PUBLIC SERVICE ENTERPRISE GROUP INC - Annual Report: 2012 (Form 10-K)

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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, 2012,

¨ 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
Public Service Electric and Gas Company	6 ³/4% Series VV, due 2016
	8%, due 2037
	5%, due 2037

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Securities registered pursuant to Section 12(g) of the Act:
Registrant		Title of Each Class
PSEG Power LLC		Limited Liability Company Membership Interest

Public Service Electric and Gas Company		Medium-Term Notes

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). 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 ¨
PSEG Power LLC	Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer x
Public Service Electric and Gas Company	Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer x

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, 2012 was $16,420,936,616 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, 2013 was 505,959,216.

As of January 31, 2013, 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 2013 Annual Meeting of Stockholders of Public Service Enterprise Group Incorporated, which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 8, 2013, as specified herein.

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TABLE OF CONTENTS



		Page
FORWARD-LOOKING STATEMENTS		ii
FILING FORMAT AND GLOSSARY		1
WHERE TO FIND MORE INFORMATION		1
PART I
Item 1.	Business	1
	Regulatory Issues	15
	Environmental Matters	23
	Segment Information	27
Item 1A.	Risk Factors	27
Item 1B.	Unresolved Staff Comments	35
Item 2.	Properties	35
Item 3.	Legal Proceedings	38
Item 4.	Mine Safety Disclosures	39
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	40
Item 6.	Selected Financial Data	42
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	43
	Overview of 2012 and Future Outlook	43
	Results of Operations	47
	Liquidity and Capital Resources	57
	Capital Requirements	61
	Off-Balance Sheet Arrangements	64
	Critical Accounting Estimates	64
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	68
Item 8.	Financial Statements and Supplementary Data	70
	Report of Independent Registered Public Accounting Firm	71
	Consolidated Financial Statements	74
	Notes to Consolidated Financial Statements
	Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies	92
	Note 2. Recent Accounting Standards	96
	Note 3. Variable Interest Entities	97
	Note 4. Discontinued Operations and Dispositions	97
	Note 5. Property, Plant and Equipment and Jointly-Owned Facilities	98
	Note 6. Regulatory Assets and Liabilities	100
	Note 7. Long-Term Investments	105
	Note 8. Financing Receivables	106
	Note 9. Available-for-Sale Securities	108
	Note 10. Goodwill and Other Intangibles	113
	Note 11. Asset Retirement Obligations (AROs)	113
	Note 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plans	114
	Note 13. Commitments and Contingent Liabilities	120
	Note 14. Schedule of Consolidated Debt	129
	Note 15. Schedule of Consolidated Capital Stock	135
	Note 16. Financial Risk Management Activities	136
	Note 17. Fair Value Measurements	142
	Note 18. Stock Based Compensation	149
	Note 19. Other Income and Deductions	153
	Note 20. Income Taxes	154
	Note 21. Earnings Per Share (EPS) and Dividends	163
	Note 22. Financial Information by Business Segment	163
	Note 23. Related-Party Transactions	166
	Note 24. Selected Quarterly Data (Unaudited)	167
	Note 25. Guarantees of Debt	169
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	172
Item 9A.	Controls and Procedures	172
Item 9B.	Other Information	172
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	177
Item 11.	Executive Compensation	179
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	179
Item 13.	Certain Relationships and Related Transactions, and Director Independence	180
Item 14.	Principal Accounting Fees and Services	180
PART IV
Item 15.	Exhibits and Financial Statement Schedules	180
	Schedule II - Valuation and Qualifying Accounts	189
	Glossary of Terms	191
	Signatures	194
	Exhibit Index	197

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FORWARD-LOOKING STATEMENTS

Certain of the matters discussed in this report constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management’s beliefs as well as assumptions made by and information currently available to management. When used herein, the words “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “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 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,


•	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,


•	any equipment failures, accidents, severe weather events or other incidents that impact our ability to provide safe and reliable service to our customers,


•	increase in competition in energy supply markets as well as competition for certain rate-based transmission projects,


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


•	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 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 expected consequences to, or effects on, us or our business prospects, financial condition or results of operations. Readers are cautioned not to place undue reliance on these forward-looking statements in making any investment decision. Forward-looking statements made in this report 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.

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FILING FORMAT AND GLOSSARY

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

Discussions throughout the document refer to PSEG and its direct operating subsidiaries, Power, PSE&G and PSEG Energy Holdings L.L.C. (Energy Holdings). Depending on the context of each section, references to “we,” “us,” and “our” relate to the specific company or companies being discussed. In addition, certain key acronyms and definitions are summarized in a glossary beginning on page 191.

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 other wholly owned subsidiary, provides us and these operating subsidiaries with certain management, administrative and general services at cost.

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 and energy trading 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 demand response and energy efficiency programs and invested in solar 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 primarily from its portfolio of lease investments and its solar generation projects.

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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

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 kilowatt hour (kWh) or dollars per megawatt hour (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 megawatt (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. This long-term contract was for an initial period which extended through March 31, 2012 and continues on a year-to-year basis thereafter, unless terminated by either party with a one year notice.

Approximately 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 13,226 MW of generation capacity located in the Northeast and Mid-Atlantic regions of the United States in some of the country’s largest and most developed electricity markets.

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


•	Generation Capacity

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 in October 2011. Unit 2 upgrades were completed in October 2012. The balance of work to ensure efficient operation is expected to be completed by 2014. Total expenditures through December 31, 2012 were $154 million.

Power has also approved the expenditure of $419 million for an extended power uprate of the Peach Bottom nuclear units. The uprate is expected to result in an increase in Power’s share of nominal capacity by approximately 130 MW. The uprate is expected to be in service in 2015 for Unit 2 and 2016 for Unit 3. Total expenditures through December 31, 2012 were $73 million.

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.

Our installed capacity utilizes a diverse mix of fuels: 45% gas, 28% nuclear, 18% coal, 8% oil and 1% pumped storage. This fuel diversity helps to mitigate risks associated with fuel price volatility and market demand cycles. Our total generating output in 2012 was approximately 53,000 gigawatt hours (GWh). The generation 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. The following table indicates the proportionate share of generating output by fuel type.

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Generation by Fuel Type	Actual 2012
Nuclear:
New Jersey facilities	39	%
Pennsylvania facilities	18	%
Fossil:
Coal:
Pennsylvania facilities	9	%
Connecticut facilities	—	%	(A)
Coal and Natural Gas:
New Jersey facilities	2	%
Oil and Natural Gas:
New Jersey facilities	23	%
New York facilities	9	%
Connecticut facilities	—	%	(A)
Total	100	%

(A) Less than one percent.


•	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 33% base load, 43% load following and 24% 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 run the most and typically 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 2012, our base load capacity factors were as follows:




Unit	2012 Capacity Factor
Nuclear
Salem Unit 1	95.2	%
Salem Unit 2	87.3	%
Hope Creek	89.8	%
Peach Bottom Unit 2	85.9	%
Peach Bottom Unit 3	99.0	%
Coal
Keystone	63.8	%
Conemaugh	71.3	%

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

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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.

The following chart depicts the merit order of dispatch of our units 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 size of each facility's fuel circle in the above chart illustrates the relative MW capacity of the generating capacity of that facility. For additional information on each of our generation facilities, see Item 2. Properties.

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.

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 following graphs which present historical annual spot prices and forward calendar prices as averaged over each year.

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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.

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.

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•	Coal Supply—Coal is the primary fuel for our Keystone, Conemaugh and Bridgeport stations. Coal is also used by Hudson and Mercer which operate on both coal and natural gas. We have coal 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, its 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. Management's Discussion and Analysis (MD&A)—Overview of 2012 and Future Outlook and Item 8. Financial Statements and Supplementary Data -Note 13. Commitments and Contingent Liabilities.

Markets and Market Pricing

Power’s generation 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 20% of the total United States population, and has a peak demand of over 163,848 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 33,939 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 greater 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 re-contract 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

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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 transparency 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 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
June 2015 to May 2016	$	167.46	$	61.12

For each delivery year, the prices differ in the various areas of PJM, depending on the constraints in each area of the transmission system. Keystone and Conemaugh receive 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 receive higher pricing.

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

Like PJM and ISO-NE, the NYISO provides capacity payments to its generating units, but unlike 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.

For additional information on the RPM and FCM markets, as well as on state subsidization through various mechanisms, 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:

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Load Zone ($/MWh)	2009-2012	2010-2013	2011-2014	2012-2015	2013-2016
PSE&G	$103.72	$95.77	$94.30	$83.88	$92.18
Jersey Central Power & Light	$103.51	$95.17	$92.56	$81.76	$83.70
Atlantic City Electric	$105.36	$98.56	$100.95	$85.10	$87.27
Rockland Electric Company	$112.70	$103.32	$106.84	$92.51	$92.58

We have obtained price certainty for all of our PJM and New England capacity through May 2016 through the RPM and FCM pricing mechanisms.

Although we enter into these hedges in an effort to provide price certainty for a large portion of our anticipated generation, there is 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 supplier to serve a percentage of the default load of a New Jersey electric distribution company (EDC), that is, the load that remains after some customers have chosen to be served directly by third party suppliers. The amount of power supplied through the BGS auction varies based on the level of the EDC'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 recent years, 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 6, 2013, we had contracted for the following percentages of our anticipated base load generation output for the next three years with modest amounts beyond 2015.




Base Load Generation	2013	2014	2015
Generation Sales	100%	80%-85%	40%-45%

Our strategy is to maintain certain levels of uranium in inventory and to make periodic purchases to support such levels. Our nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements for the three years. We also have various long-term fuel purchase commitments for coal to support our fossil generation stations. These purchase obligations are consistent with our 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.

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

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PSE&G

Our public utility, PSE&G, distributes electric energy and gas to customers within a designated service territory running diagonally across New Jersey where approximately 6.2 million people, or about 70% of New Jersey's population resides.

Products and Services

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


•	Transmission—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—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 portion of our utility business’ electric and gas sales is 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 increase the level of solar generation including:


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


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

We have also implemented a set of energy efficiency and demand response programs to encourage conservation and energy efficiency by providing energy and cost saving measures directly to businesses and families. For additional information concerning these programs and the components of our tariffs, see Regulatory Issues.

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How PSE&G Operates

We provide network transmission and point-to-point transmission services, which are coordinated with PJM, and provide distribution service to 2.2 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 three hundred suburban and rural communities.

Transmission

We use formula rates for our 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. 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, 2012
Network Circuit Miles	Billing Peak (MW)	Historical Annual Load Growth 2008-2012
1,461	10,470	0.4%

Distribution

The primary business of our utility 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 2012. We believe that we have all the franchise rights (including consents) necessary for our electric and gas distribution operations in the territory we serve.




	% of 2012 Sales
Customer Type	Electric		Gas
Commercial	57	%	36	%
Residential	33	%	60	%
Industrial	10	%	4	%
Total	100	%	100	%

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




Electric and Gas Distribution Statistics

	December 31, 2012
	Number of Customers		Electric Sales and Gas Sold and Transported		Historical Annual Load Decline 2008-2012
Electric	2.2	Million	41,641	GWh	(1.4)%
Gas	1.8	Million	3,397	Million Therms	(0.6)%

The decline in both electric and gas sales were impacted by the unfavorable winter weather experienced in 2012 and customer conservation as a result of the economy. The first six months of 2012 were the warmest first half of a year on record in the United States. Electric sales were also impacted by a decline in the Industrial sector.

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Solar Generation

We have undertaken major initiatives in order to spur investment in solar power in New Jersey. For additional details, please refer to our discussion under Energy Policy.

Supply

Although commodity revenues make up almost 48% of our revenues, we make no margin 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. Pursuant to the BPU requirements, we serve as the supplier of last resort for electric and gas customers within our service territory that 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 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 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 from our customers 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—Overview of 2012 and Future Outlook.

Energy Holdings

Energy Holdings primarily owns and manages a portfolio of lease investments and solar generation projects and is exploring opportunities for additional investment in renewable generation.

