where our generation facilities are located establishes aggressive goals for the reduction of CO₂ emissions over a 40-year period. There could be significant costs incurred to continue operation of our fossil generation facilities, including the potential need to purchase CO₂ emission allowances. Such expenditures could materially affect the continued economic viability of one or more such facilities. Multiple states are developing or have developed state-specific or regional initiatives to obtain CO₂ emissions reductions in the electric power industry. The RGGI is such a program in the northeast. RGGI member states control emissions of GHG by issuance of allowances to emit CO₂ primarily through an auction. New Jersey announced that it is withdrawing from RGGI beginning in 2012.

A portion of our fossil fuel-fired electric generation is located in Connecticut and New York, which are within the RGGI region. The costs or inability to purchase CO₂ allowances for our fleet operating within a RGGI state could place us at an economic disadvantage compared to our competitors not located in a RGGI state.

• Potential closed-cycle cooling requirements—Our Salem nuclear generating facility has a permit from the NJDEP allowing for its continued operation with its existing cooling water system. That permit expired in July 2006. Our application to renew the permit, filed in February 2006, estimated the costs associated with cooling towers for Salem to be approximately $1 billion, of which our share was approximately $575 million.

If the NJDEP and the Connecticut Department of Environmental Protection were to require installation of closed-cycle cooling or its equivalent at our Salem, Mercer, Hudson, Bridgeport, Sewaren or New

37

Haven generating stations, the related increased costs and impacts would be material to our financial position, results of operations and net cash flows and would require further economic review to determine whether to continue operations or decommission the stations.

The EPA issued a proposed rule in 2011 regarding regulation of cooling water intake structures. If adopted as proposed, the impact of this rulemaking could significantly impact states’ permitting decisions on whether to require closed cycle cooling and could materially increase our cost of compliance. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities.

• Remediation of environmental contamination at current or formerly owned facilities—We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we generated. Remediation activities associated with our former Manufactured Gas Plant (MGP) operations are one source of such costs. Also, we are currently involved in a number of proceedings relating to sites where other hazardous substances may have been discharged and may be subject to additional proceedings in the future, the related costs of which could have a material adverse effect on our financial condition, results of operations and cash flows. Recent amendments to New Jersey law now place affirmative obligations on us to investigate and, if necessary, remediate contaminated property upon which we were in any way responsible for a discharge of hazardous substances. While those amendments do not change our liability, they do impact the speed by which we will need to investigate contaminated properties, which could adversely impact cash flow.

In 2007, the State of New Jersey filed multiple lawsuits against parties, including us, who were alleged to be responsible for injuries to natural resources in New Jersey, including a site being remediated under our MGP program. We cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to these or other natural resource damages claims. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities.

• More stringent air pollution control requirements in New Jersey—Most of our generating facilities are located in New Jersey where restrictions are generally considered to be more stringent in comparison to other states. Therefore, there may be instances where the facilities located in New Jersey are subject to more restrictive and, therefore, more costly pollution control requirements and liability for damage to natural resources, than competing facilities in other states. Most of New Jersey has been classified as “nonattainment” with NAAQS for one or more air pollutants. This requires New Jersey to develop programs to reduce air emissions. Such programs can impose additional costs on us by requiring that we offset any emissions increases from new electric generators we may want to build and by setting more stringent emission limits on our facilities that run during the hottest days of the year.

• Coal Ash Management—Coal ash is a CCR produced as a byproduct of generation at our coal-fired facilities. We currently have a program to beneficially reuse coal ash as presently allowed by federal and state regulations. In June 2010, the EPA formally published a proposed rule offering three main options for the management of CCRs under the Resource Conservation and Recovery Act. One of these options regulates CCRs as a hazardous waste and the other two options are variations of a non-hazardous designation. All options communicate the EPA’s intent of ceasing wet ash transfer and instituting engineering controls on ash ponds and landfills to limit impact on human health and the environment. The outcome of the EPA rulemaking cannot be predicted. Proposed regulations which more stringently regulate coal ash, including regulating coal ash as hazardous waste, could materially increase costs at our coal-fired generation facilities. The EPA has not established a date for release of a final rule.

38

Our ownership and operation of nuclear power plants involve regulatory, financial, environmental, health and safety risks.

Approximately half of our total generation output each year is provided by our nuclear fleet, which comprises approximately one-fourth of our total owned generation capacity. For this reason, we are exposed to risks related to the continued successful operation of our nuclear facilities and issues that may adversely affect the nuclear generation industry. These include:

• Storage and Disposal of Spent Nuclear Fuel—We currently use on-site storage for spent nuclear fuel. Disposal of nuclear materials, including the availability or unavailability of a permanent repository for spent nuclear fuel, could impact future operations of these stations. In addition, the availability of an off-site repository for spent nuclear fuel may affect our ability to fully decommission our nuclear units in the future.

• Regulatory and Legal Risk—The NRC may modify, suspend or revoke licenses, or shut down a nuclear facility and impose substantial civil penalties for failure to comply with the Atomic Energy Act, related regulations or the terms and conditions of the licenses for nuclear generating facilities. As with all of our generation facilities, as discussed above, our nuclear facilities are also subject to comprehensive, evolving environmental regulation. Our nuclear generating facilities are currently operating under NRC licenses that expire in 2033 through 2046.

• Operational Risk—Operations at any of our nuclear generating units could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. Since our nuclear fleet provides the majority of our generation output, any significant outage could result in reduced earnings as we would need to purchase or generate higher-priced energy to meet our contractual obligations. For additional information, see our discussion of operational performance for all of our generation facilities below.

• Nuclear Incident or Accident Risk—Accidents and other unforeseen problems have occurred at nuclear stations, both in the U.S. and elsewhere. The consequences of an accident can be severe and may include loss of life, significant property damage and/or a change in the regulatory climate. We have nuclear units at two sites. It is possible that an accident or other incident at a nuclear generating unit could adversely affect our ability to continue to operate unaffected units located at the same site, which would further affect our financial condition, operating results and cash flows. An accident or incident at a nuclear unit not owned by us could also affect our ability to continue to operate our units. Any resulting financial impact from a nuclear accident may exceed our resources, including insurance coverages.

We may be adversely affected by changes in energy regulatory policies, including energy and capacity market design rules and developments affecting transmission.

The energy industry continues to be regulated and the rules to which our businesses are subject are always at risk of being changed. Various rules have recently been implemented to respond to commodity pricing, reliability and other industry concerns. Our business has been impacted by established rules that create locational capacity markets in each of PJM, ISO-NE and NYISO. Under these rules, generators located in constrained areas are paid more for their capacity so there is an incentive to locate in those areas where generation capacity is most needed. Because much of our generation is located in constrained areas in PJM and ISO-NE, the existence of these rules has had a positive impact on our revenues. PJM’s locational capacity market design rules and New England forward capacity market rules have been challenged in court and continue to evolve. Any changes to these rules may have an adverse impact on our financial condition, results of operations and cash flows.

In addition, recent legislative developments in the State of New Jersey have the potential to adversely impact RPM prices. In January 2011, New Jersey enacted a law establishing a LCAPP which provides for the construction of subsidized base load or mid-merit electric power generation. The LCAPP may have the effect

39

of artificially depressing prices in the competitive wholesale market. PJM’s Independent Market Monitor has released a report estimating that the impact of bidding 2,000 MW of capacity in New Jersey as a price taker could be a reduction in capacity market revenues to PJM suppliers of more than $2 billion in the first year.

Many other factors will affect the capacity pricing in PJM, including but not limited to:

• changes in load and demand,

• changes in the available amounts of demand response resources,

• 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 increasing the potential 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.

Potential changes to the rules governing energy markets in which the output of our plants is sold also poses risk to our business. Certain stakeholders, primarily consumer advocates and state commissions, have been arguing that each generating plant should be paid its “as bid” price rather than allowing all units to be paid a single clearing price based on the marginal unit’s bid. If adopted, this change could reduce the energy payments received by certain of our generating units.

We could also be impacted by a number of other events, including regulatory or legislative actions favoring non-competitive markets and energy efficiency initiatives. Further, some of the market-based mechanisms in which we participate, including BGS auctions, are at times the subject of review or discussion by some of the participants in the New Jersey and Federal regulatory and political arenas. We can provide no assurance that these mechanisms will continue to exist in their current form, nor otherwise be modified.

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. Developers of long-distance “green” transmission projects are seeking inclusion in regional transmission planning processes, with the potential to move lower-cost generation to eastern markets, including New Jersey and New York. Moreover, FERC has issued a rule that requires changes to transmission planning processes so that more transmission can be built to facilitate renewable generation development. This rule has also opened up the construction of transmission to competition. In addition, the DOE-funded Eastern Interconnection Planning Collaborative (EIPC) continues its efforts to study transmission planning across the Eastern Interconnection, evaluating the extent to which the construction of large-scale transmission is needed.

Changes in the current policies for building new transmission lines, such as the proposal by FERC to eliminate provisions for us to have the “right of first refusal” to construct projects in our service territory, could result in additional competition to build transmission lines in our area in the future and would allow us to seek opportunities to build in other service territories.

We face significant competition in the merchant energy markets.

Our wholesale power and marketing businesses are subject to significant competition that may adversely affect our ability to make investments or sales on favorable terms and achieve our annual objectives. Increased competition could contribute to a reduction in prices offered for power and could result in lower earnings. Decreased competition could negatively impact results through a decline in market liquidity. Some of our competitors include:

• merchant generators,

• domestic and multi-national utility rate-based generators,

• energy marketers,

40

• utilities,

• banks, funds and other financial entities,

• fuel supply companies, and

• affiliates of other industrial companies.

Regulatory, environmental, industry and other operational developments will have a significant impact on our ability to compete in energy markets, potentially resulting in erosion of our market share and impairment in the value of our power plants. Our ability to compete will also be impacted by:

• DSM and other efficiency efforts—DSM and other efficiency efforts aimed at changing the quantity and patterns of consumers’ usage could result in a reduction in load requirements.

• Changes in technology and/or customer conservation—It is possible that advances in technology will reduce the cost of alternative methods of producing electricity, such as fuel cells, micro turbines, windmills and PV (solar) cells, to a level that is competitive with that of most central station electric production. It is also possible that electric customers may significantly decrease their electric consumption due to demand-side energy conservation programs. Changes in technology could also alter the channels through which retail electric customers buy electricity, which could adversely affect our financial results.

Our inability to balance energy obligations with available supply could negatively impact results.

The revenues generated by the operation of our generating stations are subject to market risks that are beyond our control. Generation output will either be used to satisfy wholesale contract requirements, other bilateral contracts or be sold into competitive power markets. Participants in the competitive power markets are not guaranteed any specified rate of return on their capital investments. Generation revenues and results of operations are dependent upon prevailing market prices for energy, capacity, ancillary services and fuel supply in the markets served.

Our generation business frequently involves the establishment of forward sale positions in the wholesale energy markets on long-term and short-term bases. To the extent that we have produced or purchased energy in excess of our contracted obligations, a reduction in market prices could reduce profitability. Conversely, to the extent that we have contracted obligations in excess of energy we have produced or purchased, an increase in market prices could reduce profitability. If the strategy we utilize to hedge our exposure to these various risks is not effective, we could incur significant losses. Our market positions can also be adversely affected by the level of volatility in the energy markets that, in turn, depends on various factors, including weather in various geographical areas, short-term supply and demand imbalances, customer migration and pricing differentials at various geographic locations. These cannot be predicted with certainty.

Increases in market prices also affect our ability to hedge generation output and fuel requirements as the obligation to post margin increases with increasing prices and could require the maintenance of liquidity resources that would be prohibitively expensive.

Any inability to recover the carrying amount of our assets could result in future impairment charges which could have a material adverse impact on our financial condition, results of operations and cash flows.

In accordance with accounting guidance, management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate or market conditions, could potentially indicate an asset’s carrying amount may not be recoverable. Significant reductions in our expected revenues or cash flows for an extended period of time resulting from such events could result in future asset impairment charges, which could have a material adverse impact on our financial condition and results of operations.

41

Inability to access sufficient capital at reasonable rates or commercially reasonable terms or maintain sufficient liquidity in the amounts and at the times needed could adversely impact our business.

Capital for projects and investments has been provided primarily by internally-generated cash flow and external financings. We have significant capital requirements and will need continued access to debt capital from outside sources in order to efficiently fund the construction and other cash flow needs of our businesses. The ability to arrange financing and the costs of capital depend on numerous factors including, among other things, general economic and market conditions, the availability of credit from banks and other financial institutions, investor confidence, the success of current projects and the quality of new projects.

The ability to have continued access to the credit and capital markets at a reasonable economic cost is dependent upon our current and future capital structure, financial performance, our credit ratings and the availability of capital under reasonable terms and conditions. As a result, no assurance can be given that we will be successful in obtaining re-financing for maturing debt, financing for projects and investments or funding the equity commitments required for such projects and investments in the future.

Financial market performance directly affects the asset values of our nuclear decommissioning trust funds and defined benefit plan trust funds. Sustained decreases in asset value of trust assets could result in the need for significant additional funding.

The performance of the financial markets will affect the value of the assets that are held in trust to satisfy our future obligations under our pension and postretirement benefit plans and to decommission our nuclear generating plants. A decline in the market value of our pension assets similar to the one experienced in 2008 could result in the need for us to make significant contributions in the future to maintain our funding at sufficient levels.

An extended economic recession would likely have a material adverse effect on our businesses.

Our results of operations may be negatively affected by sustained downturns or sluggishness in the economy, including low levels in the market prices of commodities. Adverse conditions in the economy affect the markets in which we operate and can negatively impact our results. Declines in demand for energy will reduce overall sales and lessen cash flows, especially as customers reduce their consumption of electricity and gas. Although our utility business is subject to regulated allowable rates of return, overall declines in electricity and gas sold and/or increases in non-payment of customer bills would materially adversely affect our liquidity, financial condition and results of operations.

We may be adversely affected by equipment failures, accidents, severe weather events or other incidents that impact our ability to provide safe and reliable service to our customers.

The success of our businesses is dependent on our ability to continue providing safe and reliable service to our customers. Equipment or system failures could result in a disruption of service to our customers. We are also exposed to the risk of accidents, severe weather events or other incidents which could result in damage to or destruction of our facilities or damage to persons or property. Such issues experienced at our facilities, or by others in our industry, could adversely impact our revenues, increase costs to repair and maintain our systems, subject us to potential litigation and/or damage claims and increase the level of oversight at our facilities through investigations or through the imposition of additional regulatory or legislative requirements.

Acts of war, terrorism or cybersecurity breaches could adversely affect our operations.

Our businesses and industry may be impacted by acts and threats of war or terrorism. These actions could result in increased political, economic and financial market instability and volatility in fuel prices which could materially adversely affect our operations. In addition, our infrastructure facilities, such as our generating stations, transmission and distribution facilities and information management systems for customer-related operations, could be direct or indirect targets or be affected by terrorist or other criminal activity.

42

Our businesses could also be impacted by cybersecurity breaches. Cybersecurity threats include:

• operational interference, such as attacks on our generation facilities, transmission lines or the power grid;

• information theft as to employees and/or customers, such as personal financial and health records; and

• business system interruption or compromise.

Such events could severely disrupt business operations and result in loss of service to customers. These events could also result in significant expenses to repair security breaches or system damage as well as increased capital, insurance and operating costs, including increased security costs for our facilities. In addition, new or updated security regulations may require us to make changes to our current measures which could also result in additional expenses.

The BPU has issued an order, effective January 2012, in which it directed New Jersey utilities to outline what equipment and safety measures they have in place to monitor against cyber intrusions and to report any incidents.

Inability to successfully develop or construct generation, transmission and distribution projects within budget could adversely impact our businesses.

Our business plan calls for extensive investment in capital improvements and additions, including the installation of required environmental upgrades and retrofits, construction and/or acquisition of additional generation units and transmission facilities and modernizing existing infrastructure. Currently, we have several significant projects underway or being contemplated.

Our success will depend, in part, on our ability to complete these projects within budgets, on commercially reasonable terms and conditions and, in our regulated businesses, our ability to recover the related costs through rates. Any delays, cost escalations or otherwise unsuccessful construction and development could materially affect our financial position, results of operations and cash flows.

We may be unable to achieve, or continue to sustain, our expected levels of operating performance.

One of the key elements to achieving the results in our business plan is the ability to sustain generating operating performance and capacity factors at expected levels since our forward sales of energy and capacity assume acceptable levels of operating performance. This is especially important at our lower-cost facilities. Operations at any of our plants could degrade to the point where the plant has to shut down or operate at less than full capacity. Some issues that could impact the operation of our facilities are:

• breakdown or failure of equipment, processes or management effectiveness;

• disruptions in the transmission of electricity;

• labor disputes;

• fuel supply interruptions;

• transportation constraints;

• limitations which may be imposed by environmental or other regulatory requirements;

• permit limitations; and

• operator error or catastrophic events such as fires, earthquakes, explosions, floods, severe storms, acts of terrorism or other similar occurrences.

Identifying and correcting any of these issues may require significant time and expense. Depending on the materiality of the issue, we may choose to close a plant rather than incur the expense of restarting it or returning it to full capacity. In either event, to the extent that our operational targets are not met, we could have to operate higher-cost generation facilities or meet our obligations through higher-cost open market purchases.

43

Challenges associated with retention of a qualified workforce could adversely impact our businesses.

Our operations depend on the retention of a skilled workforce. The loss or retirement of key executives or other employees, including those with the specialized knowledge required to support our generation, transmission and distribution operations, could result in various operational challenges. These challenges may include the lack of appropriate replacements, the loss of institutional and industry knowledge and the increased costs to hire and train new personnel. This has the potential to become more critical over the next several years as a growing number of employees become eligible to retire.

In addition, because a significant portion of our employees are covered under collective bargaining agreements, our success will depend on our ability to successfully renegotiate these agreements as they expire. Inability to do so may result in employee strikes or work stoppages which would disrupt our operations and could also result in increased costs.

Our receipt of payment of receivables related to our domestic leveraged leases is dependent upon the credit quality and the ability of lessees to meet their obligations.

Our receipt of payments of equity rent, debt service and other fees related to our leveraged lease portfolio in accordance with the lease contracts can be impacted by various factors. The factors which may impact future lease cash flow include, but are not limited to, new environmental legislation regarding air quality and other discharges in the process of generating electricity, market prices for fuel and electricity, including the impact of low gas prices on our coal generation investments, overall financial condition of lease counterparties and the quality and condition of assets under lease. If a lessee were to default, we could potentially be required to impair our current investment balances. For additional information relating to these leases, see Item 7. MD&A—Critical Accounting Estimates and Item 8. Financial Statements and Supplementary Data—Note 8. Financing Receivables.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

PSEG, Power and PSE&G

None.

ITEM 2.    PROPERTIES

All of our physical property is owned by our subsidiaries. We believe that we and our subsidiaries maintain adequate insurance coverage against loss or damage to plants and properties, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost. For a discussion of nuclear insurance, see Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities.

44

Generation Facilities

Power

As of December 31, 2011, Power’s share of summer installed generating capacity is shown in the following table:

Name	Location		Total Capacity (MW)		% Owned		Owned Capacity (MW)		Principal Fuels Used	Mission
Steam:
Hudson		NJ		608		100%		608	Coal/Gas	Load Following
Mercer		NJ		632		100%		632	Coal	Load Following
Sewaren		NJ		453		100%		453	Gas	Load Following
Keystone (A)		PA		1,711		23%		391	Coal	Base Load
Conemaugh (A)		PA		1,711		23%		385	Coal	Base Load
Bridgeport Harbor		CT		383		100%		383	Coal	Load Following
New Haven Harbor		CT		448		100%		448	Oil	Load Following
Total Steam				5,946				3,300
Nuclear:
Hope Creek		NJ		1,173		100%		1,173	Nuclear	Base Load
Salem 1 & 2		NJ		2,326		57%		1,336	Nuclear	Base Load
Peach Bottom 2 & 3 (B)		PA		2,247		50%		1,123	Nuclear	Base Load
Total Nuclear				5,746				3,632
Combined Cycle:
Bergen		NJ		1,178		100%		1,178	Gas	Load Following
Linden		NJ		1,230		100%		1,230	Gas	Load Following
Bethlehem		NY		754		100%		754	Gas	Load Following
Total Combined Cycle				3,162				3,162
Combustion Turbine:
Essex		NJ		617		100%		617	Gas	Peaking
Edison		NJ		504		100%		504	Gas	Peaking
Kearny		NJ		446		100%		446	Gas	Peaking
Burlington		NJ		557		100%		557	Oil/Gas	Peaking
Linden		NJ		340		100%		340	Gas	Peaking
Mercer		NJ		115		100%		115	Oil	Peaking
Sewaren		NJ		105		100%		105	Oil	Peaking
Bergen		NJ		21		100%		21	Gas	Peaking
National Park		NJ		21		100%		21	Oil	Peaking
Salem		NJ		38		57%		22	Oil	Peaking
Bridgeport Harbor		CT		18		100%		18	Oil	Peaking
Total Combustion Turbine				2,782				2,766
Pumped Storage:
Yards Creek (C)		NJ		400		50%		200		Peaking
Total Operating Power Plants				18,036				13,060

(A) Operated by GenOn Northeast Management Company

(B) Operated by Exelon Generation

(C) Operated by Jersey Central Power & Light Company

45

PSE&G

As of December 31, 2011, PSE&G had 58 MW of installed solar capacity in various towns throughout New Jersey.

Energy Holdings

Energy Holdings had investments in the following generation facilities as of December 31, 2011:

Name	Location	Total Capacity (MW)		% Owned		Owned Capacity (MW)		Principal Fuels Used
United States
Kalaeloa	HI		209		50%		105	Oil
GWF (A)	CA		105		50%		53	Petroleum coke
Bridgewater	NH		16		40%		6	Biomass
Hackettstown	NJ		2		100%		2	Solar
Wyandot	OH		12		100%		12	Solar
Jacksonville	FL		15		100%		15	Solar
Total United States			359				193
International
Turboven	Venezuela		120		50%		60	Natural gas
Turbogeneradores de Maracay (TGM)	Venezuela		40		9%		4	Natural gas
Total International			160				64
Total Operating Power Plants			519				257

(A) In February, 2012, the California Public Utilities Commission approved the shut down of GWF Power.

Transmission and Distribution Facilities

As of December 31, 2011, PSE&G’s electric transmission and distribution system included 23,553 circuit miles, of which 8,163 circuit miles were underground, and 836,465 poles, of which 546,129 poles were jointly-owned. Approximately 99% of this property is located in New Jersey.

In addition, as of December 31, 2011, PSE&G owned four electric distribution headquarters and five subheadquarters in four operating divisions, all located in New Jersey.

As of December 31, 2011, the daily gas capacity of PSE&G’s 100%-owned peaking facilities (the maximum daily gas delivery available during the three peak winter months) consisted of liquid petroleum air gas and liquefied natural gas and aggregated 2,790,500 therms (270,922,330 cubic feet on an equivalent basis of 1,030 Btu/cubic foot) as shown in the following table:

Plant	Location	Daily Capacity (Therms)
Burlington LNG	Burlington, NJ		670,500
Camden LPG	Camden, NJ		320,000
Central LPG	Edison Twp., NJ		900,000
Harrison LPG	Harrison, NJ		900,000
Total			2,790,500

46

As of December 31, 2011, PSE&G owned and operated 17,710 miles of gas mains, owned 12 gas distribution headquarters and two subheadquarters, all in four operating regions located in New Jersey and owned one meter shop in New Jersey serving all such areas. In addition, PSE&G operated 62 natural gas metering and regulating stations, all located in New Jersey, of which 26 were located on land owned by customers or natural gas pipeline suppliers and were operated under lease, easement or other similar arrangement. In some instances, the pipeline companies owned portions of the metering and regulating facilities.

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

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

In addition, as of December 31, 2011, PSE&G owned 42 switching stations in New Jersey with an aggregate installed capacity of 23,898 megavolt-amperes and 246 substations with an aggregate installed capacity of 8,179 megavolt-amperes. In addition, four substations in New Jersey having an aggregate installed capacity of 109 megavolt-amperes were operated on leased property.

ITEM 3.    LEGAL PROCEEDINGS

We are party to various lawsuits and regulatory matters, including in the ordinary course of business. For information regarding material legal proceedings, other than those discussed below, see Item 1. Business—Regulatory Issues and Environmental Matters and Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities.

Con Edison (Con Ed)

In 2001, Con Ed filed a complaint with FERC against PSE&G, PJM and NYISO asserting a failure to comply with agreements between PSE&G and Con Ed covering 1,000 MW of transmission. On September 16, 2010, FERC approved a settlement agreement entered into by PSE&G, Con Ed, PJM, NYISO and others. This settlement provides the basis for moving forward with Con Ed after the current contracts expire in 2012 and settles all issues associated with the existing contracts, including cases pending in the D.C. Circuit Court of Appeals. However, dismissal of these court cases is contingent upon receipt of a final, non-appealable order from the FERC. One party to the proceeding sought rehearing of the FERC approval order, which FERC denied in an order issued on April 8, 2011. The party then appealed this decision to the D.C. Circuit Court of Appeals. This appeal is pending.

Environmental Matters

The following items are environmental matters involving governmental authorities not discussed elsewhere in this Form 10-K. We do not expect expenditures for any such site relating to the items listed below, individually or for all such current sites in the aggregate, to have a material effect on our financial condition, results of operations and net cash flows.

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

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

47

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

(4) Claim by the EPA, Region III, under CERCLA with respect to a Cottman Avenue Superfund Site, a former non-ferrous scrap reclamation facility located in Philadelphia, Pennsylvania, owned and formerly operated by Metal Bank of America, Inc. PSE&G, other utilities and other companies are alleged to be liable for contamination at the site and PSE&G has been named as a PRP. A Final Remedial Design Report was submitted to the EPA in September of 2002. This document presented the design details of the EPA’s selected remediation remedy. PSE&G and other utility companies as members of a PRP group entered into a Consent Decree and agreed to implement a negotiated EPA selected remediation remedy. The PRP group implementation of the remedy was completed in 2010. Although subject to EPA approval and oversight, long term monitoring activities designed to demonstrate the effectiveness of the implemented remedy are planned through 2018 at an estimated cost of $2.8 million.

(5) The Klockner Road site is located in Hamilton Township, Mercer County, New Jersey, and occupies approximately two acres on PSE&G’s Trenton Switching Station property. In 1996, PSE&G entered into a memorandum of agreement with the NJDEP for the Klockner Road site pursuant to which PSE&G conducted an RI/FS and remedial action at the site to address the presence of soil and groundwater contamination. Anticipated future activities at the site include the filing of certification(s) with NJDEP once every two years regarding the effectiveness of engineering and institutional controls, quarterly groundwater monitoring for several years and the installation of additional off-site groundwater monitoring wells as directed by NJDEP.

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

(7) In 1996, Morton International, Inc., a subsidiary of The Dow Chemical Company, filed a lawsuit against the former customers of a former mercury refining operation located on the banks of Berry’s Creek in Wood-Ridge, New Jersey. The lawsuit seeks to recover cleanup costs incurred and to be incurred in remediating the site. PSE&G was among the former customers sued based on allegations that mercury originating at its Kearny Generating Station was sent to the site for refining.

(8) The EPA sent Power, PSE&G and approximately 157 other entities a notice that the EPA considered each of the entities to be a PRP with respect to contamination in Berry’s Creek in Bergen County, New Jersey and requesting that the PRPs perform a RI/FS on Berry’s Creek and the connected tributaries and wetlands. Berry’s Creek flows through approximately 6.5 miles of areas that have been used for a variety of industrial purposes and landfills. The EPA estimates that the study could be completed in approximately five years at a total cost of approximately $18 million. As members of a PRP Group, Power and certain of the other entities named in the EPA Notice entered into an Administrative Settlement Agreement and Order on Consent to conduct the RI/FS.

(9) In 2004, Exelon Generation signed an agreement for Peach Bottom regarding the DOE’s delay in accepting spent nuclear fuel for permanent storage. Under the agreement, Exelon Generation would be reimbursed for costs previously incurred, with future costs incurred resulting from the DOE delays in accepting spent fuel to be reimbursed annually until the DOE fulfills its obligation. In addition, Exelon Generation and Power are required to reimburse the DOE for the previously received credits from the Nuclear Waste Fund. In September 2009, Power signed an agreement with the DOE applicable to Salem and Hope Creek under which we will be reimbursed for past and future reasonable and allowable costs

48

resulting from the DOE’s delay in accepting spent nuclear fuel for permanent disposition. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities.

(10) In January 2010, we received a letter from the NJDEP asserting that we are the current owner of the Gates Construction Corporation Landfill and that the subject landfill has not been properly closed in accordance with NJDEP Solid Waste Regulations.

ITEM 4.    MINE SAFETY DISCLOSURES

Not applicable.

49

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is listed on the New York Stock Exchange, Inc. As of December 31, 2011, there were 78,280 registered holders.

The graph below shows a comparison of the five-year cumulative return assuming $100 invested on December 31, 2006 in our common stock and the subsequent reinvestment of quarterly dividends, the S&P Composite Stock Price Index, the Dow Jones Utilities Index and the S&P Electric Utilities Index.

	2006		2007		2008		2009		2010		2011
PSEG	$	100.00	$	151.93	$	93.51	$	111.14	$	111.05	$	120.15
S&P 500	$	100.00	$	105.48	$	66.52	$	84.07	$	96.71	$	98.76
DJ Utilities	$	100.00	$	120.06	$	86.70	$	97.47	$	103.75	$	124.08
S&P Electrics	$	100.00	$	123.07	$	91.33	$	94.38	$	97.61	$	118.05

50

The following table indicates the high and low sale prices for our common stock and dividends paid for the periods indicated:

Common Stock	High		Low		Dividend per Share
2011
First Quarter	$	33.12	$	30.15	$	0.3425
Second Quarter	$	34.22	$	30.30	$	0.3425
Third Quarter	$	35.48	$	27.97	$	0.3425
Fourth Quarter	$	34.96	$	30.60	$	0.3425
2010
First Quarter	$	33.75	$	29.01	$	0.3425
Second Quarter	$	34.21	$	29.02	$	0.3425
Third Quarter	$	34.93	$	30.92	$	0.3425
Fourth Quarter	$	33.97	$	30.35	$	0.3425

On February 21, 2012, our Board of Directors approved $0.3550 per share of common stock dividend for the first quarter of 2012. This reflects an indicated annual dividend rate of $1.42 per share.

The following table indicates our common share repurchases in the open market to satisfy obligations under various equity compensation award grants during the fourth quarter of 2011:

Three Months Ended December 31, 2011	Total Number of Shares Purchased		Average Price Paid per Share
October 1-October 31		0	$	0.00
November 1-November 30		50,117	$	33.66
December 1-December 31		27,000	$	32.40

The following table indicates the securities authorized for issuance under equity compensation plans as of December 31, 2011:

Plan Category	Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans
Equity compensation plans approved by security holders		3,272,300	$	32.78		17,564,232	(A)
Equity compensation plans not approved by security holders		0	$	0.00		3,589,032	(B)
Total		3,272,300	$	32.78		21,153,264

(A) Shares issuable under our Long-Term Incentive Plan (LTIP).

(B) Shares issuable under our Employee Stock Purchase Plan.

For additional discussion of specific plans concerning equity-based compensation, see Item 8. Financial Statements and Supplementary Data—Note 18. Stock Based Compensation.

Power

We own all of Power’s outstanding limited liability company membership interests. For additional information regarding Power’s ability to pay dividends, see Item 7. MD&A—Overview of 2011 and Future Outlook.

51

PSE&G

We own all of the common stock of PSE&G. For additional information regarding PSE&G’s ability to continue to pay dividends, see Item 7. MD&A—Overview of 2011 and Future Outlook.

ITEM 6.    SELECTED FINANCIAL DATA

PSEG

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

PSEG
	2011		2010		2009		2008		2007
For the Years Ended December 31:	Millions, where applicable
Operating Revenues	$	11,079	$	11,793	$	12,035	$	12,609	$	12,051
Income from Continuing Operations (A)	$	1,407	$	1,557	$	1,594	$	918	$	1,274
Net Income	$	1,503	$	1,564	$	1,592	$	1,188	$	1,335
Earnings per Share:
Income from Continuing Operations
Basic(A)	$	2.78	$	3.08	$	3.15	$	1.81	$	2.51
Diluted(A)	$	2.77	$	3.07	$	3.14	$	1.81	$	2.50
Net Income
Basic	$	2.97	$	3.09	$	3.15	$	2.34	$	2.63
Diluted	$	2.96	$	3.08	$	3.14	$	2.34	$	2.62
Dividends Declared per Share	$	1.37	$	1.37	$	1.33	$	1.29	$	1.17
As of December 31:
Total Assets	$	29,821	$	29,909	$	28,678	$	29,049	$	28,299
Long-Term Obligations (B)	$	7,482	$	7,847	$	7,679	$	8,044	$	8,709

(A) Income from Continuing Operations for 2011 and 2008 includes after-tax charges of $170 million and $490 million, respectively, related to certain leveraged leases.

(B) Includes capital lease obligations.

Power and PSE&G

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

52

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

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

PSEG’s business consists of three reportable segments, which are:

• Power, our wholesale energy supply company that integrates its generating asset operations with its wholesale energy, fuel supply, energy trading and marketing and risk management activities primarily in the Northeast and Mid Atlantic United States,

• PSE&G, our public utility company which provides transmission and distribution of electric energy and gas in New Jersey; implements demand response and energy efficiency programs and invests in solar generation, and

• Energy Holdings, which owns our energy-related leveraged leases and other investments.

Our business discussion in Item 1 provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets, focusing on operational excellence, financial strength and making disciplined investments. Our risk factor discussion in Item 1A. provides information about factors that could have a material adverse impact in our businesses. The following discussion expands upon those sections by describing significant events and business developments that have occurred during 2011 and key factors that we expect will drive our future performance. The following discussion refers to the Consolidated Financial Statements (Statements) and the Related Notes to Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements and Notes.

OVERVIEW OF 2011 AND FUTURE OUTLOOK

During 2011, our results continued to be adversely impacted by lower prices for electricity and natural gas in the markets we serve. We began experiencing a greater pricing impact due to a decline in both PJM Reliability Pricing Model (RPM) and Basic Generation Service (BGS) rates which became effective in the second quarter. Our pricing also continues to be affected by customer migration away from our BGS supply contracts as these volumes are replaced with lower priced spot market sales. While the effect of customer migration on our results has been reduced as average BGS rates have been declining to a level more closely resembling current market prices, customers may still see an incentive to switch to third party suppliers. The result of such a switch may affect the price we receive on our sales, shifting from BGS rates that are established in auctions that have taken place over the past three years, to prices offered by third party suppliers which may be more representative of recent market pricing.

Partially offsetting this lower commodity pricing are higher revenues due to increased distribution rates at PSE&G as a result of the base rate case settlement in mid-2010. This included an increase of $73.5 million and $26.5 million in annual electric and gas revenues, respectively, with a return on equity (ROE) of 10.3%. We have also realized an increase in transmission revenues as a result of our 2011 Formula Rate Update which provided for approximately $45 million in increased revenues in our 2011 transmission rates effective January 1, 2011. We filed our 2012 Annual Formula Rate Update with FERC in October 2011, which provides for approximately $94 million in increased annual transmission revenues effective January 1, 2012.

These increased delivery charges have been offset by lower supply costs. The reduction in supply costs allows us to invest in infrastructure improvements without raising customer rates. Since January 2010, PSE&G’s typical average residential customers who purchased supply from PSE&G have seen a total annual bill reduction of 19% for gas and 1% for electric.

For 2012 and beyond, the key issues our business will confront include:

• the continuing potential for sustained lower natural gas and electricity prices,

53

• uncertainty in the economic recovery,

• regulatory and political uncertainty, particularly with regard to future energy policy, transmission policy and environmental regulation, and

• challenges to competitive markets, including support for subsidized generation in many states, particularly in New Jersey.

Our future success will also depend on our ability to respond to these challenges and take advantage of opportunities presented by these and other regulatory and legislative initiatives. In order to do this, we must:

• continue to focus on controlling costs while maintaining our safety, reliability and compliance standards,

• successfully recontract our open supply positions, and

• execute our capital investment program, including investments for growth that yield contemporaneous and attractive risk adjusted returns.

There have also been other significant regulatory and legislative developments during the year which may affect our operations in the future as new rules and regulations are adopted. For additional information on these issues, see Item 1. Business—Regulatory Issues and Environmental Matters.

• In 2011, the State of New Jersey enacted the Long-Term Capacity Agreement Pilot Program Act (LCAPP Act) to subsidize up to 2,000 MW of new natural gas-fired generation. The LCAPP Act provided that subsidies would be offered through long-term standard offer capacity agreements (SOCAs) by New Jersey EDCs, including PSE&G, to generators selected by the BPU. Legal challenges to the BPU’s implementation of the LCAPP Act, as well as to the constitutionality of the LCAPP Act were filed and are pending.

Maryland is also considering similar subsidies to above-market new generation. In September 2011, the Maryland Public Utility Commission (PUC) issued an order requiring its EDCs to issue a Request for Proposals (RFP) to procure up to 1,500 MW of new natural gas-fired generation located in the Southwest MAAC electrical region. The RFP is similar to the LCAPP SOCA. These developments in Maryland could impact energy and capacity prices in PJM and may also impact developments in New Jersey regarding the construction of subsidized generation.

The LCAPP, Maryland’s RFP or similar activity in other states may artificially depress prices in the competitive wholesale market and have the potential to harm competitive markets, on both a short-term and long-term basis. The lack of consistent rules in energy markets can adversely impact the competitiveness of our plants.

See Item 1. Business, Federal Regulation, FERC—Capacity Market Issues for further information.

• The United States Environmental Protection Agency (EPA) published a proposed rule in April 2011 related to 316(b) Clean Water Act requirements. The rule, as proposed, would establish a marine life mortality standard for certain existing cooling water intake structures. We are unable to predict the outcome of this proposed rulemaking, the final form that the proposed regulations may take or the effect, if any, that they may have on our future capital requirements, financial condition or results of operations.

• In July 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR) that limits power plant emissions in 28 states that contribute to the ability of downwind states to attain and/or maintain current particulate matter and ozone emission standards. Emission reductions would have been governed by this rule beginning on January 1, 2012 for Sulfur Dioxide (SO₂) and “annual Nitrogen Oxide (NO_X)” and May 1, 2012 for “Ozone season NO_X”. Certain states would have been required to make additional SO₂ reductions in 2014. The EPA issued draft technical adjustments to the final CSAPR in October 2011. CSAPR is generally expected to have an upward impact on electricity prices, resulting from the

54

retirement of some units, as well as from the potential cost increase from either the purchase of allowances or the cost of operation of emissions control equipment. Technical revisions to the CSAPR were finalized on February 7, 2012. The EPA increased New Jersey’s allocation of annual NO_X and ozone season NO_X allowances beyond what was proposed. The EPA also finalized the increase in New Jersey’s allocation of SO₂ allowances from the October proposal. The additional increases in NOx allocations are favorable to PSEG, since both PSEG and New Jersey as a whole are projected to be very tight on NOx allowances (both ozone season and annual).

On December 30, 2011, the United States Court of Appeals for the D.C. Circuit issued a ruling to stay CSAPR pending judicial review. Until a final decision is reached, the court has ordered that the Clean Air Interstate Rule (CAIR) requirements continue temporarily. We have intervened in this litigation, along with other generating companies, in support of the EPA. The continuation of CAIR affects our generating stations in Connecticut, New Jersey and New York. If 2012 operations are similar to those in the past three years, the impact to our operations from the temporary implementation of CAIR in 2012 is not expected to be significant.

• The EPA proposed a Maximum Achievable Control Technology (MACT) regulation in March 2011 which was finalized on December 21, 2011. This regulation prescribes reduced levels of mercury and other hazardous air pollutants pursuant to the Clean Air Act.

• As a result of events at the Fukushima Daiichi nuclear facility in Japan following the earthquake and tsunami in March 2011, the Nuclear Regulatory Commission (NRC) has been performing additional operational and safety reviews of nuclear facilities in the United States. These reviews and the lessons learned from the events in Japan will result in additional regulation for the nuclear industry and could impact future operations and capital requirements for our facilities. We believe that our nuclear plants meet the stringent applicable design and safety specifications of the NRC.

• We received our requested 20-year license extensions for the Salem and Hope Creek facilities in June and July 2011, respectively. Salem Units 1 and 2 are now licensed through 2036 and 2040, respectively, and Hope Creek is now licensed through 2046. Peach Bottom Units 2 and 3 are currently licensed through 2033 and 2034, respectively.

• During 2011, the SEC and the Commodity Futures Trading Commission (CFTC) continued efforts enact stricter regulation over swaps and derivatives. The CFTC has issued Notices of Proposed Rulemakings (NOPRs) on many of the key issues. We cannot assess the exact scope of the new rules until they are issued by the SEC and CFTC. We will carefully monitor these new rules as they are developed to analyze the potential impact on our swap and derivatives transactions, including any potential increase in our collateral requirements.

• In December 2011, New Jersey released its revised Energy Master Plan (EMP) which contains a number of policy recommendations that the State can be expected to pursue through legislative and regulatory responses. The policy recommendations supporting nuclear power, solar and wind energy, energy efficiency and natural gas infrastructure are generally favorable to our business.

• On July 21, 2011, FERC issued a Final Rule which, among other things directs regional planners such as PJM to (i) consider public policy requirements in planning new transmission, (ii) remove the Right of First Refusal (ROFR)—which permits incumbent transmission owners, like us, the first opportunity to construct transmission within their respective service territories—from its tariffs and agreements, subject to certain exceptions, and (iii) allocate costs for transmission projects in a way that roughly matches costs with benefits, while leaving flexibility to the regions to determine precise cost allocation methodologies. We cannot predict the final outcome or impact on us; however, specific implementation of the Final Rule in the various regions, including within our utility service territory, may expose us to competition for construction of transmission, additional regulatory considerations and potential delay with respect to future transmission projects.

55

Operational Excellence

Our nuclear and fossil facilities continued their strong operating performance through the fourth quarter. Our nuclear units have achieved a capacity factor of 93% for the year and our combined cycle units have continued to improve their forced outage rates. Our generation fleet performed well during the July and August heat waves. During Hurricane Irene, the Salem and Hope Creek nuclear stations remained online. Overall, generation volumes for the year 2011 were 54.0 TWh, approximately 5% lower than in 2010 due primarily to reduced demands.

In addition, we continued to demonstrate system reliability by limiting customer outages. In February 2011, our service territory experienced winter storms that affected the electric transmission and distribution systems due to heavy icing and salt spray and in March 2011, our northern gas service territory was impacted by two heavy rainstorms that resulted in widespread flooding. Our personnel were prepared in each case for widespread outages and, as a result, were able to minimize the length of time our customers were without electric or gas service.

In August 2011, Hurricane Irene caused severe damage that resulted in flooding throughout our service territory, disrupting service to over 800,000 customers. With the assistance of mutual aid crews from other utilities, our associates worked to fully restore service to the majority of our customers within five days. In October 2011, a wet heavy snow storm caused extensive tree and power line damage, disrupting service to over 570,000 customers. By seeking the assistance of other utilities, as well as hiring a significant number of contractor power line and tree crews, we restored power to most of our customers within seven days. We filed a petition with the BPU asking permission to defer the incremental storm related costs and the opportunity to seek recovery in our next base rate proceeding. We have deferred approximately $60 million of incremental Operation and Maintenance (O&M) storm costs associated with Hurricane Irene and the October snow storm.

In December 2011, the Long Island Power Authority (LIPA) selected PSEG Long Island LLC (PSEG LI), a newly formed wholly owned subsidiary of Energy Holdings, to manage its electric transmission and distribution system in Long Island, New York. LIPA issued a press release that it had selected us for a variety of reasons, including our proven track record of first quartile customer service and reliability, commitment to cost control, corporate culture of transparency and local decision making, technical expertise and proven environmental track record. The ten year contract commences January 1, 2014, after LIPA’s current contract with another party for utility services management expires. As part of the management contract, PSEG LI will be expected to develop and implement a number of operational improvements to provide safe and reliable service for LIPA’s customers, increase customer satisfaction, and manage the operational and maintenance costs of LIPA.

On January 31, 2012, we entered into a specific matter closing agreement settling our dispute with the IRS over certain challenged lease transactions. This agreement settles the leasing dispute with finality for all tax periods in which we realized tax deductions from these transactions. In addition, we signed a settlement agreement covering all audit issues for tax years 1997 through 2003. We believe that there will be no material impact on earnings as a result of these settlement agreements. For additional information, see Note 13. Commitments and Contingent Liabilities.

Financial Strength

For 2011, our cash from operations was over $3.5 billion. Cash from operations for the year has benefited from two federal tax provisions enacted in 2010 which generated a total of approximately $900 million of cash benefits for us through accelerated depreciation. See Note 20. Income Taxes for additional information. These funds, combined with proceeds from asset sales, were used to support our capital expenditures, dividend payments and pension funding for the year. During 2011, we made approximately $2.1 billion in capital expenditures and paid dividends of $693 million. On February 21, 2012, our Board of Directors approved a $0.3550 per share common stock dividend for the first quarter of 2012. This reflects an indicated annual dividend rate of $1.42 per share. The Board’s approval represents a change in our dividend policy moving from a strict earnings payout based approach to one that takes into consideration the growing contribution to earnings and cash from our regulated operations and continued cash flow from our generation business.

56

We made our entire planned pension and OPEB contributions for the year 2011 of $426 million and, as of December 31, 2011, we had funded approximately 84% of our projected benefit obligation. For 2012, we expect to fund up to $124 million and $11 million for pension and OPEB, respectively.

In December, we were also able to early redeem $600 million of 6.95% Senior Notes due in June 2012 at Power.

In April 2011, PSEG, Power and PSE&G entered into new 5-year credit agreements resulting in an increase of $650 million in Power’s credit capacity. As of December 31, 2011, our total credit capacity was $4.2 billion and we had over $800 million of cash on hand.

Disciplined Investment

We seek to invest in areas that complement our existing businesses and provide attractive risk-adjusted returns. These areas include upgrading critical energy infrastructure, responding to trends in environmental protection and providing new energy supplies in domestic markets with growing demand. We also have several projects where we are investing to continue to improve our operational performance. Over the past few years, we have shifted our focus to investing at the utility. Our capital expenditure forecast includes over $6.8 billion in spending over the next three years, over 75% of which is at PSE&G.

• During 2011, we sold our two 1,000 MW combined-cycle generating facilities in Texas in separate transactions for a total of $687 million. See Note 4. Discontinued Operations and Dispositions for further information.

• We are continuing to pursue obtaining the necessary regulatory approvals for the Susquehanna-Roseland transmission project including approval from the National Park Service (NPS), which has resulted in a delay to the project implementation date. In October 2011, the NPS issued a Draft Environmental Impact Statement (EIS), which recommended a “no action” alternative that would require re-routing of the project around the affected federal park areas. The NPS has stated that it will select a final preferred route for the project in March 2012. We have submitted comments to the draft EIS and will continue to work with the NPS on mitigation for unavoidable impacts associated with the project. The estimated cost of construction is $750 million for this project. Our project estimate will be refined when we obtain additional information from the NPS regarding mitigation-related requirements as well as contractor bids.