Over the past several years, we have terminated all of our international leveraged leases in order to reduce the cash tax exposure related to these leases. We have also reduced our risk by opportunistically monetizing all of our previous international investments. In February, 2012, the California Public Utilities Commission approved the shutdown 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 $840 million of domestic lease investments are primarily energy-related leveraged leases. As of December 31, 2012, 67% of our total leveraged lease investments were rated as below investment grade by Standard & Poor's.

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

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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, 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, Delaware, Florida, Ohio and Arizona totaling 69 MW. See Item 2. Properties for additional information.

In January 2012, we acquired a 25 MW solar project in Arizona. This project is currently in service. 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 was approximately $75 million.

In September 2012, we acquired a 15 MW solar project in Delaware. This project is currently in service. The project has a 20-year power purchase agreement for energy and the majority of renewable energy credits with a wholesale electric utility servicing municipal EDCs in Delaware. Energy Holdings has issued guarantees of up to $37 million for payment of obligations related to the construction of the project, of which $4 million was outstanding as of December 31, 2012. The total investment for the project was approximately $47 million.

In December 2012, we acquired an additional 19 MW solar project currently under construction in Arizona. The project is expected to begin commercial operation in the latter half of 2013. Energy Holdings has issued guarantees of up to $48 million for payment of obligations related to the construction of the project, all of which were outstanding as of December 31, 2012. The total investment for the project is expected to be approximately $51 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. 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, Operations Services Agreement (OSA), is scheduled to commence on January 1, 2014, following completion of the Transition Services Agreement (TSA). As part of the OSA, PSEG LI will be expected to develop and manage the implementation of 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. In November, 2012, the Governor of New York initiated an inquiry into the current structure of LIPA as a political subdivision of the State Of New York. The privatization of LIPA's transmission and distribution system is among the restructuring options under consideration. LIPA has the right under the OSA and the TSA to terminate each agreement, in the event that LIPA elects to either transfer its transmission and distribution system to a third party (privatization) or operate and maintain its transmission and distribution system with its own employees (municipalization). If LIPA elects to implement either of these options, LIPA is required to pay PSEG LI its service fees, milestone payments and wind-down expenses, in each case up to the effective date of such termination.

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.

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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, weather, 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 what types of transmission will be built, who is permitted to build transmission and who will pay the costs of future transmission could also impact our revenues.

We are also at risk if the states in which we operate take actions that interfere with competitive wholesale markets. For example, on January 28, 2011, New Jersey enacted a law 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 action 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.

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. If any new legislation were to require our competitors to meet the environmental standards currently imposed upon us, we would likely have an economic advantage since we have already installed significant pollution-control technology at most of our fossil stations.

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 proposed implementing changes to their respective regional transmission planning processes that may enable the construction of large amounts of “public policy” transmission to move renewable generation to load centers. For additional information, see the discussion in Regulatory Issues—Federal Regulation, below.

PSE&G

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 those ordered by the FERC and being implemented by PJM and other ISOs 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.

Construction of new local generation, such as the proposed subsidized generation in New Jersey and Maryland, 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, 2012, we had 9,798 employees within our subsidiaries, including 6,248 covered under collective bargaining agreements. During the fourth quarter of 2012, we reached agreements with four labor unions to extend their collective bargaining agreements for four years. Three of these agreements expire in April 2017 and one expires in October 2017. Collectively, these four unions represent approximately 80% of union employees of PSE&G, Power and Services. Our collective bargaining agreements with our other two unions are set to expire in April and May 2014, respectively. We believe we maintain satisfactory relationships with our employees.

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Employees as of December 31, 2012
	Power	PSE&G	Energy Holdings	Services
Non-Union	1,172	1,398	15	965
Union	1,442	4,797	—	9
Total Employees	2,614	6,195	15	974
Number of Union Groups	3	5	—	1

REGULATORY ISSUES

Federal Regulation

FERC

The 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. The FERC has extensive oversight over such “public utilities.” FERC approval is usually required when a public utility seeks to: sell or acquire an asset that is regulated by the 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.

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

The FERC also regulates Regional Transmission Operators/ISOs, such as PJM, and their energy and capacity markets.

For us, the major effects of the 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 the FERC for authority to make market based rate (MBR) sales. For a requesting company to receive MBR authority, the FERC must first make a determination that the requesting company lacks market power in the relevant markets and/or that market power in the relevant markets is sufficiently mitigated. The FERC requires that holders of MBR tariffs file an update every three years demonstrating that they continue to lack market power and/or that market power has been sufficiently mitigated and report in the interim to FERC any material change in facts from those the FERC relied on in granting MBR authority.

PSE&G, PSEG Energy Resources & Trade LLC, PSEG Power Connecticut, PSEG Fossil LLC and PSEG Nuclear LLC were each granted continued MBR authority from the FERC in June 2011. PSEG New Haven LLC was also granted initial MBR authority in May 2012. Retention of MBR authority is important to the maintenance of our current generation business’ revenues.

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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 market rules, bids are subject to price caps and mitigation rules applicable to certain generation units. The 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.

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. 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, including examining how demand response resources should be paid and how these resources and programs should be measured and verified to ensure their availability.

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 ruled in our favor and remanded the proceeding to the FERC where it remains pending. We and other generators also filed a complaint at the FERC regarding ISO-NE’s capacity market design, alleging that it insufficiently reflects locational capacity values. The FERC acted on the complaint, largely accepting the ISO-NE’s capacity market design; however, an appeal of this rule is pending.

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. NYISO is creating a third locality encompassing the lower Hudson Valley to take effect May 1, 2014. The exact configuration of this new zone has not yet been determined. The triennial process for updating demand curves used for establishing capacity prices is also underway. The NYISO is required to file with the FERC by the end of 2013 revised demand curves covering the May 1, 2014 through April 30, 2017 period. Discussions concerning other potential changes to NYISO capacity markets, including rules to govern payments and bidding requirements for generators proposing to exit the market but required to remain in service for reliability reasons, are also ongoing.

Long-Term Capacity Agreement Pilot Program Act (LCAPP)—In 2011, the State of New Jersey concluded that new natural gas-fired generation was needed and enacted the LCAPP Act to subsidize approximately 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 required each New Jersey EDC to provide the generators with guaranteed capacity payments funded by ratepayers. Each of the New Jersey EDCs, including PSE&G, entered into the SOCAs as directed by the State, but did so under protest reserving their rights. In May 2012, two of the three generators, CPV Shore, LLC (CPV), a subsidiary of Competitive Power Ventures, Inc. and Hess Newark, LLC (Hess), a subsidiary of Hess Corporation, that received SOCA contracts cleared the RPM auction for the 2015/2016 delivery year in the aggregate notional amount of approximately 1,300 MW of installed capacity.

Legal challenges to the BPU's implementation of the LCAPP Act were filed in New Jersey appellate court and the appeal remains pending. In addition, the LCAPP Act has been challenged on constitutional grounds in federal court. The hearing for this matter is scheduled to begin in March 2013.

Maryland is also taking action to subsidize above-market new generation. In April 2012, the Maryland Public Service Commission (PSC) issued an order requiring the Maryland utility companies to enter into a contract with CPV Shore, LLC (CPV) to build a new 661 MW natural gas-fired, combined cycle station in Maryland with an in-service date of June 2015. This contract has not yet been finalized, as the Maryland PSC continues to evaluate its terms. In the May 2012 RPM auction, the CPV generator cleared the auction. We have joined other generators in challenging this order on constitutional grounds in federal court and that case is set for hearing in March 2013. The Maryland EDCs have also appealed the April 2012 order in state court.

These efforts to artificially depress prices in the wholesale capacity auction were intended to be mitigated by the Minimum Offer Price Rule (MOPR) approved by the FERC. The MOPR was intended to 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 MOPR was in place for the May 2012 auction, but we believe it did

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not operate to protect the market against these suppression efforts given that two of the three SOCA generators cleared the auction. As a result, discussions among a diverse group of PJM stakeholders to improve the MOPR ensued and a settlement was reached among those stakeholders. That proposal was then subject to a PJM stakeholder review and vote. The proposal was modified and received almost a 90% supporting vote. In December 2012, PJM filed Tariff changes with the FERC to implement the revised MOPR. In February 2013, the FERC issued a deficiency letter to PJM seeking additional information regarding the proposed MOPR changes. PJM must respond to those changes within 30 days and then the FERC has 60 days to act on the proposal. If FERC approves the proposal, we believe these modifications should significantly improve the MOPR rules and appropriately reduce the ability for subsidized generation assets to artificially suppress wholesale market prices. We cannot predict the outcome of this matter.

Transmission Regulation

The 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. Our 2012 Annual Formula Rate Update with the FERC provided for approximately $94 million in increased annual transmission revenues effective January 1, 2012. We filed our 2013 Annual Formula Rate Update with the FERC in October 2012, which provides for approximately $174 million in increased annual transmission revenues effective January 1, 2013.

•

Transmission Policy Developments—In 2010, the FERC initiated a proceeding to evaluate whether reforms to current transmission planning and cost allocation rules were necessary to stimulate additional transmission development. The rulemaking also addressed the issue of whether construction of transmission should be opened up to competition by eliminating the “right of first refusal” (ROFR) under which incumbent transmission companies such as PSE&G have a ROFR to build transmission located within their respective service territories. The FERC ultimately concluded in Order No. 1000 that the ROFR should be eliminated, subject to certain exceptions, and left it to Regional Transmission Organizations/Independent System Operators such as PJM to establish the implementation details. We, along with many other companies, have challenged the FERC's orders in federal court. In addition, we have joined other PJM transmission owners in filing for the FERC approval of new rules that will determine who pays for future transmission projects in PJM.

We cannot predict the final outcome or impact on us; however, specific implementation of Order 1000 in the various regions, including within our service territory, may expose us to competition for certain types of transmission projects, while at the same time providing opportunities to build transmission outside of our service territory.

•

Transmission Expansion—In June 2007, PJM identified the need for the construction of the Susquehanna-Roseland line, a new 500 kiloVolt (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 up to $790 million, and PJM had originally directed that the line be placed into service by June 2012. As of December 31, 2012, total capital expenditures were $324 million. Construction of the Susquehanna-Roseland line is contingent upon obtaining all necessary federal, state, municipal and landowner permits and approvals. We have obtained environmental permits for the project from the New Jersey Department of Environmental Protection (NJDEP). On October 1, 2012, the National Park Service (NPS) issued a final Environmental Impact Statement (EIS) for the Susquehanna-Roseland line, selecting our and PPL's choice of route in certain federal park lands subject to the NPS' jurisdiction that follows the existing right of way. On October 15, 2012, several environmental groups filed a complaint in federal court, which, as amended, challenges the NPS' issuance of the final EIS, seeking to set aside the EIS and asking the court for an injunction that would generally prohibit construction of the project within the federal park lands at issue. If this request for injunctive relief is granted, the construction schedule for the project could be impacted. We have begun construction in those areas where necessary permits have been obtained. 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 cost of construction and the timing of expected transmission revenues.

Also, in 2010, certain environmental groups had appealed the BPU's approval of the Susquehanna-Roseland line, although no stay was sought. On February 11, 2013, the Appellate Division of the New Jersey Superior Court issued an order rejecting the appeal and affirming the BPU's approval of the project.

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We had previously been directed by PJM to build a 500 kV reliability project from Branchburg to Roseland to Hudson. The scope of this project has since changed; it is now a 230 kV project referred to as the Northeast Grid project, for which we are currently seeking to obtain municipal siting approvals. The Northeast Grid project has an expected in-service date of June 2015 and an estimated cost of construction of $895 million. As of December 31, 2012, total capital expenditures were $88 million.

In 2012, both the BPU and the NJDEP approved siting of the North Central Reliability project. This project, which involves upgrading certain circuits and switching stations from 138 kV to 230 kV in the northern and central portions of New Jersey, is estimated to cost up to $390 million and has an in-service date of June 2014. The project is currently under construction and, as of December 31, 2012, total capital expenditures for this project were $163 million.

In 2012, we received both municipal siting and the NJDEP approval for the Burlington-Camden project. The project, which also involves upgrading certain circuits and switching stations from 138 kV to 230 kV in the southern portion of New Jersey, is estimated to cost up to $399 million and has an in-service date of June 2014. The project is currently under construction. As of December 31, 2012, total capital expenditures for the project were $169 million.

We are still in the process of obtaining necessary municipal and environmental approvals for the Mickleton-Gloucester-Camden project. This is another project that involves converting both circuits and switching stations from 138 kV to 230 kV in southern New Jersey and is estimated to cost up to $435 million. The project has an in-service date of June 2015. This project is still in the engineering/design phase and, as of December 31, 2012, total capital expenditures were $24 million.

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Transmission Rate Proceedings—In September 2011, the Massachusetts Attorney General, along with several state utility commissions, consumer advocates and consumer groups from six New England states, filed a complaint at the FERC against a group of New England transmission owners seeking to reduce the base return on equity used in calculating these transmission owners' formula transmission rates. The matter has been set for hearing, and the proceeding is pending. In addition, there have been FERC complaints filed by municipal utilities in New York against a New York transmission-owning utility seeking to lower that utility's transmission ROE. While we are not the subject of any of these complaints. The results of these proceedings could set a precedent for the FERC-regulated transmission owners with formula rates in place, such as ours.

Compliance

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FERC Audit—Each of the PSEG companies that have MBR authority from the FERC is being audited by the FERC for compliance with its rules for (i) receiving and retaining MBR authority (ii) the filing of electric quarterly reports and (iii) our units' receipt of payments from the RTO/ISO when they are required to run for reliability reasons when it is not economic for them to do so. The FERC will issue a report at the conclusion of the audit.

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Reliability Standards—Congress has required the FERC to put in place, through the North American Electric Reliability Council (NERC), national and regional reliability standards to ensure the reliability of the United States 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 were audited in 2012. 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 accordance with the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), the SEC and the CFTC are in the process of implementing a new regulatory framework for swaps and security-based swaps. The legislation was enacted to reduce systemic risk, increase transparency and promote market integrity within the financial system by providing for the registration and comprehensive regulation of swap dealers and by imposing recordkeeping, data reporting, margin and clearing requirements with respect to swaps. To implement the Dodd-Frank Act, the CFTC has engaged in a comprehensive rulemaking process and has issued a number of proposed and final rules addressing many of the key issues. For example, the CFTC has issued rules defining the term “swap dealer” and “commercial end user” (We fall in the latter category). The CFTC also issued rules establishing position limits for trading in certain commodities, such as natural gas but a federal court vacated these rules. The CFTC has appealed this decision to vacate the position limits rules. We are currently preparing to comply with the new record keeping and data reporting requirements of the Dodd-Frank Act applicable to commercial end users, for compliance in April 2013. We are continuing to analyze the potential impact of these rules and preparing to comply with the requirements that apply to entities that are considered commercial end-users under the Dodd-Frank Act.

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Nuclear Regulatory Commission (NRC)

Our operation of nuclear generating facilities is subject to comprehensive regulation by the NRC, a federal agency established to regulate nuclear activities to ensure protection of public health and safety, as well as the security and protection of the environment. Such regulation involves testing, evaluation and modification of all aspects of plant operation in light of NRC safety and environmental requirements. Continuous demonstration to the NRC that plant operations meet requirements is also necessary. The NRC has the ultimate authority to determine whether any nuclear generating unit may operate. 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 (ESP) 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 a decision with respect to the issuance of the ESP in 2015. While the ESP qualifies the site as an approved location for a new reactor for a period of 20 years, it imposes no obligation to do so.

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

In 2011, the NRC task force submitted a report containing various recommendations to ensure plant protection, enhance accident mitigation, strengthen emergency preparedness and improve NRC program efficiency. The NRC staff also issued a document which provided for a prioritization of the task force recommendations. 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), to review 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 issued letters and orders to licensees implementing the Tier 1 recommendations in March 2012. Additional regulations are expected.

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 the petition

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. PSE&G's participation in solar, demand response and energy efficiency programs is also regulated by the BPU, as the terms and conditions of these programs are approved by the BPU. 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


•	Electric and Gas Base Rates—We must file electric and gas rate cases with the BPU in order to change our utility base distribution rates. Our last base rate adjustment was in 2010.

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Rate Adjustment Clauses and Other Regulatory Filings—In addition to base rates, we recover certain costs or earn on certain investments, from customers pursuant to mechanisms known as adjustment clauses. These clauses permit, at set intervals, the flow-through of costs to, or the recovery of investments from, customers related to specific programs, outside the context of base rate case proceedings. Recovery of these costs or investments is subject to BPU approval for which we make periodic filings. Delays in the pass-through of costs or recovery of investments under these mechanisms could result in significant changes in cash flow. For additional information on our specific filings, see Item 8. Financial Statements and Supplementary Data—Note 6. Regulatory Assets and Liabilities.

Some of our more significant recovery mechanisms and filings are as follows:

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Storm Damage Deferral—In December 2012, the BPU granted our request to defer on our books actually incurred, uninsured, incremental storm restoration costs to our gas and electric distribution systems associated with extraordinary storms, including Hurricane Irene and Superstorm Sandy. In February 2013, the BPU announced that it would initiate a generic proceeding to evaluate the prudency of extraordinary, storm-related costs incurred by all of the regulated utilities as a result of the natural disasters experienced in New Jersey in 2011 and 2012 and in this proceeding will consider the manner in which such prudent costs shall be recovered.

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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 reliability of our utility's infrastructure and New Jersey's economy through job creation. The programs allow us to receive a full return of and on our investments. In December 2012, the BPU approved stipulations regarding our CIP I and CIP II filings effective January 1, 2013. These Orders resulted in a combined increase of $40 million and $23 million for electric and gas customers, respectively.

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Weather Normalization Clause (WNC)—Our WNC is an annual rate mechanism that allows us to increase our rates to compensate for lower revenues we receive from customers as a result of warmer-than-normal winters and to decrease our rates to make up for higher revenues we receive as a result of colder-than-normal winters. The payments and refunds are subject to certain limitations and rate caps. Unrecovered balances associated with application of the rate cap are deferred until the next recovery period. This rate mechanism requires us to calculate, at the end of each October-to-May period, the level by which margin revenues differed from what would have resulted if normal weather had occurred. In June 2012, we filed a petition and testimony with the BPU including eight months of actual and four months of forecasted data, which sought BPU approval to recover $41 million in deficiency revenues from our customers during the 2012-2013 Winter Period (October 1 to May 31) and a carryover deficiency of $16 million to the 2013-2014 Winter Period. In September 2012, an Order approving the stipulation for provisional rates was signed. In December 2012, we made a supplemental filing incorporating twelve months of actual financial data, which would, if approved by the BPU, result in no change to customer rates during the 2012-2013 Winter Period. The supplemental filing would, however, result in an increase of the carryover deficiency to the 2013-2014 Winter Period from $16 million to $24 million. We are awaiting a final Order.

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Solar and Energy Efficiency Recovery Charges (RRC)—are comprised of: Carbon Abatement, Energy Efficiency Economic Stimulus Program (EEE), EEE Extension, Demand Response, Solar 4 All, and Solar Loan II. These programs are aimed at reducing the New Jersey's Greenhouse Gas (GHG) Emissions. We file for annual recovery for our investments under these programs which includes a return on our investment and recovery of expenses. In July 2012, we filed a petition with the BPU requesting an increase in RRC seeking to recover approximately $62 million in electric revenue and $8 million in gas revenue, on an annual basis consistent with the terms of the approved program. The discovery phase of this proceeding is underway.

Other material rate filings pending before the BPU include:

Energy Strong (ES) Program—In February 2013, we filed a petition with the BPU describing the improvements we recommend making to our BPU jurisdictional electric and gas system to harden and improve resiliency for the future. The changes that were described would be made over a ten year period. In this petition, we are seeking approval to invest $0.9 billion in our gas distribution system and $1.7 billion in our electric distribution system over an initial five year period, plus associated expenses, and to receive contemporaneous recovery of and on such investments. The current estimated cost of the entire program, including the first five years of investments for which we sought approval in this petition, is $3.9 billion. We anticipate seeking BPU approval to complete our investment under the program at a later date. For additional information, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Capital Requirements.

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Solar 4 All Extension—In July 2012, we filed for an extension of our Solar 4 All program. In this filing, we are seeking BPU approval to invest up to $690 million to develop 136 MW of utility-owned solar photovoltaic systems over a five year period starting in 2013. Consistent with the existing Solar 4 All program, we propose to sell the energy and capacity from the solar systems in the PJM wholesale energy and capacity markets which will offset the cost of the program.

We also filed for an additional extension of our Solar Loan program (Solar Loan III) in July 2012. In the filing, we are seeking BPU approval to provide financing support for the installation of 97.5 MW of solar systems by providing loans to qualified customers. The total investment of the proposed Solar Loan III program is anticipated to be up to $193 million once the program is fully subscribed, the projects are built and the loans are closed.

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 80% 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.

Approximately one-third of PSE&G’s total BGS-Fixed Price eligible load is auctioned each year for a three-year term. Current pricing is as follows:




	2010	2011	2012	2013
36 Month Terms Ending	May 2013	May 2014	May 2015	May 2016	(A)
Eligible Load (MW)	2,800	2,800	2,900	2,800
$ per kWh	0.09577	0.09430	0.08388	0.09218

(A)Prices set in the February 2013 BGS Auction will be effective on June 1, 2013 when the 2010 BGS agreements expire.

The BPU approved the auction process for 2013 with no significant changes to the process.

For additional information, see Item 8. Financial Statements and Supplementary Data— 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 had a full requirements contract with Power for an initial period which extended through March 2012 to meet the supply requirements of default service gas customers. This long-term contract continues on a year-to-year basis thereafter, unless terminated by either party with a one year notice. Power charges PSE&G for gas commodity costs which PSE&G recovers from customers. Any difference between rates charged by Power under the BGSS contract and rates charged to PSE&G’s residential customers are deferred and collected or refunded through adjustments in future rates. PSE&G earns no margin on the provision of BGSS.

In June 2012, we made our annual BGSS filing with the BPU. The filing requested a decrease in annual BGSS revenue of $71 million, excluding sales and use tax, to be effective October 1, 2012. This represented a reduction of approximately 5.2% for a typical residential gas heating customer. This BGSS reduction was the ninth consecutive reduction since January 2009. We entered into a Stipulation with the parties which put the requested lower BGSS rate into effect as filed on October 1, 2012 on a provisional basis. A final decision is expected in early 2013.

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Energy Policy

New Jersey Energy Master Plan (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.

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 redefined 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.

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Solar Loans: The first solar initiative 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 are used to offset program costs.

The total investment of both phases of the Solar Loan Program is expected to be between $210 million and $250 million once the program is fully subscribed, projects are built and loans are closed. As of December 31, 2012, we have provided a total of $209 million in loans for 878 projects representing 67 MW.

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Solar 4 All: The second solar initiative is the Solar 4 All Program under which we are investing approximately $456 million to develop 80 MW of utility-owned solar photovoltaic (PV) systems over four years. The program consists of centralized solar systems 500 kW 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, 2012, we have installed and placed in service 35 MW on approximately 160,000 distribution poles with an investment of approximately $245 million, and 39 MW of centralized solar systems representing 23 projects with an investment of approximately $192 million.

BPU Storm Report — In 2011, the BPU commenced an investigation of all four New Jersey electric utilities, including PSE&G, to examine their preparations, performance and restoration efforts during Hurricane Irene and the October 2011 snow storm. Following the completion of a report by its consultant, the BPU issued an order in January 2013, ordering the utilities to take specific action to improve their preparedness and responses to major storms. There are 103 separate measures contained in the Order, with most of the measures requiring utility implementation by September 2013. We are evaluating the implications of this report.

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BPU Audits

Management/Affiliate Audit—In 2009, the BPU, in accordance with New Jersey statutes, initiated audits of PSE&G with respect to the effectiveness of its management and its compliance with rules governing PSE&G's interactions with its affiliated companies. In 2012, the BPU issued a report making a number of findings and recommendations, including the finding that no violations of either the state or federal affiliate rules were found. The BPU is expected to issue an order addressing the audit report's findings and recommendations, although timing is uncertain.