• In October 2010, PJM approved the North East Grid project, a 230 kV project running from Roseland to Hudson. This project has an expected in-service date of June 2015 with an estimated cost of construction of $895 million. We have also filed for BPU approval of the North-Central Reliability project, a 230 kV upgrade project located in the northern and central portions of New Jersey with an estimated cost of construction of approximately $390 million. The North-Central Reliability project has an expected in-service date of June 2014. Delays in the construction schedules of these projects could impact the timing of expected transmission revenues. The North East Grid project was approved in place of a previously approved 500 kV Branchburg-Roseland-Hudson project. On December 30, 2011, FERC granted incentive rates for the Northeast Grid project including recovery of 100% of Construction Work in Process (CWIP) in rate base and abandonment costs, along with a 25 basis point adder to ROE, with an effective date of January 1, 2012.

• In April 2011, we filed a petition with FERC seeking incentive rates with an effective date of June 14, 2011 for five 230 kV transmission projects, including the North-Central Reliability project. In June 2011, FERC granted incentive rates for three of these 230 kV projects, with a total capital investment of approximately $1.0 billion, representing approximately 80% of our request. The incentive rates include recovery for CWIP and 100% recovery of prudently-incurred abandonment costs. See Item 1. Business, Federal Regulation, Transmission Regulation—Transmission Expansion for further information.

57

• We have made additional investments in solar power in New Jersey. Under our solar loan program we have provided a total of $127 million in loans for 518 projects as of December 31, 2011, representing 38 MW to date. Under our Solar 4 All program we have made total program expenditures of approximately $361 million as of December 31, 2011. Approximately 25 MW of solar panels have been installed on distribution poles and another 33 MW representing 19 projects have been placed into service. Additional projects are in various stages of development. Our total anticipated expenditures to develop all approved 80 MW is approximately $451 million. The BPU is currently conducting a generic stakeholder proceeding, however, to examine whether utility rate-based solar programs should be modified, expanded or terminated in the future.

• We made additional expenditures under our Capital Infrastructure Programs (CIP). As of December 31, 2011, total capital expenditures since inception of these programs were $702 million and $59 million for CIP I and CIP II, respectively. In July, the BPU approved CIP II which provides for approximately $273 million in accelerated capital investments in our electric and gas infrastructure through 2012.

• We continued various construction activities at Power, including a steam path retrofit and extended power uprate at Peach Bottom and construction of new gas fired peaking units at Kearny and in Connecticut (see Note 13. Commitments and Contingent Liabilities for additional information). This additional capacity at Kearny was bid into and has cleared the RPM capacity auction, and the additional capacity in Connecticut is subject to a contract with a Connecticut utility.

• We are continuing our efforts to obtain an Early Site Permit for a new nuclear generating station to be located at the current site of Salem and Hope Creek stations. The NRC acceptance review is complete and agency evaluation is underway. There were no petitions filed for permission to intervene. The current NRC schedule would likely result in issuance of the Early Site Permit in 2014.

• In January 2012, we acquired an additional 25 MW solar project at Energy Holdings, currently under construction in Arizona. Completion of this project is expected by the third quarter of 2012. All of the energy, capacity and environmental attributes generated by the project in the first 20 years are expected to be sold under a long-term power purchase agreement. The total investment for the project will be approximately $75 million.

• As part of our ongoing efforts to focus on energy investments, in December 2011, we sold our investment in an office building in Denver, Colorado for approximately $215 million. Net proceeds from the sale were approximately $175 million. The sale resulted in an after-tax gain of $34 million.

There is no guarantee that the projects described above or any future initiatives will be achieved since many issues need to be favorably resolved, such as regulatory approvals.

As a result of Dynegy’s corporate reorganization in September 2011, Energy Holdings evaluated its likely recovery under the lease arrangements for the Roseton and Danskammer facilities leased to subsidiaries of Dynegy Holdings LLC (DH). Considering the overall value of the underlying assets subject to lease, Energy Holdings fully reserved its $264 million gross investment. This gross charge was reflected as a reduction to third quarter Operating Revenues and resulted in an after-tax charge of approximately $170 million. On November 7, 2011, DH including the lessee entities in our Danskammer and Roseton leveraged lease transactions (Dynegy leases), filed for relief under Chapter 11 of the Bankruptcy Code. DH filed a Restructuring Support Agreement (RSA) expected to become effective in August 2012 assuming confirmation of its plan of reorganization by the Bankruptcy Court.

On December 13, 2011, Energy Holdings and Dynegy reached a settlement agreement resolving disputes that had arisen between them with regard to DH’s rejection of the Dynegy leases. The settlement agreement assigns to Dynegy our rights to certain future payments or distributions related to the Dynegy leases; it also resolves our claims under our Tax Indemnity Agreement with DH. The terms of the agreement include a cash payment of $7.5 million, which was received on January 4, 2012, and the allowance of a $110 million claim against DH payable through a mix of cash and notes upon final approval of the DH reorganization. The Court approved the settlement agreement and DH’s rejection of the Dynegy leases with an effective date of December 30, 2011, triggering a write-off of the entire $264 million fully reserved gross lease receivable and the reclassification of $30 million of the deferred tax liability to current status.

58

The ultimate amount recognized from our $110 million claim could change based upon the final outcome of Dynegy’s RSA and the respective fair values of the securities received. See Note 8. Financing Receivables for further information.

RESULTS OF OPERATIONS

	Years Ended December 31,
Earnings (Losses)	2011			2010		2009
	Millions
Power	$	1,002		$	1,136	$	1,191
PSE&G (A)		521			359		325
Energy Holdings (B)		(134	)		49		72
Other (C)		18			13		6
PSEG Income from Continuing Operations		1,407			1,557		1,594
Income (Loss) from Discontinued Operations, Including Gain on Disposal (D)		96			7		(2	)
PSEG Net Income	$	1,503		$	1,564	$	1,592

	Years Ended December 31,
Earnings Per Share (Diluted)	2011		2010		2009
PSEG Income from Continuing Operations	$	2.77	$	3.07	$	3.14
Income from Discontinued Operations, Including Gain on Disposal (D)		0.19		0.01		0.00
PSEG Net Income	$	2.96	$	3.08	$	3.14

(A) PSE&G’s results in 2010 include an after-tax charge of $72 million related to an agreement to refund previous Market Transition Charge (MTC) collections in the succeeding two years.

(B) Energy Holdings’ results include an after-tax charge of $170 million taken in 2011 related to the reserve for assets underlying a leveraged lease receivable. See Item 8. Financial Statements and Supplementary Data—Note 8. Financing Receivables.

(C) Other includes parent company interest and financing costs, donations, certain administrative and general expenses and certain consolidating entries related to a debt exchange in 2009 between Power and Energy Holdings.

(D) See Item 8. Financial Statements and Supplementary Data—Note 4. Discontinued Operations and Dispositions.

Our results include the realized gains, losses and earnings on Power’s Nuclear Decommissioning Trust (NDT) Fund and other related NDT activity. This includes the net realized gains, interest and dividend income and other costs related to the NDT Fund which are recorded in Other Income and Deductions. This also includes credit-related impairments on certain NDT securities which are included in Other-Than-Temporary Impairments and the interest accretion expense on Power’s nuclear asset retirement obligation (ARO), which is recorded in Operation and Maintenance Expense and the depreciation related to the ARO. The combined after-tax impact on earnings of this activity for the years ended December 31, 2011, 2010 and 2009 is shown in the chart below along with the after-tax impacts of mark-to-market (MTM) activity:

	Millions, after tax
Years Ended December 31,	2011		2010			2009
NDT Fund Income	$	50	$	46		$	9
Non-Trading Mark-to-Market Gains (Losses)	$	107	$	(1	)	$	(11	)

59

PSEG

Our results of operations are primarily comprised of the results of operations of our operating subsidiaries, Power, PSE&G and Energy Holdings, excluding changes related to intercompany transactions, which are eliminated in consolidation. We also include certain financing costs, charitable contributions and general and administrative costs at the parent company. For additional information on intercompany transactions, see Item 8. Financial Statements and Supplementary Data—Note 23. Related-Party Transactions.

	For the Years Ended December 31,							Increase / (Decrease) 2011 vs 2010						Increase / (Decrease) 2010 vs 2009
	2011		2010		2009
	Millions							Millions			%			Millions			%
Operating Revenues	$	11,079	$	11,793	$	12,035		$	(714	)		(6	)	$	(242	)		(2	)
Energy Costs		4,747		5,261		5,433			(514	)		(10	)		(172	)		(3	)
Operation and Maintenance		2,481		2,504		2,534			(23	)		(1	)		(30	)		(1	)
Depreciation and Amortization		976		955		819			21			2			136			17
Income from Equity Method Investments		4		4		17			0			0			(13	)		(76	)
Other Income and (Deductions)		135		158		85			(23	)		(15	)		73			86
Other-Than-Temporary Impairments		22		11		61			11			100			(50	)		(82	)
Interest Expense		475		472		521			3			1			(49	)		(9	)
Income Tax Expense		977		1,059		1,042			(82	)		(8	)		17			2
Income from Discontinued Operations, including Gain on Disposal, net of tax		96		7		(2	)		89			N/A			9			N/A

The 2011 year-over-year decrease in our Income from Continuing Operations was driven by the following:

• $170 million after-tax charge taken in 2011 on leveraged leases related to Dynegy (see Item 8. Financial Statements and Supplementary Data—Note 8. Financing Receivables),

• the absence of an after-tax charge of $72 million related to an agreement to refund previous Market Transition Charge (MTC) collections in the succeeding two years,

• lower average pricing and volumes for electricity sold under our BGS contracts,

• lower realized prices and/or lower sales volumes in the various power pools,

• higher interest costs and depreciation expense related to the completion of installation of back-end technology at two of our fossil plants, and

• the absence of realized gains recognized in 2010 due to restructuring of the investments in our Rabbi Trust.

The decreases were partially offset by:

• favorable amounts related to the MTM activity reported above,

• an increase in revenues from new wholesale contracts entered into in the first half of 2011, and

• lower Operation and Maintenance costs primarily due to lower pension and OPEB costs.

The 2010 year-over-year decrease in our Income from Continuing Operations was driven by the following:

• higher priced sales under our BGS contracts being replaced with comparatively lower priced sales into the various power pools and under new wholesale contracts entered into during 2010 as a result of customer migration,

• losses on certain wholesale electric energy supply contracts,

• the aforementioned $72 million after-tax charge recorded in June related to MTC,

• lower gas sales volumes and pricing due to milder winter weather and economic conditions, and

• lower gains on lease sales.

60

The decreases were partially offset by:

• higher electric sales volumes and market pricing due primarily to warmer summer weather,

• higher electric delivery revenues due to our base rate increase approved in June,

• lower interest expenses, and

• realized gains related to the restructuring of the investments in our Rabbi Trust.

For a detailed explanation of the variances, see the discussions for Power, PSE&G and Energy Holdings below.

Power

	For the Years Ended December 31,							Increase/ (Decrease)			Increase/ (Decrease)
	2011		2010		2009			2011 vs 2010			2010 vs 2009
	Millions
Income from Continuing Operations	$	1,002	$	1,136	$	1,191		$	(134	)	$	(55	)
Income (Loss) from Discontinued Operations, net of tax		96		7		(2	)		89			9
Net Income	$	1,098	$	1,143	$	1,189		$	(45	)	$	(46	)

For the year ended December 31, 2011, the primary reasons for the decrease in Income from Continuing Operations were

• lower average pricing and lower volumes of electricity sold under our BGS contracts, as a result of customer migration,

• higher Operation and Maintenance expense related to planned outage work at certain of our fossil plants, and

• higher depreciation expense related to the completion of installation of back-end technology at two of our fossil plants.

The decreases were partially offset by

• favorable amounts related to the MTM activity,

• favorable results from our coal optimization efforts, and

• an increase from new wholesale contracts entered into in the first half of 2011.

For the year ended December 31, 2010, the primary reasons for the decrease in Income from Continuing Operations were

• higher priced sales under our BGS contracts being replaced with comparatively lower priced sales into the various power pools and under new wholesale contracts entered into during 2010 as customer migration levels have increased, and

• losses on certain wholesale electric energy supply contracts.

The decreases were partially offset by

• favorable amounts related to our NDT and MTM activity, discussed previously,

• higher volumes of generation sold at higher market prices in PJM due to warmer summer weather, and

• realized gains on the investments in our Rabbi Trust.

61

The year-over-year detail for these variances for these periods is discussed below:

	For the Years Ended December 31,							Increase / (Decrease) 2011 vs 2010						Increase / (Decrease) 2010 vs 2009
Power	2011		2010		2009
	Millions							Millions			%			Millions			%
Operating Revenues	$	6,143	$	6,558	$	6,772		$	(415	)		(6	)	$	(214	)		(3	)
Energy Costs		3,046		3,374		3,462			(328	)		(10	)		(88	)		(3	)
Operation and Maintenance		1,102		1,046		1,045			56			5			1			0
Depreciation and Amortization		224		175		184			49			28			(9	)		(5	)
Other Income (Deductions)		111		117		98			(6	)		(5	)		19			19
Other-Than-Temporary Impairments		20		9		60			11			122			(51	)		(85	)
Interest Expense		175		157		161			18			11			(4	)		(2	)
Income Tax Expense		685		778		767			(93	)		(12	)		11			1
Income (Loss) from Discontinued Operations		96		7		(2	)		89			N/A			9			N/A

For the year ended December 31, 2011 as compared to 2010

Operating Revenues decreased $415 million due to

Gas Supply Revenues decreased $290 million due primarily to

• a net decrease of $283 million in sales under the BGSS contract, substantially comprised of lower average gas prices on lower volumes of sales in 2011 due to warmer average temperatures during the fourth quarter of 2011,

• a net decrease of $7 million due primarily to lower average gas prices partially offset by higher sales volumes to third party customers.

Generation Revenues decreased $143 million due primarily to

• a net decrease of $305 million due primarily to lower average pricing and lower volumes of electricity sold under our BGS contracts as a result of customer migration,

• a decrease of $70 million due primarily to lower capacity payments from the various power pools resulting from lower market prices, and

• a decrease of $8 million due to lower operating reserve revenue in 2011.

These were partially offset by

• an increase of $136 million from new wholesale load contracts in the PJM and New England (NE) regions commencing in January 2011 and April 2011, respectively, net of lower average realized prices in the NE region, and

• higher net revenues of $108 million due primarily to MTM gains on economic hedging activity of $228 million, partially offset by lower realized prices in the PJM and NY power pools and lower volumes of generation sold in the PJM and NE power pools of $120 million.

Trading Revenues increased $18 million due primarily to lower net losses in 2011 on certain electric energy supply contracts as well as the discontinuation of trading activities in the second quarter of 2011.

62

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel purchases for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $328 million due to

• Gas costs decreased $282 million, principally related to obligations under the BGSS contract, reflecting lower average gas inventory costs coupled with lower sales volumes in 2011 due to warmer average temperatures during the fourth quarter of 2011.

• Generation costs decreased by $46 million due primarily to $211 million of lower fuel costs, including $251 million of lower fossil fuel costs primarily reflecting the utilization of lower volumes of both coal and oil, favorable results from our coal optimization efforts, and lower natural gas prices, partially offset by higher MTM losses and higher nuclear fuel costs in 2011. The decrease was also attributable to $16 million of lower emission charges, including $10 million of lower impairment charges related to excess SO₂ emission allowances. These decreases were partially offset by an increase of $153 million in higher energy purchases in 2011 in the PJM and NE power pools as the result of lower generation and the need to meet higher load contract demand in 2011 and $23 million of higher operating reserve obligations in the PJM region.

Operation and Maintenance increased $56 million due primarily to

• a net increase of $47 million due largely to planned outage costs, including hot gas path inspection outage costs at our gas-fired BEC and Linden facilities as well as higher outage costs at our gas-fired Bergen facility, coal-fired Mercer facility in New Jersey and our coal-fired Keystone facility in Pennsylvania, partially offset by higher outage and repair costs at certain of our other fossil plants in 2010,

• $20 million of costs incurred for the cancellation and renegotiation of a major contractual agreement for parts and services for our combined cycle Bethlehem Energy (BEC) facility in New York and Linden and Bergen facilities in New Jersey, and

• a net increase of $3 million due to refurbishment projects at our Salem nuclear facilities,

• partially offset by a decrease of $13 million due to a decrease in pension and OPEB costs tempered by higher labor costs and incentive awards.

Depreciation and Amortization increased $49 million due primarily to

• a $37 million increase due to completion of installation of back-end technology at the end of 2010 at our Mercer and Hudson generating facilities, and

• a $12 million increase due to higher depreciable asset bases at Nuclear and Fossil.

Other Income and (Deductions) The net decrease of $6 million was due primarily to

• a $17 million premium paid on the early extinguishment of 6.95% Senior Notes due in June 2012, and

• the absence of $7 million of gains realized in 2010 from restructuring the Rabbi Trust,

• partially offset by higher net realized gains of $19 million on our NDT Fund.

Other-Than-Temporary Impairments increased $11 million due primarily to higher impairments on the NDT Fund in 2011.

Interest Expense increased $18 million due primarily to

• Higher interest expense of $49 million resulting primarily from the installation by year-end 2010 of back-end technology at our Mercer and Hudson fossil stations for which we had been allowed to capitalize interest costs in 2010 while such projects were under construction,

• partially offset by lower interest expense of $30 million due primarily to the redemption of $606 million of 7.75% Senior Notes in early April 2011 and lower debt issuance costs of $3 million.

Income Tax Expense decreased $93 million in 2011 due primarily to lower pre-tax income.

63

Income (Loss) from Discontinued Operations

In 2011, we sold our two 1,000 MW combined-cycle generating facilities in Texas in separate transactions. In March 2011, we completed the sale of one plant for proceeds of $352 million at an after-tax gain of $54 million. In July, we completed the sale of the second plant for proceeds of $335 million at an after-tax gain of $25 million. The results of operations for both plants for 2011 and 2010, including the gains in 2011 on the sales of the plants, are included in this category. See Item 8. Financial Statements and Supplementary Data—Note 4. Discontinued Operations and Dispositions for additional information.

For the year ended December 31, 2010 as compared to 2009

Operating Revenues decreased $214 million due to

Gas Supply Revenues decreased $296 million

• including a net decrease of $304 million in sales under the BGSS contract, substantially comprised of lower average gas prices on lower volumes of sales in 2010 as well as lower net gains on financial hedging transactions in 2010,

• partially offset by a net increase of $8 million due to higher average gas prices on reduced sales volumes to third party customers.

Trading Revenues decreased $86 million due primarily to net losses on certain electric energy supply contracts in 2010 partly offset by losses on certain gas supply contracts realized in 2009 that expired in December 2009.

Generation Revenues increased $168 million due primarily to

• increased net revenues of $161 million due to higher average realized prices offset by lower volumes of generation sold in the PJM power pool,

• an increase of $166 million from new wholesale load contracts in PJM commencing in January 2010, and

• an increase of $20 million in capacity payments largely due to changes in PJM’s capacity market,

• partially offset by a net decrease of $184 million due primarily to lower volumes of electricity sold under our BGS contracts as a result of customer migration.

Operating Expenses

Energy Costs decreased by $88 million due to

• Gas costs decreased $294 million, principally related to Power’s obligations under the BGSS contract, reflecting lower average gas inventory costs and lower demand.

• Generation costs increased $206 million due primarily to $208 million of higher fossil fuel costs, primarily reflecting the utilization of higher volumes of both coal and natural gas, $22 million of higher net energy purchases due to higher purchases in the PJM region to meet higher load contract demand in 2010 offset by lower energy purchases in the NE region driven by the expiration of certain contracts in 2010, $15 million of higher nuclear fuel costs as a result of higher prices, and an $18 million impairment charge in 2010 related to forecasted excess SO₂ emissions allowances. These increases were partially offset by $40 million of lower congestion charges and $28 million of lower purchases of firm transmission rights in PJM in 2010.

Operation and Maintenance experienced no material change.

Depreciation and Amortization decreased $9 million due primarily to a $19 million decrease due to an extension of the remaining useful lives of the Mercer and Hudson generating facilities resulting from significant plant upgrades as well as revisions in assumptions regarding the decommissioning of our plants. This was partially offset by

• an increase of $7 million due to pollution control equipment being placed into service in October 2009 at our Keystone station, and

64

• an increase of $4 million due to a reversal of depreciation expense in September 2009 related to the reimbursement of previously capitalized storage costs for spent nuclear fuel resulting from a favorable settlement for such costs by the U.S. Department of Energy (DOE).

Other Income and (Deductions)—The net increase of $19 million was due primarily to

• $10 million of lower purchases of New Jersey net operating losses related to the state corporate business tax,

• a $7 million gain realized on the investments in our Rabbi Trust, and

• a $4 million increase in net earnings related to our NDT Fund.

Other-Than-Temporary Impairments decreased $51 million due to the lower charges in 2010 related to certain NDT Fund securities.

Interest Expense decreased $4 million due to

• higher capitalized interest of $21 million due primarily to an increased level of projects under construction in 2010,

• partially offset by higher net interest costs of $15 million related to higher interest and debt issuance costs related to $303 million of Senior Notes issued in September 2009 as part of a debt exchange with Energy Holdings, partly offset by the effects of the early redemption of two medium-term note obligations and a note exchange that all occurred in April 2010, and an increase of $2 million in credit facility fees.

Income Tax Expense increased $11 million in 2010 due primarily to

• an increase of $18 million due to lower manufacturer’s deductions under the American Jobs Creation Act of 2004, primarily caused by lower taxable income due to increased bonus depreciation allowed by the passage in 2010 of tax law changes,

• an increase of $8 million due to the impacts of new health care legislation (see Item 8. Financial Statements and Supplementary Data -Note 20. Income Taxes), and

• a net increase of $3 million related to prior year adjustments, state taxes, the NDT Fund and other miscellaneous adjustments,

• partially offset by a decrease of $18 million due to lower pre-tax income.

Income (Loss) from Discontinued Operations

As discussed above, we sold our two Texas plants in March 2011 and July 2011, respectively. The results of operations for both plants for 2010 and 2009 are included in this category. See Item 8. Financial Statements and Supplementary Data—Note 4. Discontinued Operations and Dispositions for additional information.

PSE&G

	For the Years Ended December 31,						Increase/ (Decrease)		Increase/ (Decrease)
	2011		2010		2009		2011 vs 2010		2010 vs 2009
	Millions
Income from Continuing Operations	$	521	$	359	$	325	$	162	$	34
Net Income	$	521	$	359	$	325	$	162	$	34

For the year ended December 31, 2011, the primary reasons for the increase in Income from Continuing Operations were

• the absence of a $72 million after-tax charge recorded in June 2010 related to the refund of previous MTC collections,

65

• higher annualized base rates for electric and gas delivery as well as transmission, and

• lower Operation and Maintenance expense, largely due to lower pension and OPEB costs.

For the year ended December 31, 2010, the primary reasons for the increase in Income from Continuing Operations were

• higher base rates for electric and gas delivery as well as transmission,

• higher revenues from our Capital Economic Stimulus Infrastructure and Regional Greenhouse Gas Initiative (RGGI) programs, and

• higher electric delivery volume.

The increases were partially offset by

• the $72 million after-tax MTC charge in 2010, and

• lower gas sales volumes due to milder winter weather.

The year-over-year details for these variances for these periods are discussed below:

	For the Years Ended December 31,						Increase/ (Decrease)						Increase/ (Decrease)
PSE&G	2011		2010		2009		2011 vs 2010						2010 vs 2009
	Millions						Millions			%			Millions			%
Operating Revenues	$	7,326	$	7,869	$	8,243	$	(543	)		(7	)	$	(374	)		(5	)
Energy Costs		3,951		4,655		5,170		(704	)		(15	)		(515	)		(10	)
Operation and Maintenance		1,372		1,442		1,474		(70	)		(5	)		(32	)		(2	)
Depreciation and Amortization		719		750		608		(31	)		(4	)		142			23
Other Income and (Deductions)		21		23		5		(2	)		(9	)		18			N/A
Other-Than-Temporary Impairments		1		0		0		1			N/A			0			0
Interest Expense		310		318		312		(8	)		(3	)		6			2
Income Tax Expense		340		232		226		108			47			6			3

For the year ended December 31, 2011 as compared to 2010

Operating Revenues decreased $543 million due primarily to

Commodity Revenue decreased $704 million due to lower Electric and Gas revenues. This is entirely offset as savings in Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS.

• Electric revenues decreased $397 million due primarily to $466 million in lower BGS revenues, partially offset by $69 million in higher revenues from the sale of Non-Utility (NUG) energy and collections of Non-Utility Generation Charges (NGC) due primarily to higher prices. BGS sales decreased 16% due primarily to customer migration to third party suppliers (TPS); in contrast, delivery sales decreased only 2%.

• Gas revenues decreased $307 million due to lower BGSS prices of $259 million and lower BGSS volumes of $48 million. The average price of gas was 3% lower in 2011 than in 2010.

Delivery Revenues increased $74 million due primarily to an increase in prices for electric and gas distribution and transmission.

• Transmission revenues were $42 million higher due primarily to net rate increases.

• Gas distribution revenues increased $32 million due primarily to higher Weather Normalization Clause revenue of $19 million and the impact of base rate increases of $17 million, partially offset by lower capital stimulus revenue of $5 million. The lower stimulus revenue is offset by a deferral in O&M.

• Electric distribution revenues were flat due primarily to the impact of base rate increases of $17 million and higher stimulus revenue of $1 million, offset by lower sales volumes of $18 million. The lower stimulus revenue is offset by a deferral in O&M.

66

Clause Revenues increased $73 million due primarily to the absence of $122 million charge recorded in June 2010 related to our agreement to refund previous MTC collections over two years and higher Societal Benefit Charges (SBC) and Margin Adjustment Clause (MAC) of $49 million, partially offset by lower STC revenues of $98 million. The changes in Securitization Transition Charge (STC), SBC and MAC amounts were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, Depreciation and Amortization and Interest Expense. PSE&G earns no margins on SBC, STC or MAC collections.

Other Operating Revenues increased $14 million due primarily to increased revenues from our appliance repair business and miscellaneous electric operating revenues.

Energy Costs decreased $704 million. This is entirely offset by Commodity Revenue. Details are as follows:

• Electric costs decreased $397 million due to $405 million or 14% in lower BGS and NUG volumes due to customer migration to TPS and $75 million of lower BGS and NUG prices, partially offset by $83 million for increased deferred cost recovery.

• Gas costs decreased $307 million due to $259 million or 16% in lower prices and $48 million or 3% in lower sales volumes due primarily to weather.

Operation and Maintenance decreased $70 million due primarily to

• a $71 million decrease in pension and other postretirement benefits (OPEB) expenses,

• $20 million of lower net deferred expenses associated with SBC, RGGI and Stimulus clauses, and

• the absence of $15 million in expenses relating to 2010 rate case disallowances.

These were partially offset by

• a $9 million increase in storm restoration work,

• a $6 million increase in costs relating to tree trimming,

• a $3 million increase in bad debt expense, and

• a $3 million increase in incentive payments.

Depreciation and Amortization decreased $31 million due primarily to

• a decrease of $63 million for amortization of Regulatory Assets,

• partially offset by an increase of $28 million for additional plant in service, and an increase of $3 million in net other charges.

Other Income and (Deductions) experienced no material change.

Other-Than-Temporary Impairments experienced no material change.

Interest Expense decreased $8 million due primarily to lower average debt balances.

Income Tax Expense increased $108 million due primarily to higher pre-tax income.

For the year ended December 31, 2010 as compared to 2009

Operating Revenues decreased $374 million due primarily to

Commodity Revenue decreased $515 million due to lower Electric and Gas revenues. This is entirely offset as savings in Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS.

• Gas revenues decreased $291 million due to decreased BGSS prices of $206 million and lower BGSS volumes of $85 million due to warmer weather and economic conditions. The average price of gas was 11% lower in 2010 than in 2009.

• Electric revenues decreased $224 million due primarily to $339 million in lower BGS revenues, partially offset by $115 million in higher revenues from the sale of NUG energy and collections of NGCs due primarily to higher prices. BGS sales were down 9% due primarily to large customer migration to TPS; in contrast delivery sales were up 5% due to warmer weather.

67

Clause Revenues decreased by $45 million due primarily to the MTC refund of $122 million and the Gas Weather Normalization deferral of $9 million, which were partially offset by higher STC revenues of $86 million. The Electric Societal Benefit Charge SBC was $8 million higher, offset by lower Gas SBC of $8 million. The changes in STC and SBC amounts were entirely offset by the amortization of related costs (Regulatory Assets) in Operation and Maintenance, Depreciation and Amortization and Interest. PSE&G earns no margins on SBC or STC collections.

Delivery Revenues increased $170 million due primarily to an increase in prices for electric and gas distribution and transmission.

• Electric distribution revenues were up $137 million due primarily to higher sales volumes of $54 million, the impact of the June base rate increases of $49 million, stimulus revenue increases of $17 million and RGGI revenue increases of $17 million.

• Transmission revenues were up $29 million due primarily to net rate increases.

• Gas distribution revenues were up $4 million due primarily to the impact of the July base rate increase of $8 million, capital stimulus revenue increase of $6 million and RGGI revenue increase of $5 million, partially offset by lower sales volumes of $15 million.

Other Operating Revenues increased $16 million due primarily to increased revenues from our appliance repair business and miscellaneous electric operating revenues.

Energy Costs decreased $515 million. This is entirely offset by Commodity Revenue. Details are as follows:

• Gas costs decreased $291 million due to $206 million or 11% in lower prices and by $85 million or 5% in lower sales volumes due primarily to warmer weather and economic conditions.

• Electric costs decreased $224 million due to $261 million or 8% in lower BGS and NUG volumes due to large customer migration to TPS and warmer weather, partially offset by $37 million of higher BGS and NUG prices.

Operation and Maintenance decreased $32 million due to

• a $54 million decrease in electric and gas operating expenses due primarily to our overall cost reduction efforts, and

• a $12 million reduction in bad debt expense.

These were partially offset by

• a $14 million write-off of deferred costs associated with a new customer accounting system,

• $11 million in storm restoration work, and

• a net $9 million of higher expenses associated with SBC, STC, RGGI and Stimulus clauses.

Depreciation and Amortization increased $142 million due primarily to

• an increase of $116 million for amortization of Regulatory Assets,

• an increase of $15 million for additional plant in service,

• a net increase of $6 million relating to various adjustments, and

• an increase of $5 million in software amortization.

Other Income and (Deductions)—The net increase of $18 million was due primarily to $11 million of gains realized on the investments in our Rabbi Trust, a $5 million increase in Solar Loan interest income and a $5 million increase in capitalized allowance for Equity Funds used during construction, partially offset by $3 million of various other items.

Interest Expense increased by $6 million due primarily to new debt issued in 2010.

Income Tax Expense increased by $6 million due primarily to higher pre-tax income, partially offset by flow-through tax benefits primarily related to uncollectible accounts and other adjustments.

68

Energy Holdings

	For the Years Ended December 31,							Increase/ (Decrease)			Increase/ (Decrease)
	2011			2010		2009		2011 vs 2010			2010 vs 2009
	Millions
Income (Loss) from Continuing Operations	$	(134	)	$	49	$	72	$	(183	)	$	(23	)
Net Income (Loss)	$	(134	)	$	49	$	72	$	(183	)	$	(23	)

For the year ended December 31, 2011, the primary reason for the decrease in Income from Continuing Operations was

• the $170 million after-tax charge on leveraged leases related to Dynegy (see Item 8. Financial Statements and Supplementary Data—Note 8. Financing Receivables).

For the year ended December 31, 2010, the primary reasons for the decrease in Income from Continuing Operations were

• lower gains on the sales of leveraged lease assets, and

• asset impairment charges (see Item 8. Financial Statements and Supplementary Data -Note 17. Fair Value Measurements),

• partially offset by a gain on the sale of real estate assets and the absence of the premium paid on the debt exchange with Power in 2009.

LIQUIDITY AND CAPITAL RESOURCES

The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions, where material, of our three direct operating subsidiaries.

Financing Methodology

Our capital requirements are met through internally generated cash flows and external financings, consisting of short-term debt for working capital needs and long-term debt and equity for capital investments.

PSE&G’s sources of external liquidity include a $600 million multi-year syndicated credit facility. PSE&G’s commercial paper program is the primary vehicle for meeting seasonal, intra-month and temporary working capital needs. PSE&G does not engage in any intercompany borrowing or lending. PSE&G maintains back-up facilities in an amount sufficient to cover 100% of commercial paper outstanding. PSE&G’s dividend payments to PSEG are consistent with its capital structure objectives which have been established to maintain investment grade credit ratings. PSE&G’s long-term financing plan is designed to replace maturities, fund a portion of its capital program and manage short-term debt balances. Generally, PSE&G uses either secured medium-term notes or first mortgage bonds to raise long-term capital.

PSEG, Power, Energy Holdings and PSEG Services Corporation participate in a corporate money pool, an aggregation of daily cash balances designed to efficiently manage their respective short-term liquidity needs. Energy Holdings has historically lent to the money pool; its primary source of liquidity is its invested balance with PSEG. PSEG’s sources of external liquidity include multi-year syndicated credit facilities totaling $977 million. These facilities are available to back-stop PSEG’s commercial paper program, issue letters of credit and for general corporate purposes. These facilities may also be used to provide support to Power for the issuance of letters of credit. PSEG’s credit facilities and the commercial paper program are available to support PSEG working capital needs or to temporarily fund growth opportunities in advance of obtaining permanent financing. From time to time, PSEG may make equity contributions or provide credit support to its subsidiaries.

69

Power’s sources of external liquidity include $2.6 billion of syndicated multi-year credit facilities. Additionally, from time to time, Power maintains bilateral credit agreements designed to enhance its liquidity position. Credit capacity is primarily used to provide collateral in support of hedging activities and to meet potential collateral postings in the event of a credit rating downgrade below investment grade. Power’s dividend payments to PSEG are also designed to be consistent with its capital structure objectives which have been established to maintain investment grade credit ratings and provide sufficient financial flexibility. Generally, Power issues senior unsecured debt to raise long-term capital.

Operating Cash Flows

We expect our operating cash flows combined with cash on hand and financing activities to be sufficient to fund capital expenditures and shareholder dividend payments.

For the year ended December 31, 2011, our operating cash flow increased by $1,393 million. For the year ended December 31, 2010, our operating cash flow increased by $309 million. The net changes were due to net changes from our subsidiaries as discussed below.

Power

Power’s operating cash flow increased $246 million from $1,566 million to $1,812 million for the year ended December 31, 2011, as compared to 2010, primarily resulting from

• an increase of $368 million due to lower tax payments, primarily related to the benefits of accelerated tax depreciation under new tax provisions enacted in 2010 (see Item 8. Financial Statements and Supplementary Data—Note 20. Income Taxes for additional information), and

• a $302 million increase from net collection of counterparty receivables.

These were partially offset by:

• a $171 million increase in net payment of counterparty payables,

• a $161 million net increase in spending on fuel inventories, and

• lower earnings.

Power’s operating cash flow decreased $92 million from $1,658 million to $1,566 million for the year ended December 31, 2010, as compared to 2009, primarily resulting from lower earnings for the year combined with

• a $214 million decrease from net collection of counterparty receivables, and

• an increase of $60 million in net cash collateral payments,

• partially offset by an increase of $132 million from lower net payments of counterparty payables.

PSE&G

PSE&G’s operating cash flow increased $765 million from $1,011 million to $1,776 million for the year ended December 31, 2011 as compared to 2010, due primarily to higher earnings combined with

• an increase of $587 million due to lower tax payments, primarily related to the benefits of accelerated tax depreciation under new tax provisions enacted in 2010 (see Item 8. Financial Statements and Supplementary Data—Note 20. Income Taxes for additional information), and

• an increase of $273 million due to higher collections of customer receivables,

• partially offset by a decrease of $108 million in net other working capital.

PSE&G’s operating cash flow increased $54 million from $957 million to $1,011 million for the year ended December 31, 2010 as compared to 2009, due primarily to higher earnings combined with

• a $142 million increase in depreciation and amortization due to higher collections of securitized costs and amounts related to plant additions,

70

• a $102 million net increase in other working capital including increased customer advances, increased collections for TPS and lower injuries and damages, and

• partially offset by $173 million in lower collections of customer receivables, and $47 million in lower net collection of deferred expenses, primarily the SBC and MTC refund.

Energy Holdings

Energy Holdings’ operating cash flow increased $341 million for the year ended December 31, 2011, as compared to 2010, primarily due to lower tax payments in 2011 related to the absence of lease sale activity in 2011.

Energy Holdings’ operating cash flow increased by $389 million for the year ended December 31, 2010, as compared to 2009. The increase was mainly attributable to lower tax payments in 2010 due to reduced lease sale activity and a $140 million additional tax deposit made with the IRS in June 2009.

Short-Term Liquidity

We continually monitor our liquidity and seek to add capacity as needed to meet our liquidity requirements. Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. Our total credit facilities and available liquidity as of December 31, 2011 were as follows:

Company/Facility			As of December 31, 2011
	Total Facility		Usage		Available Liquidity
	Millions
PSEG	$	977	$	12	$	965
Power		2,625		175		2,450
PSE&G		600		0		600
Total	$	4,202	$	187	$	4,015

As of December 31, 2011, our total credit facility capacity was in excess of our anticipated maximum liquidity requirements through 2012. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities and Note 14. Schedule of Consolidated Debt.

Long-Term Debt Financing

Power has $66 million of 5.00% Pollution Control Notes maturing in March 2012. PSE&G has $300 million of 5.13% Medium Term Notes maturing in September 2012.

For a discussion of our long-term debt transactions during 2011 and into 2012, see Item 8. Financial Statements and Supplementary Data—Note 14. Schedule of Consolidated Debt.

Debt Covenants

Our credit agreements may contain maximum debt to equity ratios and other restrictive covenants and conditions to borrowing. We are currently in compliance with all of our debt covenants. Continued compliance with applicable financial covenants will depend upon our future financial position, level of earnings and cash flows, as to which no assurances can be given.

71

In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements, provided that its ratio of earnings to fixed charges calculated in accordance with its Mortgage is at least 2 to 1, and/or against retired Mortgage Bonds. As of December 31, 2011, PSE&G’s Mortgage coverage ratio was 4.8 to 1 and the Mortgage would permit up to approximately $2.7 billion aggregate principal amount of new Mortgage Bonds to be issued against additions and improvements to its property.

Default Provisions

Our bank credit agreements and indentures contain various default provisions that could result in the potential acceleration of payment under the defaulting company’s agreement. We have not defaulted under these agreements.

PSEG’s bank credit agreements contain cross default provisions under which events at Power or PSE&G, including payment defaults, bankruptcy events, the failure to satisfy certain final judgments or other events of default under their financing agreements, would each constitute an event of default. Under the bank credit agreements, it would be an event of default if both Power and PSE&G cease to be wholly owned by PSEG.

There are no cross default provisions to affiliates in Power’s or PSE&G’s credit agreements or indentures.

Ratings Triggers

Our debt indentures and credit agreements do not contain any material ‘ratings triggers’ that would cause an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a downgrade, any one or more of the affected companies may be subject to increased interest costs on certain bank debt and certain collateral requirements. In the event that we are not able to affirm representations and warranties on credit agreements, lenders would not be required to make loans.

Fluctuations in commodity prices or a deterioration of Power’s credit rating to below investment grade could increase Power’s required margin postings under various agreements entered into in the normal course of business. Power believes it has sufficient liquidity to meet the required posting of collateral which would likely result from a credit rating downgrade at today’s market prices.

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

PSE&G is the servicer for the bonds issued by PSE&G Transition Funding LLC and PSE&G Transition Funding II LLC. Cash collected by PSE&G to service these bonds is commingled with PSE&G’s other cash until it is remitted to the bond trustee each month. If PSE&G were to lose its investment grade rating, PSE&G would be required to remit collected cash daily to the bond trustee. PSE&G is prohibited from advancing its own funds to make payments related to such bonds.

Common Stock Dividends

	For the Years Ended December 31,
Dividend Payments on Common Stock	2011		2010		2009
Per Share	$	1.37	$	1.37	$	1.33
in Millions	$	693	$	693	$	673

On February 21, 2012, our Board of Directors approved a $0.3550 per share common stock dividend for the first quarter of 2012. This reflects an indicated annual dividend rate of $1.42 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors may deem relevant.

72

Credit Ratings

If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Outlooks assigned to ratings are as follows: stable, negative (Neg) or positive (Pos). There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security. In April 2011, S&P published an updated credit opinion which left the ratings for PSEG, Power and PSE&G unchanged and improved their outlooks to positive from stable. In May 2011, Moody’s affirmed its ratings for PSEG, Power and PSE&G. PSE&G’s outlook was improved to positive from stable while the outlooks at PSEG and Power remain at stable. In August 2011, Fitch affirmed its ratings for PSEG, Power and PSE&G and kept all outlooks at stable. In October 2011, S&P published updated research on Power and PSE&G, which left their respective ratings and outlooks unchanged. In December 2011, S&P published updated research on PSEG, which left its ratings and outlook unchanged.

	Moody’s(A)	S&P(B)	Fitch(C)
PSEG:
Outlook	Stable	Positive	Stable
Commercial Paper	P2	A2	F2
Power:
Outlook	Stable	Positive	Stable
Senior Notes	Baa1	BBB	BBB+
PSE&G:
Outlook	Positive	Positive	Stable
Mortgage Bonds	A2	A–	A
Commercial Paper	P2	A2	F2

(A) Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities.

(B) S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities.

(C) Fitch ratings range from AAA (highest) to D (lowest) for long-term securities and F1 (highest) to D (lowest) for short-term securities.

Other Comprehensive Income

For the year ended December 31, 2011, we had Other Comprehensive Loss of $181 million on a consolidated basis. Other Comprehensive Loss was due primarily to $80 million of unrealized losses on derivative contracts accounted for as hedges, a $62 million increase in our consolidated liability for pension and postretirement benefits and $39 million of net unrealized losses related to Available-for-Sale Securities.

73

CAPITAL REQUIREMENTS

It is expected that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. Projected capital construction and investment expenditures, excluding nuclear fuel purchases, for the next three years are presented in the table below. These amounts are subject to change, based on various factors. We will continue to approach non-regulated solar and other renewables investments opportunistically, seeking projects that will provide attractive risk-adjusted returns for our shareholders.

	2012		2013		2014
Power:			Millions
Baseline Maintenance	$	330	$	185	$	175
Environmental/Regulatory		70		95		80
Fossil Growth Opportunities		65		0		0
Nuclear Expansion		75		120		120
Total Power	$	540	$	400	$	375
PSE&G:
Transmission
Reliability Enhancements	$	870	$	1,165	$	1,015
Facility Replacement		115		140		175
Support Facilities		10		15		10
Distribution
Reliability Enhancements		200		75		80
Facility Replacement		265		135		135
Support Facilities		45		40		60
New Business		120		130		130
Environmental/Regulatory		30		30		30
Renewables/EMP		250		60		25
Total PSE&G	$	1,905	$	1,790	$	1,660
Non-Utility Renewables		75		0		0
Other		45		40		30
Total PSEG	$	2,565	$	2,230	$	2,065

Power

Power’s projected expenditures for the various items listed above are primarily comprised of the following:

• Baseline Maintenance—investments to replace major parts and enhance operational performance.

• Environmental/Regulatory—investments made in response to environmental, regulatory or legal mandates.

• Fossil Growth Opportunities—investments associated with potential opportunities to build other new plants, such as peaking facilities.

• Nuclear Expansion—investments associated with various capital projects at existing facilities to either extend plants’ useful lives or increase operating output.

In 2011, Power made $563 million of capital expenditures, including interest capitalized during construction (IDC) but excluding $194 million for nuclear fuel, primarily related to various projects at Fossil and Nuclear.

74

PSE&G

PSE&G’s projections for future capital expenditures include material additions and replacements to its transmission and distribution systems to meet expected growth and to manage reliability. As project scope and cost estimates develop, PSE&G will modify its current projections to include these required investments. PSE&G’s projected expenditures for the various items reported above are primarily comprised of the following:

• Reliability Enhancements—investments made to improve the reliability and efficiency of the system or function.

• Facility Replacement—investments made to replace systems or equipment in kind.

• Support Facilities—ancillary equipment needed to support the business lines, such as computers, office furniture and buildings and structures housing support personnel or equipment/inventory.

• New Business—investments made in support of new business (e.g. to add new customers).

• Environmental/Regulatory—investments made in response to environmental, regulatory or legal mandates.

• Renewables/EMP—investments made in response to regulatory or legal mandates relating to renewable energy.

In 2011, PSE&G made $1,359 million of capital expenditures, including $1,302 million of investment in plant, primarily for transmission and distribution system reliability and $57 million in solar loan investments. This does not include expenditures for certain energy efficiency and renewable programs of $46 million or cost of removal, net of salvage, of $62 million, which are included in operating cash flows.

75

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

The following table reflects our contractual cash obligations and other commercial commitments in the respective periods in which they are due. See Item 8. Financial Statements and Supplementary Data -Note 13. Commitments and Contingent Liabilities for a discussion of contractual commitments related to the construction activity, discussed above, and for a variety of services for which annual amounts are not quantifiable. In addition, the table summarizes anticipated recourse and non-recourse debt maturities for the years shown. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 14. Schedule of Consolidated Debt. The table below does not reflect any anticipated cash payments for pension obligations due to uncertain timing of payments or liabilities for uncertain tax positions since we are unable to reasonably estimate the timing of liability payments in individual years beyond 12 months due to uncertainties in the timing of the effective settlement of tax positions. See Item 8. Financial Statements and Supplementary Data—Note 20. Income Taxes for additional information.

	Total Amount Committed		Less Than 1 Year		2 - 3 Years		4- 5 Years		Over 5 Years
	Millions
Contractual Cash Obligations
Long-Term Recourse Debt Maturities
Power	$	2,767	$	66	$	594	$	853	$	1,254
PSE&G		4,277		300		1,225		471		2,281
Transition Funding (PSE&G)		895		205		439		251		0
Transition Funding II (PSE&G)		44		11		25		8		0
Long-Term Non-Recourse Project Financing
Energy Holdings (A)		45		1		2		24		18
Interest on Recourse Debt
Power		1,458		141		262		222		833
PSE&G		2,999		216		357		273		2,153
Transition Funding (PSE&G)		136		56		69		11		0
Transition Funding II (PSE&G)		4		2		2		0		0
Interest on Non-Recourse Project Financing
Energy Holdings (A)		14		2		4		4		4
Capital Lease Obligations
PSEG		27		7		14		6		0
Power		6		2		3		1		0
Operating Leases
Power		8		0		1		2		5
PSE&G		50		6		9		5		30
Energy Holdings		9		1		1		0		7
Energy-Related Purchase Commitments
Power		2,694		815		868		795		216
Total Contractual Cash Obligations	$	15,433	$	1,831	$	3,875	$	2,926	$	6,801
Commercial Commitments
Standby Letters of Credit
Power	$	232	$	187	$	45	$	0	$	0
Energy Holdings		1		1		0		0		0
Guarantees and Equity Commitments
Energy Holdings		72		72		0		0		0
Total Commercial Commitments	$	305	$	260	$	45	$	0	$	0
Liability Payments for Uncertain Tax Positions
PSEG	$	35	$	35	$	0	$	0	$	0
Power		64		64		0		0		0
PSE&G		27		27		0		0		0
Energy Holdings		453		453		0		0		0

(A) The Energy Holdings non-recourse debt contractual cash obligations exclude any related principal and interest associated with the Dynegy related debt. See Item 8. Financial Statements and Supplementary Data—Note 14. Schedule of Consolidated Debt for further discussion.

76

OFF-BALANCE SHEET ARRANGEMENTS

Power

Power issues guarantees in conjunction with certain of its energy contracts. See Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities for further discussion.

Energy Holdings

We have certain investments that are accounted for under the equity method in accordance GAAP. Accordingly, amounts recorded on the Consolidated Balance Sheets for such investments represent our equity investment, which is increased for our pro-rata share of earnings less any dividend distribution from such investments. One of the companies in which we invest that is accounted for under the equity method has an aggregate $47 million of long-term debt on its Consolidated Balance Sheet. Our pro-rata share of such debt is $24 million. This debt is non-recourse to us. We are generally not required to support the debt service obligations of this company. However, default with respect to this non-recourse debt could result in a loss of invested equity.

Through Energy Holdings, we have investments in leveraged leases that are accounted for in accordance with GAAP—Accounting for Leases. Leveraged lease investments generally involve three parties: an owner/lessor, a creditor and a lessee. In a typical leveraged lease financing, the lessor purchases an asset to be leased. The purchase price is typically financed 80% with debt provided by the creditor and the balance comes from equity funds provided by the lessor. The creditor provides long-term financing to the transaction secured by the property subject to the lease. Such long-term financing is non-recourse to the lessor and is not presented on our Consolidated Balance Sheets. In the event of default, the leased asset, and in some cases the lessee, secures the loan. As a lessor, Energy Holdings has ownership rights to the property and rents the property to the lessees for use in their business operations. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 7. Long-Term Investments.

In the event that collectability of the minimum lease payments to be received by Energy Holdings is no longer reasonably assured, the accounting treatment for some of the leases may change. In such cases, Energy Holdings may deem that a lessee has a high probability of defaulting on the lease obligation, and would reclassify the lease from a leveraged lease to an operating lease and would consider the need to record an impairment of its investment. Should this event occur, the fair value of the underlying asset and the associated debt would be recorded on the Consolidated Balance Sheets instead of the net equity investment in the lease.

CRITICAL ACCOUNTING ESTIMATES

Under GAAP, many accounting standards require the use of estimates, variable inputs and assumptions (collectively referred to as estimates) that are subjective in nature. Because of this, differences between the actual measure realized versus the estimate can have a material impact on results of operations, financial position and cash flows. We have determined that the following estimates are considered critical to the application of rules that relate to the respective businesses.

Accounting for Pensions

We calculate pension costs using various economic and demographic assumptions.

Assumptions and Approach Used: Economic assumptions include the discount rate and the long-term rate of return on trust assets. Demographic assumptions include projections of future mortality rates, pay increases and retirement patterns.

Assumption	2011			2010			2009
Discount Rate		5.00	%		5.51	%		5.91	%
Rate of Return on Plan Assets		8.50	%		8.50	%		8.75	%

77

Our discount rate assumption, which is determined annually, is based on the rates of return on high-quality fixed-income investments currently available and expected to be available during the period to maturity of the pension benefits. The discount rate used to calculate pension obligations is determined as of December 31 each year, our measurement date. The discount rate used to determine year-end obligations is also used to develop the following year’s net periodic pension cost.

Our expected rate of return on plan assets reflects current asset allocations, historical long-term investment performance and an estimate of future long-term returns by asset class and long-term inflation assumptions.

Based on the above assumptions, we have estimated net periodic pension expense of approximately $119 million, net of amounts capitalized, and contributions of up to $124 million in 2012.

Effect if Different Assumptions Used: As part of the business planning process, we have modeled future costs assuming an 8.00% rate of return and a 5.00% discount rate for 2012, a 5.25% discount rate for 2013 and a 5.50% discount rate for 2014 and beyond. Actual future pension expense and funding levels will depend on future investment performance, changes in discount rates, market conditions, funding levels relative to our projected benefit obligation and accumulated benefit obligation and various other factors related to the populations participating in the pension plans.

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

			As of 12/31/2011 Impact on Pension Benefit Obligation		Increase to Pension Expense in 2012
Assumption	Change		Millions
Discount Rate		-1%	$	622	$	61
Rate of Return on Plan Assets		-1%	$	0	$	38

See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for additional information.

Uncertain Tax Positions

We are required to make judgments regarding the potential tax effects of various financial transactions and results of operations in order to estimate our obligations to taxing authorities.

Assumptions and Approach Used: We account for uncertain income tax positions using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold.

We also have non-income tax obligations related to real estate, sales and use and employment-related taxes and ongoing appeals related to these tax matters. We record liabilities for such obligations when we believe they are both probable and reasonably estimable.

Accounting for tax obligations requires judgments, including estimating reserves for potential adverse outcomes regarding tax positions that have been taken. We also assess our ability to utilize tax attributes, including those in the form of carryforwards, for which the benefits have already been reflected in the financial statements. We do not record valuation allowances for deferred tax assets related to capital losses that we believe will be realized in future periods.

Effect if Different Assumptions Used: While we believe the resulting tax reserve balances as of December 31, 2011 are appropriately accounted for, the ultimate outcome of such matters could result in favorable or unfavorable adjustments to our consolidated financial statements and such adjustments could be material.

78

Hedge and MTM Accounting

Current guidance requires us to recognize the fair value of derivative instruments, not designated as normal purchases or normal sales, at their fair value on the balance sheet. Many non-trading contracts qualify for normal purchases and normal sales exemption and are accounted for upon settlement.

Assumptions and Approach Used: In general, the fair value of our derivative instruments is determined by reference to quoted market prices from contracts listed on exchanges or from brokers. Some of these derivative contracts are long-term and rely on forward price quotations over the entire duration of the derivative contracts.

For a small number of contracts where quoted market prices are not available, we utilize mathematical models that rely on historical data to develop forward pricing information in the determination of fair value. Because the determination of fair value using such models is subject to significant assumptions and estimates, we developed reserve policies that are consistently applied to model-generated results to determine reasonable estimates of the fair value to record in the financial statements.

We have entered into various derivative instruments to manage risk from changes in commodity prices and interest rates. In accordance with our hedging strategy, derivatives that are hedging these risks and qualify are designated as either cash flow hedges or fair value hedges. For derivatives designated as hedges, the change in the value of a derivative instrument is measured against the offsetting change in the value of the underlying contract, anticipated transaction or other business condition that the derivative instrument is intended to hedge. This is known as the measure of hedge effectiveness. Changes in the fair value of the effective portion of a derivative instrument designated as a fair value hedge, along with changes in the fair value of the hedged asset or liability that are attributable to the hedged risk, are recorded in current period earnings. Changes in the fair value of the effective portion of derivative instruments designated as cash flow hedges, are reported in Accumulated Other Comprehensive Income (Loss), net of tax, or as a Regulatory Asset (Liability), as applicable, until earnings are affected by the variability of cash flows of the hedged transaction. Any hedge ineffectiveness is included in current period earnings. During periods of extreme price volatility, there will be significant changes in the value recorded in Accumulated Other Comprehensive Income (Loss).

For our wholesale energy business, many of the forward sale, forward purchase, option and other contracts are derivative instruments that hedge commodity price risk, but do not meet the requirements for either cash flow or fair value hedge accounting. The changes in value of such derivative contracts are marked to market through earnings as the related commodity prices fluctuate. As a result, our earnings may experience significant fluctuations depending on the volatility of commodity prices.

Effect if Different Assumptions Used: Any significant changes to the fair market values of our derivatives instruments could result in a material change in the value of the assets or liabilities recorded on our Consolidated Balance Sheets and could result in a material change to the unrealized gains or losses recorded in our Consolidated Statements of Operations.

For additional information regarding Derivative Financial Instruments, see Item 8. Financial Statements and Supplementary Data—Note 16. Financial Risk Management Activities.

Lease Investments

Our Investments in Leases, included in Long-Term Investments on our Consolidated Balance Sheets, are comprised of Lease Receivables (net of non-recourse debt), the estimated residual value of leased assets, and unearned and deferred income. A significant portion of the estimated residual value of leased assets is related to merchant power plants leased to other energy companies. See Item 8. Financial Statements and Supplementary Data – Note 7. Long-Term Investments, and Note 8. Financing Receivables.

79

Assumptions and Approach Used: Residual values are the estimated values of the leased assets at the end of the respective lease terms. The estimated values are calculated by discounting the cash flows related to the leased assets after the lease term. For the merchant power plants, the estimated discounted cash flows are dependent upon various assumptions, including:

• estimated forward power and capacity prices in the years after the lease;

• related prices of fuel for the plants;

• dispatch rates for the plants;

• future capital expenditures required to maintain the plants;

• future operation and maintenance expenses, and

• discount rates.

Residual valuations are performed annually for each plant subject to lease using specific assumptions tailored to each plant. Those annual valuations are compared to the recorded residual values to determine if an impairment is warranted.

Effect if Different Assumptions Used: A significant change to the assumptions, such as a large decrease in near-term power prices that affects the market’s view of long-term power prices, could result in an impairment of one or more of the residual values, but not necessarily to all of the residual values. However, if, because of changes in assumptions, all the residual values related to the merchant energy plants were deemed to be zero, we would recognize an after-tax charge to income of approximately $170 million.

NDT Fund

Our NDT Funds is comprised of both debt and equity securities. The assets in the NDT Fund are classified as available-for-sale securities and are marked to market with unrealized gains and losses recorded in Accumulated Other Comprehensive Income (Loss) unless securities with such unrealized losses are deemed to be other-than-temporarily-impaired. Realized gains, losses and dividend and interest income are recorded in our Consolidated Statements of Operations as Other Income and Other Deductions. Unrealized losses that are deemed to be other-than-temporarily-impaired are charged against earnings rather than Accumulated Other Comprehensive Income (Loss) and reflected as a separate line in the Consolidated Statement of Operations.

Assumptions and Approach Used: The NDT Fund investments are valued using quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. See Item 8. Financial Statements and Supplementary Data—Note 17. Fair Value Measurements for additional information.

Effect if Different Assumptions Used: Any significant changes to the fair market values of the fund securities could result in a material change in the value of our NDT Fund, which could potentially result in additional funding requirements to satisfy our decommissioning obligations. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for additional information.

Asset Retirement Obligations (ARO)

Power, PSE&G and Services recognize liabilities for the expected cost of retiring long-lived assets for which a legal obligation exists. These AROs are recorded at fair value in the period in which they are incurred and are capitalized as part of the carrying amount of the related long-lived assets. PSE&G, as a rate-regulated entity, recognizes regulatory assets or liabilities as a result of timing differences between the recording of costs and costs recovered through the ratemaking process. We accrete the ARO liability to reflect the passage of time.

Assumptions and Approach Used: Because quoted market prices are not available for AROs, we estimate the initial fair value of an ARO by calculating discounted cash flows that are dependent upon various assumptions, including:

• estimation of dates for retirement;

80

• amounts and timing of future cash expenditures associated with retirement, settlement or remediation activities;

• discount rates;

• cost escalation rates;

• inflation rates; and

• if applicable, past experience with government regulators regarding similar obligations.

We review cost studies every three years unless new information necessitates updates more often. The most recent cost study was done in 2009. When we revise any assumptions used to calculate fair values of existing AROs, we adjust the ARO balance and corresponding long-lived asset.

Nuclear Decommissioning AROs

AROs related to the future decommissioning of Power’s nuclear facilities comprised 92% of Power’s total AROs as of December 31, 2011. Power determines its AROs for its nuclear units by assigning probability weighting to various discounted cash flow outcomes for each of its nuclear units that incorporate the assumptions above as well as:

• license renewals;

• early shutdown;

• safe storage for a period of time after retirement; and

• recovery from the Federal government of costs incurred for spent nuclear fuel.

Effect if Different Assumptions Used: Changes in the assumptions could result in a material change in the ARO balance sheet obligation and the period over which we accrete to the ultimate liability. For example, a 1% decrease in the discount rate used at December 31, 2009 would result in a $104 million increase in the Nuclear ARO as of December 31, 2011. A 1% increase in the inflation rate used at December 31, 2009 would result in a $188 million increase in the Nuclear ARO as of December 31, 2011. Also, if we did not assume that we would recover from the federal government the costs incurred for spent nuclear fuel, the Nuclear ARO would increase by $76 million at December 31, 2011. These changes would not have a material impact on net income in 2012.

Accounting for Regulated Businesses

PSE&G prepares its financial statements to comply with GAAP for rate-regulated enterprises, which differs in some respects from accounting for non-regulated businesses. In general, accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (Regulatory Asset) or recognize obligations (Regulatory Liability) if the rates established are designed to recover the costs and if the competitive environment makes it probable that such rates can be charged or collected. This accounting results in the recognition of revenues and expenses in different time periods than that of enterprises that are not regulated.

Assumptions and Approach Used: PSE&G recognizes Regulatory Assets where it is probable that such costs will be recoverable in future rates from customers and Regulatory Liabilities where it is probable that refunds will be made to customers in future billings. The highest degree of probability is an order from the BPU either approving recovery of the deferred costs over a future period or requiring the refund of a liability over a future period.

Virtually all of PSE&G’s regulatory assets and liabilities are supported by BPU orders. In the absence of an order, PSE&G will consider the following when determining whether to record a regulatory asset or liability:

• past experience regarding similar items with the BPU;

81

• treatment of a similar item in an order by the BPU for another utility;

• passage of new legislation; and

• recent discussions with the BPU.

All deferred costs are subject to prudence reviews by the BPU. PSE&G’s experience is that little of the deferred cost has been subsequently denied by the BPU. When the recovery of a regulated asset or payment of a regulatory liability is no longer probable, PSE&G charges or credits earnings, as appropriate.

Effect if Different Assumptions Used: A change in the above assumptions may result in a material impact on our results of operations or our cash flows. See Item 8. Financial Statements and Supplementary Data—Note 6. Regulatory Assets and Liabilities for a description of the amounts and nature of regulatory balance sheet amounts.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The market risk inherent in our market-risk sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, equity security prices and interest rates as discussed in the Notes to Consolidated Financial Statements. It is our policy to use derivatives to manage risk consistent with business plans and prudent practices. We have a Risk Management Committee comprised of executive officers who utilize a risk oversight function to ensure compliance with our corporate policies and risk management practices.

Additionally, we are exposed to counterparty credit losses in the event of non-performance or non-payment. We have a credit management process, which is used to assess, monitor and mitigate counterparty exposure. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on our financial condition, results of operations or net cash flows.

Commodity Contracts

The availability and price of energy-related commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market rules and other events. To reduce price risk caused by market fluctuations, we enter into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties. These contracts, in conjunction with physical sales and other services, help reduce risk and optimize the value of owned electric generation capacity.

Value-at-Risk (VaR) Models

We use VaR models to assess the market risk of our commodity businesses. The portfolio VaR model includes our owned generation and physical contracts, as well as fixed price sales requirements, load requirements and financial derivative instruments. VaR represents the potential losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. We estimate VaR across our commodity businesses.

Non-trading MTM VaR consists of MTM derivatives that are economic hedges, some of which qualify for hedge accounting. The non-trading MTM VaR calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and some load serving activities. The MTM derivatives that are not hedges are included in the trading VaR.

The VaR models used are variance/covariance models adjusted for the change of positions with a 95% confidence level and a one-day holding period for the MTM trading and non-trading activities. The models assume no new positions throughout the holding periods; however, we actively manage our portfolio.

82

As of December 31, 2011, there was no trading VaR since we discontinued trading activities in the second quarter of 2011. As of December 31, 2010, trading VaR was $1 million.

For the Year Ended December 31, 2011	Trading VaR		Non-Trading MTM VaR
	Millions
95% Confidence Level,
Loss could exceed VaR one day in 20 days
Period End	$	0	$	16
Average for the Period	$	0	$	9
High	$	2	$	19
Low	$	0	$	4
99.5% Confidence Level,
Loss could exceed VaR one day in 200 days
Period End	$	0	$	25
Average for the Period	$	1	$	14
High	$	3	$	30
Low	$	0	$	7

Interest Rates

We are subject to the risk of fluctuating interest rates in the normal course of business. We manage interest rate risk by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, we use a mix of fixed and floating rate debt, interest rate swaps and interest rate lock agreements.

As of December 31, 2011, a hypothetical 10% increase in market interest rates would result in

• less than $1 million of additional annual interest costs related to both the current and long-term portion of long-term debt, and

• a $200 million decrease in the fair value of debt, including a $72 million decrease at Power and a $127 million decrease at PSE&G.

Debt and Equity Securities

We have $4.0 billion of assets in our pension plan trusts. Although fluctuations in market prices of securities within this portfolio do not directly affect our earnings in the current period, changes in the value of these investments could affect

• our future contributions to these plans,

• our financial position if our accumulated benefit obligation under our pension plans exceeds the fair value of the pension trust funds, and

• future earnings, as we could be required to adjust pension expense and the assumed rate of return.

The NDT Fund is comprised of both fixed income and equity securities totaling $1.3 billion as of December 31, 2011. As of December 31, 2011, the portfolio includes $685 million of equity securities and $640 million in fixed income securities. The fair market value of the assets in the NDT Fund will fluctuate primarily depending upon the performance of equity markets. As of December 31, 2011, a hypothetical 10% change in the equity market would impact the value of the equity securities in the NDT Fund by approximately $69 million.

We use duration to measure the interest rate sensitivity of the fixed income portfolio. Duration is a summary statistic of the effective average maturity of the fixed income portfolio. The benchmark for the fixed income component of the NDT Fund currently has a duration of 4.95 years and a yield of 2.97%. The portfolio’s value will appreciate or depreciate by the duration with a 1% change in interest rates. As of December 31, 2011, a hypothetical 1% increase in interest rates would result in a decline in the market value for the fixed income portfolio of approximately $32 million.

83

Credit Risk

See Item 8. Financial Statements and Supplementary Data—Note 16. Financial Risk Management Activities for a discussion of credit risk and a discussion about Power’s credit risk.

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

Energy Holdings has credit risk with respect to its counterparties to power purchase agreements and other parties.

Energy Holdings also has credit risk related to its investments in leases, totaling $165 million, which is net of deferred taxes of $716 million, as of December 31, 2011. These investments are primarily leveraged leases concentrated in the United States energy industry. See Item 8. Financial Statements and Supplementary Data -Note 8. Financing Receivables for counterparties’ credit ratings and other information. The credit exposure to the lessees is partially mitigated through various credit enhancement mechanisms within the lease transactions. These credit enhancement features vary from lease to lease. Some of the leasing transactions include covenants that restrict the flow of dividends from the lessee to its parent, over-collateralization of the lessee with non-leased assets, historical and forward cash flow coverage tests that prohibit discretionary capital expenditures and dividend payments to the parent/lessee if stated minimum coverages are not met and similar cash flow restrictions if ratings are not maintained at stated levels. These covenants are designed to maintain cash reserves in the transaction entity for the benefit of the non-recourse lenders and the lessor/equity participants in the event of a temporary market downturn or degradation in operating performance of the leased assets.

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

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

This combined Form 10-K is separately filed by PSEG, Power and PSE&G. Information contained herein relating to any individual company is filed by such company on its own behalf. Power and PSE&G each make representations only as to itself and make no representations as to any other company.

84

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors of

Public Service Enterprise Group Incorporated:

We have audited the accompanying consolidated balance sheets of Public Service Enterprise Group Incorporated and subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15(B)(a). These consolidated financial statements and consolidated financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and consolidated financial statement schedule based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2011 and 2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2012 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey

February 27, 2012

85

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Sole Member and Board of Directors of

PSEG Power LLC:

We have audited the accompanying consolidated balance sheets of PSEG Power LLC and subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, member’s equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15(B)(b). These consolidated financial statements and consolidated financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and consolidated financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2011 and 2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey

February 27, 2012

86

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Sole Stockholder and Board of Directors of

Public Service Electric and Gas Company:

We have audited the accompanying consolidated balance sheets of Public Service Electric and Gas Company and subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15(B)(c). These consolidated financial statements and consolidated financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and consolidated financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2011 and 2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey

February 27, 2012

87

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

	For The Years Ended December 31,
	2011			2010			2009
OPERATING REVENUES	$	11,079		$	11,793		$	12,035
OPERATING EXPENSES
Energy Costs		4,747			5,261			5,433
Operation and Maintenance		2,481			2,504			2,534
Depreciation and Amortization		976			955			819
Taxes Other Than Income Taxes		133			136			133
Total Operating Expenses		8,337			8,856			8,919
OPERATING INCOME		2,742			2,937			3,116
Income from Equity Method Investments		4			4			17
Other Income		220			221			246
Other Deductions		(85	)		(63	)		(161	)
Other-Than-Temporary Impairments		(22	)		(11	)		(61	)
Interest Expense		(475	)		(472	)		(521	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		2,384			2,616			2,636
Income Tax (Expense) Benefit		(977	)		(1,059	)		(1,042	)
INCOME FROM CONTINUING OPERATIONS		1,407			1,557			1,594
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax (expense) benefit of $(51), $(8) and $(2) for the years ended 2011, 2010 and 2009, respectively		96			7			(2	)
NET INCOME	$	1,503		$	1,564		$	1,592
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):
BASIC		505,949			505,985			505,986
DILUTED		506,982			507,045			507,064
EARNINGS PER SHARE:
BASIC
INCOME FROM CONTINUING OPERATIONS	$	2.78		$	3.08		$	3.15
NET INCOME	$	2.97		$	3.09		$	3.15
DILUTED
INCOME FROM CONTINUING OPERATIONS	$	2.77		$	3.07		$	3.14
NET INCOME	$	2.96		$	3.08		$	3.14
DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	1.37		$	1.37		$	1.33

See Notes to Consolidated Financial Statements.

88

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED BALANCE SHEETS

Millions

	December 31,
	2011			2010
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	834		$	280
Accounts Receivable, net of allowances of $56 and $68 in 2011 and 2010, respectively		967			1,387
Tax Receivable		16			689
Unbilled Revenues		289			400
Fuel		685			666
Materials and Supplies, net		367			359
Prepayments		308			204
Derivative Contracts		156			182
Assets of Discontinued Operations		0			564
Deferred Income Taxes		0			43
Regulatory Assets		167			155
Other		122			122
Total Current Assets		3,911			5,051
PROPERTY, PLANT AND EQUIPMENT		25,080			23,272
Less: Accumulated Depreciation and Amortization		(7,231	)		(6,882	)
Net Property, Plant and Equipment		17,849			16,390
NONCURRENT ASSETS
Regulatory Assets		3,805			3,736
Regulatory Assets of Variable Interest Entities (VIEs)		925			1,128
Long-Term Investments		1,303			1,623
Nuclear Decommissioning Trust (NDT) Funds		1,349			1,363
Other Special Funds		172			160
Goodwill		16			16
Other Intangibles		131			136
Derivative Contracts		106			79
Restricted Cash of VIEs		22			21
Other		232			206
Total Noncurrent Assets		8,061			8,468
TOTAL ASSETS	$	29,821		$	29,909

See Notes to Consolidated Financial Statements.

89

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED BALANCE SHEETS

Millions

	December 31,
	2011			2010
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year (includes $50 at fair value as of December 31, 2011)	$	417		$	915
Securitization Debt of VIEs Due Within One Year		216			206
Commercial Paper and Loans		0			64
Accounts Payable		1,184			1,176
Derivative Contracts		131			103
Accrued Interest		97			108
Accrued Taxes		30			49
Deferred Income Taxes		170			0
Clean Energy Program		214			195
Obligation to Return Cash Collateral		107			104
Regulatory Liabilities		100			174
Liabilities of Discontinued Operations		0			72
Other		291			319
Total Current Liabilities		2,957			3,485
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		5,458			5,129
Regulatory Liabilities		228			285
Regulatory Liabilities of VIEs		9			8
Asset Retirement Obligations		489			461
Other Postretirement Benefit (OPEB) Costs		1,127			967
Accrued Pension Costs		734			788
Clean Energy Program		39			235
Environmental Costs		643			669
Derivative Contracts		26			22
Long-Term Accrued Taxes		292			248
Other		86			152
Total Noncurrent Liabilities		9,131			8,964
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt		6,694			6,834
Securitization Debt of VIEs		723			939
Project Level, Non-Recourse Debt		44			46
Total Long-Term Debt		7,461			7,819
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000,000,000 shares; issued, 2011 and 2010—533,556,660 shares		4,823			4,807
Treasury Stock, at cost, 2011—27,611,374 shares; 2010—27,582,437 shares		(601	)		(593	)
Retained Earnings		6,385			5,575
Accumulated Other Comprehensive Loss		(337	)		(156	)
Total Common Stockholders’ Equity		10,270			9,633
Noncontrolling Interest		2			8
Total Stockholders’ Equity		10,272			9,641
Total Capitalization		17,733			17,460
TOTAL LIABILITIES AND CAPITALIZATION	$	29,821		$	29,909

See Notes to Consolidated Financial Statements.

90

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

	For the Years Ended December 31,
	2011			2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	1,503		$	1,564		$	1,592
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Gain on Disposal of Discontinued Operations		(122	)		0			0
Depreciation and Amortization		982			974			838
Amortization of Nuclear Fuel		153			136			121
Provision for Deferred Income Taxes (Other than Leases) and ITC		811			1,106			326
Non-Cash Employee Benefit Plan Costs		175			315			347
Lease Transaction Reserves, net of tax		170			0			(29	)
Net (Gain) Loss on Lease Investments		(55	)		(56	)		(167	)
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes		(55	)		(336	)		(678	)
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives		(165	)		50			25
Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs		43			(36	)		(32	)
Over (Under) Recovery of Societal Benefits Charge (SBC)		(96	)		(123	)		4
Market Transition Charge Refund		(61	)		84			0
Cost of Removal		(62	)		(58	)		(54	)
Net Realized (Gains) Losses and (Income) Expense from NDT Funds		(117	)		(106	)		(50	)
Net Change in Tax Receivable		673			(689	)		0
Net Change in Certain Current Assets and Liabilities		247			(221	)		221
Employee Benefit Plan Funding and Related Payments		(508	)		(508	)		(446	)
Other		41			68			(163	)
Net Cash Provided By (Used In) Operating Activities		3,557			2,164			1,855
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(2,083	)		(2,160	)		(1,794	)
Proceeds from Sale of Discontinued Operations		687			0			0
Proceeds from the Sale of Capital Leases and Investments		179			496			880
Proceeds from Sales of Available-for-Sale Securities		1,355			1,116			1,769
Investments in Available-for-Sale Securities		(1,386	)		(1,140	)		(1,798	)
Restricted Funds		0			(2	)		116
Other		(21	)		21			35
Net Cash Provided By (Used In) Investing Activities		(1,269	)		(1,669	)		(792	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans		(64	)		(466	)		511
Issuance of Long-Term Debt		794			1,728			459
Redemption of Long-Term Debt		(1,514	)		(775	)		(820	)
Repayment of Non-Recourse Debt		(1	)		(32	)		(286	)
Redemption of Securitization Debt		(206	)		(197	)		(187	)
Premium Paid on Debt Exchange/Redemption		(17	)		(18	)		(36	)
Cash Dividends Paid on Common Stock		(693	)		(693	)		(673	)
Redemption of Preferred Securities		0			(80	)		0
Other		(33	)		(32	)		(2	)
Net Cash Provided By (Used In) Financing Activities		(1,734	)		(565	)		(1,034	)
Net Increase (Decrease) in Cash and Cash Equivalents		554			(70	)		29
Cash and Cash Equivalents at Beginning of Period		280			350			321
Cash and Cash Equivalents at End of Period	$	834		$	280		$	350
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(219	)	$	1,070		$	1,364
Interest Paid, Net of Amounts Capitalized	$	479		$	444		$	500

See Notes to Consolidated Financial Statements.

91

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

Millions

	Common Stockholders’ Equity																Noncontrolling
	Common Stock				Treasury Stock						Retained Earnings			Accumulated Other Comprehensive Income (Loss)
	Shs.		Amount		Shs.			Amount									Interest			Total
Balance as of January 1, 2009		534	$	4,756		(28	)	$	(581	)	$	3,773		$	(177	)	$	11		$	7,782
Net Income		0		0		0			0			1,592			0			0			1,592
Other Comprehensive Income (Loss), net of tax:
Available-for-Sale Securities, net of tax of $93		0		0		0			0			0			94			0			94
Change in Fair Value of Derivative Instruments, net of tax of $245		0		0		0			0			0			356			0			356
Reclassification Adjustments for Net Amounts included in Net Income, net of tax of $(240)		0		0		0			0			0			(348	)		0			(348	)
Pension/OPEB adjustment, net of tax of $(25)		0		0		0			0			0			(29	)		0			(29	)
Other Comprehensive Income																					73
Comprehensive Income																					1,665
Adoption of Accounting Guidance for Non-Credit Losses		0		0		0			0			12			(12	)		0			0
Cash Dividends on Common Stock		0		0		0			0			(673	)		0			0			(673	)
Noncontrolling Interest in Losses of Consolidated Entity		0		0		0			0			0			0			(1	)		(1	)
Other		0		32		0			(7	)		0			0			0			25
Balance as of December 31, 2009		534	$	4,788		(28	)	$	(588	)	$	4,704		$	(116	)	$	10		$	8,798
Net Income		0		0		0			0			1,564			0			0			1,564
Other Comprehensive Income (Loss), net of tax:
Available-for-Sale Securities, net of tax of $12		0		0		0			0			0			6			0			6
Change in Fair Value of Derivative Instruments, net of tax of $42		0		0		0			0			0			60			0			60
Reclassification Adjustments for Net Amounts included in Net Income, net of tax of $(90)		0		0		0			0			0			(129	)		0			(129	)
Pension/OPEB adjustment, net of tax of $18		0		0		0			0			0			23			0			23
Other Comprehensive Income (Loss)																					(40	)
Comprehensive Income																					1,524
Cash Dividends on Common Stock		0		0		0			0			(693	)		0			0			(693	)
Noncontrolling Interest in Losses of Consolidated Entity		0		0		0			0			0			0			(2	)		(2	)
Other		0		19		0			(5	)		0			0			0			14
Balance as of December 31, 2010		534	$	4,807		(28	)	$	(593	)	$	5,575		$	(156	)	$	8		$	9,641
Net Income		0		0		0			0			1,503			0			0			1,503
Other Comprehensive Income (Loss), net of tax:
Available-for-Sale Securities, net of tax of $(43)		0		0		0			0			0			(39	)		0			(39	)
Change in Fair Value of Derivative Instruments, net of tax of $33		0		0		0			0			0			47			0			47
Reclassification Adjustments for Net Amounts included in Net Income, net of tax of $(87)		0		0		0			0			0			(127	)		0			(127	)
Pension/OPEB adjustment, net of tax of $(44)		0		0		0			0			0			(62	)		0			(62	)
Other Comprehensive Income (Loss)																					(181	)
Comprehensive Income																					1,322
Cash Dividends on Common Stock		0		0		0			0			(693	)		0			0			(693	)
Noncontrolling Interest in Losses of Consolidated Entity		0		0		0			0			0			0			(6	)		(6	)
Other		0		16		0			(8	)		0			0			0			8
Balance as of December 31, 2011		534	$	4,823		(28	)	$	(601	)	$	6,385		$	(337	)	$	2		$	10,272

See Notes to Consolidated Financial Statements.

92

PSEG POWER LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

	For The Years Ended December 31,
	2011			2010			2009
OPERATING REVENUES	$	6,143		$	6,558		$	6,772
OPERATING EXPENSES
Energy Costs		3,046			3,374			3,462
Operation and Maintenance		1,102			1,046			1,045
Depreciation and Amortization		224			175			184
Total Operating Expenses		4,372			4,595			4,691
OPERATING INCOME		1,771			1,963			2,081
Other Income		190			170			233
Other Deductions		(79	)		(53	)		(135	)
Other-Than-Temporary Impairments		(20	)		(9	)		(60	)
Interest Expense		(175	)		(157	)		(161	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		1,687			1,914			1,958
Income Tax (Expense) Benefit		(685	)		(778	)		(767	)
INCOME FROM CONTINUING OPERATIONS		1,002			1,136			1,191
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax (expense) benefit of $(51), $(8) and $(2) for the years ended 2011, 2010 and 2009, respectively		96			7			(2	)
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	1,098		$	1,143		$	1,189

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

93

PSEG POWER LLC

CONSOLIDATED BALANCE SHEETS

Millions

	December 31,
	2011			2010
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	12		$	11
Accounts Receivable		267			511
Accounts Receivable—Affiliated Companies, net		381			782
Short-Term Loan to Affiliate		907			398
Fuel		685			666
Materials and Supplies, net		272			269
Derivative Contracts		139			163
Prepayments		24			80
Assets of Discontinued Operations		0			564
Total Current Assets		2,687			3,444
PROPERTY, PLANT AND EQUIPMENT		9,191			8,643
Less: Accumulated Depreciation and Amortization		(2,460	)		(2,301	)
Net Property, Plant and Equipment		6,731			6,342
NONCURRENT ASSETS
Nuclear Decommissioning Trust (NDT) Funds		1,349			1,363
Goodwill		16			16
Other Intangibles		131			130
Other Special Funds		33			32
Derivative Contracts		55			42
Long-Term Accrued Taxes		0			16
Other		85			67
Total Noncurrent Assets		1,669			1,666
TOTAL ASSETS	$	11,087		$	11,452

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

94

PSEG POWER LLC

CONSOLIDATED BALANCE SHEETS

Millions

	December 31,
	2011			2010
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	66		$	650
Accounts Payable		541			643
Derivative Contracts		124			91
Deferred Income Taxes		53			64
Accrued Interest		32			40
Liabilities of Discontinued Operations		0			72
Other		86			91
Total Current Liabilities		902			1,651
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		1,266			1,146
Asset Retirement Obligations		259			242
Other Postretirement Benefit (OPEB) Costs		180			151
Derivative Contracts		24			22
Accrued Pension Costs		236			253
Long-Term Accrued Taxes		8			0
Other		83			155
Total Noncurrent Liabilities		2,056			1,969
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13)
LONG-TERM DEBT
Total Long-Term Debt		2,685			2,805
MEMBER’S EQUITY
Contributed Capital		2,028			2,028
Basis Adjustment		(986	)		(986	)
Retained Earnings		4,678			4,080
Accumulated Other Comprehensive Loss		(276	)		(95	)
Total Member’s Equity		5,444			5,027
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	11,087		$	11,452

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

95

PSEG POWER LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

	For the Years Ended December 31,
	2011			2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	1,098		$	1,143		$	1,189
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Gain on Disposal of Discontinued Operations		(122	)		0			0
Depreciation and Amortization		231			194			203
Amortization of Nuclear Fuel		153			136			121
Provision for Deferred Income Taxes and ITC		231			650			133
Interest Accretion on Asset Retirement Obligation		18			18			27
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives		(165	)		50			25
Loss on Early Extinguishment of Debt		17			0			0
Non-Cash Employee Benefit Plan Costs		41			71			76
Net Realized (Gains) Losses and (Income) Expense from NDT Funds		(117	)		(106	)		(50	)
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies		(26	)		135			97
Margin Deposit		49			(91	)		(31	)
Accounts Receivable		197			(105	)		109
Accounts Payable		(154	)		17			(115	)
Accounts Receivable/Payable-Affiliated Companies, net		459			(386	)		75
Other Current Assets and Liabilities		30			(66	)		(27	)
Employee Benefit Plan Funding and Related Payments		(129	)		(132	)		(114	)
Other		1			38			(60	)
Net Cash Provided By (Used In) Operating Activities		1,812			1,566			1,658
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(757	)		(825	)		(869	)
Settlement of Spent Nuclear Fuel Claim		0			16			47
Proceeds from Sale of Discontinued Operations		687			0			0
Proceeds from Sales of Available-for-Sale Securities		1,355			989			1,769
Investments in Available-for-Sale Securities		(1,380	)		(1,013	)		(1,798	)
Short-Term Loan—Affiliated Company, net		(509	)		(398	)		55
Restricted Funds		0			2			115
Other		26			24			29
Net Cash Provided By (Used In) Investing Activities		(578	)		(1,205	)		(652	)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Recourse Long-Term Debt		544			594			209
Contributed Capital		0			0			230
Cash Dividend Paid		(500	)		(549	)		(940	)
Redemption of Long-Term Debt		(1,250	)		(248	)		(294	)
Redemption of Non-Recourse Long-Term Debt		0			0			(280	)
Short-Term Loan—Affiliated Company, net		0			(194	)		194
Cash Payment on Debt Redemption/Exchange		(17	)		(13	)		(101	)
Other		(10	)		(4	)		0
Net Cash Provided By (Used In) Financing Activities		(1,233	)		(414	)		(982	)
Net Increase (Decrease) in Cash and Cash Equivalents		1			(53	)		24
Cash and Cash Equivalents at Beginning of Period		11			64			40
Cash and Cash Equivalents at End of Period	$	12		$	11		$	64
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	171		$	539		$	584
Interest Paid, Net of Amounts Capitalized	$	176		$	151		$	160

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

96

PSEG POWER LLC

CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY

Millions

	Contributed Capital			Basis Adjustment			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance as of January 1, 2009	$	2,202		$	(986	)	$	3,225		$	(119	)	$	4,322
Net Income		0			0			1,189			0			1,189
Other Comprehensive Income (Loss), net of tax:
Available-for-Sale Securities, net of tax of $89		0			0			0			88			88
Change in Fair Value of Derivative Instruments, net of tax of $247		0			0			0			358			358
Reclassification Adjustments for Net Amount included in Net Income, net of tax of $(242)		0			0			0			(350	)		(350	)
Pension/OPEB adjustment, net of tax of $(21)		0			0			0			(26	)		(26	)
Other Comprehensive Income														70
Comprehensive Income														1,259
Non-Cash Return of Capital Related to Debt Exchange		(404	)		0			0			0			(404	)
Adoption of Accounting Guidance for Non-Credit Losses, net of tax		0			0			12			(12	)		0
Contributed Capital		230			0			0			0			230
Cash Dividends Paid		0			0			(940	)		0			(940	)
Balance as of December 31, 2009	$	2,028		$	(986	)	$	3,486		$	(61	)	$	4,467
Net Income		0			0			1,143			0			1,143
Other Comprehensive Income (Loss), net of tax:
Available-for-Sale Securities, net of tax of $17		0			0			0			15			15
Change in Fair Value of Derivative Instruments, net of tax of $42		0			0			0			60			60
Reclassification Adjustments for Net Amount included in Net Income, net of tax of $(90)		0			0			0			(129	)		(129	)
Pension/OPEB adjustment, net of tax of $15		0			0			0			21			21
Other		0			0			0			(1	)		(1	)
Other Comprehensive Income														(34	)
Comprehensive Income														1,109
Cash Dividends Paid		0			0			(549	)		0			(549	)
Balance as of December 31, 2010	$	2,028		$	(986	)	$	4,080		$	(95	)	$	5,027
Net Income		0			0			1,098			0			1,098
Other Comprehensive Income (Loss), net of tax:
Available-for-Sale Securities, net of tax of $(45)		0			0			0			(42	)		(42	)
Change in Fair Value of Derivative Instruments, net of tax of $33		0			0			0			47			47
Reclassification Adjustments for Net Amount included in Net Income, net of tax of $(87)		0			0			0			(127	)		(127	)
Pension/OPEB adjustment, net of tax of $(40)		0			0			0			(59	)		(59	)
Other Comprehensive Income														(181	)
Comprehensive Income														917
Cash Dividends Paid		0			0			(500	)		0			(500	)
Balance as of December 31, 2011	$	2,028		$	(986	)	$	4,678		$	(276	)	$	5,444

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

97

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

	For The Years Ended December 31,
	2011			2010			2009
OPERATING REVENUES	$	7,326		$	7,869		$	8,243
OPERATING EXPENSES
Energy Costs		3,951			4,655			5,170
Operation and Maintenance		1,372			1,442			1,474
Depreciation and Amortization		719			750			608
Taxes Other Than Income Taxes		133			136			133
Total Operating Expenses		6,175			6,983			7,385
OPERATING INCOME		1,151			886			858
Other Income		25			26			8
Other Deductions		(4	)		(3	)		(3	)
Other-Than-Temporary Impairments		(1	)		0			0
Interest Expense		(310	)		(318	)		(312	)
INCOME BEFORE INCOME TAXES		861			591			551
Income Tax (Expense) Benefit		(340	)		(232	)		(226	)
NET INCOME		521			359			325
Preferred Stock Dividends		0			(1	)		(4	)
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	521		$	358		$	321

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

98

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED BALANCE SHEETS

Millions

	December 31,
	2011			2010
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	143		$	245
Accounts Receivable, net of allowances of $56 in 2011 and $67 in 2010, respectively		691			832
Tax Receivable		16			0
Unbilled Revenues		289			400
Materials and Supplies		94			90
Prepayments		117			117
Regulatory Assets		167			155
Other		21			19
Total Current Assets		1,538			1,858
PROPERTY, PLANT AND EQUIPMENT		15,306			14,068
Less: Accumulated Depreciation and Amortization		(4,539	)		(4,326	)
Net Property, Plant and Equipment		10,767			9,742
NONCURRENT ASSETS
Regulatory Assets		3,805			3,736
Regulatory Assets of VIEs		925			1,128
Long-Term Investments		280			230
Other Special Funds		57			54
Derivative Contracts		4			17
Restricted Cash of VIEs		22			21
Other		89			87
Total Noncurrent Assets		5,182			5,273
TOTAL ASSETS	$	17,487		$	16,873

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

99

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED BALANCE SHEETS

Millions

	December 31,
	2011		2010
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	300	$	264
Securitization Debt of VIEs Due Within One Year		216		206
Accounts Payable		498		406
Accounts Payable—Affiliated Companies, net		280		85
Accrued Interest		65		65
Clean Energy Program		214		195
Derivative Contracts		7		12
Deferred Income Taxes		32		19
Obligation to Return Cash Collateral		107		104
Regulatory Liabilities		100		174
Other		186		229
Total Current Liabilities		2,005		1,759
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC		3,675		3,127
Other Postretirement Benefit (OPEB) Costs		900		770
Accrued Pension Costs		355		377
Regulatory Liabilities		228		285
Regulatory Liabilities of VIEs		9		8
Clean Energy Program		39		235
Environmental Costs		592		617
Asset Retirement Obligations		226		216
Long-Term Accrued Taxes		83		74
Other		35		23
Total Noncurrent Liabilities		6,142		5,732
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt		3,970		4,019
Securitization Debt of VIEs		723		939
Total Long-Term Debt		4,693		4,958
STOCKHOLDER’S EQUITY
Common Stock; 150,000,000 shares authorized; issued and outstanding, 2011 and 2010—132,450,344 shares		892		892
Contributed Capital		420		420
Basis Adjustment		986		986
Retained Earnings		2,347		2,126
Accumulated Other Comprehensive Income		2		0
Total Stockholder’s Equity		4,647		4,424
Total Capitalization		9,340		9,382
TOTAL LIABILITIES AND CAPITALIZATION	$	17,487	$	16,873

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

100

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

	For The Years Ended December 31,
	2011			2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	521		$	359		$	325
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		719			750			608
Provision for Deferred Income Taxes and ITC		571			444			194
Non-Cash Employee Benefit Plan Costs		118			217			236
Cost of Removal		(62	)		(58	)		(54	)
Market Transition Charge (MTC) Refund		(61	)		84			0
Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs		43			(36	)		(32	)
Over (Under) Recovery of SBC		(96	)		(123	)		4
Net Changes in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues		252			(21	)		152
Materials and Supplies		(4	)		(20	)		(9	)
Prepayments		0			(31	)		(41	)
Net Change in Tax Receivable		(16	)		0			0
Accounts Receivable/Payable-Affiliated Companies, net		197			(286	)		(62	)
Other Current Assets and Liabilities		(40	)		68			(34	)
Employee Benefit Plan Funding and Related Payments		(330	)		(327	)		(288	)
Other		(36	)		(9	)		(42	)
Net Cash Provided By (Used In) Operating Activities		1,776			1,011			957
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(1,302	)		(1,257	)		(855	)
Proceeds from Sales of Available-for-Sale Securities		0			54			1
Investments in Available-for-Sale Securities		0			(54	)		(1	)
Solar Loan Investments		(51	)		(27	)		(43	)
Other		(1	)		4			5
Net Cash Provided By (Used In) Investing Activities		(1,354	)		(1,280	)		(893	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt		0			0			(19	)
Issuance of Long-Term Debt		250			1,114			250
Redemption of Long-Term Debt		(264	)		(400	)		(203	)
Redemption of Securitization Debt		(206	)		(197	)		(187	)
Redemption of Preferred Securities		0			(80	)		0
Contributed Capital		0			0			250
Deferred Issuance Costs		(4	)		(10	)		(2	)
Cash Dividend Paid		(300	)		(150	)		0
Other		0			(3	)		(4	)
Net Cash Provided By (Used In) Financing Activities		(524	)		274			85
Net Increase (Decrease) In Cash and Cash Equivalents		(102	)		5			149
Cash and Cash Equivalents at Beginning of Period		245			240			91
Cash and Cash Equivalents at End of Period	$	143		$	245		$	240
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(514	)	$	73		$	5
Interest Paid, Net of Amounts Capitalized	$	297		$	294		$	299

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

101

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

Millions

	Common Stock		Contributed Capital from PSEG		Basis Adjustment		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance as of January 1, 2009	$	892	$	170	$	986	$	1,597		$	2		$	3,647
Net Income		0		0		0		325			0			325
Other Comprehensive Income, net of tax of $2		0		0		0		0			3			3
Comprehensive Income														328
Contributed Capital		0		250		0		0			0			250
Cash Dividends on Preferred Stock		0		0		0		(4	)		0			(4	)
Balance as of December 31, 2009	$	892	$	420	$	986	$	1,918		$	5		$	4,221
Net Income		0		0		0		359			0			359
Other Comprehensive Income, net of tax of $(3)		0		0		0		0			(5	)		(5	)
Comprehensive Income											0			354
Cash Dividends on Preferred Stock		0		0		0		(1	)		0			(1	)
Cash Dividends on Common Stock		0		0		0		(150	)		0			(150	)
Balance as of December 31, 2010	$	892	$	420	$	986	$	2,126		$	0		$	4,424
Net Income		0		0		0		521			0			521
Other Comprehensive Income, net of tax of $1		0		0		0		0			2			2
Comprehensive Income														523
Cash Dividends on Common Stock		0		0		0		(300	)		0			(300	)
Balance as of December 31, 2011	$	892	$	420	$	986	$	2,347		$	2		$	4,647

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

102

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies

Public Service Enterprise Group Incorporated, (PSEG) is a holding company with a diversified business mix within the energy industry. Its operations are primarily in the Northeastern and Mid Atlantic United States and in other select markets. PSEG’s principal direct wholly owned subsidiaries are:

• PSEG Power LLC (Power)—which is a multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply, energy trading and marketing and risk management functions through three principal direct wholly owned subsidiaries. Power’s subsidiaries are subject to regulation by the Federal Energy Regulatory Commission (FERC), the Nuclear Regulatory Commission (NRC) and the states in which they operate.

• Public Service Electric and Gas Company (PSE&G)—which is an operating public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and FERC. Pursuant to applicable BPU orders, PSE&G is also investing in the development of solar generation projects and energy efficiency programs, which are regulated by the BPU.