BPU Investigations

RRC/CIP—In January 2012, New Jersey's Rate Counsel requested that the BPU investigate certain allegations of wrong doing in PSE&G’s solar, EEE, and CIP programs raised by three former employees in a lawsuit. The BPU initiated an inquiry into these allegations and requested documentation from PSE&G. PSE&G has cooperated with the BPU and provided all requested information and documentation.

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 proceedings not discussed below, as well as 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.

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.

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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_xemission control regulations that impose new NO_x emission reduction requirements and limits for New Jersey fossil fuel-fired electric generation units. The rule has 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 86 combustion turbines (approximately 1,750 MW) and four older New Jersey steam electric generation units (approximately 400 MW) by May 2015. Retirement notifications for the combustion turbines, except for Salem Unit 3, have been filed with PJM. The Salem Unit 3 combustion turbine (38 MW) will be transitioning to an emergency generator. Evaluations are ongoing for the steam electric generation units.


•	Connecticut NO_x Regulation—Under current Connecticut regulations, our Bridgeport and New Haven facilities have been utilizing Discrete Emission Reduction Credits (DERCs) to comply with certain NOx emission limitations that

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were incorporated into the facilities’ operating permits. In 2010, we negotiated new agreements with the State of Connecticut extending the continued use of DERCs for certain emission units and equipment until May 31, 2014.

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Hazardous Air Pollutants Regulation—In accordance with a ruling of the United States Court of Appeals of the District of Columbia (Court of Appeals), the EPA published a Maximum Achievable Control Technology (MACT) regulation on February 16, 2012. These Mercury Air Toxics Standards (MATS) are scheduled to go into effect on April 16, 2015 and establish allowable emission levels for mercury as well as other hazardous air pollutants pursuant to the CAA. In February 2012, members of the electric generating industry filed a petition challenging the existing source National Emission Standard for Hazardous Air Pollutants (NESHAP), new source NESHAP and the New Source Performance Standard (NSPS). In March 2012, PSEG filed a motion to intervene with the Court of Appeals in support of the EPA's implementation of MATS. The Court of Appeals has split the litigation related to these matters into three cases, addressing separately the existing source NESHAP, new source NESHAP and the NSPS. These cases remain pending. The EPA has stayed implementation of the new source NESHAP rule pending its reconsideration. The EPA published the proposed reconsideration for the new source NESHAP and the NSPS in the Federal Register on November 30, 2012. The EPA expects to finalize the reconsideration of the new source NESHAP and the NSPS in March 2013.

The impact to our fossil generation fleet in New Jersey and Connecticut and our jointly-owned coal fired generating facilities in Pennsylvania is currently being determined. We believe the back-end technology environmental controls installed at our Hudson and Mercer coal facilities should meet the MACT's requirements. Some additional controls could be necessary at our Connecticut facility, 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 our jointly-owned coal fired generating facility at Conemaugh in Pennsylvania. This installation is expected to be completed in the fourth quarter of 2014. Our 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).

On August 21, 2012, the Court of Appeals vacated CSAPR and ordered that the existing Clean Air Interstate Rule (CAIR) requirements remain in effect until an appropriate substitute rule has been promulgated. On October 5, 2012, the EPA filed a request for rehearing which the Court denied on January 24, 2013. What future actions the EPA will take regarding the Court's decision or the timing of those actions are unknown at this time. The purpose of CAIR is to improve ozone and fine particulate 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 2013 operations are similar to those in the past three years, it is expected that the impact to operations in New Jersey, New York and Connecticut from the temporary implementation of CAIR in 2013 will not be significant.

We currently anticipate that this rule will not have a material adverse impact to our capital investment program or our units’ operations.

Climate Change

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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 GHGs 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 have phased 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. On April 13, 2012, the EPA published the

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proposed New Source Performance Standards (NSPS) for GHG for new power plants and refineries. New or modified sources must employ BACT which is defined on a case-by-case basis and can be no less stringent than the applicable NSPS. Thus, for new power plants where the proposed NSPS identifies the applicable standard, if adopted as proposed, all permit decisions regarding BACT and application completeness should be made to reflect at least the level of stringency contained in those standards. The EPA is expected to move to regulation of existing electric generating units under the CAA. However, implementation of such regulations for existing sources is anticipated to be several years away.

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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.

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Regional Greenhouse Gas Initiative (RGGI)—In response to concerns over global climate change, some states have developed initiatives to stimulate national climate legislation through CO₂emission reductions in the electric power industry. Ten northeastern states, including New Jersey, New York and Connecticut, originally established RGGI to cap and reduce CO₂emissions 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 were required to be submitted to states by March 2012 for the first compliance period.

The Governor of New Jersey withdrew 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. The Governor's action to withdraw has been challenged by environmental groups in the New Jersey state court.

New Jersey also adopted the Global Warming Response Act in 2007, which calls for stabilizing its GHGs 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.

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 by July 27, 2012.

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 two 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. On June 11, 2012, the EPA posted a Notice of Data Availability (NODA) requesting comment on a series of technical issues related to the impingement mortality proposed standards. On June 12, 2012, the EPA posted a second NODA outlining its plans to finalize a “Willingness to Pay” survey it initiated to develop non-use benefits data in support of the April 2011 rule proposal. PSEG and industry trade associations submitted comments on both NODAs in July 2012. In July 2012, the EPA and

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environmental groups agreed to delay the deadline for finalization of the Rule to June 27, 2013 to allow for more time to address public comments and analyze data submitted in response to the NODAs.

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.

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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.

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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 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

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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 U.S. Department of Energy (DOE) was required to begin taking possession of the spent nuclear fuel by no later than 1998 but has not yet done so. 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. On June 1, 2012, The U.S. Court of Appeals for the District of Columbia ruled that the DOE failed to justify continued payments by electricity consumers into the Nuclear Waste Fund. The court ordered the DOE to conduct a complete reassessment of this fee within six months. The DOE's assessment was completed in January 2013, and concluded that fee collection should be maintained. On January 31, 2013, motions were filed with the Court seeking to reopen the case and set a schedule for expedited review of the DOE fee adequacy report.

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.

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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

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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.

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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.

On April 5, 2012, several environmental organizations and CCR marketers brought a citizens' suit against the EPA in federal court arguing that the EPA has a non-discretionary duty to issue the CCR rules by a certain date. On May 15, 2012, the Utility Solid Waste Activities Group Policy Committee filed a Motion to Intervene in order to be in alignment with the EPA in defending against the environmental organizations' action. After May 2012, all parties agreed to a schedule for submitting briefs in this case. Motions for summary judgment remain pending.

SEGMENT INFORMATION

Financial information with respect to our business segments is set forth in Item 8. Financial Statements and Supplementary Data—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 retail rates are regulated by the BPU and its wholesale transmission rates are regulated by the FERC. The retail rates for electric and gas distribution services are established in a base rate case and remain in effect until a new base rate case is filed and concluded. In addition, our utility has received approval for several clause recovery mechanisms, some of which provide for recovery of and on the authorized investments. These clause mechanisms require periodic updates to be reviewed and approved by the BPU. Our utility's transmission rates are recovered through a FERC approved formula rate. The revenue requirements are reset each year through this formula. Transmission ROEs have recently become the target of certain state utility commissions, municipal utilities, consumer advocates and consumer groups seeking to lower customer rates in New England and New York. These agencies and groups have filed complaints at the FERC asking the FERC to reduce the base ROE of various transmission owners. They point to changes in the capital markets as justification for lowering the ROE of these companies. While we are not the subject of any of these complaints, the matter could set a precedent for FERC-regulated transmission owners, such as PSE&G. Inability to obtain fair or timely recovery of all our costs, including a return of or on our investments in rates, could have a material impact on our business.


•	Obtain required regulatory approvals—The majority of our businesses operate under MBR authority granted by the FERC, which has determined that our subsidiaries do not have unmitigated market power and that MBR rules have

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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 the NERC for compliance.

Further, the FERC requires compliance with all of its rules and orders, including rules concerning Standards of Conduct, market behavior and anti-manipulation rules, reporting, interlocking directorate rules and cross-subsidization. Our companies with MBR authority are currently being audited by the FERC for compliance with FERC's rules regarding MBR authority, the filing of Electric Quarterly Reports (EQRs) and the receipt of payments in organized markets by our generating units that are required to run for reliability reasons when it is not economical for them to do so.

We will soon be subject to the reporting and record-keeping requirements of the Dodd-Frank Act, as implemented by the CFTC, and may in the future be subject to CFTC requirements regarding position limits for trading of certain commodities. As part of the Dodd-Frank Act compliance, we will need to be vigilant in monitoring and reporting our swap transactions.

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. The BPU is near completion of a management audit and an affiliate transactions audit of PSE&G.

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.

Many factors may affect 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.),

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•	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, including issues currently pending at the FERC.

Potential changes to the rules governing energy markets in which the output of our plants is sold also poses risk to our business.

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, 2012, it may have had to provide approximately $654 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 2013.

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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.

•

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 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 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

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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.


•	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.

In June 2012, the United States Court of Appeals for the D.C. Circuit upheld the EPA finding that GHGs could reasonably be expected to endanger public health and welfare. However, the Court dismissed the action brought by individuals, local governments and interest groups alleging that various industries, including various energy companies, emitted GHGs, causing global climate change resulting in a variety of damages. Plaintiffs are expected to appeal to the United States Supreme Court.

In November 2012, the Ninth Circuit Court of Appeals refused to reconsider its decision not to rehear an Alaskan village's public nuisance lawsuit alleging that GHGs emissions from ExxonMobil Corporation and many other energy companies had made the village uninhabitable. The appellate court denied the petition for rehearing which accused these companies of causing GHGs emissions that contributed to global warming and alleged injury to the village. If relevant federal or state common law were to develop that imposed liability upon those that emit GHGs for alleged impacts of GHGs emissions, such potential liability to us could be material.

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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. These amounts have not been updated since our 2006 filing.

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 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.

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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.

The State of New Jersey has 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.

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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.

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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.

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.

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Nuclear Incident or Accident Risk—Accidents and other unforeseen problems have occurred at nuclear stations, both in the United States 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. 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, 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 of artificially depressing prices in the competitive wholesale market on both a short-term and long-term basis. 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.

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We could also be impacted by a number of other events, including regulatory or legislative actions favoring non-competitive markets and energy efficiency and demand response 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, Power's revenues could be adversely affected. Moreover, the FERC has issued a rule, currently being challenged in court, that requires changes to transmission planning processes which may result in more transmission being built to facilitate renewable generation. This rule has also opened up the construction of certain types of transmission to competition through elimination of the ROFR.

Changes in the current policies for building new transmission lines could result in additional competition to build transmission lines in our service territory 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,


•	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.

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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,

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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 or group of assets’ 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.

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 and remain competitive.

The success of our businesses is dependent on our ability to continue providing safe and reliable service to our customers while minimizing service disruptions. We are also exposed to the risk of accidents, severe weather events such as we experienced from Hurricane Irene and Superstorm Sandy, or other incidents which could result in damage to or destruction of our facilities or damage to persons or property. The physical risks of climate change, such as more frequent or more extreme weather events, changes in temperature and precipitation patterns and other related phenomena have exacerbated these risks. 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 of our utility and generation operations and infrastructure through investigations or through the imposition of additional regulatory or legislative requirements. Such actions could affect our costs, competitiveness and future investments, which could be material to our financial position, results of operations and cash flow.

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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.

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, shareholders, vendors and/or customers, such as personal financial and health records, and


•	business system interruption or compromise.

Such events could severely disrupt business operations and prevent us from servicing our customers or collecting revenues. 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. A breach of certain business systems could affect our ability to record, process and/or report financial information correctly. In addition, new or updated security regulations may require us to make changes to our current measures which could also result in additional expenses.

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.

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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

Our subsidiaries own all of our physical property. 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.