• PSEG Energy Holdings L.L.C. (Energy Holdings)—which owns and operates primarily domestic projects engaged in the generation of energy and has invested in leveraged leases through its direct wholly owned subsidiaries. Certain Energy Holdings’ subsidiaries are subject to regulation by FERC and the states in which they operate. Energy Holdings is also investing in solar generation projects and exploring opportunities for other investments in renewable generation.

• PSEG Services Corporation (Services)—which provides management and administrative and general services to PSEG and its subsidiaries.

Basis of Presentation

The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Annual Reports on Form 10-K and in accordance with accounting guidance generally accepted in the United States (GAAP).

Significant Accounting Policies

Principles of Consolidation

Each company consolidates those entities in which it has a controlling interest or is the primary beneficiary. See Note 3. Variable Interest Entities. Entities over which the companies exhibit significant influence, but do not have a controlling interest and/or are not the primary beneficiary, are accounted for under the equity method of accounting. For investments in which significant influence does not exist and the investor is not the primary beneficiary, the cost method of accounting is applied. All significant intercompany accounts and transactions are eliminated in consolidation, except as discussed in Note 23. Related-Party Transactions.

Power and PSE&G also have undivided interests in certain jointly-owned facilities, with each responsible for paying its respective ownership share of construction costs, fuel purchases and operating expenses. Power’s and PSE&G’s revenues and expenses related to these facilities are consolidated in the appropriate revenue and expense categories.

Accounting for the Effects of Regulation

In accordance with accounting guidance for rate-regulated entities, PSE&G’s financial statements must reflect the economic effects of regulation. PSE&G is required to defer the recognition of costs (a Regulatory Asset) or record the recognition of obligations (a Regulatory Liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs and recoveries, which are being amortized over various future periods. To the extent that

103

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

collection of any such costs or payment of liabilities is no longer probable as a result of changes in regulation and/or competitive position, the associated Regulatory Asset or Liability is charged or credited to income. Management believes that PSE&G’s transmission and distribution businesses continue to meet the accounting requirements for rate-regulated entities. For additional information, see Note 6. Regulatory Assets and Liabilities.

Derivative Financial Instruments

Each company uses derivative financial instruments to manage risk from changes in interest rates, commodity prices, congestion costs and emission credit prices, pursuant to its business plans and prudent practices.

Derivative instruments, not designated as normal purchases or sales, are recognized on the balance sheet at their fair value. Changes in the fair value of a derivative that is highly effective as, and that is designated and qualifies as, a fair value hedge, along with changes of the fair value of the hedged asset or liability that are attributable to the hedged risk, are recorded in current period earnings. Changes in the fair value of a derivative that is highly effective as, and that is designated and qualifies as, a cash flow hedge are recorded in Accumulated Other Comprehensive Income (Loss) or as a Regulatory Asset (Liability), as applicable, until earnings are affected by the variability of cash flows of the hedged transaction. Any hedge ineffectiveness is included in current period earnings. For derivative contracts that do not qualify as cash flow or fair value hedges or are not designated as normal purchases or sales, changes in fair value are recorded in current period earnings.

Many non-trading contracts qualify for the normal purchases and normal sales exemption and are accounted for upon settlement.

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

Revenue Recognition

The majority of Power’s revenues relate to bilateral contracts, which are accounted for on the accrual basis as the energy is delivered. Power’s revenue also includes changes in the value of non trading energy derivative contracts that are not designated as normal purchases or sales or as cash flow or fair value hedges of other positions. Power records margins from energy trading on a net basis. See Note 16. Financial Risk Management Activities for further discussion.

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

Energy Holdings’ revenues are earned primarily from income relating to its investments in leveraged leases, which is recognized by a method which produces a constant after-tax rate of return on the outstanding investment in the lease, net of the related deferred tax liability, in the years in which the net investment is positive. Any gains or losses incurred as a result of a lease termination are recorded as Operating Revenue as these events occur in the ordinary course of business of managing the investment portfolio. See Note 7. Long-Term Investments for further discussion.

Depreciation and Amortization

Power calculates depreciation on generation-related assets under the straight-line method based on the assets’ estimated useful lives. The estimated useful lives are:

• general plant assets—3 years to 25 years

• fossil production assets—10 years to 79 years

• nuclear generation assets—approximately 60 years

104

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

• pumped storage facilities—76 years

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

	2011		2010		2009
	Avg Rate		Avg Rate		Avg Rate
PSE&G Depreciation Rate		2.46%		2.46%		2.44%

Taxes Other Than Income Taxes

Excise taxes, transitional energy facilities assessment (TEFA) and gross receipts tax (GRT) collected from PSE&G’s customers are presented in the financial statements on a gross basis. For the years ended December 31, 2011, 2010 and 2009, combined TEFA and GRT are included in the following captions in the Consolidated Statements of Operations:

	Years Ended December 31,
	2011		2010		2009
			Millions
TEFA and GRT included in:
Operating Revenues	$	146	$	149	$	146
Taxes Other Than Income Taxes	$	133	$	136	$	133

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

IDC represents the cost of debt used to finance construction at Power. AFUDC represents the cost of debt and equity funds used to finance the construction of new utility assets at PSE&G. The amount of IDC or AFUDC capitalized as Property, Plant and Equipment is included as a reduction of interest charges or other income for the equity portion. The amounts and average rates used to calculate IDC or AFUDC for the years ended December 31, 2011, 2010 and 2009 are as follows:

					IDC/AFUDC Capitalized
	2011				2010				2009
	Millions		Avg Rate		Millions		Avg Rate		Millions		Avg Rate
Power	$	30		5.91%	$	78		6.57%	$	58		6.78%
PSE&G	$	13		6.56%	$	7		6.22%	$	1		0.88%

Income Taxes

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

We account for uncertain income tax positions using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. See Note 20. Income Taxes for further discussion.

105

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Impairment of Long-Lived Assets

In accordance with accounting guidance, management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate or market conditions, could potentially indicate an asset’s carrying amount may not be recoverable. In such an event, an undiscounted cash flow analysis would be performed to determine if an impairment exists. An impairment would result in a reduction of the long-lived asset value through a non-cash charge to earnings.

Cash and Cash Equivalents

Cash equivalents consist of short-term, highly liquid investments with original maturities of three months or less.

Accounts Receivable—Allowance for Doubtful Accounts

PSE&G’s accounts receivable are reported in the balance sheet as gross outstanding amounts adjusted for doubtful accounts. The allowance for doubtful accounts reflects PSE&G’s best estimates of losses on the accounts receivable balances. The allowance is based on accounts receivable aging, historical experience, write-off forecasts and other currently available evidence.

Accounts receivable are charged off in the period in which the receivable is deemed uncollectible. Recoveries of accounts receivable are recorded when it is known they will be received.

Materials and Supplies and Fuel

Materials and supplies for Power and Energy Holdings are valued at the lower of average cost or market. Fuel inventory at Power includes the weighted average costs of stored natural gas, coal, fuel oil and propane used to generate power and to satisfy obligations under Power’s gas supply contracts with PSE&G. The costs of fuel, including transportation costs, are included in inventory when purchased and charged at average cost to Energy Costs when used or sold. PSE&G’s materials and supplies are carried at average cost consistent with the rate-making process.

Restricted Funds

PSE&G’s restricted funds represent revenues collected from its retail electric customers that must be used to pay the principal, interest and other expenses associated with the securitization bonds of PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II).

Property, Plant and Equipment

Power capitalizes costs which increase the capacity or extend the life of an existing asset, represent a newly acquired or constructed asset or represent the replacement of a retired asset. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. Environmental costs are capitalized if the costs mitigate or prevent future environmental contamination or if the costs improve existing assets’ environmental safety or efficiency. All other environmental expenditures are expensed as incurred.

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

Available-for-Sale Securities

These securities are comprised of the Nuclear Decommissioning Trust (NDT) Fund, a master independent external trust account maintained to provide for the costs of decommissioning upon termination of operations of Power’s nuclear facilities and amounts comprising Other Special Funds that are deposited to fund a Rabbi Trust which was established to meet the obligations related to non-qualified pension plans and deferred compensation plans.

106

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Realized gains and losses on securities in the NDT Fund are recorded in earnings and unrealized gains and losses on such securities are recorded as a component of Accumulated Other Comprehensive Income (Loss) (except credit loss on debt securities which is recorded in earnings). Securities with unrealized losses that are deemed to be other-than-temporarily impaired are recorded in earnings. See Note 9. Available-for-Sale Securities for further discussion.

Pension and Other Postretirement Benefits (OPEB) Plan Assets

The market-related value of plan assets held for the qualified pension and OPEB plans is equal to the fair value of those assets as of year-end. Fair value is determined using quoted market prices and independent pricing services based upon the security type as reported by the trustee at the measurement dates (December 31) for all plan assets. See Note 12. Pension, OPEB and Savings Plans for further discussion.

Basis Adjustment

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

Use of Estimates

The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions regarding certain types of assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements.

Reclassifications

During 2011, Power sold its two natural gas combined cycle power plants in Texas that were owned and operated by its subsidiary, PSEG Texas. As a result, amounts related to these plants were reclassified as Discontinued Operations in the financial statements of PSEG and Power for the years ended December 31, 2011, 2010 and 2009. See Note 4. Discontinued Operations and Dispositions.

Note 2. Recent Accounting Standards

New Standard Adopted during 2011

Revenue Arrangements with Multiple Deliverables

• amends existing guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist,

• establishes a selling price hierarchy, such as, “vendor-specific objective evidence,” “third-party evidence” and “estimated selling price” for determining the selling price of a deliverable, and

• provides guidance for allocating and recognizing revenue based on separate deliverables.

We adopted this standard, prospectively, effective January 1, 2011, for new and significantly modified revenue arrangements. Upon adoption, there was no material impact on our financial statements and we do not anticipate any changes to the pattern or general timing of revenue recognition for our significant units of account in future periods.

107

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

New Accounting Standards Issued But Not Yet Adopted

Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in GAAP and International Financial Reporting Standards (IFRS)

This accounting standard was issued to update guidance related to fair value measurements and disclosures as a step towards achieving convergence between GAAP and IFRS. The updated guidance

• clarifies intent about application of existing fair value measurements and disclosures,

• changes some requirements for fair value measurements, and

• requires expanded disclosures.

This guidance is effective for interim and annual periods beginning after December 15, 2011. We believe our adoption of the new guidance on January 1, 2012 will not have an impact on our consolidated financial position, results of operations or cash flows; however, it will result in expanded disclosures.

Presentation of Comprehensive Income

This accounting standard addressed the presentation of comprehensive income as a step towards achieving convergence between GAAP and IFRS. The updated guidance

• allows an entity to present components of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive statements, and

• eliminates the current option to report other comprehensive income and its components in the statement of changes in equity.

This guidance is effective for fiscal years and interim periods beginning after December 15, 2011.

In December 2011, the FASB issued an amendment to this standard to indefinitely defer the effective date for some of the specific disclosure requirements that relate to the presentation of reclassification adjustments out of accumulated other comprehensive income by component in both the statement in which net income is presented and the statement in which other comprehensive income is presented. During the deferral period, the existing requirements in GAAP for the presentation of reclassification adjustments must continue to be followed.

We believe that the adoption of the new amended guidance on January 1, 2012 will not have an impact on our consolidated financial position, results of operations or cash flows, but will change the presentation of the components of other comprehensive income.

Disclosures about Offsetting Assets and Liabilities

This accounting standard was issued on balance sheet offsetting disclosures to facilitate comparability between financial statements prepared on the basis of GAAP and financial statements prepared on the basis of IFRS. This standard requires entities:

• to disclose information about offsetting and related arrangements to enable users of financial statements to understand the effect of those arrangements on an entity’s financial position, and

• to present both net (offset amounts) and gross information in the notes to the financial statements for relevant assets and liabilities that are offset.

The guidance is effective for fiscal years and interim periods beginning on or after January 1, 2013. As this standard requires disclosures only, it will not have any impact on our consolidated financial position, results of operations or cash flows upon adoption.

108

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3. Variable Interest Entities (VIEs)

VIEs for which PSE&G is the Primary Beneficiary

PSE&G is the primary beneficiary of and consolidates two marginally capitalized VIEs, Transition Funding and Transition Funding II, which were created for the purpose of issuing transition bonds and purchasing bond transitional property of PSE&G, which is pledged as collateral to the trustee. PSE&G acts as the servicer for these entities to collect securitization transition charges authorized by the BPU. These funds are remitted to Transition Funding and Transition Funding II and are used for interest and principal payments on the transition bonds and related costs.

The assets and liabilities of these VIEs are presented separately on the face of the Consolidated Balance Sheets of PSEG and PSE&G because the Transition Funding and Transition Funding II assets are restricted and can only be used to settle their respective obligations. The Transition Funding and Transition Funding II creditors do not have any recourse to the general credit of PSE&G in the event the transition charges are not sufficient to cover the bond principal and interest payments of Transition Funding and Transition Funding II, respectively.

PSE&G’s maximum exposure to loss is equal to its equity investment in these VIEs which was $16 million as of December 31, 2011 and 2010. PSE&G considers the risk of actual loss to be remote. PSE&G did not provide any financial support to Transition Funding or Transition Funding II in 2011 or 2010. Further, PSE&G does not have any contractual commitments or obligations to provide financial support to Transition Funding and Transition Funding II.

Note 4. Discontinued Operations and Dispositions

Discontinued Operations

Power

In March 2011, Power completed the sale of its 1,000 MW gas-fired Guadalupe generating facility for a total sale price of $352 million, resulting in an after-tax gain of $54 million.

In July 2011, Power completed the sale of its 1,000 MW gas-fired Odessa generating facility for a total sale price of $335 million, resulting in an after-tax gain of $25 million.

PSEG Texas’ operating results for the years ended December 31, 2011, 2010 and 2009, which were reclassified to Discontinued Operations, are summarized below:

	Years Ended December 31,
	2011		2010		2009
	Millions
Operating Revenues	$	112	$	402	$	371
Income Before Income Taxes	$	26	$	15	$	0
Net Income (Loss)	$	17	$	7	$	(2	)

109

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The carrying amounts of PSEG Texas’ assets as of December 31, 2010 are summarized in the following table:

	As of December 31,
	2010
	Millions
Current Assets	$	28
Noncurrent Assets		536
Total Assets of Discontinued Operations	$	564
Current Liabilities	$	28
Noncurrent Liabilities		44
Total Liabilities of Discontinued Operations	$	72

Dispositions

Leveraged Leases

For the year ended December, 31, 2011, Energy Holdings sold its leveraged lease investment in an office building in Denver, Colorado for gross proceeds of $215 million. Proceeds net of sales costs were $175 million.

For the year ended December, 31, 2010, Energy Holdings sold its interest in six leveraged leases, including five international leases.

For the year ended December 31, 2009, Energy Holdings sold its interest in fourteen leveraged leases, including twelve international leases.

	Years Ended December 31,
	2011		2010		2009
	Millions
Net Proceeds from Sales	$	175	$	433	$	830
Gain (Loss) on Sales, after-tax	$	34	$	30	$	70

GWF Energy LLC (GWF Energy)

In May 2009, Energy Holdings entered into a Memorandum of Understanding under which it would sell, in two separate transactions, its ownership interest in GWF Energy, an equity method investment, for a total sale price of $70 million. Energy Holdings completed the first stage of the sale in June 2009 for approximately $7 million. Energy Holdings completed the second stage of the sale in September 2010 for approximately $63 million. The total proceeds from both sales approximated the book value of the investment.

Enterprise Group Development Corporation (EGDC)

In December 2010, Energy Holdings sold its EGDC assets in State Street I, II and III for a total sale price of $46 million. The sale resulted in an after-tax gain of $4 million.

PPN Power Generating Company Limited (PPN)

In May 2009, Energy Holdings sold its ownership interest in PPN, which owned and operated a 330 MW generation facility in India for approximately book value.

Other

In May 2009, Energy Holdings sold its 6.5% interest in Midland Cogeneration Venture LP for an after-tax gain of $2 million.

110

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5. Property, Plant and Equipment and Jointly-Owned Facilities

Information related to Property, Plant and Equipment as of December 31, 2011 and 2010 is detailed below:

	Power		PSE&G		Other		PSEG Consolidated
	Millions
2011
Generation:
Fossil Production	$	6,415	$	0	$	0	$	6,415
Nuclear Production		1,138		0		0		1,138
Nuclear Fuel in Service		774		0		0		774
Other Production-Solar		0		345		89		434
Construction Work in Progress		784		19		0		803
Total Generation		9,111		364		89		9,564
Transmission and Distribution:
Electric Transmission		0		2,441		0		2,441
Electric Distribution		0		6,522		0		6,522
Gas Transmission		0		91		0		91
Gas Distribution		0		4,858		0		4,858
Construction Work in Progress		0		546		0		546
Plant Held for Future Use		0		9		0		9
Other		0		386		0		386
Total Transmission and Distribution		0		14,853		0		14,853
Other		80		89		494		663
Total	$	9,191	$	15,306	$	583	$	25,080

	Power		PSE&G		Other		PSEG Consolidated
	Millions
2010
Generation:
Fossil Production	$	6,442	$	0	$	0	$	6,442
Nuclear Production		965		0		0		965
Nuclear Fuel in Service		717		0		0		717
Other Production-Solar		0		204		87		291
Construction Work in Progress		441		0		0		441
Total Generation		8,565		204		87		8,856
Transmission and Distribution:
Electric Transmission		0		2,148		0		2,148
Electric Distribution		0		6,208		0		6,208
Gas Transmission		0		91		0		91
Gas Distribution		0		4,684		0		4,684
Construction Work in Progress		0		211		0		211
Plant Held for Future Use		0		5		0		5
Other		0		389		0		389
Total Transmission and Distribution		0		13,736		0		13,736
Other		78		128		474		680
Total	$	8,643	$	14,068	$	561	$	23,272

As of December 31, 2011, we had accrued capital expenditures of $132 million and $204 million at Power and PSE&G, respectively. As of December 31, 2010, we had accrued capital expenditures of $111 million and $124 million at Power and PSE&G, respectively.

111

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Power and PSE&G have ownership interests in and are responsible for providing their respective shares of the necessary financing for the following jointly-owned facilities. All amounts reflect the share of Power’s and PSE&G’s jointly-owned projects and the corresponding direct expenses are included in the Consolidated Statements of Operations as operating expenses.

	Ownership				Accumulated
December 31, 2011	Interest		Plant		Depreciation
			Millions
Power:
Coal Generating
Conemaugh		23%	$	289	$	126
Keystone		23%	$	381	$	117
Nuclear Generating
Peach Bottom		50%	$	559	$	171
Salem		57%	$	807	$	211
Nuclear Support Facilities		Various	$	171	$	27
Pumped Storage Facilities
Yards Creek		50%	$	34	$	23
Merrill Creek Reservoir		14%	$	1	$	0
PSE&G:
Transmission Facilities		Various	$	152	$	61
Linden SNG Plant		90%	$	5	$	5

	Ownership				Accumulated
December 31, 2010	Interest		Plant		Depreciation
			Millions
Power:
Coal Generating
Conemaugh		23%	$	254	$	122
Keystone		23%	$	376	$	107
Nuclear Generating
Peach Bottom		50%	$	399	$	149
Salem		57%	$	770	$	225
Nuclear Support Facilities		Various	$	135	$	21
Pumped Storage Facilities
Yards Creek		50%	$	32	$	22
Merrill Creek Reservoir		14%	$	1	$	0
PSE&G:
Transmission Facilities		Various	$	148	$	61
Linden SNG Plant		90%	$	5	$	5

Power holds undivided ownership interests in the jointly-owned facilities above, excluding related nuclear fuel and inventories. Power is entitled to shares of the generating capability and output of each unit equal to its respective ownership interests. Power also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. Power’s share of expenses for the jointly-owned facilities is included in the appropriate expense category. Each owner is responsible for any financing with respect to its pro rata share of capital expenditures.

112

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Power co-owns Salem and Peach Bottom with Exelon Generation. Power is the operator of Salem and Exelon Generation is the operator of Peach Bottom. A committee appointed by the co-owners reviews/approves major planning, financing and budgetary (capital and operating) decisions.

GenOn Northeast Management Company is a co-owner and the operator for Keystone Generating Station and Conemaugh Generating Station. A committee appointed by all co-owners makes all planning, financing and budgetary (capital and operating) decisions.

Power is a co-owner in the Yards Creek Pumped Storage Generation Facility. Jersey Central Power & Light Company (JCP&L) is also a co-owner and the operator of this facility. JCP&L submits separate capital and Operations and Maintenance budgets, subject to the approval of Power.

Power is a minority owner in the Merrill Creek Reservoir and Environmental Preserve in Warren County, New Jersey. Merrill Creek Reservoir is the owner-operator of this facility. The operator submits separate capital and Operations and Maintenance budgets, subject to the approval of the non-operating owners.

Note 6. Regulatory Assets and Liabilities

As discussed in Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies, PSE&G prepares its financial statements in accordance with GAAP accounting for regulated utilities. A regulated utility is required to defer the recognition of costs (a Regulatory Asset) or the recognition of obligations (a Regulatory Liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs, which will be amortized over various future periods. These costs are deferred based on rate orders issued by the BPU or FERC or PSE&G’s experience with prior rate cases. With the exception of the Storm Damage and Cape May Street Regulatory Assets, all of PSE&G’s Regulatory Assets and Liabilities at December 31, 2011 and 2010 are supported by written rate orders, either explicitly or implicitly through the BPU’s treatment of various cost items.

Regulatory Assets are subject to prudence reviews and can be disallowed in the future by regulatory authorities. PSE&G believes that all of its Regulatory Assets are probable of recovery. To the extent that collection of any Regulatory Assets or payments of Regulatory Liabilities is no longer probable, the amounts would be charged or credited to income.

113

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PSE&G had the following Regulatory Assets and Liabilities:

	As of December 31,
	2011		2010		Recovery/Refund Period
	Millions
Regulatory Assets
Current:
Non-Utility Generation Charge (NGC)	$	0	$	66	Annual filing for recovery(1)(2)
Underrecovered Electric Costs—BGS		28		12	Various(1)(2)
Societal Benefits Charges (SBC)		87		74	Annual filing for recovery(1)(2)
Renewables & Energy Efficiency		10		0	Annual filing for recovery(1)(2)
Capital Stimulus Undercollection		21		0	Annual filing for recovery(1)(2)
Gas Weather Normalization Deferral		2		0	Annual filing for recovery(2)
OPEB Costs		19		0	Through December 2012(2)
FERC Formula Rate True-up		0		3	Annual filing for recovery(1)(2)
Total Current Regulatory Assets	$	167	$	155
Noncurrent
Stranded Costs To Be Recovered	$	1,460	$	1,776	Through December 2016(1)(2)
Manufactured Gas Plant (MGP) Remediation Costs		635		661	Various(2)
Pension and Other Postretirement		1,280		953	Various
Deferred Income Taxes		393		402	Various
Remediation Adjustment Clause (Other SBC)		92		119	Through 2019(1)(2)
New Jersey Clean Energy Program		253		430	Through February 2013(1)(2)
Gas Contract Mark-to-Market		110		50	Various(1)
OPEB Costs		0		39	Through December 2012(2)
Unamortized Loss on Reacquired Debt and Debt Expense		96		102	Over remaining debt life(1)
Conditional Asset Retirement Obligation		84		72	Various
Repair Allowance Taxes		17		27	Through August 2013(1)(2)
Regulatory Restructuring Costs		8		13	Through August 2013(1)(2)
Gas Margin Adjustment Clause		29		44	Through July 2015(2)
Customer Care System		15		20	Through July 2014
Plant and Regulatory Study Costs		7		9	Through December 2021(2)
Incurred But Not Reported Claim Reserve		15		14	Various
Asbestos Abatement		6		7	Through 2020(2)
Cape May Street Cleanup		9		8	To be determined
Renewables & Energy Efficiency		140		96	Various(2)
Storm Damage		68		8	To be determined
Other		13		14	Various
Total Noncurrent Regulatory Assets	$	4,730	$	4,864
Total Regulatory Assets	$	4,897	$	5,019

114

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	As of December 31,
	2011		2010		Recovery/Refund Period
	Millions
Regulatory Liabilities
Current:
Market Transition Charge Refund, net	$	23	$	58	Through June 2012(2)
Deferred Income Taxes		39		46	Various
Overrecovered Gas Costs—BGSS		30		40	Annual filing for recovery(1)(2)
Renewables & Energy Efficiency		2		7	Annual filing for recovery(1)(2)
Excess Cost of Removal		0		11	Recovery ends November 2011
Capital Stimulus Overcollection		0		5	Annual filing for recovery(1)(2)
FERC Formula Rate True-up		1		5	Annual filing for recovery(1)(2)
NGC		5		0	Annual filing for recovery(1)(2)
BGS Retail Adder		0		2	Charge ends June 2011
Current Regulatory Liabilities	$	100	$	174
Noncurrent:
Electric Cost of Removal	$	222	$	244	Reduced as cost is incurred
Market Transition Charge Refund, net		0		26	January - June 2012
Gas Weather Normalization Deferral		0		9	Annual filing for recovery(1)(2)
Other		15		14	Various(1)
Total Noncurrent Regulatory Liabilities	$	237	$	293
Total Regulatory Liabilities	$	337	$	467

(1) Recovered/Refunded with interest

(2) Recoverable/Refundable per specific rate order

All Regulatory Assets and Liabilities are excluded from PSE&G’s rate base unless otherwise noted. The Regulatory Assets and Liabilities in the table above are defined as follows:

• NGC: Represents the difference between the cost of non-utility generation and the amounts realized from selling that energy at market rates through PJM and ratepayer collections. The BPU instructed PSE&G to transfer the remaining $150 million debit balance for the Market Transition Charge (MTC) from the SBC to the NGC in March 2007.

• Underrecovered Electric Energy Costs: These costs represent the underrecovered amounts associated with Basic Generation Service (BGS), as approved by the BPU.

• SBC: The SBC, as authorized by the BPU and the New Jersey Electric Discount and Energy Competition Act (Competition Act), includes costs related to PSE&G’s electric and gas business as follows: 1) the Universal Service Fund; 2) Energy Efficiency and Renewable Energy Programs; 3) Social Programs (electric only) which include electric bad debt expense; and 4) the Remediation Adjustment Clause (RAC) for incurred MGP remediation expenditures. All components accrue interest on both over and underrecoveries.

• Renewables & Energy Efficiency: These costs are the overrecovered or underrecovered amounts associated with various renewable energy and energy efficiency programs.

• Capital Stimulus Undercollection/Overcollection: BPU approved collection of costs related to distribution projects.

• Gas Weather Normalization Deferral: This represents the over or under collection of gas margin refundable or recoverable under the BPU’s weather normalization clause.

115

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

• FERC Formula Rate True-up: Over or under collection of transmission earnings calculated using a FERC approved formula.

• Stranded Costs To Be Recovered: This reflects deferred costs, which are being recovered through the securitization transition charges authorized by the BPU in irrevocable financing orders and being collected by PSE&G, as servicer on behalf of Transition Funding and Transition Funding II, respectively. Funds collected are remitted to Transition Funding and Transition Funding II and are used for interest and principal payments on the transition bonds and related costs and taxes.

Transition Funding and Transition Funding II are wholly owned, bankruptcy-remote subsidiaries of PSE&G that purchased certain transition property from PSE&G and issued transition bonds secured by such property. The transition property consists principally of the rights to receive electricity consumption-based per kilowatt-hour (kWh) charges from PSE&G electric distribution customers, which represent irrevocable rights to receive amounts sufficient to recover certain of PSE&G’s transition costs related to deregulation, as approved by the BPU.

• MGP Remediation Costs: Represents the low end of the range for the remaining environmental investigation and remediation program costs that are probable of recovery in future rates. Once these costs are incurred, they are recovered through the RAC clause in the SBC.

• Pension and Other Postretirement: Pursuant to the adoption of accounting guidance for employers’ defined benefit pension and OPEB plans, PSE&G recorded the unrecognized costs for defined benefit pension and other OPEB plans on the balance sheet as a Regulatory Asset. These costs represent actuarial gains or losses, prior service costs and transition obligations as a result of adoption, which have not been expensed. These costs will be amortized and recovered in future rates.

• Deferred Income Taxes: These amounts represent the portion of deferred income taxes that will be recovered or refunded through future rates, based upon established regulatory practices. The Regulatory Asset is expected to be recovered, without interest, over the period the underlying book-tax timing differences reverse and become current taxes. The Regulatory Liability is expected to be refunded, without interest, within the next twelve months.

• Remediation Adjustment Clause (Other SBC): Costs incurred to clean up manufactured gas plants which are recovered over seven years.

• New Jersey Clean Energy Program: The BPU approved future funding requirements for Energy Efficiency and Renewable Energy Programs through 2012. Once the rates are measured, they are recovered through the SBC.

• Gas Contract Mark-to-Market (MTM): The fair value of gas hedge contracts and gas cogeneration supply contracts. This asset is offset by a derivative liability and an intercompany payable on the Consolidated Balance Sheets.

• OPEB Costs: Include costs associated with the adoption of accounting guidance for employers’ benefits other than pensions, which were deferred and amortized over fifteen years.

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

• Conditional Asset Retirement Obligation: These costs represent the differences between rate regulated cost of removal accounting and asset retirement accounting under GAAP. These costs will be recovered in future rates.

• Repair Allowance Taxes: This represents tax, interest and carrying charges relating to disallowed tax deductions for repair allowance as authorized by the BPU with recovery over 10 years effective August 1, 2003.

116

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

• Regulatory Restructuring Costs: These are costs related to the restructuring of the energy industry in New Jersey through the Competition Act and include such items as the system design work necessary to transition PSE&G to a transmission and distribution only company, as well as costs incurred to transfer and establish the generation function as a separate corporate entity with recovery over 10 years beginning August 1, 2003.

• Gas Margin Adjustment Clause: PSE&G defers the margin differential received from Transportation Gas Service Non-Firm Customers versus bill credits provided to Basic Gas Supply Service (BGSS)-Firm customers.

• Customer Care System: These are deferred costs associated with the replacement of PSE&G’s legacy customer accounting system in March 2009.

• Plant and Regulatory Study Costs: These are costs incurred by PSE&G and required by the BPU which are related to current and future operations, including safety, planning, management and construction.

• Incurred But Not Reported Claim Reserve: Represents reserves for worker’s compensation and injuries and damages that exceed the amounts recognized in rates on a settlement accounting basis.

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

• Cape May Street Cleanup: Estimated cost for environmental remediation of a company owned site. Recovery will be sought from the BPU.

• Storm Damage: Costs incurred in the cleanup of 2010 and 2011 storms for which recovery will be sought from the BPU.

• Other Regulatory Assets: This includes: 1) Undercollected gas cost of removal; 2) an offset to a liability for future demand side management standard offer spending; and 3) costs related to LCAPP.

• Market Transition Charge Refund (MTC), net: These costs represent the overrecovered amounts associated with MTC.

• Overrecovered Gas Costs: These costs represent the overrecovered amounts associated with BGSS, as approved by the BPU. Interest is accrued on overrecovered balances.

• Excess Cost of Removal: The BPU directed PSE&G to refund $66 million of excess gas cost of removal accruals over a five-year period ending November 2011.

• BGS Retail Adder: Charge included in the BGS tariff rate to induce customer shopping.

• Electric Cost of Removal: PSE&G accrues and collects for cost of removal in rates. The liability for non-legally required cost of removal is classified as a Regulatory Liability. This liability is reduced as removal costs are incurred. Accumulated cost of removal is a reduction to the rate base.

• Other Regulatory Liabilities: This includes: 1) amounts collected from customers in order for Transition Funding to obtain a AAA rating on its transition bonds; 2) third party billing discounts related to the Competition Act; and 3) uncertain tax positions.

117

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 7. Long-Term Investments

Long-Term Investments as of December 31, 2011 and 2010 included the following:

	As of December 31,
	2011		2010
	Millions
Power
Partnerships and Corporate Joint Ventures (Equity Method Investments)	$	32	$	25
PSE&G
Life Insurance and Supplemental Benefits		162		161
Solar Loan Investments		111		62
Other Investments		7		7
Energy Holdings
Leases		881		1,255
Partnerships and Corporate Joint Ventures:
Equity Method Investments (A)		106		105
Cost Method Investments (B)		4		7
Other Investments		0		1
Total Long-Term Investments	$	1,303	$	1,623

(A) During the three years ended December 31, 2011, 2010 and 2009, the amount of dividends from these investments was $3 million, $5 million and $10 million, respectively. Energy Holdings’ share of income and cash flow distribution percentages ranged from 40% to 50% as of December 31, 2011.

(B) Energy Holdings has investments in certain companies in which it does not have the ability to exercise significant influence. Such investments are accounted for under the cost method.

Leases

Energy Holdings has investments in domestic energy and real estate assets subject primarily to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third party debt investor. The debt is recourse only to the assets subject to lease and is not included on PSEG’s Consolidated Balance Sheets. As an equity investor, Energy Holdings’ equity investments in the leases are comprised of the total expected lease receivables over the lease terms plus the estimated residual values at the end of the lease terms, reduced for any income not yet earned on the leases. This amount is included in Long-Term Investments on PSEG’s Consolidated Balance Sheets. The more rapid depreciation of the leased property for tax purposes creates tax cash flow that will be repaid to the taxing authority in later periods. As such, the liability for such taxes due is recorded in Deferred Income Taxes on PSEG’s Consolidated Balance Sheets. The table below shows Energy Holdings’ gross and net lease investment as of December 31, 2011 and 2010, respectively. The net investment in leases was comprised of the following:

	As of December 31,
	2011			2010
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	763		$	896
Estimated Residual Value of Leased Assets		553			905
		1,316			1,801
Unearned and Deferred Income		(435	)		(546	)
Gross Investments in Leases		881			1,255
Deferred Tax Liabilities		(716	)		(899	)
Net Investments in Leases	$	165		$	356

118

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The above table does not include $264 million of Gross Investments in Leases to subsidiaries of Dynegy Incorporated (Dynegy) as of December 31, 2011 as Energy Holdings wrote off its fully-reserved gross investment in these leases in December 2011. See Note 8. Financing Receivables for further discussion.

The pre-tax income and income tax effects, excluding gains and losses on sales, related to investments in leases were as follows:

	Years Ended December 31,
	2011			2010		2009
	Millions
Pre-Tax Income (Loss) from Leases	$	(228	)	$	45	$	23
Income Tax Expense (Benefit) on Pre-Tax Income from Leases	$	(77	)	$	14	$	23

Equity Method Investments

Power and Energy Holdings had the following equity method investments as of December 31, 2011:

			%
Name	Location		Owned
Power
Keystone		PA		23%
Conemaugh		PA		23%
Energy Holdings
Kalaeloa		HI		50%
GWF		CA		50%
Hanford L. P. (Hanford)		CA		50%
Bridgewater		NH		40%
Turboven		Venezuela		50%

Note 8. Financing Receivables

PSE&G

PSE&G sponsors a solar loan program designed to help finance the installation of solar power systems throughout its electric service area. The loans are generally paid back with Solar Renewable Energy Certificates (SRECS) generated from the installed solar electric system. The following table reflects the outstanding short and long-term loans by class of customer, none of which would be considered “non-performing.”

Credit Risk Profile Based on Payment Activity
	As of December 31,
Consumer Loans	2011		2010
	Millions
Commercial/Industrial	$	106	$	62
Residential		10		4
	$	116	$	66

Energy Holdings

Energy Holdings had a net investment in domestic energy and real estate assets subject primarily to leveraged lease accounting of $165 million and $356 million as of December 31, 2011 and 2010, respectively (See Note 7. Long-Term Investments).

119

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The corresponding receivables associated with the lease portfolio are reflected below, net of non-recourse debt. The ratings in the table represent the ratings of the entities providing payment assurance to Energy Holdings. “Not Rated” counterparties relate to investments in leases of commercial real estate properties.

	Lease Receivables, Net of Non-Recourse Debt
	As of December 31,
Counterparties’ Credit Rating (S&P)	2011		2010
	Millions
AAA - AA	$	21	$	21
A		110		112
BBB - BB		316		316
B - B-		299		430
Not Rated		17		17
	$	763	$	896

The “B” and “B-” ratings above represent lease receivables underlying coal fired assets in Illinois and Pennsylvania. As of December 31, 2011, the gross investment in the leases of such assets, net of non-recourse debt, was $550 million ($37 million, net of deferred taxes). A more detailed description of such assets under lease is presented in the table below.

			Gross		%				Fuel
Asset	Location		Investment		Owned		Total		Type		Counterparty
			Millions				MW
Powerton Station Units 5 and 6		IL	$	134		64%		1,538		Coal	Edison Mission Energy
Joliet Station Units 7 and 8		IL	$	84		64%		1,044		Coal	Edison Mission Energy
Keystone Station Units 1 and 2		PA	$	112		17%		1,711		Coal	GenOn REMA, LLC
Conemaugh Station Units 1 and 2		PA	$	112		17%		1,711		Coal	GenOn REMA, LLC
Shawville Station Units 1, 2, 3 and 4		PA	$	108		100%		603		Coal	GenOn REMA, LLC

Although all payments of equity rent, debt service and other fees are current, no assurances can be given that all payments in accordance with the lease contracts will continue. Factors which may impact future lease cash flows include, but are not limited to, new environmental legislation and regulation regarding air quality, water and other discharges in the process of generating electricity, market prices for fuel and electricity, overall financial condition of lease counterparties and the quality and condition of assets under lease. Of our facilities under lease to GenOn REMA, LLC (GenOn REMA), PSEG believes Keystone has adequate environmental controls installed and Conemaugh has flue gas desulfurization controls and mercury controls, with the final component, selective catalytic reduction (SCR) equipment for Nitrogen Oxide (NO_x) scheduled to be installed in 2014.

GenOn REMA’s Shawville facility recently received approval to delay until July 31, 2015, the implementation requirements under a renewed National Pollutant Discharge Elimination System (NPDES) permit to reduce thermal impacts from the plant. Those requirements could include the installation of cooling towers. There are also interim milestones that could trigger regulatory action prior to July 31, 2015 if changes are not made. The lessee is continuing to evaluate the economics of installing cooling towers and other environmental capital expenditures while considering its options under the lease which could include termination for economic

120

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

obsolescence. In the event of an early termination for obsolescence, the lessee would be required to pay equal to the difference between the pre-determined termination value ($218 million in December 2011 and declining each month thereafter) as specified in the lease agreement and the proceeds received in connection with the sale of the facility to a third party.

With respect to Edison Mission Energy’s (EME) Midwest Generation leases on the efficient Powerton and Joliet coal units in Illinois, the lessees completed investments in low NOx burners and Selective Non-Catalytic Reduction system and plan to utilize a Trona system to reduce sulfur. EME and these units remain in litigation with the United States Environmental Protection Agency (EPA) and the State of Illinois regarding certain environmental matters, but EME has announced that the above actions should enable compliance with pending environmental rules. The federal district court has dismissed the new source review claims in reference to Powerton and Joliet, but the opacity claims remain active. The EPA and the State of Illinois have appealed this dismissal to the United States Seventh Circuit Court of Appeals. EME is opposing the appeal. EME continues to contest the opacity claims. The federal district court has stayed proceedings in connection with the opacity claims until the appeal is determined.

The credit exposure to the lessors is partially mitigated through various credit enhancement mechanisms within the lease transactions. These credit enhancement features vary from lease to lease. Some of the leasing transactions include covenants that restrict the flow of dividends from the lessee to its parent, over-collateralization of the lessee with non-leased assets, historical and forward cash flow coverage tests that prohibit discretionary capital expenditures and dividend payments to the parent/lessee if stated minimum coverage ratios are not met and similar cash flow restrictions if ratings are not maintained at stated levels. These covenants are designed to maintain cash reserves in the transaction entity for the benefit of the non-recourse lenders and the lessor/equity participants in the event of a temporary market downturn or degradation in operating performance of the leased assets. In the event of a default in any of the lease transactions, Energy Holdings would exercise its rights and attempt to seek recovery of its investment. The results of such efforts may not be known for a period of time. A bankruptcy of a lessee and failure to recover adequate value could lead to a foreclosure of the lease. If foreclosures were to occur, Energy Holdings could potentially record a pre-tax write-off up to its gross investment in these facilities and may also be required to pay significant cash tax liabilities.

As a result of Dynegy’s corporate reorganization in September 2011, Energy Holdings evaluated its likely recovery under the lease arrangements for the Roseton and Danskammer facilities leased to subsidiaries of Dynegy Holdings LLC (DH). Considering the overall value of the underlying assets subject to lease, Energy Holdings fully reserved its $264 million gross investment. This gross charge was reflected as a reduction to third quarter Operating Revenues and resulted in an after-tax charge of approximately $170 million. On November 7, 2011, DH, including the lessee entities in our Danskammer and Roseton leveraged lease transactions (Dynegy leases), filed for relief under Chapter 11 of the Bankruptcy Code. DH filed a Restructuring Support Agreement (RSA) between Dynegy, DH and holders of approximately 40% of DH’s outstanding senior unsecured and subordinated notes and debentures as part of its bankruptcy filings. DH expects the terms of the RSA, which are set forth in DH’s proposed plan of reorganization, to become effective in August 2012 assuming confirmation of its plan of reorganization by the Bankruptcy Court.

On December 13, 2011, Energy Holdings and Dynegy reached a settlement agreement resolving disputes that had arisen between them with regard to DH’s rejection of the Dynegy leases. The settlement agreement assigns to Dynegy our rights to certain future payments or distributions related to the Dynegy leases; it also resolves our claims under our Tax Indemnity Agreement with DH. The terms of the settlement agreement include a cash payment of $7.5 million, which was received on January 4, 2012, and the allowance of a $110 million claim against DH payable through a mix of cash, senior secured notes and mandatorily convertible notes following confirmation of the DH plan of reorganization by the Bankruptcy Court. The Bankruptcy Court approved the settlement agreement and DH’s rejection of the Dynegy leases by an order that became effective on December 30, 2011. The rejection of the leases triggered the reclassification of $30 million of the deferred tax liability to current status. The ultimate amount recognized from our claim could change based

121

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

upon the final outcome of the Bankruptcy Court’s review of DH’s plan of reorganization and the respective fair values of the securities received pursuant to the plan of reorganization. The amounts received will be reflected as an increase in Operating Revenues.

A Bankruptcy Examiner was appointed on January 11, 2012 to investigate events surrounding Dynegy’s reorganization that it completed prior to the filing of its Chapter 11 petition. The Examiner’s report could impact the potential approval and overall timing of the Court’s review of Dynegy’s plan of reorganization which could impact both the outcome and timing of the realization of our settlement claim.

Upon the effective date of the order authorizing the Dynegy lease rejections, the leases no longer qualified for leveraged lease accounting treatment under GAAP since the lease agreements were effectively terminated. As a result, Energy Holdings wrote off the $264 million gross lease investment against the aforementioned reserve. As the owner of the two plants, Energy Holdings’ lessor entities ceased leveraged lease accounting, and recorded the generation assets and related nonrecourse project debt on their balance sheets at their respective fair values. (See Note 17. Fair Value Measurements) The lessor entities were consolidated by Energy Holdings as of December 31, 2011.

Note 9. Available-for-Sale Securities

NDT Fund

In accordance with NRC regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operation. As a general practice, each nuclear owner places funds in independent external trust accounts it maintains to provide for decommissioning. Power is required to file periodic reports with the NRC demonstrating that the NDT Fund meets the formula-based minimum NRC funding requirements.

Power maintains an external master NDT to fund its share of decommissioning for its five nuclear facilities upon their respective termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. Power’s share of decommissioning costs related to its five nuclear units was estimated at approximately $2.1 billion, including contingencies. The liability for decommissioning recorded on a discounted basis as of December 31, 2011 was approximately $238 million and is included in the Asset Retirement Obligation. The trust funds are managed by third-party investment advisors who operate under investment guidelines developed by Power.

Power classifies investments in the NDT Fund as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund:

	As of December 31, 2011
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	582	$	126	$	(23	)	$	685
Debt Securities
Government Obligations		343		16		0			359
Other Debt Securities		268		15		(2	)		281
Total Debt Securities		611		31		(2	)		640
Other Securities		24		0		0			24
Total Available-for-Sale Securities	$	1,217	$	157	$	(25	)	$	1,349

122

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	As of December 31, 2010
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	525	$	213	$	(3	)	$	735
Debt Securities
Government Obligations		301		6		(4	)		303
Other Debt Securities		247		10		(2	)		255
Total Debt Securities		548		16		(6	)		558
Other Securities		70		0		0			70
Total Available-for-Sale Securities	$	1,143	$	229	$	(9	)	$	1,363

These amounts do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table.

	As of December 31, 2011		As of December 31, 2010
	Millions
Accounts Receivable	$	27	$	35
Accounts Payable	$	22	$	60

The following table shows the value of securities in the NDT Fund that have been in an unrealized loss position for less than 12 months and greater than 12 months:

	As of December 31, 2011										As of December 31, 2010
	Less Than 12 Months					Greater Than 12 Months					Less Than 12 Months					Greater Than 12 Months
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
Equity Securities (A)	$	183	$	(23	)	$	0	$	0		$	55	$	(3	)	$	0	$	0
Debt Securities
Government Obligations (B)		20		0			3		0			106		(4	)		1		0
Other Debt Securities (C)		56		(1	)		4		(1	)		65		(1	)		8		(1	)
Total Debt Securities		76		(1	)		7		(1	)		171		(5	)		9		(1	)
Other Securities		0		0			0		0			0		0			0		0
Total Available-for-Sale Securities	$	259	$	(24	)	$	7	$	(1	)	$	226	$	(8	)	$	9	$	(1	)

(A) Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over hundreds of companies with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of December 31, 2011.

(B) Debt Securities (Government)—Unrealized losses on Power’s NDT investments in United States Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate

123

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

changes. Since these investments are guaranteed by the United States government or an agency of the United States government, it is not expected that these securities will settle for less than their amortized cost basis, since Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of December 31, 2011.

(C) Debt Securities (Corporate)—Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2011.

The proceeds from the sales of and the net realized gains on securities in the NDT Fund were:

	Years Ended December 31,
	2011			2010			2009
	Millions
Proceeds from Sales	$	1,355		$	958		$	1,769
Net Realized Gains:
Gross Realized Gains	$	144		$	119		$	183
Gross Realized Losses		(45	)		(39	)		(135	)
Net Realized Gains	$	99		$	80		$	48

Net realized gains disclosed in the above table were recognized in Other Income and Other Deductions in PSEG’s and Power’s Consolidated Statements of Operations. Net unrealized gains of $66 million (after-tax) are included in Accumulated Other Comprehensive Loss on Power’s Consolidated Balance Sheet as of December 31, 2011.

The available-for-sale debt securities held as of December 31, 2011 had the following maturities:

Time Frame	Fair Value
	Millions
Less than one year	$	10
1 - 5 years		132
6 - 10 years		177
11 - 15 years		42
16 - 20 years		14
Over 20 years		265
	$	640

The cost of these securities was determined on the basis of specific identification.

Power periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). In 2011, other-than-temporary impairments of $19 million were recognized on securities in the NDT Fund. Any subsequent recoveries in the value of these securities would be recognized in Accumulated Other Comprehensive Income (Loss) unless the securities are sold, in which case, any gain would be recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.

124

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Rabbi Trust

PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in a grantor trust commonly known as the “Rabbi Trust.” In August 2010, PSEG revised the asset structure of the Rabbi Trust and realized gains of approximately $31 million as the investments were transitioned to a new asset allocation and investment manager. The new structure resulted in lower investment management fees.

PSEG classifies investments in the Rabbi Trust as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized cost bases for the securities held in the Rabbi Trust.

	As of December 31, 2011
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	Millions
Equity Securities	$	16	$	3	$	0	$	19
Debt Securities		148		5		0		153
Total PSEG Available-for-Sale Securities	$	164	$	8	$	0	$	172

	As of December 31, 2010
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	Millions
Equity Securities	$	16	$	2	$	0	$	18
Debt Securities		142		0		0		142
Total PSEG Available-for-Sale Securities	$	158	$	2	$	0	$	160

The Rabbi Trust is invested in commingled indexed mutual funds, in which the shares have the characteristics of equity securities. Due to the commingled nature of these funds, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. In 2011, other-than-temporary impairments of $3 million were recognized on the investments of the Rabbi Trust.

	Years Ended December 31,
	2011		2010		2009
	Millions
Proceeds from Sales	$	0	$	158	$	2
Net Realized Gains (Losses):
Gross Realized Gains	$	0	$	31	$	0
Gross Realized Losses		0		0		(1	)
Net Realized Gains (Losses)	$	0	$	31	$	(1	)

The cost of these securities was determined on the basis of specific identification.

125

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	As of December 31, 2011		As of December 31, 2010
	Millions
Power	$	33	$	32
PSE&G		57		54
Other		82		74
Total PSEG Available-for-Sale Securities	$	172	$	160

Note 10. Goodwill and Other Intangibles

As of each of December 31, 2011 and 2010, Power had goodwill of $16 million related to the Bethlehem Energy Center. Power conducted an annual review for goodwill impairment as of October 31, 2011 and concluded that goodwill was not impaired. No events occurred subsequent to that date which would require a further review of goodwill for impairment.

In addition to goodwill, as of December 31, 2011 and 2010, Power had intangible assets of $131 million and $130 million, respectively, related to emissions allowances and renewable energy credits. Emissions expense includes impairments of emissions allowances and costs for emissions, which is recorded as emissions occur. Expense related to renewable energy requirements is recorded as load is served under contracts requiring energy from renewable sources. Such expenses for the years ended December 31, 2011, 2010 and 2009 were as follows:

	Years Ended December 31,
	2011		2010		2009
			Millions
Emissions Expense	$	35	$	52	$	34
Renewable Energy Expense	$	43	$	50	$	46

Note 11. Asset Retirement Obligations (AROs)

PSEG, Power and PSE&G have recorded various AROs which represent legal obligations to remove or dispose of an asset or some component of an asset at retirement.

Power’s ARO liability primarily relates to the decommissioning of its nuclear power plants. Power has an independent external trust that is intended to fund decommissioning of its nuclear facilities upon termination of operation. For additional information, see Note 9. Available-for-Sale Securities. Power also identified conditional AROs primarily related to Power’s fossil generation units, including liabilities for

• removal of asbestos, stored hazardous liquid material and underground storage tanks from industrial power sites,

• restoration of leased office space to rentable condition upon lease termination,

• permits and authorizations,

• restoration of an area occupied by a reservoir when the reservoir is no longer needed, and

• demolition of certain plants, and the restoration of the sites at which they reside when the plants are no longer in service.

PSE&G has a conditional ARO for legal obligations related to the removal of asbestos and underground storage tanks at certain industrial establishments, removal of wood poles, leases and licenses, removal of solar

126

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

panels from leased property and the requirement to seal natural gas pipelines at all sources of gas when the pipelines are no longer in service. PSE&G did not record an ARO for its protected steel and poly-based natural gas transmission lines, as management believes that these categories of transmission lines have an indeterminable life.

The changes to the ARO liabilities for PSEG, Power and PSE&G during 2011 are presented in the following table:

	PSEG			Power			PSE&G			Other
	Millions
ARO Liability as of January 1, 2011	$	461		$	242		$	216		$	3
Liabilities Settled		(6	)		(1	)		(5	)		0
Liabilities Incurred		2			0			2			0
Accretion Expense		19			18			0			1
Accretion Expense Deferred and Recovered in Rate Base (A)		13			0			13			0
ARO Liability as of December 31, 2011	$	489		$	259		$	226		$	4

(A) Not reflected as expense in Consolidated Statements of Operations

Note 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plans

PSEG sponsors several qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. Eligible employees of Power, PSE&G, Energy Holdings and Services participate in non-contributory pension and OPEB plans sponsored by PSEG and administered by Services. In addition, represented and nonrepresented employees are eligible for participation in PSEG’s two defined contribution plans described below.

PSEG, Power and PSE&G are required to record the under or over funded positions of their defined benefit pension and OPEB plans on their respective balance sheets. Such funding positions of each PSEG company are required to be measured as of the date of its respective year-end Consolidated Balance Sheets. For under funded plans, the liability is equal to the difference between the plan’s benefit obligation and the fair value of plan assets. For defined benefit pension plans, the benefit obligation is the projected benefit obligation. For OPEB plans, the benefit obligation is the accumulated postretirement benefit obligation. In addition, accounting guidance requires that the total unrecognized costs for defined benefit pension and OPEB plans be recorded as an after-tax charge to Accumulated Other Comprehensive Income (Loss), a separate component of Stockholders’ Equity. However, for PSE&G, because the amortization of the unrecognized costs is being collected from customers, the accumulated unrecognized costs are recorded as a Regulatory Asset. The unrecognized costs represent actuarial gains or losses, prior service costs and transition obligations arising from the adoption of the revised accounting guidance for pensions and OPEB, which had not been expensed.

For Power, the charge to Accumulated Other Comprehensive Income (Loss) is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations. For PSE&G, the Regulatory Asset is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations.

In early June 2011, PSEG amended certain provisions of its pension and OPEB plans, including revisions to the benefit formulas for certain participants of PSEG’s qualified and nonqualified pension and OPEB plans. The weighted average discount rate for the pension plans decreased from 5.51% to 5.31% while the discount rate for the OPEB plans decreased from 5.50% to 5.30%. The expected long-term rate of return on plan assets remained at 8.50%. The pension benefit and OPEB obligations, as well as the asset values, were re-measured as of May 31, 2011 (the closest month-end date to the time the revisions were made). As a result, the annual net periodic pension benefit cost for 2011 decreased by $32 million and the 2011 annual net OPEB cost decreased by $6 million compared to costs that would have been expensed in 2011 if PSEG did not re-measure.

127

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides a roll-forward of the changes in the benefit obligation and the fair value of plan assets during each of the two years in the periods ended December 31, 2011 and 2010. It also provides the funded status of the plans and the amounts recognized and amounts not recognized in the Consolidated Balance Sheets at the end of both years.

	Pension Benefits						Other Benefits
	2011			2010			2011			2010
	Millions
Change in Benefit Obligation:
Benefit Obligation at Beginning of Year	$	4,353		$	4,017		$	1,162		$	1,255
Service Cost		92			87			14			16
Interest Cost		228			231			61			72
Actuarial (Gain) Loss		300			242			179			58
Gross Benefits Paid		(236	)		(224	)		(67	)		(72	)
Medicare Subsidy Receipts		0			0			6			4
Plan Amendments		(165	)		0			(17	)		(171	)
Benefit Obligation at End of Year	$	4,572		$	4,353		$	1,338		$	1,162
Change in Plan Assets:
Fair Value of Assets at Beginning of Year	$	3,555		$	2,914		$	195		$	160
Actual Return on Plan Assets		87			441			5			24
Employer Contributions		425			424			72			79
Gross Benefits Paid		(236	)		(224	)		(67	)		(72	)
Medicare Subsidy Receipts		0			0			6			4
Fair Value of Assets at End of Year	$	3,831		$	3,555		$	211		$	195
Funded Status:
Funded Status (Plan Assets less Benefit Obligation)	$	(741	)	$	(798	)	$	(1,127	)	$	(967	)
Additional Amounts Recognized in the Consolidated Balance Sheets:
Current Accrued Benefit Cost	$	(7	)	$	(10	)	$	0		$	0
Noncurrent Accrued Benefit Cost		(734	)		(788	)		(1,127	)		(967	)
Amounts Recognized	$	(741	)	$	(798	)	$	(1,127	)	$	(967	)
Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (A):
Net Transition Obligation	$	0		$	0		$	2		$	15
Prior Service Cost		(158	)		(3	)		(81	)		(85	)
Net Actuarial Loss		1,991			1,562			390			212
Total	$	1,833		$	1,559		$	311		$	142

(A) Includes $745 million ($438 million, after-tax) and $640 million ($377 million, after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2011 and 2010, respectively.

The pension benefits table above provides information relating to the funded status of all qualified and nonqualified pension plans and OPEB plans on an aggregate basis. As of December 31, 2011, PSEG has funded approximately 84% of its projected benefit obligation. This percentage does not include $172 million of assets in the Rabbi Trust as of December 31, 2011, which are used to partially fund the nonqualified pension plans. The fair values of the Rabbi Trust assets are included in the Consolidated Balance Sheets.

128

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Accumulated Benefit Obligation

The accumulated benefit obligation for all PSEG’s defined benefit pension plans was $4.3 billion as of December 31, 2011 and $3.9 billion as of December 31, 2010.

The following table provides the components of net periodic benefit cost for the years ended December 31, 2011, 2010 and 2009.

	Pension Benefits Years Ended December 31,									Other Benefits Years Ended December 31,
	2011			2010			2009			2011			2010			2009
	Millions
Components of Net Periodic Benefit Cost:
Service Cost	$	92		$	87		$	76		$	14		$	16		$	13
Interest Cost		228			231			235			61			72			73
Expected Return on Plan Assets		(334	)		(266	)		(215	)		(18	)		(14	)		(12	)
Amortization of Net
Transition Obligation		0			0			0			4			27			27
Prior Service Cost		(11	)		0			7			(13	)		13			13
Actuarial Loss		119			122			113			14			8			(2	)
Net Periodic Benefit Cost	$	94		$	174		$	216		$	62		$	122		$	112
Effect of Regulatory Asset		0			0			0			19			19			19
Total Benefit Costs, Including Effect of Regulatory Asset	$	94		$	174		$	216		$	81		$	141		$	131

Pension costs and OPEB costs for PSEG, Power and PSE&G are detailed as follows:

	Pension Benefits Years Ended December 31,						Other Benefits Years Ended December 31,
	2011		2010		2009		2011		2010		2009
	Millions
Power	$	29	$	54	$	65	$	12	$	17	$	11
PSE&G		51		97		120		67		120		116
Other		14		23		31		2		4		4
Total Benefit Costs	$	94	$	174	$	216	$	81	$	141	$	131

The following table provides the pre-tax changes recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Deferred Assets:

	Pension						OPEB
	2011			2010			2011			2010
	Millions
Net Actuarial (Gain) Loss in Current Period	$	547		$	67		$	192		$	48
Amortization of Net Actuarial Gain (Loss)		(119	)		(122	)		(14	)		(8	)
Prior Service Credit in Current Period		(165	)		0			(17	)		(171	)
Amortization of Prior Service Credit		11			0			13			(13	)
Amortization of Transition Asset		0			0			(4	)		(27	)
Total	$	274		$	(55	)	$	170		$	(171	)

129

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Amounts that are expected to be amortized from Accumulated OCL, Regulatory Assets and Deferred Assets into Net Periodic Benefit Cost in 2012 are as follows:

	Pension Benefits 2012			Other Benefits 2012
	Millions
Actuarial (Gain) Loss	$	168		$	31
Prior Service Cost	$	(19	)	$	(14	)
Transition Obligation	$	0		$	2

The following assumptions were used to determine the benefit obligations and net periodic benefit costs:

	Pension Benefits						Other Benefits
	2011		2010		2009		2011			2010			2009
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31:
Discount Rate		5.00%		5.51%		5.91%		5.00%			5.50%			5.90%
Rate of Compensation Increase		4.61%		4.61%		4.61%		4.61%			4.61%			4.61%
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31:
Discount Rate		5.40%		5.91%		6.80%		5.38%			5.90%			6.80%
Expected Return on Plan Assets		8.50%		8.50%		8.75%		8.50%			8.50%			8.75%
Rate of Compensation Increase		4.61%		4.61%		4.61%		4.61%			4.61%			4.61%
Assumed Health Care Cost Trend Rates as of December 31:
Administrative Expense								5.00%			5.00%			5.00%
Dental Costs								6.00%			6.00%			6.00%
Pre-65 Medical Costs
Immediate Rate								8.00%			7.75%			8.50%
Ultimate Rate								5.00%			5.00%			5.00%
Year Ultimate Rate Reached								2016			2015			2015
Post-65 Medical Costs
Immediate Rate								8.25%			8.75%			9.50%
Ultimate Rate								5.00%			5.00%			5.00%
Year Ultimate Rate Reached								2017			2016			2016
Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs:
							Millions
Total of Service Cost and Interest Cost							$	11		$	10		$	11
Postretirement Benefit Obligation							$	155		$	122		$	137
Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs:
Total of Service Cost and Interest Cost							$	(9	)	$	(8	)	$	(9	)
Postretirement Benefit Obligation							$	(128	)	$	(102	)	$	(115	)

Plan Assets

All the investments of pension plans and OPEB plans are held in a trust account by the trustee and consist of an undivided interest in an investment account of the Master Trust. Effective January 1, 2008, the pension plans and OPEB plans adopted accounting guidance for fair value measurements. See Note 17. Fair Value Measurements for more information on fair value guidance. Use of the Master Trust permits the commingling of pension plan assets and OPEB plan assets for investment and administrative purposes. Although assets of both plans are commingled in the Master Trust, the Trustee maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Trustee to each participating plan based on the

130

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

relationship of the interest of each plan to the total of the interests of the participating plans. As of December 31, 2011, the pension plan interest and OPEB plan interest in such assets of the Master Trust were approximately 95% and 5%, respectively.

The following tables present information about the investments measured at fair value on a recurring basis at December 31, 2011 and 2010, including the fair value measurements and the levels of inputs used in determining those fair values.

	Recurring Fair Value Measurements as of December 31, 2011
			Quoted Market Prices for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	Total		(Level 1)		(Level 2)		(Level 3)
	Millions
Temporary Investment Funds (A)	$	32	$	0	$	32	$	0
Common Stocks (B)
Commingled—US		1,653		1,653		0		0
Commingled—International		603		603		0		0
Other		356		356		0		0
Bonds (C)
Government (US & Foreign)		662		0		662		0
Other		663		0		663		0
Pooled Real Estate (D)		36		0		0		36
Private Equity (E)		37		0		0		37
	$	4,042	$	2,612	$	1,357	$	73

	Recurring Fair Value Measurements as of December 31, 2010
			Quoted Market Prices for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	Total		(Level 1)		(Level 2)		(Level 3)
	Millions
Temporary Investment Funds (A)	$	118	$	0	$	95	$	23
Common Stocks (B)
Commingled—US		1,568		1,568		0		0
Commingled—International		696		696		0		0
Other		352		352		0		0
Bonds (C)
Commingled—US		8		0		0		8
Government (US & Foreign)		378		0		378		0
Other		544		0		544		0
Pooled Real Estate (D)		48		0		0		48
Private Equity (E)		38		0		0		38
	$	3,750	$	2,616	$	1,017	$	117

(A) Certain temporary investment funds are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (primarily Level 2), whereas certain other commingled temporary investment funds are measured with significant unobservable inputs and assumptions (primarily Level 3).

131

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(B) Wherever possible, fair values of equity investments in stocks and in commingled funds are derived from quoted market prices as substantially all of these instruments have active markets (primarily Level 1). Most investments in stocks are priced utilizing the principal market close price or in some cases midpoint, bid or ask price.

(C) Investments in fixed income securities including bond funds are priced using an evaluated pricing approach or the most recent exchange or quoted bid (primarily Level 2). Certain investments in privately held commingled bond funds are valued using broker quotations or using inputs that are not market observable or can not be derived principally from or corroborated by observable market data (primarily Level 3).

(D) The fair value of real estate investments is based on the annual independent appraisals. The investments are also valued internally every quarter by the investment managers based on significant changes in property operations and market conditions (primarily Level 3).

(E) Limited partnership interests in private equity funds are valued using significant unobservable inputs as there is little, if any, market activity. In addition, there may be transfer restrictions on private equity securities. The process for determining the fair value of such securities relied on commonly accepted valuation techniques, including the use of earnings multiples based on comparable public securities, industry-specific non-earnings-based multiples and discounted cash flow models. These inputs require significant management judgment or estimation (primarily Level 3).

Reconciliations of the beginning and ending balances of the Pension and OPEB Plans’ Level 3 assets for the years ended December 31, 2011 and 2010 follow:

	Balance as of January 1, 2011		Purchases/ (Sales)			Transfer In/ (Out) (A)			Actual Return on Asset Sales		Actual Return on Assets Still Held			Balance as of December 31, 2011
	Millions
Temporary Investment Funds	$	23	$	0		$	(23	)	$	0	$	0		$	0
Commingled Bonds—US	$	8	$	(8	)	$	0		$	0	$	0		$	0
Pooled Real Estate	$	48	$	(18	)	$	0		$	1	$	5		$	36
Private Equity	$	38	$	(5	)	$	0		$	7	$	(3	)	$	37

	Balance as of January 1, 2010		Purchases/ (Sales)			Actual Return on Asset Sales			Actual Return on Assets Still Held		Balance as of December 31, 2010
	Millions
Temporary Investment Funds	$	53	$	(30	)	$	0		$	0	$	23
Commingled Bonds—US	$	17	$	(11	)	$	1		$	1	$	8
Commingled Bonds—International	$	11	$	0		$	(11	)	$	0	$	0
Pooled Real Estate	$	102	$	(53	)	$	(29	)	$	28	$	48
Private Equity	$	37	$	(7	)	$	5		$	3	$	38

(A) During the year ended December 31, 2011, $23 million of the temporary investment funds in the Pension and OPEB Fund were transferred from Level 3 to Level 2, due to more observable pricing for the underlying securities. As per PSEG’s policy, this transfer was recognized as of the beginning of the first quarter (i.e. the quarter in which the transfer occurred).

There were no transfers among levels during the year ending December 31, 2010.

132

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans as of the measurement date, December 31:

	As of December 31,
Investments	2011		2010
Equity Securities		64%		70%
Fixed Income Securities		33%		25%
Real Estate Assets		1%		1%
Other Investments		2%		4%
Total Percentage		100%		100%

PSEG utilizes forecasted returns, risk, and correlation of all asset classes in order to develop a portfolio designed to produce the maximum return opportunity per unit of risk. In 2011, PSEG completed its latest asset/liability study. The results from the study indicated that a long-term target asset allocation of 70% equities and 30% fixed income is consistent with the funds’ financial objectives. Derivative financial instruments are used by the plans’ investment managers primarily to rebalance the fixed income/equity allocation of the portfolio and hedge the currency risk component of foreign investments. The expected long-term rate of return on plan assets was 8.50% as of December 31, 2011 and will change to 8.00% for 2012. This expected return was determined based on the study discussed above and considered the plans’ historical annualized rate of return since inception, which was an annualized return of 9.2%.

Plan Contributions

PSEG may contribute up to $124 million into its pension plans and $11 million into its OPEB plan for calendar year 2012.

Estimated Future Benefit Payments

The following pension benefit and postretirement benefit payments are expected to be paid to plan participants. OPEB payments are shown both gross and net of the federal subsidy expected for prescription drugs under the Medicare Prescription Drug Improvement and Modernization Act of 2003. The Act provides a nontaxable federal subsidy to employers that provide retiree prescription drug benefits that are equivalent to the benefits of Medicare Part D.

			Other Benefits
Year	Pension Benefits		Gross OPEB		Medicare Subsidy			Net OPEB
	Millions
2012	$	247	$	81	$	(6	)	$	75
2013		251		77		0			77
2014		257		78		0			78
2015		264		78		0			78
2016		272		79		0			79
2017-2021		1,514		407		0			407
Total	$	2,805	$	800	$	(6	)	$	794

401(k) Plans

PSEG sponsors two 401(k) plans, which are Employee Retirement Income Security Act defined contribution retirement plans. Eligible represented employees of Power, PSE&G and Services participate in the PSEG Employee Savings Plan (Savings Plan), while eligible non-represented employees of Power, PSE&G, Energy Holdings and Services participate in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). Eligible

133

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

employees may contribute up to 50% of their compensation to these plans. PSEG matches certain employee contributions up to 7% for Savings Plan participants and up to 8% for Thrift Plan participants equal to 50% of such employee contributions.

Effective in February 2010, company matching contributions were suspended for non-represented employees of Power, PSE&G, Energy Holdings and Services who participate in the Thrift Plan and are eligible for retirement benefits under the qualified final average pay pension plan. Company matching contributions were reduced for certain represented employees of Power, PSE&G and Services who participate in the Savings Plan and qualify for benefits under the qualified final average pay pension plan from 50% to 25% on the first 7% of pay contributions beginning in February 2010. Effective January 1, 2011, the company matching contributions were reinstated to 50% on the first 7% of pay contributions for certain represented employees. Effective January 1, 2012, the company matching was reinstated for non-represented employees.

The amount paid for employer matching contributions to the plans for PSEG, Power and PSE&G are detailed as follows:

	Thrift Plan and Savings Plan
	Years Ended December 31,
	2011		2010		2009
	Millions
Power	$	8	$	5	$	10
PSE&G		14		9		17
Other		2		3		5
Total Employer Matching Contributions	$	24	$	17	$	32

Note 13. Commitments and Contingent Liabilities

Guaranteed Obligations

Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees.

Power has unconditionally guaranteed payments to counterparties by its subsidiaries in commodity-related transactions in order to

• support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and

• obtain credit.

Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction.

In order for Power to incur a liability for the face value of the outstanding guarantees, its subsidiaries would have to

• fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee, and

• all of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties).

Power believes the probability of this result is unlikely. For this reason, Power believes that the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. This current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.

134

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Power is subject to

• counterparty collateral calls related to commodity contracts, and

• certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries.

Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules.

The face value of outstanding guarantees, current exposure and margin positions as of December 31, 2011 and 2010 are shown below:

	As of December 31,			As of December 31,
	2011			2010
	Millions
Face Value of Outstanding Guarantees	$	1,756		$	1,936
Exposure under Current Guarantees	$	315		$	330
Letters of Credit Margin Posted	$	135		$	137
Letters of Credit Margin Received	$	91		$	109
Cash Deposited and Received
Counterparty Cash Margin Deposited	$	20		$	0
Counterparty Cash Margin Received	$	(7	)	$	(2	)
Net Broker Balance Deposited (Received)	$	(92	)	$	(28	)
In the Event Power were to Lose its Investment Grade Rating:
Additional Collateral that could be Required	$	812		$	828
Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral	$	3,415		$	2,750
Additional Amounts Posted
Other Letters of Credit	$	52		$	98

As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 16. Financial Risk Management Activities for further discussion. In accordance with our accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Balance Sheet. The remaining balances of net cash (received)/deposited after allocation is generally included in Accounts Payable and Receivable, respectively.

In the event of a deterioration of Power’s credit rating to below investment grade, which would represent a two level downgrade from its current ratings, many of these agreements allow the counterparty to demand further performance assurance. See table above.

In addition, during 2011, the SEC and the Commodity Futures Trading Commission (CFTC) are continuing efforts to implement new rules to enact stricter regulation over swaps and derivatives. Power will carefully monitor these new rules as they are developed to analyze the potential impact on its swap and derivatives transactions, including any potential increase to collateral requirements.

In April 2011, PSEG and Power entered into new 5-year credit agreements resulting in an increase of $650 million in Power’s total credit capacity.

In addition to amounts for outstanding guarantees, current exposure and margin positions, Power had posted letters of credit to support various other non-energy contractual and environmental obligations. See table above.

135

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Environmental Matters

Passaic River

Historic operations of PSEG companies and the operations of hundreds of other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex.

Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA)

The United States Environmental Protection Agency (EPA) has determined that an eight-mile stretch of the Passaic River in the area of Newark, New Jersey is a “facility” within the meaning of that term under CERCLA. The EPA has determined the need to perform a study of the entire 17-mile tidal reach of the lower Passaic River.

PSE&G and certain of its predecessors conducted operations at properties in this area on or adjacent to the Passaic River. The properties included one operating electric generating station (Essex Site), which was transferred to Power, one former generating station and four former manufactured gas plant (MGP) sites. When the Essex Site was transferred from PSE&G to Power, PSE&G obtained releases and indemnities for liabilities arising out of the former Essex generating station and Power assumed any environmental liabilities.

The EPA believes that hazardous substances were released from the Essex Site and one of PSE&G’s former MGP locations (Harrison Site). In 2006, the EPA notified the potentially responsible parties (PRPs) that the cost of its study would greatly exceed the original estimated cost of $20 million. The total cost of the study is now estimated at approximately $99 million. 73 PRPs, including Power and PSE&G, agreed to assume responsibility for the study and to divide the associated costs according to a mutually agreed upon formula. The PRP group, currently 71 members, is presently executing the study. Approximately five percent of the study costs are attributable to PSE&G’s former MGP sites and approximately one percent to Power’s generating stations. Power has provided notice to insurers concerning this potential claim.

In 2007, the EPA released a draft “Focused Feasibility Study” (FFS) that proposed six options to address the contamination cleanup of the lower eight miles of the Passaic River. The estimated costs for the proposed remedy range from $1.3 billion to $3.7 billion. The work contemplated by the study is not subject to the cost sharing agreement discussed above. The EPA is conducting a revised focused feasibility study which may be released as early as the third quarter of 2012.

In June 2008, an agreement was announced between the EPA and two PRPs for removal of a portion of the contaminated sediment in the Passaic River at an estimated cost of $80 million. The two PRPs have reserved their rights to seek contribution for the removal costs from the other PRPs, including Power and PSE&G.

The EPA has advised that the levels of contaminants at Passaic River mile 10.9 may require a pilot study and removal in advance of the completion of the Remedial Investigation and Feasibility Study or the issuance of a revised draft FFS. Preliminary cost estimates range from $20 million to $150 million.

Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to these matters.

New Jersey Spill Compensation and Control Act (Spill Act)

In 2005, the New Jersey Department of Environmental Protection (NJDEP) filed suit against a PRP and its related companies in the New Jersey Superior Court seeking damages and reimbursement for costs expended by the State of New Jersey to address the effects of the PRP’s discharge of hazardous substances into both the Passaic River and the balance of the Newark Bay Complex. Power and PSE&G are alleged to have owned, operated or contributed hazardous substances to a total of 11 sites or facilities that impacted these water bodies. In February 2009, third party complaints were filed against some 320 third party defendants, including Power and PSE&G, claiming that each of the third party defendants is responsible for its proportionate share

136

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

of the clean-up costs for the hazardous substances they allegedly discharged into the Passaic River and the Newark Bay Complex. The third party complaints seek statutory contribution and contribution under the Spill Act to recover past and future removal costs and damages. Power and PSE&G filed answers to the complaint in June 2010. A special master for discovery has been appointed by the court and document production has commenced. Power and PSE&G believe they have good and valid defenses to the allegations contained in the third party complaints and will vigorously assert those defenses. Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to this matter.

Natural Resource Damage Claims

In 2003, the NJDEP directed PSEG, PSE&G and 56 other PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the Spill Act. The NJDEP alleged that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million. In 2007, agencies of the United States Department of Commerce and the United States Department of the Interior sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In 2008, PSEG and a number of other PRPs agreed to share certain immaterial costs the trustees have incurred and will incur going forward, and to work with the trustees to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That effort is continuing. PSE&G is unable to estimate its portion of the possible loss or range of loss related to this matter.

Newark Bay Study Area

The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area and encouraged the PRPs to contact Occidental Chemical Corporation (OCC) to discuss participating in the Remedial Investigation/Feasibility Study that OCC was conducting. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but it is uncertain at this time whether the PSEG companies will consent to fund the third phase. Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to this matter.

MGP Remediation Program

PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined that the estimated cost to remediate all MGP sites to completion could range between $635 million and $733 million through 2021. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $635 million as of December 31, 2011. Of this amount, $53 million was recorded in Other Current Liabilities and $582 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $635 million Regulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly.

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

The PSD/NSR regulations, promulgated under the Clean Air Act, require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets, in some circumstances, when those sources undergo a “major modification,” as defined in the regulations. The federal government may order companies that are not in compliance with the PSD/NSR regulations to install the best available

137

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

control technology at the affected plants and to pay monetary penalties ranging from $25,000 to $37,500 per day for each violation, depending upon when the alleged violation occurred.

In 2009, the EPA issued a notice of violation to Power and the other owners of the Keystone coal fired plant in Pennsylvania, alleging, among other things, that various capital improvement projects were completed at the plant which are considered modifications (or major modifications) causing significant net emission increases of PSD/NSR air pollutants, beginning in 1985 for Keystone Unit 1 and in 1984 for Keystone Unit 2. The notice of violation states that none of these modifications underwent PSD/NSR permitting process prior to being put into service, which the EPA alleges was required under the Clean Air Act. The notice of violation states that the EPA may issue an order requiring compliance with the relevant Clean Air Act provisions and may seek injunctive relief and/or civil penalties. Power owns approximately 23% of the plant. Power cannot predict the outcome of this matter.

Hazardous Air Pollutants Regulation

In accordance with a court ruling, the EPA proposed a Maximum Achievable Control Technology (MACT) regulation in March 2011 which was finalized on December 21, 2011. This regulation prescribes reduced levels of mercury and other hazardous air pollutants pursuant to the Clean Air Act. The impact to our fossil fleet is currently being determined; but Power believes the back end technology environmental controls recently installed at its Hudson and Mercer coal facilities should meet the rule’s requirements. Some additional controls could be necessary at Power’s Connecticut facilities and some of its other New Jersey facilities, pending engineering evaluation. In December 2011, a decision was reached to upgrade the previously planned two flue gas desulfurization scrubbers and install Selective Catalytic Reduction (SCR) systems at Power’s jointly owned coal fired generating facility at Conemaugh in Pennsylvania. This installation is expected to be completed in the fourth quarter of 2014. PSEG’s share of this investment is approximately $147 million.

New Jersey regulations required coal fired electric generating units to meet certain emissions limits or reduce mercury emissions by approximately 90% by December 15, 2007. Companies that are parties to multi-pollutant reduction agreements, such as Power, have been permitted to postpone such reductions on half of their coal fired electric generating capacity until December 15, 2012.

With newly installed controls at its plants in New Jersey, Power expects to achieve the required mercury reductions that are part of Power’s multi-pollutant reduction agreement that resolved issues arising out of the PSD/NSR air pollution control programs discussed above.

NO_x Regulation

In April 2009, the NJDEP finalized revisions to NO_x emission control regulations that impose new NO_x emission reduction requirements and limits for New Jersey fossil fuel fired electric generating units. The rule will have a significant impact on Power’s generation fleet, as it imposes NO_x emissions limits that will require significant capital investment for controls or the retirement of up to 102 combustion turbines (approximately 2,000 MW) and four older New Jersey steam electric generating units (approximately 400 MW) by May 30, 2015. Power is currently evaluating its compliance options and is unable to estimate the possible loss or range of loss related to this matter.

Under current Connecticut regulations, Power’s Bridgeport and New Haven facilities have been utilizing Discrete Emission Reduction Credits (DERCs) to comply with certain NO_x emission limitations that were incorporated into the facilities’ operating permits. In 2010, Power negotiated new agreements with the State of Connecticut extending the continued use of DERCs for certain emission units and equipment until May 31, 2014.

Cross-State Air Pollution Rule (CSAPR)

On July 6, 2011, the EPA issued the final CSAPR. The CSAPR limits power plant emissions in 28 states that contribute to the ability of downwind states to attain and/or maintain current particulate matter and ozone emission standards.

138

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Technical revisions to the CSAPR were finalized on February 7, 2012. The EPA increased New Jersey’s allocation of annual NO_x and ozone season NO_x allowances beyond what was proposed. The EPA also finalized the increase in New Jersey’s allocation of SO₂ allowances from the October proposal.

On December 30, 2011, the United States Court of Appeals for the D.C. Circuit issued a ruling to stay CSAPR pending judicial review. Until a final decision is reached, the court has ordered that the Clean Air Interstate Rule (CAIR) requirements continue temporarily. PSEG has intervened in this litigation along with Calpine and Exelon in support of the rule.

The continuation of CAIR affects our generating stations in Connecticut, New Jersey and New York. The purpose of CAIR is to improve Ozone and Fine Particulate (PM2.5) air quality within states that have not demonstrated achievement of the National Ambient Air Quality Standards (NAAQS). CAIR was implemented through a cap-and-trade program and to date the impact has not been material to us as the allowances allocated to our stations were sufficient. If 2012 operations are similar to those in the past three years, it is expected that the impact to operations from the temporary implementation of CAIR in 2012 will not be significant.

PSEG continues to evaluate the impact of this rule on it due to many of the uncertainties that still exist regarding implementation. As Power has made major capital investments over the past several years to lower the SO₂ and NO_x emissions of its fossil plants in the states affected by CSAPR (New Jersey, New York and Pennsylvania), Power does not foresee the need to make significant additional expenditures to its generation fleet to comply with the regulation. As such, Power believes this rule will not have a material impact to its capital investment program or units’ operations.

Clean Water Act Permit Renewals

Pursuant to the Federal Water Pollution Control Act (FWPCA), New Jersey Pollutant Discharge Elimination System (NJPDES) permits expire within five years of their effective date. In order to renew these permits, but allow a plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit.

One of the most significant NJPDES permits governing cooling water intake structures at Power is for Salem. In 2001, the NJDEP issued a renewed NJPDES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water intake system. In February 2006, Power filed with the NJDEP a renewal application allowing Salem to continue operating under its existing NJPDES permit until a new permit is issued. Power prepared its renewal application in accordance with the FWPCA Section 316(b) and the 316(b) rules published in 2004. Those rules did not mandate the use of cooling towers at large existing generating plants. Rather, the rules provided alternatives for compliance with 316(b), including the use of restoration efforts to mitigate for the potential effects of cooling water intake structures, as well as the use of site-specific analysis to determine the best technology available for minimizing adverse impact based upon a cost-benefit test. Power has used restoration and/or a site-specific cost-benefit test in applications filed to renew the permits at its once-through cooled plants, including Salem, Hudson and Mercer.

As a result of several legal challenges to the 2004 316(b) rule by certain northeast states, environmentalists and industry groups, the rule has been suspended and has been returned to the EPA to be consistent with a 2009 United States Supreme Court decision which concluded that the EPA could rely upon cost-benefit analysis in setting the national performance standards and in providing for cost-benefit variances from those standards as part of the Phase II regulations.

In April 2011, the EPA published a new proposed rule which did not establish any particular technology as the best technology available (e.g. closed cycle cooling). Instead, the proposed rule established marine life mortality standards for existing cooling water intake structures with a design flow of more than 2 million gallons per day. Power reviewed the proposed rule, assessed the potential impact on its generating facilities and used this information to develop its comments to the EPA which were filed in August 2011.

139

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Although the EPA has recently stated that a revision of the proposed rule to include an alternative framework for compliance is currently being considered, if the rule were to be adopted as proposed, the impact would be material since the majority of Power’s electric generating stations would be affected. Power is unable to predict the outcome of this proposed rulemaking, the final form that the proposed regulations may take and the effect, if any, that they may have on its future capital requirements, financial condition or results of operations. The results of further proceedings on this matter could have a material impact on Power’s ability to renew permits at its larger once-through cooled plants, including Salem, Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to existing intake structures and cooling systems. The costs of those upgrades to one or more of Power’s once-through cooled plants would be material, and would require economic review to determine whether to continue operations at these facilities. For example, in Power’s application to renew its Salem permit, filed with the NJDEP in February 2006, the estimated costs for adding cooling towers for Salem were approximately $1 billion, of which Power’s share would have been approximately $575 million. These cost estimates have not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures.

In addition to the EPA rulemaking, several states, including California and New York, have begun setting policies that may require closed cycle cooling. It is unknown how these policies may ultimately impact the EPA’s rulemaking.

In January 2010, the NJDEP issued a draft NJPDES permit to another company which would require the installation of closed cycle cooling at that company’s nuclear generating station located in New Jersey. In December 2010, the NJDEP and that company entered into an Administrative Consent Order (ACO) which would require the company to cease operations at the nuclear generating station no later than 2019. In the ACO, the NJDEP agreed that closed cycle cooling is not the best technology available for that facility and agreed to issue a new draft NJPDES permit for that facility without a requirement for construction of cooling towers or other closed cycle cooling facilities. The new draft NJPDES permit was issued by NJDEP on June 1, 2011. The permit was issued as final on December 21, 2011 incorporating the 316(b) requirements as defined in the ACO. In that permit, NJDEP defended its position that closed-cycle cooling was not the best technology available for that facility. Per that permit the facility will cease operations on December 31, 2019. Power cannot predict at this time the final outcome of the NJDEP decision and the impact, if any; such a decision would have on any of Power’s once-through cooled generating stations.

New Generation and Development

Nuclear

Power has approved the expenditure of approximately $192 million for a steam path retrofit and related upgrades at its co-owned Peach Bottom Units 2 and 3. Unit 3 upgrades were completed on schedule in October 2011. Unit 2 upgrades are expected to result in an increase of Power’s share of nominal capacity by approximately 14 MW in 2012. Total expenditures through December 31, 2011 were $114 million and are expected to continue through 2012.

Power has begun expenditures in pursuit of additional output through an extended power uprate of the Peach Bottom nuclear units. The uprate is expected to be in service in 2015 for Unit 2 and 2016 for Unit 3. Power’s share of the increased capacity is expected to be approximately 133 MW with an anticipated cost of approximately $400 million. Total expenditures through December 31, 2011 were $36 million and are expected to continue through 2016.

Connecticut

Power was selected by the Connecticut Public Utilities Regulatory Authority (PURA), formerly the Department of Public Utility Control in a regulatory process to build 130 MW of gas fired peaking capacity. Final approval was received and construction began in the second quarter of 2011. The project is expected to be in service by June 2012. Power estimates the cost of these generating units to be approximately $148

140

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

million, (not including the capitalized cost to finance during construction). Capitalized expenditures through December 31, 2011 were $129 million, which are included in Property, Plant and Equipment on the Consolidated Balance Sheets of PSEG and Power. The initial filing was submitted in December 2011 to the PURA. Costs for this project, including financing costs capitalized during the construction period, will be recovered subject to regulatory review and approval.

PJM Interconnection L.L.C. (PJM)

Power plans to construct gas fired peaking facilities at its Kearny site. Construction began in the second quarter of 2011. The projects are expected to be in service by June 2012. Capacity in the amount of 178 MW was bid into and cleared the PJM Reliability Pricing Model (RPM) base residual capacity auction for the 2012-2013 period. Capacity in the amount of 267 MW was bid into and cleared the PJM RPM base residual capacity auction for the 2013-2014 and 2014-2015 periods. Power estimates the cost of these generating units to be $250 million to $300 million. Total capitalized expenditures through December 31, 2011 were $203 million which are included in Property, Plant and Equipment on Power’s and PSEG’s Consolidated Balance Sheets.

PSE&G—Solar

As part of the BPU-approved Solar 4 All Program, PSE&G is installing up to 40 MW of solar generation on existing utility poles within its service territory. PSE&G has entered into an agreement to purchase solar units for this program. PSE&G’s commitments under this agreement are contingent upon, among other things, the availability of suitable utility poles for installation of the units. PSE&G estimates the total cost of this project to be $265 million. Approximately 25 MW have been installed as of December 31, 2011. PSE&G’s cumulative investments for these solar units were approximately $185 million, with additional purchases to be made on a quarterly basis during the remaining two-year term of the purchase agreement, to the extent adequate space on poles is available.

Another aspect of the Solar 4 All program is the installation of 40 MW of solar systems on land and buildings owned by PSE&G and third parties. PSE&G estimates the total cost of this phase of the program to be $186 million. Through December 31, 2011, 33 MW representing 19 projects had been placed into service with an investment of approximately $160 million.

Our Solar 4 All program is comprised, in part, of the installation of up to 200,000 pole mounted solar units within our service territory. On January 18, 2012, the BPU issued an order indicating that it will conduct a proceeding to address the proposed placement of solar panels on the poles. A negative determination by the BPU could impact on our ability to complete the Solar 4 All pole mounted installations.

Energy Holdings—Solar

In January 2012, Energy Holdings acquired a 25 MW solar project currently under construction in Arizona. Completion of this project is expected by the third quarter of 2012. Energy Holdings has issued guarantees of up to $71.5 million for payment of obligations related to the construction of the project. These guarantees will terminate upon successful completion of the project. The total investment for the project is expected to be approximately $75 million.

Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS)

PSE&G obtains its electric supply requirements for customers who do not purchase electric supply from third party suppliers through the annual New Jersey BGS auctions. Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master Agreement with the winners of these BGS auctions following the BPU’s approval of the auction results. PSE&G has entered into contracts with Power, as well as with other winning BGS suppliers, to purchase BGS for PSE&G’s load requirements. The winners of the auction (including Power) are responsible for fulfilling all the requirements of a PJM Load Serving Entity including the provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards.

141

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Power seeks to mitigate volatility in its results by contracting in advance for the sale of most of its anticipated electric output as well as its anticipated fuel needs. As part of its objective, Power has entered into contracts to directly supply PSE&G and other New Jersey electric distribution companies (EDCs) with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above. In addition to the BGS-related contracts, Power also enters into firm supply contracts with EDCs, as well as other firm sales and commitments.

PSE&G has contracted for its anticipated BGS-Fixed Price eligible load, as follows:

	Auction Year
	2009		2010		2011		2012
36-Month Terms Ending		May 2012		May 2013		May 2014		May 2015	(A)
Load (MW)		2,900		2,800		2,800		2,900
$ per kWh		0.10372		0.09577		0.09430		0.08388

(A) Prices set in the 2012 BGS auction will become effective on June 1, 2012 when the 2009 BGS auction agreements expire.

PSE&G has a full requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. The contract extends through March 31, 2012, and year-to-year thereafter. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. For additional information, see Note 17. Related-Party Transactions. Current plans call for Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements.

Minimum Fuel Purchase Requirements

Power has various long-term fuel purchase commitments for coal to support its fossil generation stations and for supply of nuclear fuel for the Salem and Hope Creek nuclear generating stations and for firm transportation and storage capacity for natural gas.

Power’s various multi-year contracts for firm transportation and storage capacity for natural gas are primarily used to meet its gas supply obligations to PSE&G. These purchase obligations are consistent with Power’s strategy to enter into contracts for its fuel supply in comparable volumes to its sales contracts.

Power’s strategy is to maintain certain levels of uranium in inventory and to make periodic purchases to support such levels. As such, the commitments referred to below may include estimated quantities to be purchased that deviate from contractual nominal quantities. Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 2015 and a portion for 2016 at Salem, Hope Creek and Peach Bottom.

As of December 31, 2011, the total minimum purchase requirements included in these commitments were as follows:

	Commitments through 2016
Fuel Type	Power’s Share
		Millions
Nuclear Fuel
Uranium	$	529
Enrichment	$	492
Fabrication	$	166
Natural Gas	$	1,009
Coal	$	282

142

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Regulatory Proceedings

Electric Discount and Energy Competition Act (Competition Act)

In 2007, PSE&G and Transition Funding were served with a purported class action complaint (Complaint) in New Jersey Superior Court challenging the constitutional validity of certain stranded cost recovery provisions of the Competition Act, seeking injunctive relief against continued collection from PSE&G’s electric customers of the Transition Bond Charge (TBC) of Transition Funding, as well as recovery of TBC amounts previously collected. Under New Jersey law, the Competition Act, enacted in 1999, is presumed constitutional.

Also in 2007, the plaintiff filed an amended Complaint to also seek injunctive relief from continued collection of related taxes as well as recovery of such taxes previously collected. In October 2007, the Court granted PSE&G’s motion to dismiss the amended Complaint and in November 2007, the plaintiff filed a notice of appeal with the Appellate Division of the New Jersey Superior Court (Appellate Division). In February 2009, the Appellate Division affirmed the decision of the lower court dismissing the case. In May 2009, the New Jersey Supreme Court denied a request from the plaintiff to review the Appellate Division’s decision.

In July 2007, the same plaintiff also filed a petition with the BPU requesting review and adjustment to PSE&G’s recovery of the same stranded cost charges. In September 2007, PSE&G filed a motion with the BPU to dismiss the petition. In June 2010, the BPU granted PSE&G’s motion to dismiss. In April 2011, the BPU issued a written order memorializing this decision. In June 2011, the plaintiff/petitioner filed a notice of appeal of the BPU action with the Appellate Division. PSE&G is currently in the briefing stage of this appeal.

New Jersey Clean Energy Program

In 2008, the BPU approved funding requirements for each New Jersey EDC applicable to its Renewable Energy and Energy Efficiency programs for the years 2009 to 2012. The aggregate funding amount is $1.2 billion for all years. PSE&G’s share is $705 million. PSE&G has recorded a discounted liability of $253 million as of December 31, 2011. Of this amount, $214 million was recorded as a current liability and $39 million as a noncurrent liability. The liability is reduced as normal payments are made. The liability has been recorded with an offsetting Regulatory Asset, since the costs associated with this program are expected to be recovered from PSE&G ratepayers through the Societal Benefits Charge (SBC).

The BPU has started a new Comprehensive Resource Analysis proceeding to determine SBC funding for the years 2013-2016. The proceeding has no impact on current SBC assessments.

Long-Term Capacity Agreement Pilot Program (LCAPP)

In January 2011, New Jersey enacted the LCAPP Act directing the BPU to conduct a process to procure and subsidize up to 2,000 megawatts of base load or mid-merit electric power generation. In March 2011, the BPU issued a written order approving a form of agreement and selecting three generators to build a total of approximately 1,949 MW of new combined-cycle generating facilities located in New Jersey. Each of the New Jersey EDCs, including PSE&G, executed standard offer capacity agreements (SOCA) with each of the three selected generators in compliance with the BPU’s directive, but did so under protest preserving its respective legal rights. The SOCA provides for the EDCs to make capacity payments to, or receive capacity payments from, the generators as calculated based on the difference between the RPM clearing price for each year of the term and the price bid set forth in the SOCA. The LCAPP Act and the BPU order provide that, once the SOCAs are executed and approved by the BPU, they will be irrevocable and the EDCs will be entitled to full rate recovery of the prudently incurred costs. PSE&G will not make or receive payments under the three contracts unless (1) the plant successfully bids into and clears the capacity auction in accordance with the terms of the SOCA and (2) the proposed plant is constructed. In April 2011, the BPU approved the executed contracts; however, the EDCs appealed the BPU’s orders. Additionally, Power and another generator challenged the BPU’s implementation in a separate appeal. These two separate appeals are pending.

143

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Leveraged Lease Investments

The IRS has issued reports with respect to its audits of PSEG’s consolidated federal corporate income tax returns for tax years 1997 through 2003, which disallowed all deductions associated with certain cross-border lease transactions. The IRS reports also proposed a 20% penalty for substantial understatement of tax liability. PSEG has filed protests of these findings with the Office of Appeals of the IRS.

On January 31, 2012, PSEG entered into a specific matter closing agreement settling the dispute with the IRS over the challenged lease transactions for all tax years. This agreement settles the leasing dispute with finality for all tax periods in which PSEG realized tax deductions from these transactions. In addition, PSEG signed a Form 870-AD settlement agreement covering all audit issues for tax years 1997 through 2003. PSEG believes that there will be no material impact on earnings as a result of these settlement agreements.