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Generation Facilities

Power

As of December 31, 2012, 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	620	100%	620	Coal/Gas	Load Following
Mercer	NJ	632	100%	632	Coal/Gas	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		5,958		3,312
Nuclear:
Hope Creek	NJ	1,174	100%	1,174	Nuclear	Base Load
Salem 1 & 2	NJ	2,326	57%	1,335	Nuclear	Base Load
Peach Bottom 2 & 3 (B)	PA	2,245	50%	1,123	Nuclear	Base Load
Total Nuclear		5,745		3,632
Combined Cycle:
Bergen	NJ	1,183	100%	1,183	Gas	Load Following
Linden	NJ	1,236	100%	1,236	Gas	Load Following
Bethlehem	NY	757	100%	757	Gas	Load Following
Total Combined Cycle		3,176		3,176
Combustion Turbine:
Essex	NJ	617	100%	617	Gas	Peaking
Edison	NJ	504	100%	504	Gas	Peaking
Kearny	NJ	463	100%	463	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
New Haven Harbor	CT	129	100%	129	Gas/Oil	Peaking
Bridgeport Harbor	CT	12	100%	12	Oil	Peaking
Total Combustion Turbine		2,922		2,906
Pumped Storage:
Yards Creek (C)	NJ	400	50%	200		Peaking
Total Power Plants		18,201		13,226


(A)	Operated by GenOn Northeast Management Company


(B)	Operated by Exelon Generation


(C)	Operated by Jersey Central Power & Light Company

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PSE&G

As of December 31, 2012, PSE&G had 73 MW of installed solar capacity throughout New Jersey.

Energy Holdings

Energy Holdings had investments in the following generation facilities as of December 31, 2012:




Name	Location	Total Capacity (MW)	% Owned	Owned Capacity (MW)	Principal Fuels Used
Kalaeloa	HI	209	50%	105	Oil
Hackettstown	NJ	2	100%	2	Solar
Wyandot	OH	12	100%	12	Solar
Jacksonville	FL	15	100%	15	Solar
Queen Creek	AZ	25	100%	25	Solar
Milford	DE	15	100%	15	Solar
Total Operating Power Plants		278		174

Transmission and Distribution Facilities

As of December 31, 2012, PSE&G’s electric transmission and distribution system included 23,856 circuit miles, of which 8,357 circuit miles were underground, and 838,236 poles, of which 546,614 poles were jointly-owned. Approximately 99% of this property is located in New Jersey.

In addition, as of December 31, 2012, PSE&G owned four electric distribution headquarters and five subheadquarters in four operating divisions, all located in New Jersey.

As of December 31, 2012, the daily gas capacity of PSE&G’s 100%-owned peaking facilities (the maximum daily gas delivery available during the three peak winter months) consisted of liquid petroleum air gas (LPG) and liquefied natural gas (LNG) and aggregated 2,790,500 therms (270,932,330 cubic feet on an equivalent basis of 100,000 Btu/therm and 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, NJ	900,000
Harrison LPG	Harrison, NJ	900,000
Total		2,790,500

As of December 31, 2012, PSE&G owned and operated 17,713 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, 2012, PSE&G owned 42 switching stations in New Jersey with an aggregate installed capacity of 25,103 megavolt-amperes (MVA) and 246 substations with an aggregate installed capacity of 8,179 MVA. In addition, four of our substations in New Jersey having an aggregate installed capacity of 109 MVA were operated on leased property.

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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 the 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, the 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 the 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.

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. The Superior Court subsequently granted PSE&G’s motion to dismiss the Complaint, which dismissal was upheld by the Appellate Division.

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 June 2010, the BPU granted PSE&G’s motion to dismiss, and the plaintiff/petitioner subsequently appealed this dismissal to the Appellate Division. In June 2012, the Appellate Division affirmed the BPU’s decision, concluding that the BPU had correctly found that the plaintiff’s claims failed as a matter of law. The petitioner subsequently filed a Notice of Petition for Certification with the New Jersey Supreme Court. By order dated November 16, 2012, the New Jersey Supreme Court denied this Notice. On February 11, 2013, the Court denied the plaintiff's subsequent motion for reconsideration.

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 United States Government alleges damages of approximately $200 million. To PSE&G’s knowledge there has been no action on this matter since 1988.

(2)

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.

(3)

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.


(4)	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

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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 the 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 the NJDEP.

(5)

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.

(6)

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.


(7)	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.

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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, 2012, there were 78,842 registered holders.

The graph below shows a comparison of the five-year cumulative return assuming $100 invested on December 31, 2007 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.




	2007		2008		2009		2010		2011		2012
PSEG	$	100.00	$	61.55	$	73.15	$	73.09	$	79.08	$	76.68
S&P 500	$	100.00	$	63.06	$	79.70	$	91.68	$	93.63	$	108.55
DJ Utilities	$	100.00	$	72.22	$	81.18	$	86.41	$	103.34	$	104.70
S&P Electrics	$	100.00	$	74.20	$	76.68	$	76.68	$	95.92	$	95.37

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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
Common Stock	High		Low		Dividend per Share
2012
First Quarter	$	33.25	$	29.59	$	0.3550
Second Quarter	$	32.51	$	28.92	$	0.3550
Third Quarter	$	34.07	$	31.19	$	0.3550
Fourth Quarter	$	33.36	$	29.05	$	0.3550
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

On February 19, 2013, our Board of Directors approved $0.36 per share of common stock dividend for the first quarter of 2013. This reflects an indicated annual dividend rate of $1.44 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 2012:




Three Months Ended December 31, 2012	Total Number of Shares Purchased	Average Price Paid per Share
October 1-October 31	—	$	—
November 1-November 30	50,000	$	30.36
December 1-December 31	31,000	$	30.01

The following table indicates the securities authorized for issuance under equity compensation plans as of December 31, 2012:




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	2,945,400	$	34.19	17,013,520	(A)
Equity compensation plans not approved by security holders	—	$	—	3,589,032	(B)
Total	2,945,400	$	34.19	20,602,552


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


(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 2012 and Future Outlook.

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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 2012 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
	2012		2011		2010		2009		2008
Years Ended December 31,	Millions, except Earnings per Share
Operating Revenues	$	9,781	$	11,079	$	11,793	$	12,035	$	12,609
Income from Continuing Operations (A)	$	1,275	$	1,407	$	1,557	$	1,594	$	918
Net Income	$	1,275	$	1,503	$	1,564	$	1,592	$	1,188
Earnings per Share:
Income from Continuing Operations
Basic (A)	$	2.52	$	2.78	$	3.08	$	3.15	$	1.81
Diluted (A)	$	2.51	$	2.77	$	3.07	$	3.14	$	1.81
Net Income
Basic	$	2.52	$	2.97	$	3.09	$	3.15	$	2.34
Diluted	$	2.51	$	2.96	$	3.08	$	3.14	$	2.34
Dividends Declared per Share	$	1.42	$	1.37	$	1.37	$	1.33	$	1.29
As of December 31:
Total Assets	$	31,725	$	29,821	$	29,909	$	28,678	$	29,049
Long-Term Obligations (B)	$	6,701	$	7,482	$	7,847	$	7,679	$	8,044


(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.

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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 principally owns and manages a portfolio of lease investments and solar generation projects.

Our business discussion in Part I, Item 1. Business 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 Part I Item 1A provides information about factors that could have a material adverse impact on our businesses. The following discussion provides an overview of the significant events and business developments that have occurred during 2012 and key factors that we expect will drive our future performance. This 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 2012 AND FUTURE OUTLOOK

2012 Overview

During 2012, our financial results continued to be adversely impacted by lower prices for electricity and natural gas in the markets we serve. Electricity prices remained low due to a combination of a slow recovery in demand growth and sustained low natural gas prices. The slow economic recovery negatively impacts utility sales, and the wholesale energy and capacity markets in which we operate. The continued decline in wholesale natural gas prices resulting from greater supply from shale production has further contributed to the steady decline in the wholesale price of electricity.

In the face of reduced pricing and lower demand for electricity, we continued to pursue our three-pronged strategy of operational excellence, financial strength and disciplined investment. Our focus has been to change the business mix of our operations with increased investments in our regulated utility. Through our regulated utility operations, we secured higher and more stable transmission revenues in 2012 resulting from our annual transmission formula rate update filing with the Federal Energy Regulatory Commission (FERC) and made additional solar and energy efficiency investments in New Jersey, on which we receive contemporaneous returns. Through allocating capital to transmission and distribution infrastructure projects, we were able to take advantage of a low interest rate environment and tap into an available labor pool in the region, while enhancing the reliability of our service to our customers. Additionally, these sources of revenue allowed us to partially offset the impact of lower prices for electricity and natural gas, while the reduction in supply costs allows us to continue to invest in infrastructure improvements without raising our utility customers' rates.

While we have been successfully increasing our regulated utility earnings, we have not fully compensated for the reduction in generation earnings. Over the past few years, we experienced a decline in wholesale energy prices. Basic Generation Service (BGS) rates also declined, resulting in lower revenues for our generation business. As BGS rates reached a level closer to current spot market prices, customer migration away from BGS supply contracts continued in 2012, but at a slower pace as there was less incentive to switch to third party suppliers.

In addition, at year-end we were severely impacted by Superstorm Sandy, which resulted in the highest level of customer outages in our history. We sustained significant damage to some of our generation, transmission and distribution facilities. We received an order from the New Jersey Board of Public Utilities (BPU) allowing us to defer incurred, uninsured, incremental storm restoration costs associated with our gas and electric distribution systems.

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As of December 31, 2012, Power had incurred approximately $85 million in costs related to Superstorm Sandy, primarily comprised of repairs at certain generating stations and damage to materials and supplies, both at our fossil fleet. All the costs were recognized in Operation and Maintenance Expense, offset by $19 million of a pending future recovery of insurance proceeds. Power estimates that it will incur additional future costs primarily relating to repairs to, and replacement of, equipment and property up to approximately $215 million.

As of December 31, 2012, PSE&G had incurred approximately $295 million of costs to restore service to PSE&G's distribution and transmission systems and $5 million to repair its infrastructure and return it to pre-storm conditions. Of the costs incurred, approximately $40 million was recognized in Operation and Maintenance Expense, $75 million was recorded as Property, Plant and Equipment and $180 million was recorded as a Regulatory Asset because such costs were deferred as approved by the BPU under an Order received in December 2012. PSE&G recognized $6 million of insurance proceeds.

We are working with our insurance carriers with regard to other losses and expenses due to the storm but no assurances can be given relative to the timing or amount of insurance recovery. For additional information on the impacts of Superstorm Sandy, see Item 8. Financial Statements and Supplementary Data-Note 13. Commitments and Contingent Liabilities.

There have also been significant regulatory and legislative developments during the year which may affect our operations and financial results in the future as new rules and regulations are developed. Competitive wholesale power market design is of particular importance to our results. Through litigation and the regulatory processes, we advocated for policies and rules in response to subsidized generation and procurement activities in New Jersey in connection with the Long-Term Capacity Agreement Pilot Program (LCAPP), and in Maryland through the Maryland Public Service Commission's Request for Proposal. After a favorable stakeholder vote, PJM filed proposed modifications to the Minimum Offer Price Rule (MOPR) with the FERC. In February 2013, the FERC issued a deficiency letter to PJM seeking additional information regarding the proposed MOPR changes. If the FERC approves the proposal, these modifications should significantly improve the MOPR rules and appropriately reduce the ability for subsidized generation assets to artificially suppress wholesale market prices. Litigation with respect to the New Jersey LCAPP and Maryland's efforts to subsidize new generation and challenges to the BPU's implementation of LCAPP continues. See Item 1. Business, Federal Regulation, FERC - Capacity Market Issues for further information.

We continued to monitor and advocate for the development and implementation of fair and reasonable rules by the U.S. Environmental Protection Agency (EPA). The EPA is proceeding to implement its regulatory initiatives but the outcome of judicial review remains uncertain. The EPA's 316(b) rule on cooling water intake could adversely impact future nuclear and fossil operations and costs. However, we believe our generation business remains well-positioned for Clean Air Act regulations, if and when they are implemented. For additional information on the potential impacts of the 316(b) rule, see Item 8. Financial Statements and Supplementary Data-Note 13. Commitments and Contingent Liabilities.