Cash Impact

For tax years 1997 through 2003, the tax and interest PSEG owes the IRS as a result of this settlement will be completely defrayed by the $320 million PSEG has on deposit with the IRS for this matter. Based upon the closing agreement, for tax years from 2004 through 2008, PSEG owes the IRS approximately $1.0 billion in tax and interest. For tax years 2009 and 2010, the IRS owes PSEG approximately $1.0 billion. PSEG will attempt to work with the IRS to process these audit years simultaneously, so that the two refund and payment amounts can potentially be offset. No assurance can be given that the IRS will agree to this process. It is possible that PSEG would have to make several payments totaling $1.0 billion over the next year to the IRS and file claims for refunds for $1.0 billion which the IRS would process in the normal course; it could take several years for the IRS to process these claims. In addition to the above, PSEG will claim a tax deduction for the accrued deficiency interest associated with this settlement in 2012, which will give rise to a cash tax savings of approximately $100 million.

Nuclear Insurance Coverages and Assessments

Power is a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides the primary property and decontamination liability insurance at Salem, Hope Creek and Peach Bottom. NEIL also provides excess property insurance through its decontamination liability, decommissioning liability and excess property policy and replacement power coverage through its accidental outage policy. NEIL policies may make retrospective premium assessments in case of adverse loss experience. Power’s maximum potential liabilities under these assessments are included in the table and notes below. Certain provisions in the NEIL policies provide that the insurer may suspend coverage with respect to all nuclear units on a site without notice if the NRC suspends or revokes the operating license for any unit on that site, issues a shutdown order with respect to such unit or issues a confirmatory order keeping such unit down.

The American Nuclear Insurers (ANI) and NEIL policies both include coverage for claims arising out of acts of terrorism. NEIL makes a distinction between certified and non-certified acts of terrorism, as defined under the Terrorism Risk Insurance Act (TRIA), and thus its policies respond accordingly. For non-certified acts of terrorism, NEIL policies are subject to an industry aggregate limit of $3.2 billion plus any amounts available through reinsurance or indemnity for non-certified acts of terrorism. For any act of terrorism, Power’s nuclear liability policies will respond similarly to other covered events. For certified acts, Power’s nuclear property NEIL policies will respond similarly to other covered events.

The Price-Anderson Act sets the “limit of liability” for claims that could arise from an incident involving any licensed nuclear facility in the U.S. The “limit of liability” is based on the number of licensed nuclear reactors and is adjusted at least every five years based on the Consumer Price Index. The current “limit of liability” is $12.6 billion. All owners of nuclear reactors, including Power, have provided for this exposure through a combination of private insurance and mandatory participation in a financial protection pool as established by the Price-Anderson Act. Under the Price-Anderson Act, each party with an ownership interest in a nuclear reactor can be assessed its share of $118 million per reactor per incident, payable at $18 million per reactor per incident per year. If the damages exceed the “limit of liability,” the President is to submit to Congress a plan

144

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

for providing additional compensation to the injured parties. Congress could impose further revenue-raising measures on the nuclear industry to pay claims. Power’s maximum aggregate assessment per incident is $370 million (based on Power’s ownership interests in Hope Creek, Peach Bottom and Salem) and its maximum aggregate annual assessment per incident is $55 million. Further, a decision by the U.S. Supreme Court, not involving Power, has held that the Price-Anderson Act did not preclude awards based on state law claims for punitive damages.

Power’s insurance coverages and maximum retrospective assessments for its nuclear operations are as follows:

Type and Source of Coverages	Total Site Coverage				Retrospective Assessments
	Millions
Public and Nuclear Worker Liability (Primary Layer):
ANI	$	375	(A	)	$	0
Nuclear Liability (Excess Layer):
Price-Anderson Act		12,219	(B	)		370
Nuclear Liability Total	$	12,594	(C	)	$	370
Property Damage (Primary Layer):
NEIL Primary (Salem/Hope Creek/Peach Bottom)	$	500			$	18
Property Damage (Excess Layers):
NEIL II (Salem/Hope Creek/Peach Bottom)		750				8
NEIL Blanket Excess (Salem/Hope Creek/Peach Bottom)		850	(D	)		5
Property Damage Total (Per Site)	$	2,100			$	31
Accidental Outage:
NEIL I (Peach Bottom)	$	245	(E	)	$	6
NEIL I (Salem)		281	(E	)		7
NEIL I (Hope Creek)		490	(E	)		6
Replacement Power Total	$	1,016			$	19

(A) The primary limit for Public Liability is a per site aggregate limit with no potential for assessment. The Nuclear Worker Liability represents the potential liability from workers claiming exposure to the hazard of nuclear radiation. This coverage is subject to an industry aggregate limit that is subject to reinstatement at ANI discretion.

(B) Retrospective premium program under the Price-Anderson Act liability provisions of the Atomic Energy Act of 1954, as amended. Power is subject to retrospective assessment with respect to loss from an incident at any licensed nuclear reactor in the U.S. that produces greater than 100 MW of electrical power. This retrospective assessment can be adjusted for inflation every five years. The last adjustment was effective as of October 29, 2008. The next adjustment is due on or before October 29, 2013. This retrospective program is in excess of the Public and Nuclear Worker Liability primary layers.

(C) Limit of liability under the Price-Anderson Act for each nuclear incident.

(D) For property limits in excess of $1.25 billion, Power participates in a Blanket Limit policy where the $850 million limit is shared by Power with Exelon Generation among the Braidwood, Byron, Clinton, Dresden, La Salle, Limerick, Oyster Creek, Quad Cities, TMI-1 facilities owned by Exelon Generation and the Peach Bottom, Salem and Hope Creek facilities. This limit is not subject to reinstatement in the event of a loss. Participation in this program materially reduces Power’s premium and the associated potential assessment.

145

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(E) Peach Bottom has an aggregate indemnity limit based on a weekly indemnity of $2.3 million for 52 weeks followed by 80% of the weekly indemnity for 68 weeks. Salem has an aggregate indemnity limit based on a weekly indemnity of $2.5 million for 52 weeks followed by 80% of the weekly indemnity for 75 weeks. Hope Creek has an aggregate indemnity limit based on a weekly indemnity of $4.5 million for 52 weeks followed by 80% of the weekly indemnity for 71 weeks.

Minimum Lease Payments

PSEG and Power have entered into capital leases for administrative office space. The total future minimum payments and present value of these capital leases as of December 31, 2011 are:

	Power			Other (A)
	Millions
2012	$	2		$	7
2013		2			7
2014		1			7
2015		1			6
2016		0			0
Thereafter		0			0
Total Minimum Lease Payments		6			27
Less: Imputed Interest		(1	)		(5	)
Present Value of Net Minimum Lease Payments	$	5		$	22

(A) Other consists of PSEG (Parent Company) and Services

Power, PSE&G and Energy Holdings have entered into various operating leases. The total future minimum payments of these operating leases as of December 31, 2011 are:

	Power		PSE&G		Energy Holdings
2012	$	0	$	6	$	1
2013		0		5		1
2014		1		4		0
2015		1		3		0
2016		1		2		0
Thereafter		5		30		7
Total Minimum Lease Payments	$	8	$	50	$	9

Note 14. Schedule of Consolidated Debt

Long-Term Debt

	As of December 31,
	2011			2010
	Millions
PSEG (Parent)
Fair Value of Swaps (A)	$	62		$	39
Unamortized Discount Related to Debt Exchange (B)		(23	)		(29	)
Total Long-Term Debt of PSEG (Parent)	$	39		$	10

146

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

			As of December 31,
	Maturity		2011			2010
			Millions
Power
Senior Notes:
7.75%		2011	$	0		$	606
6.95%		2012		0			600
2.50%		2013		300			300
5.00%		2014		250			250
5.50%		2015		300			300
5.32%		2016		303			303
2.75%		2016		250			0
5.13%		2020		406			406
4.15%		2021		250			0
8.63%		2031		500			500
Total Senior Notes				2,559			3,265
Pollution Control Notes:
Floating Rate (C)		2014		44			44
5.00%		2012		66			66
5.50%		2020		14			14
5.85%		2027		19			19
5.75%		2031		25			25
5.75%		2037		40			40
Total Pollution Control Notes				208			208
Principal Amount Outstanding				2,767			3,473
Amounts Due Within One Year				(66	)		(650	)
Net Unamortized Discount				(16	)		(18	)
Total Long-Term Debt of Power			$	2,685		$	2,805

147

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

		As of December 31,
	Maturity	2011			2010
		Millions
PSE&G
First and Refunding Mortgage Bonds (D):
6.75%	2016	$	171		$	171
9.25%	2021		134			134
8.00%	2037		7			7
5.00%	2037		8			8
Total First and Refunding Mortgage Bonds			320			320
Pollution Control Bonds (D):
5.20%	2025		23			23
0.95%	2028 - 2033		0			164
1.20%	2031		0			100
5.45%	2032		50			50
Total Pollution Control Bonds			73			337
Medium-Term Notes (MTNs) (D):
5.13%	2012		300			300
5.00%	2013		150			150
5.38%	2013		300			300
6.33%	2013		275			275
0.85%	2014		250			0
5.00%	2014		250			250
2.70%	2015		300			300
5.30%	2018		400			400
7.04%	2020		9			9
3.50%	2020		250			250
5.25%	2035		250			250
5.70%	2036		250			250
5.80%	2037		350			350
5.38%	2039		250			250
5.50%	2040		300			300
Total MTNs			3,884			3,634
Principal Amount Outstanding			4,277			4,291
Amounts Due Within One Year			(300	)		(264	)
Net Unamortized Discount			(7	)		(8	)
Total Long-Term Debt of PSE&G (excluding Transition Funding and Transition Funding II)		$	3,970		$	4,019

148

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

			As of December 31,
	Maturity		2011			2010
			Millions
Transition Funding (PSE&G)
Securitization Bonds:
6.45%		2010-2011		0			46
6.61%		2011-2013		305			454
6.75%		2013-2014		220			220
6.89%		2014-2015		370			370
Principal Amount Outstanding				895			1,090
Amounts Due Within One Year				(205	)		(195	)
Total Securitization Debt of Transition Funding				690			895
Transition Funding II (PSE&G)
Securitization Bonds:
4.34%		2010-2012		1			12
4.49%		2012-2013		20			20
4.57%		2013-2015		23			23
Principal Amount Outstanding				44			55
Amounts Due Within One Year				(11	)		(11	)
Total Securitization Debt of Transition Funding II				33			44
Total Long-Term Debt of PSE&G			$	4,693		$	4,958

			As of December 31,
Energy Holdings	Maturity		2011			2010
			Millions
Non-Recourse Project Debt (E):
Resources - 5.00% to 8.75%		2010-2020	$	45		$	46
Resources - Other(F)		2012		50			0
EGDC - 8.27%		2010-2011		0			1
Principal Amount Outstanding				95			47
Amounts Due Within One Year				(51	)		(1	)
Total Non-Recourse Project Debt				44			46
Total Long-Term Debt of Energy Holdings			$	44		$	46

(A) PSEG entered into various interest rate swaps to hedge the fair value of certain debt at Power. The fair value adjustments from these hedges are reflected as offsets to long-term debt on the Consolidated Balance Sheet. For additional information, see Note 16. Financial Risk Management Activities.

(B) In September 2009, Power completed an exchange offer with eligible holders of Energy Holdings’ 8.50% Senior Notes due 2011 in order to manage long-term debt maturities. Since the debt exchange was between two subsidiaries of the same parent company, PSEG, and treated as a debt modification for accounting purposes, the resulting premium was deferred and is being amortized over the term of the newly issued debt. The deferred amount is reflected as an offset to Long-Term Debt on PSEG’s Consolidated Balance Sheet.

(C) The Pennsylvania Economic Development Authority (PEDFA) bond is a variable rate bond that is in weekly reset mode.

149

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(D) Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage.

(E) Non-recourse financing transactions consist of loans from banks and other lenders that are typically secured by project assets and cash flows and generally impose no material obligation on the parent-level investor to repay any debt incurred by the project borrower. The consequences of permitting a project-level default include the potential for loss of any invested equity by the parent.

(F) As a result of the Dynegy bankruptcy proceedings, Energy Holdings ceased leveraged lease accounting and recorded the related nonrecourse project debt on its balance sheet at its fair value of $50 million.

Long-Term Debt Maturities

The aggregate principal amounts of maturities for each of the five years following December 31, 2011 are as follows:

			PSE&G						Energy Holdings
Year	Power		PSE&G		Transition Funding		Transition Funding II		Non-Recourse Debt		Total
	Millions
2012	$	66	$	300	$	205	$	11	$	51	$	633
2013		300		725		214		12		1		1,252
2014		294		500		225		13		1		1,033
2015		300		300		251		8		17		876
2016		553		171		0		0		7		731
Thereafter		1,254		2,281		0		0		18		3,553
	$	2,767	$	4,277	$	895	$	44	$	95	$	8,078

Long-Term Debt Financing Transactions

During 2011, PSEG and its subsidiaries had the following Long-Term Debt issuances, maturities and redemptions:

Power

• caused mandatory purchase and remarketing of its $44 million of PEDFA Variable Rate Demand Bonds in December. The remarketed bonds are backed by a three-year letter of credit, expiring December 2014, which replaced an expiring one-year letter of credit,

• early redeemed $600 million of 6.95% Senior Notes due June 2012 in December,

• issued $250 million of 2.75% Senior Notes due September 2016 in September,

• issued $250 million of 4.15% Senior Notes due September 2021 in September, and

• paid $606 million of 7.75% Senior Notes at maturity in April.

PSE&G

• bought in $100 million of the New Jersey Economic Development Authority Bonds, which were serviced and secured by PSE&G’s first mortgage bonds of like tenor, on their mandatory put date in December,

• bought in $164 million of Pollution Control Financing Authority of Salem County Authority Bonds, which were serviced and secured by PSE&G’s First and Refunding Mortgage Bonds of like tenor, on their mandatory put date in November,

• issued $250 million of 0.85% Medium Term Notes due August 2014 in August,

• paid $195 million of Transition Funding’s securitization debt, and

• paid $11 million of Transition Funding II’s securitization debt.

150

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Short-Term Liquidity

PSEG meets its short-term liquidity requirements as well as those of Power primarily through the issuance of commercial paper. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Both commercial paper programs are fully back-stopped by their own separate credit facilities.

The commitments under PSEG’s credit facilities are provided by a diverse bank group. As of December 31, 2011, no single institution represented more than 8% of the total commitments in our credit facilities.

Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. Our total credit facilities and available liquidity as of December 31, 2011 were as follows:

	As of December 31, 2011
Company/Facility	Total Facility		Usage				Available Liquidity		Expiration Date		Primary Purpose
	Millions
PSEG
5-year Credit Facility(A)	$	477	$	12	(C	)	$	465		Dec 2012	Commercial Paper (CP) Support/ Funding/Letters of Credit
5-year Credit Facility	$	500		0			$	500		Apr 2016	CP Support/Funding/Letters of Credit
Total PSEG	$	977	$	12			$	965
Power
5-year Credit Facility(B)	$	1,525	$	75	(C	)	$	1,450		Dec 2012	CP Support/Funding/Letters of Credit
5-year Credit Facility		1,000		0				1,000		Apr 2016	CP Support/Funding/Letters of Credit
Bilateral Credit Facility		100		100	(C	)		0		Sept 2015	Letters of Credit
Total Power	$	2,625	$	175			$	2,450
PSE&G
5-year Credit Facility	$	600	$	0			$	600		Apr 2016	CP Support/Funding/Letters of Credit
Total PSE&G	$	600	$	0			$	600
Total	$	4,202					$	4,015

(A) In December 2011, this facility was reduced by $23 million.

(B) In December 2011, this facility was reduced by $75 million.

(C) Includes amounts related to letters of credit outstanding.

In April 2011, PSEG, Power and PSE&G entered into new 5-year credit agreements in the amounts of $500 million, $1 billion and $600 million, respectively. These new agreements will expire in April 2016. Concurrently, PSEG reduced its existing $1 billion credit facility to $500 million, Power terminated its existing

151

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

$350 million credit facility, and PSE&G terminated its existing $600 million credit facility. As a result of these changes, Power’s total credit capacity increased by $650 million.

Fair Value of Debt

The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions as of December 31, 2011 and 2010.

	December 31, 2011				December 31, 2010
	Carrying Amount		Fair Value (A)		Carrying Amount		Fair Value (A)
	Millions
Long-Term Debt:
PSEG (Parent)	$	39	$	62	$	10	$	39
Power -Recourse Debt		2,751		3,158		3,455		3,831
PSE&G		4,270		4,905		4,283		4,615
Transition Funding (PSE&G)		895		1,016		1,090		1,245
Transition Funding II (PSE&G)		44		47		55		59
Energy Holdings:
Project Level, Non-Recourse Debt(B)		95		95		47		47
	$	8,094	$	9,283	$	8,940	$	9,836

(A) Fair value excludes unamortized discounts, including amounts related to a Debt Exchange in 2009 between Power and Energy Holdings that is deferred at the PSEG parent level since the exchange was between subsidiaries of the same parent company.

(B) Fair value amounts as of December 31, 2011 include $50 million of nonrecourse project debt related to Dynegy.

Note 15. Schedule of Consolidated Capital Stock

	As of December 31,
	Outstanding Shares				Book Value
	2011		2010		2011		2010
					Millions
PSEG Common Stock (no par value) (A)
Authorized 1,000,000,000 shares		505,945,286		505,974,223	$	4,222	$	4,214

(A) PSEG did not issue any new shares under the Dividend Reinvestment and Stock Purchase Plan (DRASPP) and the Employee Stock Purchase Plan (ESPP) in 2011 or 2010. Total authorized and unissued shares of common stock available for issuance through PSEG’s DRASPP, ESPP and various employee benefit plans amounted to 7.0 million shares as of December 31, 2011.

In March 2010, PSE&G redeemed all of its outstanding preferred stock. As a result, all of the outstanding equity in PSE&G is owned by PSEG. As of December 31, 2011, there was an aggregate of 7.5 million shares of $100 par value and 10 million shares of $25 par value Cumulative Preferred Stock, which were authorized and unissued and which, upon issuance, may or may not provide for mandatory sinking fund redemption.

Note 16. Financial Risk Management Activities

The operations of PSEG, Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through hedging transactions. Hedging transactions use derivative instruments to create a relationship in which changes

152

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments.

Commodity Prices

The availability and price of energy commodities are subject to fluctuations due to weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market conditions, transmission availability and other events. Power uses physical and financial transactions in the wholesale energy markets to mitigate the effects of adverse movements in fuel and electricity prices. Derivative contracts that do not qualify for hedge accounting or normal purchases/normal sales treatment are marked to market (MTM) with changes in fair value recorded in the income statement. The fair value for the majority of these contracts is obtained from quoted market sources. Modeling techniques using assumptions reflective of current market rates, yield curves and forward prices are used to interpolate certain prices when no quoted market exists.

Cash Flow Hedges

Power uses forward sale and purchase contracts, swaps and futures contracts to hedge

• forecasted energy sales from its generation stations and the related load obligations and

• the price of fuel to meet its fuel purchase requirements.

These derivative transactions are designated as cash flow hedges. As of December 31, 2011 and 2010, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with these hedges was as follows:

	As of December 31,
	2011		2010
		Millions
Fair Value of Cash Flow Hedges	$	57	$	196
Impact on Accumulated Other Comprehensive Income (Loss) (after tax)	$	33	$	114

The expiration date of the longest-dated cash flow hedge at Power is in 2013. Power’s after-tax unrealized gains on these derivatives that are expected to be reclassified to earnings during the next 12 months are $29 million. There was no ineffectiveness associated with these hedges as of December 31, 2011.

Trading Derivatives

The primary purpose of Power’s wholesale marketing operation is to optimize the value of the output of the generating facilities via various products and services available in the markets we serve. Historically, Power engaged in trading of electricity and energy-related products where such transactions were not associated with the output or fuel purchase requirements of its facilities. This trading consisted mostly of energy supply contracts where Power secured sales commitments with the intent to supply the energy services from purchases in the market rather than from its owned generation. Such trading activities were marked to market through the income statement and represented less than one percent of gross margin (revenues less energy costs) on an annual basis. Effective July 2011, Power anticipates that it will not enter into any more trading derivative contracts.

Other Derivatives

Power enters into additional contracts that are derivatives, but do not qualify for or are not designated as cash flow hedges. These transactions are intended to mitigate exposure to fluctuations in commodity prices and optimize the value of our expected generation. Trade types include financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity. Changes in fair market value of these contracts are recorded in earnings.

Interest Rates

PSEG, Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed by targeting a balanced debt maturity profile which limits refinancing in any

153

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

given period or interest rate environment. In addition, we have used a mix of fixed and floating rate debt, interest rate swaps and interest rate lock agreements.

Fair Value Hedges

PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. In order to redeem Power’s $600 million of 6.95% Senior Notes due June 2012 in December 2011, PSEG terminated its $300 million interest rate swap that had converted a portion of this debt into variable-rate. As of December 31, 2011, PSEG had eight interest rate swaps outstanding totaling $1.1 billion. These swaps convert Power’s $250 million of 5% Senior Notes due April 2014, Power’s $300 million of 5.5% Senior Notes due December 2015, $300 million of Power’s $303 million of 5.32% Senior Notes due September 2016 and Power’s $250 million of 2.75% Senior Notes due September 2016 into variable-rate debt. These interest rate swaps are designated and effective as fair value hedges. The fair value changes of the interest rate swaps are fully offset by the changes in the fair value of the underlying debt. As of December 31, 2011 and 2010, the fair value of all the underlying hedges was $62 million and $39 million, respectively.

Cash Flow Hedges

PSEG and Energy Holdings use interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage their exposure to the variability of cash flows, primarily related to variable-rate debt instruments. As of December 31, 2011, there was no hedge ineffectiveness associated with these hedges. The total fair value of these interest rate derivatives was immaterial as of each of December 31, 2011 and December 31, 2010. The Accumulated Other Comprehensive Income (Loss) (after tax) related to interest rate derivatives designated as cash flow hedges was $(2) million and $(3) million as of December 31, 2011 and 2010, respectively.

Fair Values of Derivative Instruments

The following are the fair values of derivative instruments on the Consolidated Balance Sheets:

	As of December 31, 2011
	Power												PSE&G			PSEG			Consolidated
	Cash Flow Hedges			Non Hedges									Non Hedges			Fair Value Hedges
Balance Sheet Location	Energy- Related Contracts			Energy- Related Contracts			Netting (A)			Total Power			Energy- Related Contracts			Interest Rate Swaps			Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	55		$	532		$	(448	)	$	139		$	0		$	17		$	156
Noncurrent Assets		8			121			(74	)		55			4			47			106
Total Mark-to-Market Derivative Assets	$	63		$	653		$	(522	)	$	194		$	4		$	64		$	262
Derivative Contracts
Current Liabilities	$	(5	)	$	(506	)	$	387		$	(124	)	$	(7	)	$	0		$	(131	)
Noncurrent Liabilities		(1	)		(76	)		53			(24	)		0			(2	)		(26	)
Total Mark-to-Market Derivative (Liabilities)	$	(6	)	$	(582	)	$	440		$	(148	)	$	(7	)	$	(2	)	$	(157	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	57		$	71		$	(82	)	$	46		$	(3	)	$	62		$	105

154

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	As of December 31, 2010
	Power												PSE&G			PSEG		Consolidated
	Cash Flow Hedges			Non Hedges									Non Hedges			FairValue Hedges
Balance Sheet Location	Energy- Related Contracts			Energy- Related Contracts			Netting (A)			Total Power			Energy- Related Contracts			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	204		$	403		$	(444	)	$	163		$	0		$	19	$	182
Noncurrent Assets		3			80			(41	)		42			17			20		79
Total Mark-to-Market Derivative Assets	$	207		$	483		$	(485	)	$	205		$	17		$	39	$	261
Derivative Contracts
Current Liabilities	$	(11	)	$	(454	)	$	374		$	(91	)	$	(12	)	$	0	$	(103	)
Noncurrent Liabilities		0			(72	)		50			(22	)		0			0		(22	)
Total Mark-to-Market Derivative (Liabilities)	$	(11	)	$	(526	)	$	424		$	(113	)	$	(12	)	$	0	$	(125	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	196		$	(43	)	$	(61	)	$	92		$	5		$	39	$	136

(A) Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. As of December 31, 2011 and December 31, 2010, net cash collateral received of $82 million and $61 million, respectively, was netted against the corresponding net derivative contract positions. Of the $82 million as of December 31, 2011, cash collateral of $(77) million and $(23) million were netted against current assets and noncurrent assets, respectively, and cash collateral of $16 million and $2 million were netted against current liabilities and noncurrent liabilities, respectively. Of the $61 million as of December 31, 2010, cash collateral of $(132) million and $(3) million were netted against current assets and noncurrent assets, respectively, and cash collateral of $62 million and $12 million were netted against current liabilities and noncurrent liabilities, respectively.

Certain of PSEG’s derivative instruments contain provisions that require PSEG to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PSEG’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if PSEG were to be downgraded or lose its investment grade credit rating, it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. PSEG also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on NYMEX and ICE must adhere to comprehensive collateral and margining requirements.

The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on NYMEX and ICE that are fully collateralized) was $285 million and $226 million as of December 31, 2011 and 2010, respectively. As of December 31, 2011 and 2010, PSEG had the contractual right of offset of $149 million and $110 million, respectively, related to derivative instruments that are assets with the same counterparty under master netting agreements and net of margin posted. If PSEG had been downgraded or lost its investment grade rating, it would have had additional collateral obligations of $136 million and $116 million as of December 31, 2011

155

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

and 2010, respectively, related to its derivatives, net of the contractual right of offset under master netting agreements and the application of collateral. This potential additional collateral is included in the $812 million and $828 million as of December 31, 2011 and 2010, respectively, discussed in Note 13. Commitments and Contingent Liabilities.

The following shows the effect on the Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the years ended December 31, 2011, 2010 and 2009:

Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)								Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion)									Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	Years Ended December 31,									Years Ended December 31,									Years Ended December 31,
	2011			2010		2009				2011			2010			2009			2011			2010		2009
	Millions
PSEG (A)
Energy-Related Contracts	$	84		$	101	$	636		Operating Revenues	$	213		$	222		$	644		$	(2	)	$	1	$	(22	)
Interest Rate Swaps		0			0		0		Income from Equity Method Investments		0			0			(1	)		0			0		0
Energy-Related Contracts		(4	)		1		(45	)	Energy Costs		2			(2	)		(67	)		0			0		0
Interest Rate Swaps		0			0		(4	)	Interest Expense		(1	)		(1	)		(3	)		0			0		0
Total PSEG	$	80		$	102	$	587			$	214		$	219		$	573		$	(2	)	$	1	$	(22	)
Power
Energy-Related Contracts	$	84		$	101	$	636		Operating Revenues	$	213		$	222		$	644		$	(2	)	$	1	$	(22	)
Energy-Related Contracts		(4	)		1		(45	)	Energy Costs		2			(2	)		(67	)		0			0		0
Total Power	$	80		$	102	$	591			$	215		$	220		$	577		$	(2	)	$	1	$	(22	)
PSE&G
Interest Rate Swaps	$	0		$	0	$	(1	)	Interest Expense	$	0		$	0		$	(2	)	$	0		$	0	$	0
Total PSE&G	$	0		$	0	$	(1	)		$	0		$	0		$	(2	)	$	0		$	0	$	0
Energy Holdings
Interest Rate Swaps	$	0		$	0	$	0		Income from Equity Method Investments	$	0		$	0		$	(1	)	$	0		$	0	$	0
Total Energy Holdings	$	0		$	0	$	0			$	0		$	0		$	(1	)	$	0		$	0	$	0

(A) Includes amounts for PSEG parent.

156

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following reconciles the Accumulated Other Comprehensive Income for derivative activity included in the Accumulated Other Comprehensive Loss of PSEG on a pre-tax and after-tax basis:

Accumulated Other Comprehensive Income	Pre-Tax			After-Tax
	Millions
Balance as of December 31, 2009	$	305		$	180
Gain Recognized in AOCI (Effective Portion)		102			60
Less: Gain Reclassified into Income (Effective Portion)		(219	)		(129	)
Balance as of December 31, 2010	$	188		$	111
Gain Recognized in AOCI (Effective Portion)		80			47
Less: Gain Reclassified into Income (Effective Portion)		(214	)		(127	)
Balance as of December 31, 2011	$	54		$	31

The following shows the effect on the Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as normal purchases and sales for the years ended December 31, 2011, 2010 and 2009:

Derivatives Not Designated as Hedges	Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives	Pre-Tax Gain (Loss) Recognized in Income on Derivatives
		Years Ended December 31,
		2011			2010			2009
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	205		$	(53	)	$	128
Energy-Related Contracts	Energy Costs		(42	)		(9	)		(144	)
Derivatives in NDT Fund	Other Income		0			0			13
Total PSEG and Power		$	163		$	(62	)	$	(3	)

Power’s derivative contracts reflected in the preceding tables include contracts to hedge the purchase and sale of electricity and the purchase of fuel. Not all of these contracts qualify for hedge accounting. Most of these contracts are marked to market. The tables above do not include contracts for which Power has elected the normal purchase/normal sales exemption, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load. In addition, PSEG has interest rate swaps designated as fair value hedges. The effect of these hedges was to reduce interest expense by $25 million, $24 million and $1 million for the years ended December 31, 2011, 2010 and 2009, respectively.

157

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following reflects the gross volume, on an absolute value basis, of derivatives as of December 31, 2011 and 2010:

Type	Notional	Total		PSEG		Power		PSE&G
		Millions
As of December 31, 2011
Natural Gas	Dth		612		0		377		235
Electricity	MWh		137		0		137		0
Financial Transmission Rights (FTRs)	MWh		12		0		12		0
Interest Rate Swaps	US Dollars		1,100		1,100		0		0
Coal	Tons		1		0		1		0
As of December 31, 2010
Natural Gas	Dth		704		0		424		280
Electricity	MWh		154		0		154		0
Capacity	MW days		1		0		1		0
FTRs	MWh		23		0		23		0
Interest Rate Swaps	US Dollars		1,150		1,150		0		0

Credit Risk

Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We have established credit policies that we believe significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s and PSEG’s financial condition, results of operations or net cash flows.

As of December 31, 2011, 96% of the credit for Power’s operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives and non-derivatives and normal purchases/normal sales).

The following table provides information on Power’s credit risk from others, net of cash collateral, as of December 31, 2011. It further delineates that exposure by the credit rating of the counterparties and provides guidance on the concentration of credit risk to individual counterparties and an indication of the quality of Power’s credit risk by credit rating of the counterparties.

Rating	Current Exposure		Securities held as Collateral		Net Exposure		Number of Counterparties >10%		Net Exposure of Counterparties >10%
	Millions								Millions
Investment Grade—External Rating	$	702	$	83	$	699		2	$	427	(A)
Non-Investment Grade—External Rating		27		0		27		0		0
Investment Grade—No External Rating		9		0		9		0		0
Non-Investment Grade—No External Rating		1		0		1		0		0
Total	$	739	$	83	$	736		2	$	427

(A) Includes net exposure of $339 million with PSE&G. The remaining net exposure of $88 million is with one non-affiliated power purchaser which is a regulated investment grade counterparty.

158

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The net exposure listed above, in some cases, will not be the difference between the current exposure and the collateral held. A counterparty may have posted more cash collateral than the outstanding exposure, in which case there would be no exposure. When letters of credit have been posted as collateral, the exposure amount is not reduced, but the exposure amount is transferred to the rating of the issuing bank. As of December 31, 2011, Power had 203 active counterparties.

Note 17. Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance for fair value measurement emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels:

Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, Power and PSE&G have the ability to access. These consist primarily of listed equity securities.

Level 2—measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as forward contracts or options and most fixed income securities.

Level 3—measurements use unobservable inputs for assets or liabilities, based on the best information available and might include an entity’s own data and assumptions. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. As of December 31, 2011, these consist primarily of power swaps whose basis is deemed significant to the fair value measurement and certain long-dated capacity positions.

159

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following tables present information about PSEG’s, Power’s and PSE&G’s respective assets and (liabilities) measured at fair value on a recurring basis as of December 31, 2011 and December 31, 2010, including the fair value measurements and the levels of inputs used in determining those fair values. Amounts shown for PSEG include the amounts shown for Power and PSE&G.

	Recurring Fair Value Measurements as of December 31, 2011
Description	Total			Cash Collateral Netting (F)			Quoted Market Prices of Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Derivative Contracts:
Energy-Related Contracts(A)	$	198		$	(100	)	$	0	$	257		$	41
Interest Rate Swaps(B)	$	64		$	0		$	0	$	64		$	0
NDT Fund:(C)
Equity Securities	$	685		$	0		$	685	$	0		$	0
Debt Securities-Govt Obligations	$	359		$	0		$	0	$	359		$	0
Debt Securities-Other	$	281		$	0		$	0	$	281		$	0
Other Securities	$	24		$	0		$	0	$	24		$	0
Rabbi Trust—Mutual Funds(C)	$	172		$	0		$	19	$	153		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts(A)	$	(155	)	$	18		$	0	$	(153	)	$	(20	)
Interest Rate Swaps(B)	$	(2	)	$	0		$	0	$	(2	)	$	0
Non-Recourse Debt(E)	$	(50	)	$	0		$	0	$	0		$	(50	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts(A)	$	194		$	(100	)	$	0	$	257		$	37
NDT Fund:(C)
Equity Securities	$	685		$	0		$	685	$	0		$	0
Debt Securities-Govt Obligations	$	359		$	0		$	0	$	359		$	0
Debt Securities-Other	$	281		$	0		$	0	$	281		$	0
Other Securities	$	24		$	0		$	0	$	24		$	0
Rabbi Trust—Mutual Funds(C)	$	33		$	0		$	4	$	29		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts(A)	$	(148	)	$	18		$	0	$	(153	)	$	(13	)
PSE&G
Assets:
Derivative Contracts:
Energy-Related Contracts(A)	$	4		$	0		$	0	$	0		$	4
Rabbi Trust—Mutual Funds(C)	$	57		$	0		$	6	$	51		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts(A)	$	(7	)	$	0		$	0	$	0		$	(7	)

160

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Recurring Fair Value Measurements as of December 31, 2010
Description	Total			Cash Collateral Netting (F)			Quoted Market Prices of Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
							Millions
PSEG
Assets:
Derivative Contracts:
Energy-Related Contracts(A)	$	222		$	(135	)	$	0	$	228		$	129
Interest Rate Swaps(B)	$	39		$	0		$	0	$	39		$	0
NDT Fund:(C)
Equity Securities	$	735		$	0		$	735	$	0		$	0
Debt Securities-Govt Obligations	$	303		$	0		$	0	$	303		$	0
Debt Securities-Other	$	255		$	0		$	0	$	255		$	0
Other Securities	$	70		$	0		$	0	$	62		$	8
Rabbi Trust—Mutual Funds(C)	$	160		$	0		$	18	$	142		$	0
Other Long-Term Investments(D)	$	2		$	0		$	2	$	0		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts(A)	$	(125	)	$	74		$	0	$	(117	)	$	(82	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts(A)	$	205		$	(135	)	$	0	$	228		$	112
NDT Fund:(C)
Equity Securities	$	735		$	0		$	735	$	0		$	0
Debt Securities-Govt Obligations	$	303		$	0		$	0	$	303		$	0
Debt Securities-Other	$	255		$	0		$	0	$	255		$	0
Other Securities	$	70		$	0		$	0	$	62		$	8
Rabbi Trust—Mutual Funds(C)	$	32		$	0		$	4	$	28		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts(A)	$	(113	)	$	74		$	0	$	(117	)	$	(70	)
PSE&G
Assets:
Derivative Contracts:
Energy-Related Contracts(A)	$	17		$	0		$	0	$	0		$	17
Rabbi Trust—Mutual Funds(C)	$	54		$	0		$	6	$	48		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts(A)	$	(12	)	$	0		$	0	$	0		$	(12	)

(A) Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using the average of the bid/ask midpoints from multiple broker or dealer quotes or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs.

161

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Level 3—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. For certain energy-related option contracts where daily settled option prices are not observable, a traditional Black-Scholes valuation methodology is used which incorporates an internally developed volatility curve that is considered a significant unobservable input. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data. We considered the creditworthiness of our counterparties in the valuation of our energy-related contracts and the impacts are immaterial.

(B) Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.

(C) Power’s NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” These securities are valued using quoted market prices, broker or dealer quotations or alternative pricing sources with reasonable levels of price transparency. All fair value measurements for the fund securities are provided by the trustees of these funds. Investments in marketable equity securities within the Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price (primarily Level 1).

Power’s NDT investments in fixed income securities are primarily with investment grade corporate bonds and United States Treasury obligations or Federal Agency mortgage-backed securities with a wide range of maturities. Fixed income securities are priced using an evaluated pricing methodology that reflects observable market information such as the most recent exchange price or quoted bid for similar securities (primarily Level 2). Short-term investments and certain commingled temporary investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield (primarily Level 2).

The Rabbi Trust mutual funds are mainly invested in a United States bond index fund and a S&P 500 index fund. The equity index fund is valued based on quoted prices in an active market (Level 1) while the bond index fund is valued using recent exchange prices or a quoted bid (Level 2).

(D) Other long-term investments consist of equity securities and are valued using a market based approach based on quoted market prices.

(E) For Non-Recourse Debt, see Fair Value Option below.

(F) Cash collateral netting represents collateral amounts netted against derivative assets and liabilities as permitted under the accounting guidance for Offsetting of Amounts Related to Certain Contracts.

162

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the years ended December 31, 2011 and 2010 follows:

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis

for the Year Ended December 31, 2011

			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1,     2011		Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases, (Sales) (C)		Issuances (Settlements) (D)			Transfers In (Out) (E)			Balance as of December 31,     2011
	Millions
PSEG
Net Derivative Assets	$	47	$	22	$	(8	)	$	30	$	(37	)	$	(33	)	$	21
NDT Fund	$	8	$	0	$	0		$	0	$	0		$	(8	)	$	0
Non-Recourse Debt	$	0	$	0	$	0		$	0	$	(50	)	$	0		$	(50	)
Power
Net Derivative Assets	$	42	$	22	$	0		$	30	$	(37	)	$	(33	)	$	24
NDT Fund	$	8	$	0	$	0		$	0	$	0		$	(8	)	$	0
PSE&G
Net Derivative Assets	$	5	$	0	$	(8	)	$	0	$	0		$	0		$	(3	)

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis

for the Year Ended December 31, 2010

			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1,     2010		Included in Income (F)			Included in Regulatory Assets/ Liabilities (B)			Purchases, (Sales) and Settlements			Balance as of December 31,     2010
	Millions
PSEG
Net Derivative Assets	$	105	$	(36	)	$	(1	)	$	(21	)	$	47
NDT Fund	$	9	$	0		$	0		$	(1	)	$	8
Rabbi Trust Fund	$	14	$	0		$	0		$	(14	)	$	0
Power
Net Derivative Assets	$	99	$	(36	)	$	0		$	(21	)	$	42
NDT Fund	$	9	$	0		$	0		$	(1	)	$	8
Rabbi Trust Fund	$	3	$	0		$	0		$	(3	)	$	0
PSE&G
Net Derivative Assets	$	6	$	0		$	(1	)	$	0		$	5
Rabbi Trust Fund	$	5	$	0		$	0		$	(5	)	$	0

(A) PSEG’s and Power’s gains and losses are mainly attributable to changes in net derivative assets and liabilities of which $17 million is included in Operating Income, $2 million is included in OCI, and $3

163

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

million is included in Income from Discontinued Operations. Of the $17 million in Operating Income, $9 million is unrealized and $8 million is realized.

(B) Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or OCI, as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers.

(C) Includes $66 million in purchases and $(36) million in sales.

(D) Includes $(25) million in issuances and $(12) million in settlements for derivative contracts and includes $(50) million of issuances due to initial recognition of lessor notes resulting from rejection of the Dynegy leveraged leases.

(E) During the year ended December 31, 2011, $8 million of assets in the NDT Fund were transferred from Level 3 to Level 2, due to more observable pricing for the underlying securities and $33 million of net derivative assets were transferred from Level 3 to Level 2 due to more available observable market data. The transfers were recognized as of the beginning of the first quarter and fourth quarter, respectively, (i.e. the quarters in which the transfers occurred), as per PSEG’s policy.

(F) PSEG’s and Power’s gains and losses are mainly attributable to changes in net derivative assets and liabilities of which $(61) million is included in Operating Income, $2 million is included in OCI, and $23 million is included in Income from Discontinued Operations. Of the $(61) million in Operating Income, $(51) million is unrealized and $(10) million is realized.

As of December 31, 2011, PSEG carried $1.6 billion of net assets that are measured at fair value on a recurring basis, of which $29 million of net liabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. These Level 3 net liabilities represented less than 1% of PSEG’s total assets.

As of December 31, 2010, PSEG carried $1.7 billion of net assets that are measured at fair value on a recurring basis, of which $55 million were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. These Level 3 net assets represented less than 1% of PSEG’s total assets and there were no transfers among levels during the year ended December 31, 2010.

Fair Value Option

As of the December 31, 2011, the effective date of the Dynegy lease rejections, the leases of the Roseton and Danskammer generation facilities were effectively terminated and no longer qualified for leveraged lease accounting under the guidance for leases. As the owner of the facilities, Energy Holdings was required to recognize the underlying assets and nonrecourse notes payable (Notes) associated with these leases at their respective fair values on the effective date of the rejection. Energy Holdings has elected to record the Notes at fair value each reporting period under the fair value option in accordance with guidance for Financial Instruments. The fair value option permits the irrevocable fair value election for selected eligible financial assets or liabilities. Any changes in the fair value of the Notes will be included in earnings each period. The $550 million of contractual principal outstanding on the Notes, currently valued at $50 million, became eligible for the fair value option upon their initial recognition on the balance sheet when the leases were rejected. We elected this option to eliminate certain complexities in applying the effective interest method of amortization given the uncertain payment streams between the election date and the expected foreclosure date. There were no other debt instruments of this type eligible for the fair value option as of December 31, 2011. The $50 million fair value of these Notes is included on PSEG’s Consolidated Balance Sheet as of December 31, 2011. The fair value of the Notes include significant internal assumptions based on expected cash flows and the fair values of the underlying collateral. These Notes are classified as Level 3 in the fair value hierarchy as a result of mainly unobservable inputs.

The table of fair value of debt is included in Note 14. Schedule of Consolidated Debt.

164

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Non-recurring Fair Value Measurements

2011

• During the fourth quarter of 2011, DH filed for protection under Chapter 11 of the US Bankruptcy Code. As a result of the settlement agreement that was reached relating to the lease of electric generation facilities to subsidiaries of DH (See Note 8. Financing Receivables), Energy Holdings ceased leveraged lease accounting for the leased assets and recorded those generation facilities at their respective fair values totaling $50 million, which were carried as nonrecurring fair values at December 31, 2011. The fair values of those generation facilities were determined based on a third party appraisal using significant assumptions including expectations of cash flows which are considered mainly unobservable inputs (Level 3).

2010

• Due to a significant decline in market prices at December 31, 2010 and June 30, 2010, Power assessed the recoverability of its SO₂ emission allowances not expected to be consumed. As a result of this evaluation, Power recorded pre-tax impairment charges of $3 million and $15 million related to its forecasted excess SO₂ allowances during the quarters ended December 31, 2010 and June 30, 2010, respectively, which are included in Energy Costs in PSEG’s and Power’s Consolidated Statements of Operations.

As of December 31, 2010, the fair value of remaining excess SO₂ emission allowances of $3 million was determined based on a comparison of quoted market prices where available for each vintage year to the carrying value of the related allowances (Level 2 measurement within the fair value hierarchy). Due to the lack of observable prices beyond certain vintage years, significant internal assumptions were used in the valuation of approximately $1 million of those allowances (Level 3 measurement within the fair value hierarchy).

• During the fourth quarter of 2010, Energy Holdings recorded an after-tax impairment charge of $6 million on its investment in GWF Power. The remaining investment was carried as a nonrecurring fair value measurement as of December 31, 2010. This investment was considered a Level 3 within the fair value hierarchy based on the use of unobservable inputs.

• During the second quarter of 2010, Energy Holdings executed a new lease, triggering an assessment of the recoverability of existing property located in Michigan. As a result of the evaluation, Energy Holdings recorded a pre-tax impairment of $10 million during the quarter ended June 30, 2010, which is included in Operating Revenues in PSEG’s Consolidated Statement of Operations. The fair value of the property was determined using an internal model based on a discounted cash flow analysis (income approach valuation technique) with significant unobservable inputs (Level 3).

Note 18. Stock Based Compensation

PSEG’s 2004 Long-Term Incentive Plan (LTIP) is a broad-based equity compensation program that provides for grants of various long-term incentive compensation awards, such as stock options, stock appreciation rights, performance units, restricted stock, restricted stock units, cash awards or any combination thereof. The types of long-term incentive awards that have been granted and remain outstanding under the LTIPs are non-qualified options to purchase shares of PSEG’s common stock, restricted stock awards, restricted stock unit awards and performance unit awards. The type of equity award that is granted and the details of that award may vary from time to time and is subject to the approval of the Organization and Compensation Committee of PSEG’s Board of Directors (OCC), the plan’s administrative committee.

The 2004 LTIP currently provides for the issuance of equity awards with respect to approximately 26 million shares of common stock. As of December 31, 2011, there were approximately 18 million shares available for future awards under the 2004 LTIP.

165

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Stock Options

Under the 2004 LTIP, non-qualified options to acquire shares of PSEG common stock may be granted to officers and other key employees selected by the OCC. Option awards are granted with an exercise price equal to the market price of PSEG’s common stock at the grant date. The options generally vest based on three to five years of continuous service. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change-in-control (unless substituted with an equity award of equal value), retirement, death or disability. Options are exercisable over a period of time designated by the OCC (but not prior to one year or longer than 10 years from the date of grant) and are subject to such other terms and conditions as the OCC determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the OCC, by delivering previously acquired shares of PSEG common stock.

Restricted Stock

Under the 2004 LTIP, PSEG has granted restricted stock awards to officers and other key employees. These shares are subject to risk of forfeiture until vested by continued employment. Restricted stock generally vests annually over three or four years, but is considered outstanding at the time of grant, as the recipients are entitled to dividends and voting rights. Vesting may be accelerated upon certain events, such as change-in-control (unless substituted with an equity award of equal value), retirement, death or disability.

Restricted Stock Units

Under the 2004 LTIP, PSEG has granted restricted stock unit awards to officers and certain other key employees. These awards, which are bookkeeping entries only, are subject to risk of forfeiture until vested by continued employment. Until vested, the units are credited with dividend equivalents proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. The restricted stock unit grants for 2011 generally vest after three years. Prior to 2011, restricted stock unit grants generally vested over four years. Vesting may be accelerated upon certain events such as change-in-control, retirement, death or disability.

Performance Units

Under the 2004 LTIP, performance units were granted to officers and certain other employees, which provide for payment in shares of PSEG common stock based on achievement of certain financial goals over a three-year performance period. The payout varies from 0% to 200% of the number of performance units granted depending on PSEG’s performance with respect to certain financial targets, including targets related to comparative performance against other companies in a peer group of energy companies. The performance units are credited with dividend equivalents in an amount equal to dividends paid on PSEG common stock up until the shares are distributed. Vesting may be pro-rated for the employee’s service during the performance period as a result of certain events, such as change-in-control (unless substituted with an equity award of equal value), retirement, death or disability.