Another regulatory development in 2012 that could have a material impact on our business are FERC rules under Order 1000, which altered the right of first refusal previously held by incumbent utilities to build all transmission within their respective service territories. We are opposing these rules in litigation and have worked with PJM to develop implementing rules that mitigate the impact of Order 1000. We cannot predict the final outcome or impact on us; however, specific implementation of Order 1000 within our service territory may expose us to competition for certain types of transmission projects, while at the same time affording us opportunities to construct transmission outside of our service territory. See Item 1. Business, Federal Regulation, FERC -Transmission Regulation.

We are making progress in addressing these challenges, but regulatory uncertainty remains a concern.

In 2012, our continued focus on operational excellence provided the foundation for our financial strength, in turn enabling us to invest in a disciplined way for growth, providing value for our customers, employees and shareholders and allowing us to best succeed in a sustained low electricity price environment. Some specific highlights in the areas of operational excellence, financial strength and disciplined investment in 2012 are discussed in more detail below.

Operational Excellence

We seek to emphasize operational performance while developing opportunities in our competitive and regulated businesses. Low commodity prices continue to stress margins, but the flexibility of our generating fleet has allowed us to take advantage of market opportunities as we remain diligent in managing costs. In 2012, we


•	constructed approximately $656M million of gross plant additions to our transmission assets currently in service,


•	continued to achieve high nuclear capacity factors, which averaged 91.1% for our nuclear fleet in 2012,


•	improved fossil plant summer output,


•	realized high combined cycle gas turbine fleet capacity utilization factors,

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•	optimized fleet-switching from coal to gas to improve dispatch economics,


•	extended collective bargaining agreements with four of our labor unions for four years,


•	implemented more efficient plant staffing,


•	were awarded the 2011 National Reliability Excellence Award for “demonstrating sustained leadership, innovation and achievement in the area of electric reliability," representing the fifth time in eight years we received this recognition, and eleven straight years that we garnered the ReliabilityOne Award for the Mid-Atlantic region, and


•	received other award recognition for reliability and outage response.

Financial Strength

Our financial metrics remained strong in 2012. We maintained


•	a strong balance sheet and operating cash flow,


•	substantial liquidity resources, including total credit capacity of $4.3 billion and $379 million of cash on hand as of December 31, 2012, with a portion of available credit facilities extending until 2017,


•	stable credit ratings,


•	dividend payments of $1.42 per share for 2012, representing 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, and


•	a well-funded position for our pension obligation, having made a $224 million contribution to our pension plan in 2012.

We also funded our capital program with internally generated cash and external debt financing.

In addition, we entered into a closing agreement settling our dispute with the Internal Revenue Service (IRS) over certain international leveraged lease transactions with finality for all tax periods in which we realized tax deductions from these transactions. Also, we executed settlement agreements covering all audit issues for tax years 1997 through 2006, concluding ten years of open audits for us. For additional information on the IRS audit settlements, see Item 8. Financial Statements and Supplementary Data-Note 20. Income Taxes.

Disciplined Investment

We seek to invest in areas that complement our existing businesses and provide attractive risk-adjusted returns. These areas include upgrading our 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. As noted above, over the past few years, we have shifted our focus to investing at the utility. Our capital expenditure forecast includes approximately $6.1 billion in spending over the next three years, 80% of which is at PSE&G. In addition, in 2012 we:


•	invested approximately $1.1 billion in transmission infrastructure projects,


•	completed the Peach Bottom steam path retrofit,


•	added 400 MW of additional capacity with new peaking plants in New Jersey and Connecticut,


•	completed solar projects in Arizona and Delaware, with the expectation to complete an additional Arizona solar project in 2013,


•	made additional investments in our Capital Infrastructure Program (CIP II) and our Energy Efficiency and Demand Response Programs, and


•	obtained BPU and NJDEP approvals of the North Central Reliability transmission project.

On February 20, 2013, we filed a petition with the BPU describing $3.9 billion of improvements we recommend making to our electric and gas distribution systems over a ten year period to harden and improve resiliency for the future. In addition, we anticipate investing an additional $1.5 billion in improvements to our transmission system for the same reason. See Capital Requirements for additional information.

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There is no guarantee that our projects currently underway or any future initiatives will be achieved since many issues need to be favorably resolved, such as regulatory approvals. Delays in the construction schedules of our projects could impact their costs as well as the timing of expected revenues.

Future Outlook

Our future success will depend on our ability to continue to maintain strong operational and financial performance in a difficult economy and cost-constrained environment and to respond to the issues and challenges described below and take advantage of 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 re-contract our open supply positions,


•	execute our capital investment program, including investments for growth that yield contemporaneous and attractive risk-adjusted returns while enhancing the reliability of the service we provide to our customers,


•	advocate for measures to ensure the implementation by PJM and FERC of market design rules that continue to protect competition and achieve appropriate RPM and BGS pricing, and


•	reach out to and engage multiple stakeholders, including regulators, government officials, customers and investors.

For 2013 and beyond, the key issues and challenges we expect our business to confront include


•	the continuing potential for sustained lower natural gas and electricity prices, both at market hubs and at locations where we operate,


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


•	customer migration away from our BGS supply contracts,


•	uncertainty in the national and regional economic recovery and continuing customer conservation efforts, which impact customer demand,


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


•	the aftermath of Hurricane Irene and Superstorm Sandy, including addressing the BPU's review of performance and communications, as well as cost recovery and opportunities for investment in system strengthening and improvements,


•	compressed margins and reduced utilization at coal plants,


•	uncertain pension expenses and funding requirements given market volatility,


•	liquidating the remaining portfolio of non-core assets where possible, while managing risk,


•	monitoring financially stressed power plant leveraged lease investments, and


•	successfully managing the transition to our operation of Long Island Power Authority's (LIPA) transmission and distribution system.

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RESULTS OF OPERATIONS




	Years Ended December 31,
	2012		2011			2010
Earnings (Losses)	Millions
Power (A)	$	647	$	1,002		$	1,136
PSE&G (A) (B)	528		521			359
Energy Holdings (C)	86		(134		)	49
Other (D)	14		18			13
PSEG Income from Continuing Operations	1,275		1,407			1,557
Income (Loss) from Discontinued Operations, Including Gain on Disposal (E)	—		96			7
PSEG Net Income	$	1,275	$	1,503		$	1,564




	Years Ended December 31,
Earnings Per Share (Diluted)	2012		2011		2010
PSEG Income from Continuing Operations	$	2.51	$	2.77	$	3.07
Income from Discontinued Operations, Including Gain on Disposal (E)	—		0.19		0.01
PSEG Net Income	$	2.51	$	2.96	$	3.08


(A)	Power's and PSE&G's results in 2012 include after-tax expenses of $39 million and $24 million, respectively, for Operation and Maintenance (O&M) costs due to severe damage caused by Superstorm Sandy. See Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingencies.


(B)	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.


(C)	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.


(D)	Other includes parent company interest and financing costs, donations, certain administrative and general expenses.


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

The 2012 year-over-year decrease in our Income from Continuing Operations was driven by the following:


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


•	lower average prices realized on generation sold into various power pools,


•	unfavorable amounts related to the MTM activity, discussed below,


•	higher Operation and Maintenance costs due to severe damage caused by Superstorm Sandy to our transmission and distribution system throughout our service territory as well as to some of our generation infrastructure in the northern part of New Jersey.

The decreases were partially offset by:


•	the absence of the $170 million after-tax charge taken in 2011 on leveraged leases related to Dynegy and the settlement proceeds received in 2012 (see Item 8. Financial Statements and Supplementary Data—Note 8. Financing Receivables), and


•	higher transmission revenues at PSE&G.

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


•	the $170 million after-tax charge on leveraged leases related to Dynegy,


•	the absence of an after-tax charge of $72 million related to an agreement to refund previous 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 below,


•	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.

Our results include the realized gains, losses and earnings on Power’s Nuclear Decommissioning Trust (NDT) Fund and other related NDT activity. Net realized gains, interest and dividend income and other costs related to the NDT Fund are recorded in Other Income and Deductions, and impairments on certain NDT securities are recorded as Other-Than-Temporary Impairments. Interest accretion expense on Power's nuclear Asset Retirement Obligation (ARO) is recorded in Operation and Maintenance Expense, as well as the depreciation related to the ARO asset. In September 2012, we restructured a portion of our NDT Fund and realized gains of $59 million. The investments were transitioned to new investment managers.

Our results also include the after-tax impacts of non-trading mark-to-market (MTM) activity, which consist of the financial impact from positions with forward delivery dates.

The combined after-tax impact on Income from Continuing Operations for the years ended December 31, 2012, 2011 and 2010 include the changes related to NDT Fund and MTM activity shown in the chart below:




Years Ended December 31,	2012			2011		2010
	Millions, after tax
NDT Fund and Related Activity	$	52		$	50	$	46
Non-Trading MTM Gains (Losses)	$	(10	)	$	107	$	(1	)

PSEG

Our results of operations are primarily comprised of the results of operations of our operating subsidiaries, Power, PSE&G and Energy Holdings, excluding charges 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.

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							Increase / (Decrease)					Increase / (Decrease)
	Years Ended December 31,						Increase / (Decrease)					Increase / (Decrease)
	2012		2011		2010		2012 vs. 2011					2011 vs. 2010
	Millions						Millions			%		Millions			%
Operating Revenues	$	9,781	$	11,079	$	11,793	$	(1,298	)	(12	)	$	(714	)	(6	)
Energy Costs	3,719		4,747		5,261		(1,028		)	(22	)	(514		)	(10	)
Operation and Maintenance	2,632		2,481		2,504		151			6		(23		)	(1	)
Depreciation and Amortization	1,054		976		955		78			8		21			2
Income from Equity Method Investments	12		4		4		8			N/A		—			—
Other Income and (Deductions)	162		135		158		27			20		(23		)	(15	)
Other-Than-Temporary Impairments	18		22		11		(4		)	(18	)	11			100
Interest Expense	423		475		472		(52		)	(11	)	3			1
Income Tax Expense	736		977		1,059		(241		)	(25	)	(82		)	(8	)
Income from Discontinued Operations, including Gain on Disposal, net of tax	—		96		7		(96		)	(100	)	89			N/A

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

Power




	Years Ended December 31,						Increase/ (Decrease)			Increase/ (Decrease)
	2012		2011		2010		2012 vs. 2011			2011 vs. 2010
	Millions
Income from Continuing Operations	$	647	$	1,002	$	1,136	$	(355	)	$	(134	)
Income (Loss) from Discontinued Operations, net of tax	—		96		7		(96		)	89
Net Income	$	647	$	1,098	$	1,143	$	(451	)	$	(45	)

The 2012 year-over-year decrease in Income from Continuing Operations was driven by the following:


•	lower average prices realized on generation sold into the PJM and New York (NY) power pools and MTM losses due from the realization of prior year unrealized gains and adverse changes in unrealized prices in 2012 for forward positions,


•	lower average pricing and lower volumes of electricity sold under our BGS contracts, net of lower cost to serve,


•	lower volumes on wholesale load contracts in PJM, lower operating reserve, ancillary and Reliability Must Run (RMR) revenues primarily in PJM and New England,


•	lower average pricing and volumes of gas sold under our BGSS contracts, net of lower cost to serve, and


•	higher Operation and Maintenance Expense due to damage to our generation infrastructure, primarily our fossil fleet, from Superstorm Sandy and higher refueling and maintenance costs at our nuclear plants.

These decreases were partially offset by


•	lower planned outages and maintenance costs in 2012 at certain of our fossil plants, and

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•	lower interest expense due to the maturity of Senior Notes in April 2011 and the early redemption of Senior Notes in December 2011.

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.

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




	Years Ended December 31,						Increase / (Decrease)					Increase / (Decrease)
Power	2012		2011		2010		2012 vs. 2011					2011 vs. 2010
	Millions						Millions			%		Millions			%
Operating Revenues	$	4,865	$	6,143	$	6,558	$	(1,278	)	(21	)	$	(415	)	(6	)
Energy Costs	2,383		3,046		3,374		(663		)	(22	)	(328		)	(10	)
Operation and Maintenance	1,122		1,102		1,046		20			2		56			5
Depreciation and Amortization	237		224		175		13			6		49			28
Other Income (Deductions)	109		111		117		(2		)	(2	)	(6		)	(5	)
Other-Than-Temporary Impairments	18		20		9		(2		)	(10	)	11			N/A
Interest Expense	134		175		157		(41		)	(23	)	18			11
Income Tax Expense	433		685		778		(252		)	(37	)	(93		)	(12	)
Income (Loss) from Discontinued Operations	—		96		7		(96		)	(100	)	89			N/A

Year ended December 31, 2012 as compared to 2011

Operating Revenues decreased $1,278 million due to

Generation Revenues decreased $975 million due primarily to


•	lower net revenues of $564 million due primarily to lower average realized prices for our generation sold into the PJM and NY power pools and MTM losses due from the realization of prior year unrealized gains and adverse changes in unrealized prices in 2012 for forward positions,


•	a decrease of $264 million due primarily to lower average pricing and lower volumes of electricity sold under our BGS contracts, primarily as a result of warmer winter weather in 2012 as well as customer migration, and


•	a net decrease of $154 million due to lower volumes on wholesale load contracts in the PJM and New England (NE) regions,


•	partially offset by a net increase of $7 million in other revenues consisting of higher net capacity revenues, partially offset by lower operating reserve, ancillary and RMR revenues.

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Gas Supply Revenues decreased $336 million due primarily to


•	a decrease of $306 million in sales under the BGSS contract, substantially comprised of lower average gas prices on lower volumes of sales in 2012 due to warmer average temperatures during the first quarter of 2012, and


•	a net decrease of $31 million due primarily to lower average prices, partially offset by higher sales volumes to third party customers.

Trading Revenues increased $33 million in 2012 due to the discontinuation of trading activities in the second quarter of 2011. As a result, the increase is due primarily to the absence of losses on electric energy supply contracts recognized in 2011.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel costs 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 $663 million due to


•	Gas costs decreased $312 million, principally related to obligations under the BGSS contract, reflecting lower average gas inventory costs coupled with lower sales volumes in 2012 due primarily to warmer average temperatures during the first quarter of 2012.

•

Generation costs decreased $351 million due primarily to $227 million of lower fuel costs, reflecting the utilization of lower volumes of coal and lower average natural gas prices, partially offset by the utilization of higher volumes of natural gas and higher nuclear fuel prices in 2012. The decrease was also attributable to $152 million of lower energy purchases, primarily in the PJM region as a result of lower load contract volumes in 2012, and $31 million of lower emission charges due to lower coal generation in the PJM and NE regions and impairment charges recorded in 2011 related to excess SO₂ emission allowances. These decreases were partially offset by an increase of $59 million due primarily to higher congestion costs in the PJM region.

Operation and Maintenance increased $20 million due primarily to


•	an increase of $85 million due to damage from Superstorm Sandy for repairs to certain of our generation plants, primarily those in our fossil fleet, and to recognize the estimated loss of use of fossil materials and supplies, partially offset by a $19 million insurance recovery, and


•	a net increase of $64 million due to higher refueling costs in 2012 for refueling outages at our 100%-owned Hope Creek nuclear unit and our 57%-owned Salem Unit 2 as compared to refueling outages for both of our 57%-owned Salem nuclear units in 2011,

•

partially offset by a net decrease of $109 million largely due to lower fossil planned outages in 2012 and lower maintenance costs, principally at our gas-fired Bethlehem Energy Center (BEC) in New York, gas-fired Bergen and Linden facilities, coal/gas-fired Hudson and Mercer coal/gas-fired plants in New Jersey, and 23%-owned coal-fired Conemaugh plant in Pennsylvania, as well as to the absence of costs incurred for the cancellation and renegotiation of a major contractual agreement for parts and services in 2011.

Depreciation and Amortization increased $13 million due primarily to higher depreciable asset bases at Fossil and Nuclear, including placing into service the new gas-fired peaking units at Kearny, New Jersey and New Haven, Connecticut on June 1, 2012 and completion of the steam path retrofit upgrades at our co-owned Peach Bottom Units 2 and 3 in October 2012 and October 2011, respectively.

Other Income (Deductions) experienced no material change.

Other-Than-Temporary Impairments decreased $2 million due to lower impairments in 2012 on the NDT and Rabbi Trust Funds.

Interest Expense decreased $41 million due primarily to a decrease of $55 million resulting primarily from the maturity of $606 million of 7.75% Senior Notes in early April 2011 and the early redemption of $600 million of 6.95% Senior Notes in December 2011, partially offset by increases of $12 million due to two $250 million Senior Notes issuances in September 2011 and $3 million in higher interest costs since interest capitalization ceased for our Kearny and New Haven projects on their June 1, 2012 in-service date.

Income Tax Expense decreased $252 million in 2012 due primarily to lower pre-tax income.

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 2011, 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

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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.

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 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.

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 BEC and Linden facilities as well as higher outage costs at our Bergen, and Keystone facilities, 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

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•	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 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.

Income (Loss) from Discontinued Operations

See explanation above for year ended December 31, 2012 as compared to 2011.

PSE&G




	Years Ended December 31,						Increase		Increase
	2012		2011		2010		2012 vs. 2011		2011 vs. 2010
	Millions
Income from Continuing Operations	$	528	$	521	$	359	$	7	$	162
Net Income	$	528	$	521	$	359	$	7	$	162

For the year ended December 31, 2012, the primary reasons for the increase in Income from Continuing Operations were


•	higher transmission revenues due to increased investments in transmission projects, and


•	tax benefits related to settlement of IRS audits,


•	partially offset by higher Operation and Maintenance expense, including higher storm costs and higher pension and OPEB expenses.

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,


•	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 expenses.

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




	Years Ended December 31,						Increase / (Decrease)					Increase / (Decrease)
PSE&G	2012		2011		2010		2012 vs. 2011					2011 vs. 2010
	Millions						Millions			%		Millions			%
Operating Revenues	$	6,626	$	7,326	$	7,869	$	(700	)	(10	)	$	(543	)	(7	)
Energy Costs	3,159		3,951		4,655		(792		)	(20	)	(704		)	(15	)
Operation and Maintenance	1,508		1,372		1,442		136			10		(70		)	(5	)
Depreciation and Amortization	778		719		750		59			8		(31		)	(4	)
Taxes Other Than Income Taxes	98		133		136		(35		)	(26	)	(3		)	(2	)
Other Income (Deductions)	47		21		23		26			N/A		(2		)	(9	)
Other-Than-Temporary Impairments	—		1		—		(1		)	(100	)	1			100
Interest Expense	295		310		318		(15		)	(5	)	(8		)	(3	)
Income Tax Expense	307		340		232		(33		)	(10	)	108			47

Year ended December 31, 2012 as compared to 2011

Operating Revenues decreased $700 million due primarily to

Commodity Revenue decreased $792 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 to retail customers.

•

Electric revenues decreased $488 million due primarily to $431 million in lower BGS revenues and $57 million in lower revenues from the sale of Non-Utility Generation (NUG) energy and collections of Non-Utility Generation Charges (NGC) due primarily to lower prices. BGS sales decreased 12% due primarily to customer migration to third party suppliers (TPS); in contrast, delivery sales decreased only 1%.


•	Gas revenues decreased $304 million due to lower BGSS volumes of $115 million and lower BGSS prices of $189 million. The average price of natural gas was 15% lower in 2012 than in 2011.

Delivery Revenues increased $81 million due primarily to an increase in transmission revenues.


•	Transmission revenues were $83 million higher due to increased investments in transmission projects.


•	Electric distribution revenues decreased $6 million due primarily to lower Transitional Energy Facilities Assessment (TEFA) revenue of $22 million due to a lower TEFA rate and lower sales volumes of $13 million, partially offset by higher Solar, Energy Efficiency and Conservation Program (Solar/EE) revenue of $20 million and higher Capital Infrastructure Program (CIP) revenue of $9 million.


•	Gas distribution revenues increased $4 million due primarily to higher Weather Normalization Clause (WNC) revenue of $52 million and higher CIP revenue of $8 million, partially offset by lower sales volumes of $43 million, and lower TEFA revenue of $13 million due to a lower TEFA rate.

Clause Revenues increased $12 million due primarily to higher Securitization Transition Charge (STC) revenues of $19 million, partially offset by lower Societal Benefit Charges (SBC) of $6 million and a lower Margin Adjustment Clause (MAC) of $2 million. The changes in STC and SBC amounts were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on SBC, MAC or STC collections.

Energy Costs decreased $792 million. This is entirely offset by Commodity Revenue.


•	Electric costs decreased $488 million or 18% due to $258 million in lower BGS and NUG volumes, $202 million of lower BGS prices, and $28 million for decreased deferred cost recovery. BGS and NUG volumes decreased 10% due primarily to customer migration to TPS.


•	Gas costs decreased $304 million or 24% due to $115 million or 9% in lower sales volumes due primarily to weather and $189 million or 15% in lower prices.

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Operation and Maintenance increased $136 million, of which the most significant components were


•	a $32 million increase in costs recognized related to SBC, Solar/EE and CIP,


•	a $27 million increase in pension and other postretirement benefits (OPEB) expenses,


•	a $17 million increase in storm damages,


•	a $10 million increase in transmission related costs, and


•	a $7 million increase in payroll costs.

Depreciation and Amortization increased $59 million due primarily to


•	a $39 million increase in amortization of Regulatory Assets, and


•	a $21 million increase in additional plant in service.

Taxes Other Than Income Taxes decreased $35 million due to a lower TEFA rate and lower sales volumes for electric and gas.

Other Income and (Deductions) net increase of $26 million was due primarily to


•	a $14 million increase in capitalized allowance for equity funds used during construction,


•	an $8 million increase in solar loan interest income, and


•	a $4 million increase in Rabbi Trust interest and gains.

Other-Than-Temporary Impairments experienced no material change.

Interest Expense decreased $15 million due primarily to the partial redemption of securitization debt and higher interest capitalization related to higher construction work in progress, partially offset by interest relating to the new debt issued in 2012. See Note 9. Changes in Capitalization for details.

Income Tax Expense decreased $33 million due primarily to changes in tax reserves related to settlement of IRS tax audits.

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 NUG energy and collections of NGC due primarily to higher prices. BGS sales decreased 16% due primarily to customer migration to 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 increased investments in transmission projects.


•	Gas distribution revenues increased $32 million due primarily to higher WNC revenue of $19 million and the impact of base rate increases of $17 million, partially offset by lower CIP revenue of $5 million.


•	Electric distribution revenues were flat due primarily to the impact of base rate increases of $17 million and higher CIP revenue of $1 million, offset by lower sales volumes of $18 million.

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 SBC and MAC of $49 million, partially offset by lower STC revenues of $98 million. The changes in 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.

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Energy Costs decreased $704 million. This is entirely offset by Commodity Revenue.


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


•	Gas costs decreased $307 million or 19% 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 OPEB expenses,


•	$20 million of lower net deferred expenses associated with SBC, Regional Greenhouse Gas Initiative 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.

Energy Holdings




	Years Ended December 31,							Increase/ (Decrease)		Increase/ (Decrease)
	2012		2011			2010		2012 vs. 2011		2011 vs. 2010
	Millions
Income from Continuing Operations	$	86	$	(134	)	$	49	$	220	$	(183	)
Net Income	$	86	$	(134	)	$	49	$	220	$	(183	)

For the year ended December 31, 2012, the primary reasons for the increase in Income from Continuing Operations were


•	the absence of the $170 million after-tax charge on leveraged leases related to Dynegy in 2011 and the settlement proceeds received in 2012 (see Item 8. Financial Statements and Supplementary Data—Note 8. Financing Receivables), and


•	the tax benefits related to the settlement of IRS tax audits in the first quarter of 2012.