Stock-Based Compensation

All outstanding unvested stock options are being expensed based on their grant date fair values, which were determined using the Black-Scholes option-pricing model. Stock option awards are expensed on a tranche-specific basis over the requisite service period of the award. Ultimately, compensation expense for stock options is recognized for awards that vest.

PSEG recognizes compensation expense for restricted stock over the vesting period based on the grant date fair market value of the shares. PSEG will continue to recognize compensation expense over the vesting term.

PSEG recognizes compensation expense for performance units based on the grant date fair value of PSEG common stock. The accrual of compensation cost was based on the probable achievement of the performance conditions, which result in a payout from 0% to 200% of the initial grant. The current accrual is estimated at

166

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

100% of the original grant. The accrual is adjusted for subsequent changes in the estimated or actual outcome.

	2011		2010		2009
			Millions
Compensation Cost included in Operation and Maintenance Expense	$	23	$	29	$	27
Income Tax Benefit Recognized in Consolidated Statement of Operations	$	10	$	12	$	11

There was $1 million, $1 million and $3 million of excess tax benefits included as financing cash flows on the Consolidated Statements of Cash Flow for the years ended December 31, 2011, 2010 and 2009, respectively.

PSEG recognizes compensation cost of awards issued over the shorter of the original vesting period or the period beginning on the date of grant and ending on the date an individual is eligible for retirement and the award vests.

Changes in stock options for 2011 are summarized as follows:

	2011
	Options			Weighted Average Exercise Price
Beginning of Year		3,660,634		$	32.22
Exercised		(263,600	)		23.68
Forfeited		(70,750	)		31.65
Expired		(53,984	)		40.98
End of Year		3,272,300		$	32.78
Exercisable at End of Year		2,641,475		$	32.91

Options	Weighted Average Remaining Years Contractual Term		Aggregate Intrinsic Value
Outstanding at December 31, 2011		5.9	$	8,614,956
Exercisable at December 31, 2011		5.4	$	7,918,875

The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model. There were no option grants in 2011 and 2010. The following weighted average assumptions were used for grants in 2009:

	2009
Expected Volatility		29.00%
Risk-Free Interest Rate		2.84%
Expected Life (Years)		6.25
Weighted Average Dividend Yield		4.00%

The expected volatility assumption is based on the historical volatility of daily stock prices. The risk-free rate assumption is based upon U.S. Treasury yields in effect at the time of grant. The expected life of all options is calculated using the simplified method which assumes options are exercised midway between the vesting date and the contractual term of the option. PSEG will continue to use the simplified method until there is adequate historical experience for option exercises.

167

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The intrinsic value of options is the difference between the current market price and the exercise price. Activity for options exercised for the years ended December 31, 2011, 2010 and 2009 is shown below:

	2011		2010		2009
	Millions
Total Intrinsic Value of Options Exercised	$	2	$	1	$	4
Cash Received from Options Exercised	$	6	$	3	$	11
Tax Benefit Realized from Options Exercised	$	1	$	1	$	3

Approximately one million options vested during the years ended December 31, 2011, 2010 and 2009. The weighted average fair value per share for options vested during the years ended December 31, 2011, 2010 and 2009 was $34.30, $34.57 and $35.07, respectively.

As of December 31, 2011, there was approximately $3 million of unrecognized compensation cost related to stock options, which is to be recognized over a weighted average period of 0.82 years.

Restricted Stock Information

Changes in restricted stock for the year ended December 31, 2011 are summarized as follows:

	Shares			Weighted Average Grant Date Fair Value		Weighted Average Remaining Years Contractual Term		Aggregate Intrinsic Value
Outstanding at January 1, 2011		117,702		$	35.71
Granted		0		$	0.00
Vested		(47,402	)	$	39.99
Canceled		0		$	0.00
Outstanding at December 31, 2011		70,300		$	32.83		1.1	$	2,320,603

The weighted average grant date fair value per share was $30.18 for restricted stock awards granted during 2009. There were no restricted stock awards granted in 2011 and 2010.

The total intrinsic value of restricted stock vested during the years ended December 31, 2011, 2010 and 2009 was $1 million, $3 million and $3 million, respectively.

As of December 31, 2011, there was approximately $0.7 million of unrecognized compensation cost related to restricted stock, which is expected to be recognized over a weighted average period of 0.7 years.

Restricted Stock Units

Changes in restricted stock units for the year ended December 31, 2011 are summarized as follows:

	Shares			Weighted Average Grant Date Fair Value		Weighted Average Remaining Years Contractual Term		Aggregate Intrinsic Value
Outstanding at January 1, 2011		814,361		$	33.33
Granted		110,845		$	32.03
Vested		(216,158	)	$	36.99
Canceled		(60,497	)	$	40.96
Outstanding at December 31, 2011		648,551		$	31.17		1.5	$	21,408,669

The weighted average grant date fair value per share for restricted stock during the years ended December 31, 2011, 2010 and 2009 was $32.03, $31.13 and $30.19 per share, respectively.

The total intrinsic value of restricted stock units vested during the year ended December 31, 2011 was $7 million.

168

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2011, there was approximately $9 million of unrecognized compensation cost related to the restricted stock units, which is expected to be recognized over a weighted average period of 1.2 years. Dividend equivalents of 29,817 accrued on the restricted stock units during the year.

Performance Units Information

Changes in Performance Units for the year ended December 31, 2011 are summarized as follows:

	Shares			Weighted Average Grant Date Fair Value		Weighted Average Remaining Contractual Term		Aggregate Intrinsic Value
Outstanding at January 1, 2011		881,589		$	33.77
Granted		63,250		$	35.33
Vested		(244,406	)	$	30.60
Cancelled		(58,447	)	$	33.78
Outstanding at December 31, 2011		641,986		$	35.13		1.6	$	21,191,958

The weighted average grant date fair value per share for performance units during the years ended December 31, 2011, 2010 and 2009 was $35.33, $34.29 and $36.41 per share, respectively.

The total intrinsic value of performance units vested during the year ended December 31, 2011 was $9 million.

As of December 31, 2011, there was approximately $11 million of unrecognized compensation cost related to the performance units, which is expected to be recognized over a weighted average period of 1 year. Dividend equivalents of 42,235 accrued on the performance share units during the year.

Outside Directors

Under the Directors Equity Plan, annually, on May 1, each non-employee member of the Board of Directors is awarded stock units based on amount of annual compensation to be paid and the May 1 closing price of PSEG common stock. Dividend equivalents are credited quarterly and distributions will commence upon the director leaving the Board.

The fair value of these awards is recorded as compensation expense in the Consolidated Statements of Operations. Compensation expense for the plan for each of the years ended December 31, 2011, 2010 and 2009 was approximately $1 million.

Employee Stock Purchase Plan

PSEG maintains an employee stock purchase plan for all eligible employees of PSEG and its subsidiaries. Under the plan, shares of PSEG common stock may be purchased at 95% of the fair market value through payroll deductions. In any year, employees may purchase shares having a value not exceeding 10% of their base pay. During the years ended December 31, 2011, 2010 and 2009, employees purchased 183,338, 178,684 and 173,350 shares at an average price of $30.69, $30.32 and $29.20 per share, respectively. As of December 31, 2011, 3.6 million shares were available for future issuance under this plan.

169

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 19. Other Income and Deductions

Other Income	Power		PSE&G		Other (A)		Consolidated Total
	Millions
For the Year Ended December 31, 2011:
NDT Fund Gains, Interest, Dividend and Other Income	$	186	$	0	$	0	$	186
Solar Loan Interest		0		10		0		10
Other		4		15		5		24
Total Other Income	$	190	$	25	$	5	$	220
For the Year Ended December 31, 2010:
NDT Fund Gains, Interest, Dividend and Other Income	$	159	$	0	$	0	$	159
Realized Gains from Rabbi Trust		7		11		13		31
Solar Loan Interest		0		6		0		6
Other		4		9		12		25
Total Other Income	$	170	$	26	$	25	$	221
For the Year Ended December 31, 2009:
NDT Fund Gains, Interest, Dividend and Other Income	$	227	$	0	$	0	$	227
Solar Loan Interest		0		1		0		1
Other		6		7		5		18
Total Other Income	$	233	$	8	$	5	$	246

Other Deductions	Power		PSE&G		Other (A)		Consolidated Total
	Millions
For the Year Ended December 31, 2011:
NDT Fund Realized Losses and Expense	$	50	$	0	$	0	$	50
Loss on Early Extinguishment of Debt		17		0		0		17
Other		12		4		2		18
Total Other Deductions	$	79	$	4	$	2	$	85
For the Year Ended December 31, 2010:
NDT Fund Realized Losses and Expense	$	45	$	0	$	0	$	45
Other		8		3		7		18
Total Other Deductions	$	53	$	3	$	7	$	63
For the Year Ended December 31, 2009:
NDT Fund Realized Losses and Expense	$	117	$	0	$	0	$	117
Other		18		3		23		44
Total Other Deductions	$	135	$	3	$	23	$	161

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

170

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 20. Income Taxes

A reconciliation of reported income tax expense for PSEG with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows:

	For the Years Ended December 31,
	2011			2010			2009
	Millions
Net Income	$	1,503		$	1,564		$	1,592
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax benefit		96			7			(2	)
Income from Continuing Operations		1,407			1,557			1,594
Preferred Dividends		0			(1	)		(4	)
Income from Continuing Operations, excluding Preferred Dividends	$	1,407		$	1,558		$	1,598
Income Taxes:
Operating Income:
Current Expense:
Federal	$	258		$	(166	)	$	560
State		32			157			257
Total Current		290			(9	)		817
Deferred Expense:
Federal		501			992			178
State		191			79			44
Total Deferred		692			1,071			222
Investment Tax Credit		(5	)		(3	)		3
Total Income Taxes	$	977		$	1,059		$	1,042
Pre-Tax Income	$	2,384		$	2,617		$	2,640
Tax Computed at Statutory Rate @ 35%	$	834		$	916		$	924
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)		146			154			201
Uncertain Tax Positions		19			30			(73	)
Manufacturing Deduction		(15	)		(24	)		(7	)
Nuclear Decommissioning Trust		14			10			7
Plant-Related Items		(6	)		(3	)		3
Tax Credits		(5	)		(2	)		(3	)
Other		(10	)		(22	)		(10	)
Sub-Total		143			143			118
Total Income Tax Provision	$	977		$	1,059		$	1,042
Effective Income Tax Rate		41.0%			40.5%			39.5%

171

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following is an analysis of deferred income taxes for PSEG:

	As of December 31,
	2011		2010
	Millions
Deferred Income Taxes
Assets:
Current (net)	$	0	$	43
Noncurrent:
Unrecovered Investment Tax Credit	$	15	$	18
Accumulated Other Comprehensive Income (Loss)		39		79
Cumulative Effect of a Change in Accounting Principle		11		11
New Jersey Corporate Business Tax		0		17
OPEB		208		197
Cost of Removal		51		51
Contractual Liabilities & Environmental Costs		35		35
MTC		26		47
Related to Uncertain Tax Positions		104		73
Other		44		58
Total Non-Current Assets	$	533	$	586
Total Assets	$	533	$	629
Liabilities:
Current (net)	$	170	$	0
Noncurrent:
Plant-Related Items		3,894		3,169
Nuclear Decommissioning		155		171
New Jersey Corporate Business Tax		180		0
Securitization		495		686
Leasing Activities		527		839
Partnership Activity		18		18
Conservation Costs		97		62
Energy Clause Recoveries		0		76
Pension Costs		129		189
AROs		302		287
Taxes Recoverable Through Future Rate (net)		158		158
Other		0		18
Total Noncurrent Liabilities	$	5,955	$	5,673
Total Liabilities	$	6,125	$	5,673
Summary of Accumulated Deferred Income Taxes:
Net Current Deferred Income Tax Assets	$	0	$	43
Net Current Deferred Income Tax Liability	$	170	$	0
Net Noncurrent Deferred Income Tax Liabilities	$	5,422	$	5,087
Investment Tax Credit (ITC)		36		42
Net Total Noncurrent Deferred Income Taxes and ITC	$	5,458	$	5,129

172

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A reconciliation of reported income tax expense for Power with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows:

	For the Years Ended December 31,
	2011			2010			2009
	Millions
Net Income	$	1,098		$	1,143		$	1,189
Income (Loss) from Discontinued Operations, net of tax		96			7			(2	)
Income from Continuing Operations	$	1,002		$	1,136		$	1,191
Income Taxes:
Operating Income:
Current Expense:
Federal	$	400		$	12		$	416
State		40			127			144
Total Current		440			139			560
Deferred Expense:
Federal		151			598			177
State		94			41			30
Total Deferred		245			639			207
Total Income Taxes	$	685		$	778		$	767
Pre-Tax Income	$	1,687		$	1,914		$	1,958
Tax Computed at Statutory Rate @ 35%	$	591		$	670		$	685
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)		87			109			113
Manufacturing Deduction		(15	)		(24	)		(7	)
Nuclear Decommissioning Trust		14			10			7
Uncertain Tax Positions		11			10			(26	)
Other		(3	)		3			(5	)
Sub-Total		94			108			82
Total Income Tax Provision	$	685		$	778		$	767
Effective Income Tax Rate		40.6%			40.6%			39.2%

173

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following is an analysis of deferred income taxes for Power:

	As of December 31,
	2011		2010
	Millions
Deferred Income Taxes
Assets:
Noncurrent:
Cumulative Effect of a Change in Accounting Principle	$	11	$	11
New Jersey Corporate Business Tax		0		73
Pension Costs		53		12
Accumulated Other Comprehensive Income (Loss)		39		40
Cost of Removal		51		51
Contractual Liabilities & Environmental Costs		35		35
Related to Uncertain Tax Positions		4		0
Other		22		38
Total Noncurrent Assets	$	215	$	260
Total Assets	$	215	$	260
Liabilities:
Current (net)	$	53	$	64
Noncurrent:
Plant-Related Items	$	1,013	$	927
New Jersey Corporate Business Tax		7		0
Nuclear Decommissioning		155		171
AROs		302		287
Related to Uncertain Tax Positions		0		16
Total Noncurrent Liabilities	$	1,477	$	1,401
Total Liabilities	$	1,530	$	1,465
Summary of Accumulated Deferred Income Taxes:
Net Current Deferred Income Tax Liabilities	$	53	$	64
Net Noncurrent Deferred Income Tax Liabilities	$	1,262	$	1,141
Investment Tax Credit (ITC)		4		5
Net Total Noncurrent Deferred Income Taxes and ITC	$	1,266	$	1,146

174

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A reconciliation of reported income tax expense for PSE&G with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows:

	For the Years Ended             December  31,
	2011			2010			2009
	Millions
Net Income	$	521		$	358		$	321
Preferred Dividends		0			(1	)		(4	)
Income from Continuing Operations, excluding Preferred Dividends	$	521		$	359		$	325
Income Taxes:
Operating Income:
Current Expense:
Federal	$	(225	)	$	(211	)	$	7
State		(6	)		(1	)		22
Total Current		(231	)		(212	)		29
Deferred Expense:
Federal		483			384			158
State		92			63			38
Total Deferred		575			447			196
Investment Tax Credit		(4	)		(3	)		1
Total Income Taxes	$	340		$	232		$	226
Pre-Tax Income	$	861		$	591		$	551
Tax Computed at Statutory Rate @ 35%	$	301		$	207		$	193
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)		56			40			39
Uncertain Tax Positions		(1	)		(1	)		(3	)
Plant-Related Items		(6	)		(3	)		3
Tax Credits		(4	)		(2	)		(3	)
Other		(6	)		(9	)		(3	)
Sub-Total		39			25			33
Total Income Tax Provision	$	340		$	232		$	226
Effective Income Tax Rate		39.5%			39.2%			41.0%

175

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following is an analysis of deferred income taxes for PSE&G:

	As of December 31,
	2011		2010
	Millions
Deferred Income Taxes
Assets:
Noncurrent:
Unrecovered ITC	$	10	$	12
OPEB		197		189
MTC		26		47
Related to Uncertain Tax Positions		30		24
Other		13		5
Total Noncurrent Assets	$	276	$	277
Total Assets	$	276	$	277
Liabilities:
Current (net)	$	32	$	19
Noncurrent:
Plant-Related Items	$	2,875	$	2,216
New Jersey Corporate Business Tax		146		0
Securitization		495		686
Conservation Costs		97		62
Energy Clause Recoveries		0		76
Pension Costs		151		172
Taxes Recoverable Through Future Rate (net)		158		158
Total Noncurrent Liabilities	$	3,922	$	3,370
Total Liabilities	$	3,954	$	3,389
Summary of Accumulated Deferred Income Taxes:
Net Current Deferred Income Tax Liability	$	32	$	19
Net Noncurrent Deferred Income Tax Liability	$	3,646	$	3,093
Investment Tax Credit (ITC)		29		34
Net Total Noncurrent Deferred Income Taxes and ITC	$	3,675	$	3,127

As of December 31, 2011, PSE&G has New Jersey State income tax net operating loss (NOL) carryforwards of $127 million, which will expire in 2030. We believe that it is more likely than not that the benefit from the state NOL carryforwards will be realized.

Each of PSEG, Power and PSE&G provide deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities irrespective of the treatment for rate-making purposes. Management believes that it is probable that the accumulated tax benefits that previously have been treated as a flow-through item to PSE&G customers will be recovered from or refunded to PSE&G’s customers in the future. These amounts were determined using the enacted federal income tax rate of 35% and state income tax rate of 9%. For additional information, see Note 6. Regulatory Assets and Liabilities.

176

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 include various health care-related provisions which will go into effect over the next several years. One of the provisions eliminates the tax deductibility of retiree health care costs, to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage. Although this change does not take effect immediately, the accounting impact was required to be recognized when the legislation was signed. As a result, in the first quarter of 2010, PSEG recorded noncash after tax charges of $9 million for income tax expense to establish the related deferred tax liabilities, primarily related to Power. There was no immediate impact on PSE&G’s income tax expense or effective tax rate since the related amount of $78 million was deferred as a Regulatory Asset to be collected and amortized over future periods.

Two other tax provisions were enacted during 2010 that will have a significant impact on PSEG’s cash position. The Small Business Jobs Act of 2010, enacted September 27, 2010, extended the tax deduction for 50% bonus depreciation through 2010 for qualified property. The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, enacted December 17, 2010, included a provision making qualified property placed into service after September 8, 2010 and before January 1, 2012, eligible for 100% bonus depreciation for tax purposes. In addition, qualified property placed into service in 2012 will be eligible for 50% bonus depreciation for tax purposes. These provisions will generate cash for PSEG through tax benefits related to the accelerated depreciation most of which was realized in 2011. These tax benefits would have otherwise been received over an estimated average 20 year period.

During 2011, PSE&G accrued $51 million of Investment Tax Credits (ITC) associated with alternative energy projects. Because the law provides an option to claim either a grant or the ITC, the ITC has been accounted for as a reduction of the book basis of the related assets as opposed to being recorded in tax expense.

PSEG recorded the following amounts related to its unrecognized tax benefits, which was primarily comprised of amounts recorded for Power, PSE&G and Energy Holdings:

2011	PSEG			Power			PSE&G			Energy Holdings
	Millions
Total Amount of Unrecognized Tax Benefits at January 1, 2011	$	756		$	101		$	82		$	539
Increases as a Result of Positions Taken in a Prior Period		58			24			14			17
Decreases as a Result of Positions Taken in a Prior Period		(22	)		(9	)		0			(12	)
Increases as a Result of Positions Taken during the Current Period		37			8			18			11
Decreases as a Result of Positions Taken during the Current Period		(4	)		(3	)		(1	)		0
Decreases as a Result of Settlements with Taxing Authorities		0			0			0			0
Decreases due to Lapses of Applicable Statute of Limitations		0			0			0			0
Total Amount of Unrecognized Tax Benefits at December 31, 2011	$	825		$	121		$	113		$	555
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits		(379	)		(77	)		(65	)		(213	)
Regulatory Asset—Unrecognized Tax Benefits		(20	)		0			(20	)		0
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties)	$	426		$	44		$	28		$	342

177

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2010	PSEG			Power			PSE&G			Energy Holdings
	Millions
Total Amount of Unrecognized Tax Benefits at January 1, 2010	$	836		$	(42	)	$	35		$	820
Increases as a Result of Positions Taken in a Prior Period		290			111			79			90
Decreases as a Result of Positions Taken in a Prior Period		(450	)		(29	)		(38	)		(383	)
Increases as a Result of Positions Taken during the Current Period		82			63			6			12
Decreases as a Result of Positions Taken during the Current Period		(2	)		(2	)		0			0
Decreases as a Result of Settlements with Taxing Authorities		0			0			0			0
Decreases due to Lapses of Applicable Statute of Limitations		0			0			0			0
Total Amount of Unrecognized Tax Benefits at December 31, 2010	$	756		$	101		$	82		$	539
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits		(332	)		(67	)		(38	)		(204	)
Regulatory Asset—Unrecognized Tax Benefits		(16	)		0			(16	)		0
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties)	$	408		$	34		$	28		$	335

2009	PSEG			Power			PSE&G			Energy Holdings
	Millions
Total Amount of Unrecognized Tax Benefits at January 1, 2009	$	1,403		$	30		$	27		$	1,323
Increases as a Result of Positions Taken in a Prior Period		37			1			8			26
Decreases as a Result of Positions Taken in a Prior Period		(580	)		(39	)		(9	)		(530	)
Increases as a Result of Positions Taken during the Current Period		15			1			10			4
Decreases as a Result of Positions Taken during the Current Period		(19	)		(18	)		(1	)		0
Decreases as a Result of Settlements with Taxing Authorities		(5	)		(5	)		0			0
Decreases due to Lapses of Applicable Statute of Limitations		(15	)		(12	)		0			(3	)
Total Amount of Unrecognized Tax Benefits at December 31, 2009	$	836		$	(42	)	$	35		$	820
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits		(508	)		37			22			(551	)
Regulatory Asset—Unrecognized Tax Benefits		(55	)		0			(55	)		0
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties)	$	273		$	(5	)	$	2		$	269

On June 26, 2009, September 15, 2008 and December 17, 2007, PSEG made tax deposits with the IRS in the amount of $140 million, $80 million and $100 million, respectively, to defray potential interest costs associated with disputed tax assessments associated with certain lease investments (see Note 13. Commitments and Contingent Liabilities). The $320 million of deposits are fully refundable and are recorded in Current Accrued Taxes on PSEG’s Consolidated Balance Sheets, but are not reflected in the amounts shown above. On January 31, 2012, PSEG signed a specific matter closing agreement with the IRS regarding this matter. Based on this agreement, these deposits will be applied against tax and interest due pursuant to the closing agreement.

178

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PSEG and its subsidiaries include all accrued interest and penalties related to uncertain tax positions required to be recorded, as income tax expense. Interest and penalties on uncertain tax positions were as follows:

	Interest and Penalties on Uncertain Tax Positions Years Ended December 31,
	2011			2010			2009
	Millions
Power	$	(11	)	$	(17	)	$	(2	)
PSE&G		(24	)		(20	)		(22	)
Energy Holdings		420			407			370
Other		10			9			8
Total	$	395		$	379		$	354

It is reasonably possible that total unrecognized tax benefits will decrease within the next twelve months due to either agreements with various taxing authorities upon audit or the expiration of the Statute of Limitations. These potential decreases are as follows:

Possible Decrease in Total Unrecognized Tax Benefits including Interest	Over the next 12 Months
		Millions
PSEG	$	579
Power	$	64
PSE&G	$	27

As a result of a change in accounting method for the capitalization of indirect costs, PSEG reduced the net amount of its uncertain tax positions (including interest) by $97 million, approximately $43 million of which related to PSE&G. Pursuant to an agreement signed with the IRS on January 31, 2012, this matter is settled and there will be a resulting increase in uncertain tax positions within the next twelve months. These amounts are not included in the table above.

Due to a specific matter closing agreement signed with the IRS on January 31, 2012, unrecognized tax benefits associated with the leasing tax issue discussed in Note 13. Commitments and Contingent Liabilities, will decrease by approximately $300 million within the next twelve months.

Description of income tax years that remain subject to examination by material jurisdictions, where an examination has not already concluded are:

	PSEG		Power		PSE&G
United States
Federal		2007-2010		2007-2010		2007-2010
New Jersey		2006-2010		N/A		2006-2010
Pennsylvania		2009-2010		N/A		2008-2010
Connecticut		2007-2010		N/A		N/A
Texas		2007-2010		N/A		N/A
California		2003-2010		N/A		N/A
New York		2004-2010		2004-2010		N/A

179

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 21. Earnings Per Share (EPS) and Dividends

EPS

Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding or vesting of restricted stock awards granted under our stock compensation plans and upon payment of performance units or restricted stock units. The following table shows the effect of these stock options, performance units and restricted stock units on the weighted average number of shares outstanding used in calculating diluted EPS:

	For the Years Ended December 31,
	2011				2010				2009
	Basic		Diluted		Basic		Diluted		Basic			Diluted
EPS Numerator:
(Millions)
Continuing Operations	$	1,407	$	1,407	$	1,557	$	1,557	$	1,594		$	1,594
Discontinued Operations		96		96		7		7		(2	)		(2	)
Net Income	$	1,503	$	1,503	$	1,564	$	1,564	$	1,592		$	1,592
EPS Denominator:
(Thousands)
Weighted Average Common Shares Outstanding		505,949		505,949		505,985		505,985		505,986			505,986
Effect of Stock Based Compensation Awards		0		1,033		0		1,060		0			1,078
Total Shares		505,949		506,982		505,985		507,045		505,986			507,064
EPS:
Continuing Operations	$	2.78	$	2.77	$	3.08	$	3.07	$	3.15		$	3.14
Discontinued Operations		0.19		0.19		0.01		0.01		0.00			0.00
Net Income	$	2.97	$	2.96	$	3.09	$	3.08	$	3.15		$	3.14

There were approximately 1.8 million, 1.9 million and 1.6 million stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect for the years ended December 31, 2011, 2010 and 2009, respectively. No other stock options had an antidilutive effect for the years ended December 31, 2011, 2010 or 2009.

Dividends

	For the Years Ended December 31,
Dividend Payments on Common Stock	2011		2010		2009
Per Share	$	1.37	$	1.37	$	1.33
in Millions	$	693	$	693	$	673

On February 21, 2012, PSEG’s Board of Directors approved a $0.3550 per share common stock dividend for the first quarter of 2012.

180

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 22. Financial Information by Business Segment

Basis of Organization

PSEG’s operating segments are Power, PSE&G and Energy Holdings. The operating segments were determined by management in accordance with GAAP—Disclosures about Segments of an Enterprise and Related Information. These segments were determined based on how management measures performance based on segment Net Income, as illustrated in the following table, and how it allocates resources to each business.

See Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies for additional information.

Power

Power earns revenues by selling energy, capacity and ancillary services on a wholesale basis under contract to power marketers and to load serving entities and by bidding energy, capacity and ancillary services into the markets for these products. Power also enters into trading contracts for energy, capacity, FTRs, gas, emission allowances and other energy-related contracts to optimize the value of its portfolio of generating assets and its electric and gas supply obligations.

PSE&G

PSE&G earns revenues from its tariffs, under which it provides electric transmission and electric and gas distribution services to residential, commercial and industrial customers in New Jersey. The rates charged for electric transmission are regulated by FERC while the rates charged for electric and gas distribution are regulated by the BPU. Revenues are also earned from several other activities such as sundry sales, the appliance service business, wholesale transmission services and other miscellaneous services.

Energy Holdings

Energy Holdings earns revenues from its solar generation projects and its portfolio of passive investments primarily consisting of domestic leveraged leases. Gains and losses on sales of the lease investments are typically recognized in revenues. Energy Holdings also has equity method generation projects. Earnings from these projects are presented below Operating Income.

Other

Other activities include amounts applicable to PSEG (parent corporation), Services and intercompany eliminations, primarily relating to intercompany transactions between Power and PSE&G. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between Power and PSE&G, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between Power and PSE&G, see Note 23. Related-Party Transactions. The net losses primarily relate to financing and certain administrative and general costs.

181

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Power		PSE&G		Energy Holdings			Other			Consolidated Total
	Millions
For the Year Ended December 31, 2011:
Operating Revenues	$	6,143	$	7,326	$	(140	)	$	(2,250	)	$	11,079
Depreciation and Amortization		224		719		15			18			976
Operating Income (Loss)		1,771		1,151		(197	)		17			2,742
Income from Equity Method Investments		0		0		4			0			4
Interest Income		4		12		2			1			19
Interest Expense		175		310		3			(13	)		475
Income (Loss) before Income Taxes		1,687		861		(193	)		29			2,384
Income Tax Expense (Benefit)		685		340		(59	)		11			977
Income (Loss) from Continuing Operations		1,002		521		(134	)		18			1,407
Income from Discontinued Operations, net of tax		96		0		0			0			96
Net Income (Loss)		1,098		521		(134	)		18			1,503
Segment Earnings (Loss)		1,098		521		(134	)		18			1,503
Gross Additions to Long-Lived Assets	$	757	$	1,302	$	4		$	20		$	2,083
As of December 31, 2011:
Total Assets	$	11,087	$	17,487	$	1,888		$	(641	)	$	29,821
Investments in Equity Method Subsidiaries	$	31	$	0	$	106		$	0		$	137

	Power		PSE&G		Energy Holdings		Other			Consolidated Total
	Millions
For the Year Ended December 31, 2010:
Operating Revenues	$	6,558	$	7,869	$	137	$	(2,771	)	$	11,793
Depreciation and Amortization		175		750		14		16			955
Operating Income (Loss)		1,963		886		81		7			2,937
Income from Equity Method Investments		0		0		4		0			4
Interest Income		3		7		2		8			20
Interest Expense		157		318		11		(14	)		472
Income (Loss) before Income Taxes		1,914		591		86		25			2,616
Income Tax Expense (Benefit)		778		232		37		12			1,059
Income (Loss) from Continuing Operations		1,136		359		49		13			1,557
Income from Discontinued Operations, net of tax		7		0		0		0			7
Net Income (Loss)		1,143		359		49		13			1,564
Segment Earnings (Loss)		1,143		358		49		14			1,564
Gross Additions to Long-Lived Assets	$	825	$	1,257	$	63	$	15		$	2,160
As of December 31, 2010:
Total Assets	$	11,452	$	16,873	$	2,234	$	(650	)	$	29,909
Investments in Equity Method Subsidiaries	$	25	$	0	$	105	$	0		$	130

182

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Power			PSE&G		Energy Holdings		Other			Consolidated Total
	Millions
For the Year Ended December 31, 2009:
Operating Revenues	$	6,772		$	8,243	$	221	$	(3,201	)	$	12,035
Depreciation and Amortization		184			608		11		16			819
Operating Income (Loss)		2,081			858		163		14			3,116
Income from Equity Method Investments		0			0		17		0			17
Interest Income		6			2		5		(6	)		7
Interest Expense		161			312		37		11			521
Income (Loss) before Income Taxes		1,958			551		117		10			2,636
Income Tax Expense (Benefit)		767			226		45		4			1,042
Income (Loss) from Continuing Operations		1,191			325		72		6			1,594
Loss from Discontinued Operations, net of tax		(2	)		0		0		0			(2	)
Net Income (Loss)		1,189			325		72		6			1,592
Segment Earnings (Loss)		1,189			321		72		10			1,592
Gross Additions to Long-Lived Assets	$	869		$	855	$	62	$	8		$	1,794

Note 23. Related-Party Transactions

The majority of the following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP.

Power

The financial statements for Power include transactions with related parties presented as follows:

	Years Ended December 31,
Related Party Transactions	2011			2010			2009
	Millions
Revenue from Affiliates:
Billings to PSE&G through BGSS(A)	$	1,294		$	1,591		$	1,838
Billings to PSE&G through BGS(A)		921			1,139			1,322
Total Revenue from Affiliates	$	2,215		$	2,730		$	3,160
Expense Billings from Affiliates:
Administrative Billings from Services(B)	$	(147	)	$	(145	)	$	(153	)
Total Expense Billings from Affiliates	$	(147	)	$	(145	)	$	(153	)

183

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Years Ended December 31,
Related Party Transactions	2011			2010
	Millions
Receivables from PSE&G through BGS and BGSS Contracts(A)	$	247		$	372
Receivables from PSE&G Related to Gas Supply Hedges for BGSS(A)		109			58
Receivable from (Payable to) Services(B)		(26	)		(26	)
Tax Receivable from (Payable to) PSEG(C)		58			381
Receivable from (Payable to) PSEG		(7	)		(3	)
Accounts Receivable (Payable)—Affiliated Companies, net	$	381		$	782
Short-Term Loan to (from) Affiliate (demand Note to (from) PSEG)(D)	$	907		$	398
Working Capital Advances to Services(E)	$	17		$	17
Long-Term Accrued Taxes Receivable (Payable)(C)	$	(8	)	$	16

PSE&G

The financial statements for PSE&G include transactions with related parties presented as follows:

	Years Ended December 31,
Related Party Transactions	2011			2010			2009
	Millions
Expense Billings from Affiliates:
Billings from Power through BGSS(A)	$	(1,294	)	$	(1,591	)	$	(1,838	)
Billings from Power through BGS(A)		(921	)		(1,139	)		(1,322	)
Administrative Billings from Services(B)		(210	)		(206	)		(240	)
Total Expense Billings from Affiliates	$	(2,425	)	$	(2,936	)	$	(3,400	)

	Years Ended December 31,
Related Party Transactions	2011			2010
	Millions
Payable to Power through BGS and BGSS Contracts(A)	$	(247	)	$	(372	)
Payable to Power Related to Gas Supply Hedges for BGSS(A)		(109	)		(58	)
Payable to Power from SREC Liability(F)		(7	)		(7	)
Receivable from (Payable to) Services(B)		(56	)		(48	)
Tax Receivable from (Payable to) PSEG(C)		131			394
Receivable from (Payable to) PSEG		8			6
Accounts Receivable (Payable)—Affiliated Companies, net	$	(280	)	$	(85	)
Working Capital Advances to Services(E)	$	33		$	33
Long-Term Accrued Taxes Receivable (Payable)(C)	$	(83	)	$	(74	)

(A) PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements through March 31, 2012 and year-to-year thereafter. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process.

(B) Services provides and bills administrative services to Power and PSE&G at cost. In addition, Power and PSE&G have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies.

184

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(C) PSEG files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits.

(D) Power’s short-term loans with PSEG are for working capital and other short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial.

(E) Power and PSE&G have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on Power’s and PSE&G’s Consolidated Balance Sheets.

(F) In 2008, the BPU issued a decision that certain BGS suppliers will be reimbursed for the cost they incurred above $300 per Solar Renewable Energy Certificate (SREC) during the period June 1, 2008 through May 31, 2010. The BPU order further provided that the excess cost may be passed on to ratepayers. Following an appeal, on March 10, 2011, the New Jersey Supreme Court reversed and remanded the BPU’s 2008 order. The Court did not rule on the substantive issue of whether the pass-through of SREC costs was appropriate. The BPU subsequently held a legislative hearing process to comply with the Court’s ruling. PSE&G, along with other New Jersey utilities and Power participated at the hearing and filed comments. The BPU has not yet issued a decision. PSE&G has estimated and accrued a total liability for the excess SREC cost of $17 million as of December 31, 2011 and 2010, including approximately $7 million for Power’s share which is included in PSE&G’s Accounts Payable—Affiliated Companies as of December 31, 2011 and 2010. Under current guidance, Power is unable to record the related intercompany receivable on its Consolidated Balance Sheet. As a result, PSE&G’s liability to Power is not eliminated in consolidation and is included in Other Current Liabilities on PSEG’s Consolidated Balance Sheet as of December 31, 2011 and 2010.

185

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 24. Selected Quarterly Data (Unaudited)

The information shown in the following tables, in the opinion of PSEG, Power and PSE&G includes all adjustments, consisting only of normal recurring accruals, necessary to fairly present such amounts.

	Quarter Ended
	March 31,					June 30,				September 30,				December 31,
	2011		2010			2011		2010		2011		2010		2011		2010
PSEG Consolidated:	Millions
Operating Revenues	$	3,354	$	3,573		$	2,469	$	2,361	$	2,620	$	3,114	$	2,636	$	2,745
Operating Income	$	856	$	946		$	621	$	431	$	556	$	971	$	709	$	589
Income (Loss) from Continuing Operations	$	462	$	498		$	320	$	222	$	265	$	547	$	360	$	290
Income (Loss) from Discontinued Operations, including Gain (Loss) on Disposal, net of tax	$	64	$	(7	)	$	3	$	2	$	29	$	20	$	0	$	(8	)
Net Income (Loss)	$	526	$	491		$	323	$	224	$	294	$	567	$	360	$	282
Earnings Per Share:
Basic:
Income (Loss) from Continuing Operations	$	0.91	$	0.99		$	0.63	$	0.44	$	0.52	$	1.08	$	0.71	$	0.57
Net Income (Loss)	$	1.04	$	0.97		$	0.63	$	0.44	$	0.58	$	1.12	$	0.71	$	0.56
Diluted:
Income (Loss) from Continuing Operations	$	0.91	$	0.99		$	0.63	$	0.44	$	0.52	$	1.08	$	0.71	$	0.57
Net Income (Loss)	$	1.04	$	0.97		$	0.63	$	0.44	$	0.58	$	1.12	$	0.71	$	0.56
Weighted Average Common Shares Outstanding:
Basic		506		506			506		506		506		506		506		506
Diluted		507		507			507		507		507		507		507		507

	Quarter Ended
	March 31,					June 30,				September 30,				December 31,
	2011		2010			2011		2010		2011		2010		2011		2010
Power:	Millions
Operating Revenues	$	1,967	$	2,196		$	1,285	$	1,264	$	1,398	$	1,523	$	1,493	$	1,575
Operating Income	$	501	$	651		$	355	$	348	$	483	$	607	$	432	$	357
Income (Loss) from Continuing Operations	$	298	$	371		$	205	$	202	$	273	$	364	$	226	$	199
Income (Loss) from Discontinued Operations, including Gain (Loss) on Disposal, net of tax	$	64	$	(7	)	$	3	$	2	$	29	$	20	$	0	$	(8	)
Net Income (Loss)	$	362	$	364		$	208	$	204	$	302	$	384	$	226	$	191

	Quarter Ended
	March 31,				June 30,				September 30,				December 31,
	2011		2010		2011		2010		2011		2010		2011		2010
PSE&G:	Millions
Operating Revenues	$	2,306	$	2,444	$	1,571	$	1,536	$	1,841	$	2,007	$	1,608	$	1,882
Operating Income	$	350	$	271	$	252	$	71	$	328	$	325	$	221	$	219
Income (Loss) from Continuing Operations	$	163	$	118	$	105	$	3	$	154	$	155	$	99	$	83
Net Income (Loss)	$	163	$	118	$	105	$	3	$	154	$	155	$	99	$	83
Earnings Available to PSEG	$	163	$	117	$	105	$	3	$	154	$	155	$	99	$	83

186

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 25. Guarantees of Debt

Power’s Senior Notes are fully and unconditionally and jointly and severally guaranteed by its subsidiaries, PSEG Fossil LLC, PSEG Nuclear LLC and PSEG Energy Resources & Trade LLC. The following table presents financial information for the guarantor subsidiaries as well as Power’s non-guarantor subsidiaries as of December 31, 2011 and 2010 and for the years ended December 31, 2011, 2010 and 2009.

	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
For the Year Ended December 31, 2011:
Operating Revenues	$	0		$	7,452		$	146		$	(1,455	)	$	6,143
Operating Expenses		5			5,673			150			(1,456	)		4,372
Operating Income (Loss)		(5	)		1,779			(4	)		1			1,771
Equity Earnings (Losses) of Subsidiaries		1,175			92			0			(1,267	)		0
Other Income		40			195			0			(45	)		190
Other Deductions		(28	)		(51	)		0			0			(79	)
Other-Than-Temporary Investments		(1	)		(19	)		0			0			(20	)
Interest Expense		(146	)		(56	)		(18	)		45			(175	)
Income Tax Benefit (Expense)		63			(762	)		14			0			(685	)
Income (Loss) on Discontinued Operations, net of Tax Benefit		0			0			97			(1	)		96
Net Income (Loss)	$	1,098		$	1,178		$	89		$	(1,267	)	$	1,098
As of December 31, 2011:
Current Assets	$	4,311		$	7,248		$	951		$	(9,823	)	$	2,687
Property, Plant and Equipment, net		66			5,715			950			0			6,731
Investment in Subsidiaries		4,185			804			0			(4,989	)		0
Noncurrent Assets		179			1,557			51			(118	)		1,669
Total Assets	$	8,741		$	15,324		$	1,952		$	(14,930	)	$	11,087
Current Liabilities	$	172		$	9,549		$	1,003		$	(9,822	)	$	902
Noncurrent Liabilities		440			1,589			145			(118	)		2,056
Long-Term Debt		2,685			0			0			0			2,685
Member’s Equity		5,444			4,186			804			(4,990	)		5,444
Total Liabilities and Member’s Equity	$	8,741		$	15,324		$	1,952		$	(14,930	)	$	11,087
For the Year Ended December 31, 2011:
Net Cash Provided By (Used In) Operating Activities	$	609		$	2,427		$	(284	)	$	(940	)	$	1,812
Net Cash Provided By (Used In) Investing Activities	$	596		$	(1,171	)	$	594		$	(597	)	$	(578	)
Net Cash Provided By (Used In) Financing Activities	$	(1,205	)	$	(1,256	)	$	(309	)	$	1,537		$	(1,233	)

187

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
For the Year Ended December 31, 2010:
Operating Revenues	$	0		$	7,746		$	125		$	(1,313	)	$	6,558
Operating Expenses		9			5,760			139			(1,313	)		4,595
Operating Income (Loss)		(9	)		1,986			(14	)		0			1,963
Equity Earnings (Losses) of Subsidiaries		1,182			(15	)		0			(1,167	)		0
Other Income		45			170			0			(45	)		170
Other Deductions		(4	)		(49	)		0			0			(53	)
Other-Than-Temporary Investments		0			(9	)		0			0			(9	)
Interest Expense		(113	)		(67	)		(22	)		45			(157	)
Income Tax Benefit (Expense)		42			(834	)		14			0			(778	)
Income (Loss) on Discontinued Operations, net of Tax Benefit		0			0			7			0			7
Net Income (Loss)	$	1,143		$	1,182		$	(15	)	$	(1,167	)	$	1,143
As of December 31, 2010:
Current Assets	$	3,988		$	6,807		$	1,117		$	(8,468	)	$	3,444
Property, Plant and Equipment, net		55			5,385			902			0			6,342
Investment in Subsidiaries		4,794			1,079			0			(5,873	)		0
Noncurrent Assets		170			1,549			41			(94	)		1,666
Total Assets	$	9,007		$	14,820		$	2,060		$	(14,435	)	$	11,452
Current Liabilities	$	751		$	8,519		$	849		$	(8,468	)	$	1,651
Noncurrent Liabilities		423			1,510			129			(93	)		1,969
Long-Term Debt		2,805			0			0			0			2,805
Member’s Equity		5,028			4,791			1,082			(5,874	)		5,027
Total Liabilities and Member’s Equity	$	9,007		$	14,820		$	2,060		$	(14,435	)	$	11,452
For the Year Ended December 31, 2010:
Net Cash Provided By (Used In) Operating Activities	$	467		$	2,249		$	28		$	(1,178	)	$	1,566
Net Cash Provided By (Used In) Investing Activities	$	(252	)	$	(1,567	)	$	(34	)	$	648		$	(1,205	)
Net Cash Provided By (Used In) Financing Activities	$	(216	)	$	(687	)	$	(40	)	$	529		$	(414	)

188

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
For the Year Ended December 31, 2009:
Operating Revenues	$	0		$	7,932		$	122		$	(1,282	)	$	6,772
Operating Expenses		4			5,846			125			(1,284	)		4,691
Operating Income (Loss)		(4	)		2,086			(3	)		2			2,081
Equity Earnings (Losses) of Subsidiaries		1,208			(20	)		0			(1,188	)		0
Other Income		57			256			1			(81	)		233
Other Deductions		(14	)		(120	)		0			(1	)		(135	)
Other-Than-Temporary Investments		0			(60	)		0			0			(60	)
Interest Expense		(145	)		(73	)		(23	)		80			(161	)
Income Tax Benefit (Expense)		87			(861	)		7			0			(767	)
Income (Loss) on Discontinued Operations, net of Tax Benefit		0			0			(2	)		0			(2	)
Net Income (Loss)	$	1,189		$	1,208		$	(20	)	$	(1,188	)	$	1,189
For the Year Ended December 31, 2009:
Net Cash Provided By (Used In) Operating Activities	$	383		$	2,520		$	10		$	(1,255	)	$	1,658
Net Cash Provided By (Used In) Investing Activities	$	490		$	(1,320	)	$	(50	)	$	228		$	(652	)
Net Cash Provided By (Used In) Financing Activities	$	(873	)	$	(1,202	)	$	66		$	1,027		$	(982	)

189

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

PSEG, Power and PSE&G

We have established and maintain disclosure controls and procedures as defined under Rule 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) that are designed to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported and is accumulated and communicated to the Chief Executive Officer and Chief Financial Officer of each respective company, as appropriate, by others within the entities to allow timely decisions regarding required disclosure. We have established a disclosure committee which includes several key management employees and which reports directly to the Chief Financial Officer and Chief Executive Officer of each respective company. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The Chief Financial Officer and Chief Executive Officer of each company have evaluated the effectiveness of the disclosure controls and procedures and, based on this evaluation, have concluded that disclosure controls and procedures at each respective company were effective at a reasonable assurance level as of the end of the period covered by the report.

Internal Controls

PSEG, Power and PSE&G

We have conducted assessments of our internal control over financial reporting as of December 31, 2011, as required by Section 404 of the Sarbanes-Oxley Act, using the framework promulgated by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. Management’s reports on PSEG’s, Power’s and PSE&G’s internal control over financial reporting are included on pages 191, 192 and 193, respectively. The Independent Registered Public Accounting Firm’s report with respect to the effectiveness of PSEG’s internal control over financial reporting is included on page 194. Management has concluded that internal control over financial reporting is effective as of December 31, 2011.

We continually review our disclosure controls and procedures and make changes, as necessary, to ensure the quality of their financial reporting. There have been no changes in internal control over financial reporting that occurred during the fourth quarter of 2011 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

190

MANAGEMENT REPORT ON INTERNAL CONTROL OVER

FINANCIAL REPORTING—PSEG

Management of Public Service Enterprise Group (PSEG) is responsible for establishing and maintaining effective internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the SEC in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and implemented by the company’s management and other personnel, with oversight by the Audit Committee of the Board of Directors to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles).

PSEG’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of PSEG’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of PSEG are being made only in accordance with authorizations of PSEG’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of PSEG’s assets that could have a material effect on the financial statements.

In connection with the preparation of PSEG’s annual financial statements, management of PSEG has undertaken an assessment, which includes the design and operational effectiveness of PSEG’s internal control over financial reporting using the framework promulgated by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. The COSO framework is based upon five integrated components of control: control environment, risk assessment, control activities, information and communications and ongoing monitoring.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Based on the assessment performed, management has concluded that PSEG’s internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of PSEG’s financial reporting and the preparation of its financial statements as of December 31, 2011 in accordance with generally accepted accounting principles. Further, management has not identified any material weaknesses in internal control over financial reporting as of December 31, 2011.

PSEG’s external auditors, Deloitte & Touche LLP, have audited PSEG’s financial statements for the year ended December 31, 2011 included in this annual report on Form 10-K and, as part of that audit, have issued a report on the effectiveness of PSEG’s internal control over financial reporting, a copy of which is included in this annual report on Form 10-K.

/S/ RALPH IZZO

Chief Executive Officer

/s/ CAROLINE DORSA

Chief Financial Officer

February 27, 2012

191

MANAGEMENT REPORT ON INTERNAL CONTROL OVER

FINANCIAL REPORTING—Power

Management of PSEG Power LLC (Power) is responsible for establishing and maintaining effective internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the SEC in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and implemented by the company’s management and other personnel, with oversight by the Audit Committee of the Board of Directors of its parent, Public Service Enterprise Group Incorporated, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles).

Power’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of Power’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of Power are being made only in accordance with authorizations of Power’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of Power’s assets that could have a material effect on the financial statements.

In connection with the preparation of Power’s annual financial statements, management of Power has undertaken an assessment, which includes the design and operational effectiveness of Power’s internal control over financial reporting using the framework promulgated by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. The COSO framework is based upon five integrated components of control: control environment, risk assessment, control activities, information and communications and ongoing monitoring.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Based on the assessment performed, management has concluded that Power’s internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of Power’s financial reporting and the preparation of its financial statements as of December 31, 2011 in accordance with generally accepted accounting principles. Further, management has not identified any material weaknesses in internal control over financial reporting as of December 31, 2011.

/s/ RALPH IZZO

Chief Executive Officer

/s/ CAROLINE DORSA

Chief Financial Officer

February 27, 2012

192

MANAGEMENT REPORT ON INTERNAL CONTROL OVER

FINANCIAL REPORTING—PSE&G

Management of Public Service Electric and Gas Company is responsible for establishing and maintaining effective internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the SEC in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and implemented by the company’s management and other personnel, with oversight by the Audit Committee of the Board of Directors of its parent, Public Service Enterprise Group Incorporated, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles).

PSE&G’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of PSE&G’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of PSE&G are being made only in accordance with authorizations of PSE&G’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of PSE&G’s assets that could have a material effect on the financial statements.

In connection with the preparation of PSE&G’s annual financial statements, management of PSE&G has undertaken an assessment, which includes the design and operational effectiveness of PSE&G’s internal control over financial reporting using the framework promulgated by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. The COSO framework is based upon five integrated components of control: control environment, risk assessment, control activities, information and communications and ongoing monitoring.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Based on the assessment performed, management has concluded that PSE&G’s internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of PSE&G’s financial reporting and the preparation of its financial statements as of December 31, 2011 in accordance with generally accepted accounting principles. Further, management has not identified any material weaknesses in internal control over financial reporting as of December 31, 2011.

/s/ RALPH IZZO

Chief Executive Officer

/s/ CAROLINE DORSA

Chief Financial Officer

February 27, 2012

193

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors of

Public Service Enterprise Group Incorporated:

We have audited the internal control over financial reporting of Public Service Enterprise Group Incorporated and subsidiaries (the “Company”) as of December 31, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control Over Financial Reporting-PSEG. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and consolidated financial statement schedule listed in the Index at Item 15(B)(a) as of and for the year ended December 31, 2011 of the Company and our report dated February 27, 2012 expressed an unqualified opinion on those consolidated financial statements and consolidated financial statement schedule.

/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey

February 27, 2012

194

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Executive Officers

PSEG

Name	Age as of December 31, 2011	Office	Effective Date First Elected to Present Position
Ralph Izzo	54	Chairman of the Board, President and Chief Executive Officer (PSEG)	April 2007 to present
		Chairman of the Board and Chief Executive Officer (Power)	April 2007 to present
		Chairman of the Board and Chief Executive Officer (PSE&G)	April 2007 to present
		Chairman of the Board and Chief Executive Officer (Energy Holdings)	April 2007 to present
		Chairman of the Board, President and Chief Executive Officer (Services)	January 2010 to present
		Chairman of the Board and Chief Executive Officer (Services)	April 2007 to January 2010
		President and Chief Operating Officer (PSEG)	October 2006 to March 2007
Caroline Dorsa	52	Executive Vice President and Chief Financial Officer (PSEG)	April 2009 to present
		Executive Vice President and Chief Financial Officer (Power)	April 2009 to present
		Executive Vice President and Chief Financial Officer (PSE&G)	April 2009 to present
		Chief Financial Officer (Energy Holdings)	April 2009 to present
		Executive Vice President and Chief Financial Officer (Services)	April 2009 to present
		Senior Vice President, Global Human Health Strategy and Integration (Merck and Co., Inc.)	January 2008 to April 2009
		Senior Vice President and Chief Financial Officer (Gilead Sciences, Inc.)	November 2007 to January 2008
		Senior Vice President and Chief Financial Officer (Avaya, Inc.)	February 2007 to November 2007
William Levis	55	President and Chief Operating Officer (Power)	June 2007 to present
		President and Chief Nuclear Officer (Nuclear)	January 2007 to October 2008
Ralph LaRossa	48	President and Chief Operating Officer (PSE&G)	October 2006 to present

195

Name	Age as of December 31, 2011	Office	Effective Date First Elected to Present Position
Derek M. DiRisio	47	Vice President and Controller (PSEG)	January 2007 to present
		Vice President and Controller (PSE&G)	January 2007 to present
		Vice President and Controller (Power)	January 2007 to present
		Vice President and Controller (Energy Holdings)	January 2007 to present
		Vice President and Controller (Services)	January 2007 to present
		Assistant Controller Enterprise (Services)	July 2004 to January 2007
Randall E. Mehrberg	56	President and Chief Operating Officer (Energy Holdings)	June 2009 to present
		Executive Vice President—Strategy and Development (Services)	April 2009 to present
		Executive Vice President—Planning and Strategy (Services)	September 2008 to April 2009
		Various positions, last being Executive Vice President, Chief Administrative Officer and Chief Legal Officer (Exelon Corporation)	2000 to June 2008
J.A. Bouknight, Jr.	67	Executive Vice President and General Counsel (PSEG)	January 2010 to present
		Executive Vice President and General Counsel (Power)	January 2010 to present
		Executive Vice President and General Counsel (PSE&G)	January 2010 to present
		Executive Vice President and General Counsel (Services)	January 2010 to present
		Partner, Steptoe & Johnson LLP	July 2008 to November 2009
		Executive Vice President and General Counsel (Edison International)	July 2005 to July 2008

Power and PSE&G

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

Directors

PSEG

The information required by Item 10 of Form 10-K with respect to (i) present directors of PSEG who are nominees for election as directors at PSEG’s 2012 Annual Meeting of Stockholders, and (ii) compliance with Section 16(a) of the Securities Exchange Act of 1934, as amended, is set forth under the headings ‘Election of Directors’ and “Section 16(a) Beneficial Ownership Reporting Compliance” in PSEG’s definitive Proxy Statement for such Annual Meeting of Stockholders, which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about March 2, 2012 and which information set forth under said heading is incorporated herein by this reference thereto.

196

Power and PSE&G

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

Code of Ethics

Our Standards of Integrity (Standards) is a code of ethics applicable to us and our subsidiaries. The Standards are an integral part of our business conduct compliance program and embody our commitment to conduct operations in accordance with the highest legal and ethical standards. The Standards apply to all of our directors and employees (including Power’s, PSE&G’s, Energy Holdings’ and Services’ respective principal executive officer, principal financial officer, principal accounting officer or Controller and persons performing similar functions). Each such person is responsible for understanding and complying with the Standards. The Standards are posted on our website, www.pseg.com/investor/governance. We will send you a copy on request.

The Standards establish a set of common expectations for behavior to which each employee must adhere in dealings with investors, customers, fellow employees, competitors, vendors, government officials, the media and all others who may associate their words and actions with us. The Standards have been developed to provide reasonable assurance that, in conducting our business, employees behave ethically and in accordance with the law and do not take advantage of investors, regulators or customers through manipulation, abuse of confidential information or misrepresentation of material facts.

We will post on our website, www.pseg.com/investor/governance:

• Any amendment (other than one that is technical, administrative or non-substantive) that we adopt to our Standards; and

• Any grant by us of a waiver from the Standards that applies to any director, principal executive officer, principal financial officer, principal accounting officer or Controller, or persons performing similar functions, for us or our direct subsidiaries noted above, and that relates to any element enumerated by the SEC.

In 2011, we did not grant any waivers to the Standards.

ITEM 11. EXECUTIVE COMPENSATION

PSEG

The information required by Item 11 of Form 10-K is set forth in PSEG’s definitive Proxy Statement for the 2012 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about March 2, 2012 and such information set forth under such heading is incorporated herein by this reference thereto.

Section 16 Beneficial Ownership Reporting Compliance

During 2011, none of our directors or executive officers was late in filing a Form 3, 4 or 5 in accordance with the requirements of Section 16(a) of the Securities Exchange Act of 1934, as amended, with regard to transactions involving our Common Stock, with the exception of Derek M. DiRisio, Vice President and Controller (who is not one of our NEOs). Mr. DiRisio filed one late report on Form 4 involving the sale of shares of our Common Stock due to our mandatory income tax withholding of shares earned by Mr. DiRisio upon the vesting and payment to him of restricted stock units awarded under the LTIP.

Power and PSE&G

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

197

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDERS MATTERS

PSEG

The information required by Item 12 of Form 10-K with respect to directors, executive officers and certain beneficial owners is set forth under the heading “Security Ownership of Directors, Management and Certain Beneficial Owners” in PSEG’s definitive Proxy Statement for the 2012 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 2, 2012, and such information set forth under such heading is incorporated herein by this reference thereto.

For information relating to securities authorized for issuance under equity compensation plans, see Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Power and PSE&G

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

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

PSEG

The information required by Item 13 of Form 10-K is set forth under the heading “Transactions with Related Persons” in PSEG’s definitive Proxy Statement for the 2012 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 2, 2012 and such information set forth under such heading is incorporated herein by this reference thereto.

Power and PSE&G

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

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by Item 14 of Form 10-K is set forth under the heading “Fees Billed to PSEG by Deloitte & Touche LLP for 2011 and 2010” in PSEG’s definitive Proxy Statement for the 2012 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 2, 2012. Such information set forth under such heading is incorporated herein by this reference hereto.

198

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(A) The following Financial Statements are filed as a part of this report:

a. Public Service Enterprise Group Incorporated’s Consolidated Balance Sheets as of December 31, 2011 and 2010 and the related Consolidated Statements of Operations, Cash Flows and Stockholders’ Equity for the three years ended December 31, 2011 on pages 89, 90, 88, 91 and 92, respectively.

b. PSEG Power LLC’s Consolidated Balance Sheets as of December 31, 2011 and 2010 and the related Consolidated Statements of Operations, Cash Flows and Capitalization and Member’s Equity for the three years ended December 31, 2011 on pages 94, 95, 93, 96 and 97, respectively.

c. Public Service Electric and Gas Company’s Consolidated Balance Sheets as of December 31, 2011 and 2010 and the related Consolidated Statements of Operations, Cash Flows and Common Stockholders’ Equity for the three years ended December 31, 2011 on pages 99, 100, 98, 101 and 102, respectively.

(B) The following documents are filed as a part of this report:

a. PSEG’s Financial Statement Schedules:

Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2011 (page 208).

b. Power’s Financial Statement Schedules:

Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2011 (page 209).

c. PSE&G’s Financial Statement Schedules:

Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2011 (page 209).

Schedules other than those listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.

(C) The following documents are filed as part of this report:

LIST OF EXHIBITS:

a.	PSEG:
3a	Certificate of Incorporation Public Service Enterprise Group Incorporated(1)
3b	By-Laws of Public Service Enterprise Group Incorporated effective November 17, 2009(2)
3c	Certificate of Amendment of Certificate of Incorporation of Public Service Enterprise Group Incorporated, effective April 23, 1987(3)
3d	Certificate of Amendment of Certificate of Incorporation of Public Service Enterprise Group Incorporated, effective April 20, 2007(4)
4a(1)	Indenture between Public Service Enterprise Group Incorporated and First Union National Bank (U.S. Bank National Association, successor), as Trustee, dated January 1, 1998 providing for Deferrable Interest Subordinated Debentures in Series (relating to Quarterly Preferred Securities)(5)
9	Inapplicable
10a(1)	Supplemental Executive Retirement Income Plan, effective as of May 31, 2011(6)

199

10a(2)	Retirement Income Reinstatement Plan for Non-Represented Employees as amended May 31, 2011(7)
10a(3)	Employment Agreement with William Levis dated December 8, 2006(8)
10a(4)	Amended and Restated 2007 Equity Compensation Plan for Outside Directors, effective July 19, 2011(9)
10a(5)	Employee Stock Purchase Plan(10)
10a(6)	Deferred Compensation Plan for Directors, amended July 19, 2011(11)
10a(7)	Deferred Compensation Plan for Certain Employees, amended November 1, 2011
10a(8)	1989 Long-Term Incentive Plan, as amended(13)
10a(9)	2001 Long-Term Incentive Plan(14)
10a(10)	Senior Management Incentive Compensation Plan(15)
10a(11)	Amended and Restated Key Executive Severance Plan, amended effective December 1, 2009(16)
10a(12)	Severance Agreement with Ralph Izzo dated December 16, 2008(17)
10a(13)	Employment Agreement with Randall Mehrberg dated June 30, 2008(18)
10a(14)	Employment Agreement with Caroline Dorsa dated March 11, 2009, as amended April 24, 2009(19)
10a(15)	Stock Plan for Outside Directors, as amended(20)
10a(16)	Compensation Plan for Outside Directors(21)
10a(17)	2004 Long-Term Incentive Plan, amended effective December 1, 2009(22)
10a(18)	Form of Advancement of Expenses Agreement with Outside Directors(23)
10a(19)	Equity Deferral Plan, effective November 1, 2011, amended December 9, 2011
10a(20)	Employment Agreement with J.A. Bouknight dated August 26, 2009
10a(21)	Amendment to Employment Agreement with Randall Mehrberg, dated May 3, 2011(73)
10a(22)	Amendment to Employment Agreement with Caroline Dorsa, dated July 12, 2011(74)
10a(23)	Amendment to Employment Agreement with Randall Mehrberg, dated June 8, 2011(75)
10a(24)	Amendment to Employment Agreement with William Levis, dated September 19, 2011(12)
11	Inapplicable
12	Computation of Ratios of Earnings to Fixed Charges
13	Inapplicable
16	Inapplicable
18	Inapplicable
21	Subsidiaries of the Registrant
22	Inapplicable
23	Consent of Independent Registered Public Accounting Firm
24	Inapplicable
31	Certification by Ralph Izzo, pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 (1934 Act)
31a	Certification by Caroline Dorsa, pursuant to Rules 13a-14 and 15d-14 of the 1934 Act

200

32	Certification by Ralph Izzo, pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
32a	Certification by Caroline Dorsa, pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Calculation Linkbase
101.LAB	XBRL Taxonomy Extension Labels Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Document
b.	Power:
3a	Certificate of Formation of PSEG Power LLC(24)
3b	PSEG Power LLC Limited Liability Company Agreement(25)
3c	Trust Agreement for PSEG Power Capital Trust I(26)
3d	Trust Agreement for PSEG Power Capital Trust II(27)
3e	Trust Agreement for PSEG Power Capital Trust III(28)
3f	Trust Agreement for PSEG Power Capital Trust IV(29)
3g	Trust Agreement for PSEG Power Capital Trust V(30)
4a	Indenture dated April 16, 2001 between and among PSEG Power, PSEG Fossil, PSEG Nuclear, PSEG Energy Resources & Trade and The Bank of New York Mellon and form of Subsidiary Guaranty included therein(31)
4b	First Supplemental Indenture, supplemental to Exhibit 4a, dated as of March 13, 2002(32)
10a(1)	Supplemental Executive Retirement Income Plan, effective as of May 31, 2011(6)
10a(2)	Retirement Income Reinstatement Plan for Non-Represented Employees, as amended May 31, 2011(7)
10a(3)	Employment Agreement with William Levis dated December 8, 2006(8)
10a(4)	Employee Stock Purchase Plan(10)
10a(5)	Deferred Compensation Plan for Certain Employees, amended November 1, 2011
10a(6)	1989 Long-Term Incentive Plan, as amended(13)
10a(7)	2001 Long-Term Incentive Plan(14)
10a(8)	Senior Management Incentive Compensation Plan(15)
10a(9)	Amended and Restated Key Executive Severance Plan, amended effective December 1, 2009(16)
10a(10)	Severance Agreement with Ralph Izzo dated December 16, 2008(17)
10a(11)	Employment Agreement with Caroline Dorsa dated March 11, 2009, as amended April 24, 2009(19)
10a(12)	2004 Long-Term Incentive Plan, amended effective December 1, 2009(22)
10a(19)	Equity Deferral Plan, effective November 1, 2011, amended December 9, 2011
10a(20)	Employment Agreement with J.A. Bouknight dated August 26, 2009
10a(21)	Amendment to Employment Agreement with Caroline Dorsa, dated July 12, 2011(74)
10a(22)	Amendment to Employment Agreement with William Levis, dated September 19, 2011(12)

201

11	Inapplicable
12a	Computation of Ratio of Earnings to Fixed Charges
13	Inapplicable
16	Inapplicable
18	Inapplicable
19	Inapplicable
23a	Consent of Independent Registered Public Accounting Firm
24	Inapplicable
31b	Certification by Ralph Izzo, pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
31c	Certification by Caroline Dorsa, pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
32b	Certification by Ralph Izzo, pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
32c	Certification by Caroline Dorsa, pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
c.	PSE&G
3a(1)	Restated Certificate of Incorporation of PSE&G(33)
3a(2)	Certificate of Amendment of Certificate of Restated Certificate of Incorporation of PSE&G filed February 18, 1987 with the State of New Jersey adopting limitations of liability provisions in accordance with an amendment to New Jersey Business Corporation Act(34)
3a(3)	Certificate of Amendment of Restated Certificate of Incorporation of PSE&G filed June 17, 1992 with the State of New Jersey, establishing the 7.44% Cumulative Preferred Stock ($100 Par) as a series of Preferred Stock(35)
3a(4)	Certificate of Amendment of Restated Certificate of Incorporation of PSE&G filed March 11, 1993 with the State of New Jersey, establishing the 5.97% Cumulative Preferred Stock ($100 Par) as a series of Preferred Stock(36)
3a(5)	Certificate of Amendment of Restated Certificate of Incorporation of PSE&G filed January 27, 1995 with the State of New Jersey, establishing the 6.92% Cumulative Preferred Stock ($100 Par) and the 6.75% Cumulative Preferred Stock—$25 Par as series of Preferred Stock(37)
3b(1)	By-Laws of PSE&G as in effect April 17, 2007(38)
4a(1)	Indenture between PSE&G and Fidelity Union Trust Company (now, Wachovia Bank, National Association), as Trustee, dated August 1, 1924(39), securing First and Refunding Mortgage Bond and Supplemental Indentures between PSE&G and U.S. Bank National Association, successor, as Trustee, supplemental to Exhibit 4a(1), dated as follows:
4a(2)	April 1, 1927(40)
4a(3)	June 1, 1937(41)
4a(4)	July 1, 1937(42)
4a(5)	December 19, 1939(43)
4a(6)	March 1, 1942(44)
4a(7)	June 1, 1991 (No. 1)(45)
4a(8)	July 1, 1993(46)
4a(9)	September 1, 1993(47)
4a(10)	February 1, 1994(48)

202

4a(11)	March 1, 1994 (No. 2)(49)
4a(12)	May 1, 1994(50)
4a(13)	October 1, 1994 (No. 2)(51)
4a(14)	January 1, 1996 (No. 1)(52)
4a(15)	January 1, 1996 (No. 2)(53)
4a(16)	May 1, 1998(54)
4a(17)	September 1, 2002(55)
4a(18)	August 1, 2003(56)
4a(19)	December 1, 2003 (No. 1)(57)
4a(20)	December 1, 2003 (No. 2)(58)
4a(21)	December 1, 2003 (No. 3)(59)
4a(22)	December 1, 2003 (No. 4)(60)
4a(23)	June 1, 2004(61)
4a(24)	August 1, 2004 (No. 1)(62)
4a(25)	August 1, 2004 (No. 2)(63)
4a(26)	August 1, 2004 (No. 3)(64)
4a(27)	August 1, 2004 (No. 4)(65)
4a(28)	April 1, 2007(66)
4a(29)	November 1, 2008(67)
4a(30)	November 1, 2009(68)
4a(31)	October 1, 2010(69)
4b	Indenture of Trust between PSE&G and Chase Manhattan Bank (National Association) (The Bank of New York Mellon, successor), as Trustee, providing for Secured Medium-Term Notes dated July 1, 1993(70)
4c	Indenture dated as of December 1, 2000 between Public Service Electric and Gas Company and First Union National Bank (U.S. Bank National Association, successor), as Trustee, providing for Senior Debt Securities(71)
10a(1)	Supplemental Executive Retirement Income Plan, effective as of May 31, 2011(6)
10a(2)	Retirement Income Reinstatement Plan for Non-Represented Employees, as amended May 31, 2011(7)
10a(3)	Amended and Restated 2007 Equity Compensation Plan for Outside Directors, effective July 19, 2011(9)
10a(4)	Employee Stock Purchase Plan(10)
10a(5)	Deferred Compensation Plan for Directors, amended July 19, 2011(11)
10a(6)	Deferred Compensation Plan for Certain Employees, amended November 1, 2001
10a(7)	1989 Long-Term Incentive Plan, as amended(13)
10a(8)	2001 Long-Term Incentive Plan(14)

203

10a(9)	Senior Management Incentive Compensation Plan(15)
10a(10)	Amended and Restated Key Executive Severance Plan, amended effective December 1, 2009(16)
10a(11)	Severance Agreement with Ralph Izzo dated December 16, 2008(17)
10a(12)	Employment Agreement with Caroline Dorsa dated March 11, 2009, as amended April 24, 2009(19)
10a(13)	Stock Plan for Outside Directors, as amended(20)
10a(14)	Compensation Plan for Outside Directors(21)
10a(15)	2004 Long-Term Incentive Plan, amended effective December 1, 2009(22)
10a(16)	Form of Advancement of Expenses Agreement with Outside Directors(72)
10a(19)	Equity Deferral Plan, effective November 1, 2011, amended December 9, 2011
10a(20)	Employment Agreement with J. A Bouknight dated August 26, 2009
10a(21)	Amendment to Employment agreement with Caroline Dorsa, dated July 12, 2011(74)
11	Inapplicable
12b	Computation of Ratios of Earnings to Fixed Charges
12c	Computation of Ratios of Earnings to Fixed Charges Plus Preferred Stock Dividend Requirements
13	Inapplicable
16	Inapplicable
18	Inapplicable
19	Inapplicable
23b	Consent of Independent Registered Public Accounting Firm
24	Inapplicable
31d	Certification by Ralph Izzo, pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
31e	Certification by Caroline Dorsa, pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
32d	Certification by Ralph Izzo, pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
32e	Certification by Caroline Dorsa, pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code

(1) Filed as Exhibit 3.1a with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120 on May 4, 2007 and incorporated herein by this reference.

(2) Filed as Exhibit 3.1 with Current Report on Form 8-K, File No. 001-09120 on November 18, 2009 and incorporated herein by this reference.

(3) Filed as Exhibit 3.1b with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120 on May 4, 2007 and incorporated herein by this reference.

(4) Filed as Exhibit 3.1c with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120 on May 4, 2007 and incorporated herein by this reference.

(5) Filed as Exhibit 4(f) with Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, File No. 001-09120 on May 13, 1998 and incorporated herein by this reference.

(6) Filed as Exhibit 10.1 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, File No. 001-09120 on November 1, 2011 and incorporated herein by this reference.

(7) Filed as Exhibit 10.2 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, File No. 001-09120 on November 1, 2011 and incorporated herein by this reference.

(8) Filed as Exhibit 10a(4) with Annual Report on Form 10-K for the year ended December 31, 2007, File Nos. 001-09120 on February 28, 2008 and 000-49614, and incorporated herein by reference.

204

(9) Filed as Exhibit 10.5 with Quarterly Report on Form 10-Q for the quarter ended September 20, 2011, File No. 001-09120 on November 1, 2011 and incorporated herein by this reference.

(10) Filed with Registration Statement on Form S-8, File No. 333-106330 filed on June 20, 2003 and incorporated herein by this reference.

(11) Filed as Exhibit 10.6 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, File No. 001-09120 on November 1, 2011 and incorporated herein by this reference.

(12) Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, File No. 001-09120 on November 1, 2011 and incorporated herein by this reference.

(13) Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, File No. 001-09120, on November 4, 2002 and incorporated herein by this reference.

(14) Filed as Exhibit 10a(7) with Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-09120, on March 6, 2001 and incorporated herein by this reference.

(15) Filed as Exhibit 10a(11) with Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-09120, on February 26, 2009 and incorporated herein by this reference.

(16) Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, File No. 001-09120 on May 5, 2011 and incorporated herein by this reference.

(17) Filed as Exhibit 99 with Current Report on Form 8-K, File Nos. 001-09120, 000-49614 and 001-00973 on December 22, 2008 and incorporated herein by this reference.

(18) Filed as Exhibit 10a(14) with Annual Report on Form 10-K, for the year ended December 31, 2009, File No. 001-09120 on February 25, 2010 and incorporated herein by reference.

(19) Filed as Exhibit 10 with Quarterly Report on Form 10-Q, File No. 001-00973 on May 6, 2009 and incorporated herein by reference.

(20) Filed as Exhibit 10a(17) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120, on February 26, 2003 and incorporated herein by this reference.

(21) Filed as Exhibit 10a(20) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120, on February 26, 2003 and incorporated herein by this reference.

(22) Filed as Exhibit 10.1 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, File No. 001-09120 on May 5, 2011 and incorporated herein by this reference.

(23) Filed as Exhibit 10.1 with Current Report on Form 8-K, File No. 001-09120 on February 19, 2009 and incorporated herein by reference.

(24) Filed as Exhibit 3.1 to Registration Statement on Form S-4, No. 333-69228 filed on September 10, 2001 and incorporated herein by this reference.

(25) Filed as Exhibit 3.2 to Registration Statement on Form S-4, No. 333-69228 filed on September 10, 2001 and incorporated herein by this reference.

(26) Filed as Exhibit 3.6 to Registration Statement on Form S-3, No. 333-105704 filed on May 30, 2003 and incorporated herein by this reference.

(27) Filed as Exhibit 3.7 to Registration Statement on Form S-3, No. 333-105704 filed on May 30, 2003 and incorporated herein by this reference.

(28) Filed as Exhibit 3.8 to Registration Statement on Form S-3, No. 333-105704 filed on May 30, 2003 and incorporated herein by this reference.

(29) Filed as Exhibit 3.9 to Registration Statement on Form S-3, No. 333-105704 filed on May 30, 2003 and incorporated herein by this reference.

(30) Filed as Exhibit 3.10 to Registration Statement on Form S-3, No. 333-105704 filed on May 30, 2003 and incorporated herein by this reference.

(31) Filed as Exhibit 4.1 to Registration Statement on Form S-4, No. 333-69228 filed on September 10, 2001 and incorporated herein by this reference.

(32) Filed as Exhibit 4.7 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, File No. 000-49614, on May 15, 2002 and incorporated herein by this reference.

205

(33) Filed as Exhibit 3(a) with Quarterly Report on Form 10-Q for the quarter ended June 30, 1986, File No. 001-00973, on August 28, 1986 and incorporated herein by this reference.

(34) Filed as Exhibit 3a(2) with Annual Report on Form 10-K for the year ended December 31, 1987, File No. 001-00973, on March 28, 1988 and incorporated herein by this reference.

(35) Filed as Exhibit 3a(3) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.

(36) Filed as Exhibit 3a(4) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.

(37) Filed as Exhibit 3a(5) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.

(38) Filed as Exhibit 3.3 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-00973 on May 4, 2007 and incorporated herein by this reference.

(39) Filed as Exhibit 4b(1) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(40) Filed as Exhibit 4b(2) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(41) Filed as Exhibit 4b(3) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(42) Filed as Exhibit 4b(4) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(43) Filed as Exhibit 4b(5) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(44) Filed as Exhibit 4b(6) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference.

(45) Filed as Exhibit 4 with Current Report on Form 8-A, File No. 001-00973 on June 1, 1991 and incorporated herein by this reference.

(46) Filed as Exhibit 4(i) with Current Report on Form 8-A, File No. 001-00973 on December 1, 1993 and incorporated herein by this reference.

(47) Filed as Exhibit 4 with Current Report on Form 8-A, File No. 001-00973 on December 1, 1993 and incorporated herein by this reference.

(48) Filed as Exhibit 4(i) with Current Report on Form 8-A, File No. 001-00973 on February 4, 1994 and incorporated herein by this reference.

(49) Filed as Exhibit 4 with Current Report on Form 8-A, File No. 001-00973 on March 15, 1994 and incorporated herein by this reference.

(50) Filed as Exhibit 4a(88) on Form 10-Q, File No. 001-00973 on November 8, 1994 and incorporated herein by this reference.

(51) Filed as Exhibit 4a(91) with Quarterly Report on Form 10-Q for the quarter ended September 30, 1994, File No. 001-00973, on November 8, 1994 and incorporated herein by this reference.

(52) Filed as Exhibit 4a(2) on Form 8-A, File No. 001-00973 on January 26, 1996 and incorporated herein by this reference.

(53) Filed as Exhibit 4a(3) on Form 8-A, File No. 001-00973 on January 26, 1996 and incorporated herein by this reference.

(54) Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on May 15, 1998 and incorporated herein by this reference.

(55) Filed as Exhibit 4a(97) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-00973 on February 25, 2003 and incorporated herein by this reference.

(56) Filed as Exhibit 4a(98) with Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-00973 on February 25, 2004 and incorporated herein by this reference.

206

(57) Filed as Exhibit 4a(99) with Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-00973 on February 25, 2004 and incorporated herein by this reference.

(58) Filed as Exhibit 4a(100) with Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-00973 on February 25, 2004 and incorporated herein by this reference.

(59) Filed as Exhibit 4a(101) with Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-00973 on February 25, 2004 and incorporated herein by this reference.

(60) Filed as Exhibit 4a(102) with Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-00973 on February 25, 2004 and incorporated herein by this reference.

(61) Filed as Exhibit 4 with Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File No. 001-00973 on August 3, 2004 and incorporated herein by this reference.

(62) Filed as Exhibit 4a(25) with Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-00973 on March 1, 2005 and incorporated herein by this reference.

(63) Filed as Exhibit 4a(26) with Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-00973 on March 1, 2005 and incorporated herein by this reference.

(64) Filed as Exhibit 4a(27) with Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-00973 on March 1, 2005 and incorporated herein by this reference.

(65) Filed as Exhibit 4a(28) with Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-00973 on March 1, 2005 and incorporated herein by this reference.

(66) Filed as Exhibit 4a(28) with Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-00973, on February 28, 2008 and incorporated herein by this reference.

(67) Filed as Exhibit 4a(29) with Annual Report on Form 10-K, for the year ended December 31, 2009, File No. 001-00973 on February 25, 2010 and incorporated herein by reference.

(68) Filed as Exhibit 4a(30) with Annual Report on Form 10-K, for the year ended December 31, 2009, File No. 001-00973 on February 25, 2010 and incorporated herein by reference.

(69) Filed as Exhibit 4 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, File No. 001-00973 on October 29, 2010 and incorporated herein by reference.

(70) Filed as Exhibit 4 with Current Report on Form 8-K, File No. 001-00973 on December 1, 1993 and incorporated herein by this reference.

(71) Filed as Exhibit 4.6 to Registration Statement on Form S-3, No. 333-76020 filed on December 27, 2001 and incorporated herein by this reference.

(72) Filed as Exhibit 10.2 with Current Report on Form 8-K, File No. 001-00973 on February 19, 2009 and incorporated herein by reference.

(73) Filed as Exhibit 10.2 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, File No. 001-09120 on May 5, 2011 and incorporated herein by this reference.

(74) Filed as Exhibit 10.1 with Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, File No. 001-09120 on August 3, 2011 and incorporated herein by this reference.

(75) Filed as Exhibit 10.2 with Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, File No. 001-09120 on August 3, 2011 and incorporated herein by this reference.

207

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED Schedule II—Valuation and Qualifying Accounts Years Ended December 31, 2011—December 31, 2009

Column A	Column B		Column C				Column D			Column E
			Additions
Description	Balance at Beginning of Period		Charged to cost and expenses		Charged to other accounts- describe		Deductions- describe			Balance at End of Period
	Millions
2011
Allowance for Doubtful Accounts	$	68	$	102	$	0	$	114	(A)	$	56
Materials and Supplies Valuation Reserve		4		2		0		3	(B)		3
2010
Allowance for Doubtful Accounts	$	79	$	99	$	0	$	110	(A)	$	68
Materials and Supplies Valuation Reserve		5		0		0		1	(B)		4
Other Valuation Allowances		8		0		0		8	(C)		0
2009
Allowance for Doubtful Accounts	$	66	$	110	$	0	$	97	(A)	$	79
Materials and Supplies Valuation Reserve		5		1		0		1	(B)		5
Other Valuation Allowances		8		0		0		0			8

(A) Accounts Receivable written off.

(B) Reduced reserve to appropriate level and to remove obsolete inventory.

(C) Valuation Allowance written off.

208

PSEG POWER LLC

Schedule II—Valuation and Qualifying Accounts Years Ended December 31, 2011—December 31, 2009

	Column A	Column B		Column C				Column D			Column E
				Additions
	Description	Balance at Beginning of Period		Charged to cost and expenses		Charged to other accounts- describe		Deductions- describe			Balance at End of Period
						Millions
2011
	Materials and Supplies Valuation Reserve	$	4	$	2	$	0	$	3	(A)	$	3
2010
	Materials and Supplies Valuation Reserve	$	5	$	0	$	0	$	1	(A)	$	4
2009
	Materials and Supplies Valuation Reserve	$	5	$	1	$	0	$	1	(A)	$	5

(A) Reduced reserve to appropriate level and to remove obsolete inventory.

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

Schedule II—Valuation and Qualifying Accounts

Years Ended December 31, 2011—December 31, 2009

	Column A	Column B		Column C				Column D			Column E
				Additions
	Description	Balance at Beginning of Period		Charged to cost and expenses		Charged to other accounts- describe		Deductions- describe			Balance at End of Period
						Millions
2011
	Allowance for Doubtful Accounts	$	67	$	102	$	0	$	113	(A)	$	56
2010
	Allowance for Doubtful Accounts	$	78	$	99	$	0	$	110	(A)	$	67
2009
	Allowance for Doubtful Accounts	$	65	$	109	$	0	$	96	(A)	$	78

(A) Accounts Receivable written off.

209

GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:

Term	Phrase/Description
Base load	Minimum amount of electric power delivered or required over a given period of time at a constant rate, this is the level of demand that is seen as a minimum during a 24-hour day
BGS	Basic Generation Service
	PSE&G is required to provide BGS for all customers in New Jersey who are not supplied by a TPS.
BGS-Fixed Price	Basic Generation Service-Fixed Price
	Seasonally adjusted fixed prices charged for a three-year term for electric supply service to smaller industrial and commercial customers and residential customers who are not supplied by a TPS
BGSS	Basic Gas Supply Service
	Mechanism approved by the BPU for NJ utilities to recover all commodity costs related to supplying gas to residential customers
BPU	New Jersey Board of Public Utilities
	Agency responsible for regulating pubic utilities doing business in New Jersey
Capacity	Amount of electricity that can be produced by a specific generating facility
Combined Cycle	A method of generation whereby electricity and process steam are produced from otherwise lost waste heat exiting from one or more combustion turbines. The exiting heat is routed to a conventional boiler or to a heat recovery steam generator for use by a steam turbine in the production of electricity
Competition Act	Electric Discount and Energy Competition Act
	New Jersey’s 1999 Electric Utility Restructuring Legislation
Congestion	Condition when the available capacity of a transmission line is being closely approached (or exceeded) by the electric power trying to go through it; at such times, alternative power line pathways (or local generators near the load) must be used instead
Deregulation	In the energy industry, the process by which regulated markets become competitive, giving customers the opportunity to choose their energy supplier
Distribution	The delivery of electricity to the retail customer’s home, business or industrial facility through low voltage distribution lines
EDC	Electric Distribution Company
	A company that owns the power lines and equipment necessary to deliver purchased electricity to the end user.
EMP	New Jersey Energy Master Plan
	Plan mandated by New Jersey statute to be developed by the BPU and other New Jersey policy-making agencies to ensure safe, secure and reasonably-priced energy supply, foster economic growth and development and protect the environment
Energy Holdings	PSEG Energy Holdings L.L.C.
EPA	U.S. Environmental Protection Agency
FASB	Financial Accounting Standards Board
	A private, not-for-profit organization whose primary purpose, as designated by the SEC, is to develop accounting standards for public companies in the U.S.

210

Term	Phrase/Description
FERC	U.S. Federal Energy Regulatory Commission
Forward contracts	A customized, non-exchange traded contract in which the buyer is obligated to deliver a specified amount of a commodity with a predetermined price formula on a specified future date, at which time payment is due in full
GAAP	Generally Accepted Accounting Principles
	Standard framework of guidelines issued by the FASB for financial accounting used in the U.S.
Greenhouse gas emissions	Gases (including carbon dioxide, methane, nitrous oxide, ozone, and chlorofluorocarbon) that trap the heat of the sun in the earth’s atmosphere, increasing the mean global surface temperature of the earth
Grid	A system of interconnected power lines and generators that is managed so that the generators are dispatched as needed to meet the electricity requirements of the customers connected to the grid at various points
Hedging	Entering into a contract or transaction designed to reduce exposure to various risks, such as changes in market prices
Hope Creek	Hope Creek Nuclear Generating Station
ISO	Independent System Operator
	An independent, regulated entity established to manage a regional electric transmission system in a non-discriminatory manner and to help ensure the safety and reliability of the bulk of the power system
ITC	Investment Tax Credit
	A credit against income taxes, usually computed as a percent of the cost of investment in certain types of assets
LCAPP	Long-Term Capacity Agreement Pilot Program
	A new program established in January 2011 which provides for up to 2,000 MW of subsidized base load or mid-merit electric power generation in New Jersey.
Lifeline Program	A New Jersey social program for utility assistance that offers $225 per year to persons who meet the eligibility requirements
Load	Amount of electric power delivered or required at any specific point or points on a system. The requirement originates at the energy-consuming equipment of consumers.
MBR	Market Based Rates
	Electric service prices determined in an open market system of supply and demand under which the price is set solely by agreement as to what a buyer will pay and a seller will accept
MGP	Manufactured Gas Plant
MTM	Mark-to-Market
	Valuation of a security, commodity or financial instrument to reflect current resale values
NDT	Nuclear Decommissioning Trust
NEO	Named Executive Officer
	A term under the SEC’s disclosure regulations designating a registrant’s Chief Executive Officer, Chief Financial Officer and three other highest paid decision making managers
ISO-NE	New England Power Pool
	An ISO comprised of an alliance of approximately 100 utility companies who manage and direct all major energy production and transmission in the New England states

211

Term	Phrase/Description
NJDEP	New Jersey Department of Environmental Protection
NRC	U.S. Nuclear Regulatory Commission
NUG	Non-Utility Generation
	Power produced by independent power producers, exempt wholesale generators and other companies that have been exempted from traditional utility regulation
Off peak	Periods of lower electrical demand
OPEB	Other Postretirement Benefits
	Benefits other than pensions payable to former employees
Outage	The period during which a generating unit, transmission line, or other facility is out of service due to scheduled (planned) or unscheduled maintenance
Peach Bottom	Peach Bottom Atomic Power Station
Peak load	A measure of the amount of electricity required to be delivered during periods of highest demand
PJM	PJM Interconnection, L.L.C.
	A regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 13 northeastern states and the District of Columbia
Power	PSEG Power LLC
Power Pool	An association of two or more interconnected electric systems having an agreement to coordinate operations and planning for improved reliability and efficiencies
PRP	Potentially Responsible Parties
PSE&G	Public Service Electric and Gas Company
PSEG	Public Service Enterprise Group Incorporated
Renewable Energy	Energy derived from resources that are regenerative or that can not be depleted (i.e. moving water (hydro, tidal and wave power), thermal gradients in ocean water, biomass, geothermal energy, solar energy, and wind energy)
Regulatory Asset	Costs deferred by a regulated utility company in accordance with SFAS 71
Regulatory Liability	Costs recognized by a regulated utility company in accordance with SFAS 71
RGGI	Regional Greenhouse Gas Initiative
	The first mandatory, market-based effort in the U. S. to reduce greenhouse gas emissions; states will sell emission allowances through auctions and invest proceeds in consumer benefits: energy efficiency, renewable energy, and other clean energy technologies
RMR	Reliability-Must-Run
	Designation of a power plant whose output is needed to maintain local reliability regardless of its operating cost or market price
RPM	Reliability Pricing Model
	A process for pricing generation capacity based on overall system reliability requirements; using multi-year forward auctions, participants could bid capacity in the form of generation, demand response, or transmission to meet reliability needs by location and/or an ISO market
Salem	Salem Nuclear Generating Station
SBC	Societal Benefits Charge

212

Term	Phrase/Description
SEC	U.S. Securities and Exchange Commission
Services	PSEG Services Corporation
Spill Act	New Jersey Spill Compensation and Control Act
TPS	Third Party Supplier

213

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
By:	/s/ RALPH IZZO
	Ralph Izzo
	Chairman of the Board, President and
	Chief Executive Officer

Date: February 27, 2012

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

Signature	Title	Date
/s/ RALPH IZZO Ralph Izzo	Chairman of the Board, President, Chief Executive Officer and Director (Principal Executive Officer)	February 27, 2012
/s/ CAROLINE DORSA Caroline Dorsa	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	February 27, 2012
/s/ DEREK M. DIRISIO Derek M. DiRisio	Vice President and Controller (Principal Accounting Officer)	February 27, 2012
/s/ ALBERT R. GAMPER, JR. Albert R. Gamper, Jr.	Director	February 27, 2012
/s/ CONRAD K. HARPER Conrad K. Harper	Director	February 27, 2012
/s/ WILLIAM V. HICKEY William V. Hickey	Director	February 27, 2012
/s/ SHIRLEY ANN JACKSON Shirley Ann Jackson	Director	February 27, 2012
/s/ DAVID LILLEY David Lilley	Director	February 27, 2012
/s/ THOMAS A. RENYI Thomas A. Renyi	Director	February 27, 2012
/s/ HAK CHEOL SHIN Hak Cheol Shin	Director	February 27, 2012
/s/ RICHARD J. SWIFT Richard J. Swift	Director	February 27, 2012

214

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

PSEG POWER LLC
By:	/s/ WILLIAM LEVIS
	William Levis
	President and
	Chief Operating Officer

Date: February 27, 2012

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

Signature	Title	Date
/s/ RALPH IZZO Ralph Izzo	Chairman of the Board and Chief Executive Officer and Director (Principal Executive Officer)	February 27, 2012
/s/ CAROLINE DORSA Caroline Dorsa	Executive Vice President and Chief Financial Officer and Director (Principal Financial Officer)	February 27, 2012
/s/ DEREK M. DIRISIO Derek M. DiRisio	Vice President and Controller (Principal Accounting Officer)	February 27, 2012
/s/ J.A. BOUKNIGHT, JR. J.A. Bouknight, Jr.	Director	February 27, 2012
/s/ WILLIAM LEVIS William Levis	Director	February 27, 2012
/s/ RANDALL E. MEHRBERG Randall E. Mehrberg	Director	February 27, 2012

215

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
By:	/s/ RALPH LAROSSA
	Ralph LaRossa
	President and Chief Operating Officer

Date: February 27, 2012

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

Signature	Title	Date
/s/ RALPH IZZO Ralph Izzo	Chairman of the Board and Chief Executive Officer and Director (Principal Executive Officer)	February 27, 2012
/s/ CAROLINE DORSA Caroline Dorsa	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	February 27, 2012
/s/ DEREK M. DIRISIO Derek M. DiRisio	Vice President and Controller (Principal Accounting Officer)	February 27, 2012
/s/ ALBERT R. GAMPER, JR. Albert R. Gamper, Jr.	Director	February 27, 2012
/s/ CONRAD K. HARPER Conrad K. Harper	Director	February 27, 2012
/s/ RICHARD J. SWIFT Richard J. Swift	Director	February 27, 2012

216

EXHIBIT INDEX

The following documents are filed as a part of this report:

a. PSEG:
Exhibit 10a(7)	Deferred Compensation Plan for Certain Employees, amended November 1, 2011
Exhibit 10a(19):	Equity Deferral Plan, effective November 1, 2011, amended December 9, 2011
Exhibit 10a(20):	Employment Agreement with J.A. Bouknight dated August 26, 2009
Exhibit 12:	Computation of Ratios of Earnings to Fixed Charges
Exhibit 21:	Subsidiaries of the Registrant
Exhibit 23:	Consent of Independent Registered Public Accounting Firm
Exhibit 31:	Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31a:	Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32:	Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32a:	Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:	XBRL Instance Document
Exhibit 101.SCH:	XBRL Taxonomy Extension Schema
Exhibit 101.CAL:	XBRL Taxonomy Calculation Linkbase
Exhibit 101.LAB:	XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:	XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:	XBRL Taxonomy Extension Definition Document
b. Power:
Exhibit 10a(5)	Deferred Compensation Plan for Certain Employees, amended November 1, 2011
Exhibit 10a(19):	Equity Deferral Plan, effective November 1, 2011, amended December 9, 2011
Exhibit 10a(20):	Employment Agreement with J.A. Bouknight dated August 26, 2009
Exhibit 12a:	Computation of Ratios of Earnings to Fixed Charges
Exhibit 23a:	Consent of Independent Registered Public Accounting Firm
Exhibit 31b:	Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31c:	Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32b:	Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32c:	Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:	XBRL Instance Document*
Exhibit 101.SCH:	XBRL Taxonomy Extension Schema*
Exhibit 101.CAL:	XBRL Taxonomy Calculation Linkbase*
Exhibit 101.LAB:	XBRL Taxonomy Extension Labels Linkbase*
Exhibit 101.PRE:	XBRL Taxonomy Extension Presentation Linkbase*
Exhibit 101.DEF:	XBRL Taxonomy Extension Definition Document*

217

c. PSE&G:
Exhibit 10a(6)	Deferred Compensation Plan for Certain Employees, amended November 1, 2011
Exhibit 10a(19):	Equity Deferral Plan, effective November 1, 2011, amended December 9, 2011
Exhibit 10a(20):	Employment Agreement with J.A. Bouknight dated August 26, 2009
Exhibit 12b:	Computation of Ratios of Earnings to Fixed Charges
Exhibit 12c:	Computation of Ratios of Earnings to Fixed Charges Plus Preferred Stock Dividend Requirements
Exhibit 23b:	Consent of Independent Registered Public Accounting Firm
Exhibit 31d:	Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31e:	Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32d:	Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32e:	Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:	XBRL Instance Document*
Exhibit 101.SCH:	XBRL Taxonomy Extension Schema*
Exhibit 101.CAL:	XBRL Taxonomy Calculation Linkbase*
Exhibit 101.LAB:	XBRL Taxonomy Extension Labels Linkbase*
Exhibit 101.PRE:	XBRL Taxonomy Extension Presentation Linkbase*
Exhibit 101.DEF:	XBRL Taxonomy Extension Definition Document*

* XBRL information is furnished, not filed.

218