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.

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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

We expect our capital requirements to be met through internally generated cash flows and external financings, consisting of short-term debt for working capital needs and long-term debt 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. PSEG’s sources of external liquidity include multi-year syndicated credit facilities totaling $1 billion. 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 PSEG's subsidiaries. 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.

Power’s sources of external liquidity include $2.7 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, 2012, our operating cash flow decreased by $770 million. For the year ended December 31, 2011, our operating cash flow increased by $1,393 million. The net changes were due to net changes from our subsidiaries as discussed below.

Power

Power’s operating cash flow decreased $433 million from $1,812 million to $1,379 million for the year ended December 31, 2012, as compared to 2011, primarily resulting from lower earnings and a $173 million decrease from lower net collections of counterparty receivables, partially offset by


•	a decrease of $57 million in benefit plan funding,


•	a $73 million decrease in spending for fuel, materials and supplies, and


•	a $246 million decrease in net payment of counterparty payables.

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,

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


•	lower earnings.

PSE&G

PSE&G’s operating cash flow decreased $520 million from $1,776 million to $1,256 million for the year ended December 31, 2012, as compared to 2011, due primarily to


•	a lower tax receipt of $484 million due to lower benefit of accelerated tax depreciation, and


•	a decrease of $306 million due to lower collections from customer billings,


•	partially offset by a decrease of $117 million in benefit plan funding, and


•	a decrease of $88 million in net prepayments due primarily to the application of prior year prepayment carryforwards towards current year state tax liabilities.

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 billings,


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

Energy Holdings

Energy Holdings’ operating cash flow increased $149 million for the year ended December 31, 2012, as compared to 2011, primarily due to lower tax payments in 2012 related to the absence of lease sale activity in 2012 and tax benefits related to settlement of IRS audits.

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 less lease sale activity in 2011.

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, 2012 were as follows:




Company/Facility	As of December 31, 2012
Company/Facility	Total Facility		Usage		Available Liquidity
	Millions
PSEG	$	1,000	$	4	$	996
Power	2,700		165		2,535
PSE&G	600		276		324
Total	$	4,300	$	445	$	3,855

As of December 31, 2012, our credit facility capacity is in excess of our projected maximum liquidity requirements over our 12 month planning horizon. Our maximum liquidity requirements are based on stress scenarios that incorporate changes in commodity prices and the potential impact of Power losing its investment grade credit rating. PSE&G’s credit facility primary use is to support its Commercial Paper Program under which as of December 31, 2012, $263 million was outstanding. For

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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

PSE&G had $150 million of 5.00% Medium Term Notes mature in January 2013 and issued $400 million of 3.80% Secured Medium-Term Notes, Series H, due January, 2043. PSE&G also has $300 million of 5.38% Medium Term Notes maturing in September 2013 and $275 million of 6.33% Medium Term Notes maturing in November 2013. Power has $300 million of 2.50% Senior Notes maturing in April 2013.

For a discussion of our long-term debt transactions during 2012 and into 2013, see Item 8. Financial Statements and Supplementary Data—Note 14. Schedule of Consolidated Debt.

Debt Covenants

Our credit agreements 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.

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, 2012, PSE&G’s Mortgage coverage ratio was 3.6 to 1 and the Mortgage would permit up to approximately $2.6 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.

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Common Stock Dividends




	Years Ended December 31,
Dividend Payments on Common Stock	2012		2011		2010
Per Share	$	1.42	$	1.37	$	1.37
in Millions	$	718	$	693	$	693

In 2012, dividend payments increased from $1.37 per share to $1.42 per share, representing 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.

On February 19, 2013, our Board of Directors approved a $0.36 per share common stock dividend for the first quarter of 2013. This reflects an indicated annual dividend rate of $1.44 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 deems relevant.

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 May 2012, Moody's published updated credit opinions on PSEG, Power and PSE&G. Moody's upgraded PSE&G's Mortgage Bond Rating to A1 from A2 and revised the outlook to stable from positive. PSEG's and Power's ratings and outlooks remained unchanged. In October 2012, S&P published updated credit opinions that left the ratings and outlooks for Power and PSE&G unchanged. In November 2012, S&P published an updated credit opinion for PSEG that left its ratings and outlook unchanged. In July 2012, Fitch upgraded PSE&G's Mortgage Bond Rating to A+ from A and its stable outlook remained unchanged. In January 2013, Fitch published updated credit opinions on PSEG, Power and PSE&G. PSEG's, Power's and PSE&G's ratings and outlooks remained 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	Stable	Positive	Stable
Mortgage Bonds	A1	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.

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Other Comprehensive Loss

For the year ended December 31, 2012, we had Other Comprehensive Loss of $51 million on a consolidated basis. Other Comprehensive Loss was due primarily to a $46 million increase in our consolidated liability for pension and postretirement benefits and $24 million of unrealized losses on derivative contracts accounted for as hedges and was partially offset by $19 million of net unrealized gains related to Available-for-Sale Securities.

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.




	2013		2014		2015
Power:			Millions
Baseline Maintenance	$	215	$	170	$	200
Environmental/Regulatory	70		70		15
Nuclear Expansion	115		125		90
Total Power	$	400	$	365	$	305
PSE&G:
Transmission
Reliability Enhancements	$	1,230	$	1,040	$	550
Facility Replacement	265		145		160
Support Facilities	10		15		10
Environmental/Regulatory	5		—		—
Distribution
Reliability Enhancements	85		75		75
Facility Replacement	140		150		175
Support Facilities	45		50		45
New Business	125		130		135
Environmental/Regulatory	35		35		30
Renewables	100		40		—
Total PSE&G	$	2,040	$	1,680	$	1,180
Non-Utility Renewables	50		—		—
Other	45		40		30
Total PSEG	$	2,535	$	2,085	$	1,515

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.


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

In 2012, Power made $438 million of capital expenditures, including interest capitalized during construction (IDC) but excluding $208 million for nuclear fuel, primarily related to various projects at Fossil and Nuclear.

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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—investments made in response to regulatory or legal mandates relating to renewable energy.

In 2012, PSE&G made $1,852 million of capital expenditures, including $1,770 million of investment in plant, primarily for transmission and distribution system reliability and $82 million in solar loan investments. This does not include expenditures for certain energy efficiency and renewable programs of $8 million or cost of removal, net of salvage, of $116 million, which are included in operating cash flows.

Additional Projects

The estimated project expenditures related to the following filings or transmission infrastructure investments are not included in our $6.1 billion three-year capital forecast table.

In February 2013, we filed a petition with the BPU describing the improvements we recommend making to our electric and gas distribution systems over a ten year period to harden and improve resiliency for the future. In this petition, we sought approval to invest $0.9 billion in our gas distribution system and $1.7 billion in our electric distribution over an initial five year period, plus associated expenses, and to receive contemporaneous recovery of and on such investments. This matter is pending. The current estimated cost of the entire program, including the first five years of investments for which we sought approval in this petition, is $3.9 billion. We anticipate seeking BPU approval to complete our investment under the program at a later date. We also intend to invest $1.5 billion in FERC jurisdictional investments in transmission infrastructure over the next ten years.

In July 2012, we filed for an extension of our Solar 4 All program. In this filing, we are seeking BPU approval for up to $690 million to develop 136 MW of utility-owned solar photovoltaic systems over a five year period starting in 2013. Consistent with the existing Solar 4 All program, we propose to sell the energy and capacity from the solar systems in the PJM wholesale energy and capacity markets which will offset the cost of the program.

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.

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	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	$	2,353	$	300	$	344	$	553	$	1,156
PSE&G	4,804		725		800		171		3,108
Transition Funding (PSE&G)	690		214		476		—		—
Transition Funding II (PSE&G)	32		12		20		—		—
Long-Term Non-Recourse Project Financing
Energy Holdings	44		1		18		8		17
Interest on Recourse Debt
Power	1,194		118		228		172		676
PSE&G	3,370		224		356		314		2,476
Transition Funding (PSE&G)	80		42		38		—		—
Transition Funding II (PSE&G)	2		1		1		—		—
Interest on Non-Recourse Project Financing
Energy Holdings	12		2		4		3		3
Capital Lease Obligations
PSEG	20		7		13		—		—
Power	5		2		3		—		—
Operating Leases
PSEG	214		—		3		25		186
Power	8		—		2		2		4
PSE&G	54		7		9		6		32
Energy Holdings	21		2		4		3		12
Energy-Related Purchase Commitments
Power	2,796		667		1,133		811		185
Total Contractual Cash Obligations	$	15,699	$	2,324	$	3,452	$	2,068	$	7,855
Commercial Commitments
Standby Letters of Credit
Power	$	214	$	169	$	45	$	—	$	—
PSE&G	13		13		—		—		—
Guarantees and Equity Commitments
Energy Holdings	53		53		—		—		—
Total Commercial Commitments	$	280	$	235	$	45	$	—	$	—
Liability Payments for Uncertain Tax Positions
PSEG	$	—	$	—	$	—	$	—	$	—
Power	5		5		—		—		—
PSE&G	—		—		—		—		—
Energy Holdings	70		70		—		—		—

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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 with 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 $28 million of long-term debt on its Consolidated Balance Sheet. Our pro-rata share of such debt is $14 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 arrangement, 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	2012		2011		2010
Discount Rate	4.20	%	5.00	%	5.51	%
Rate of Return on Plan Assets	8.00	%	8.50	%	8.50	%

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.

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Based on the above assumptions, we have estimated net periodic pension expense of approximately $110 million, net of amounts capitalized, and contributions of up to $145 million in 2013.

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 4.20% discount rate for 2013, a 4.50% discount rate for 2014, increasing annually by 25 basis points to 5.25% in 2017. 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.




	% Change	Impact on Pension Benefit Obligation As of December 31, 2012		Increase to Pension Expense in 2013
Assumption		Millions
Discount Rate	(1)%	$	751	$	72
Rate of Return on Plan Assets	(1)%	$	—	$	44

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

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, 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.

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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.

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, or a change in the credit rating or bankruptcy of a counterparty, 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 $177 million.

NDT Fund

Our NDT Fund 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 with a corresponding impact to earnings, 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,


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

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•	discount rates,


•	cost escalation rates,


•	market risk premium,


•	inflation rates, and


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

We obtain updated cost studies every three years unless new information necessitates more frequent updates. The most recent cost study was done in 2012. When we revise any assumptions used to calculate fair values of existing AROs, we adjust the ARO balance and corresponding long-lived asset which impacts the amount of accretion and depreciation expense recognized in future periods.

Nuclear Decommissioning AROs

AROs related to the future decommissioning of Power’s nuclear facilities comprised 94% of Power’s total AROs as of December 31, 2012. 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, 2012 would result in a $134 million increase in the Nuclear ARO as of December 31, 2012. A 1% increase in the inflation rate used at December 31, 2012 would result in a $335 million increase in the Nuclear ARO as of December 31, 2012. 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 $273 million at December 31, 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,


•	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. When the recovery of a Regulatory asset or payment of a Regulatory Liability is no longer probable, PSE&G charges or credits earnings, as appropriate.

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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.

Accounting for Insurance Proceeds

In late October 2012, Superstorm Sandy caused severe damage to our transmission and distribution system as well as to some of our generation infrastructure in the northern part of New Jersey. Strong winds resulted in a storm surge that caused damage to switching stations, substations and generating infrastructure. We are in the early stages of gathering information needed in preparing an insurance claim relating to that damage. As of December 31, 2012, we recorded estimated insurance proceeds of $25 million ($19 million for Power and $6 million for PSE&G). See Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingencies for additional information.

Assumptions and Approach Used: In December 2012, we received correspondence from representatives of the various insurance carriers acknowledging that damages were sustained and authorizing $25 million in advance payments to be made to us. Based on that authorization, we recorded the estimated insurance proceeds of $25 million. We believe that any further proceeds to be received under our policies are not estimable at December 31, 2012. We are at the early stages of documenting our insurance claim which then needs to be submitted to, and reviewed by, the insurers. We believe we have no basis for developing an estimate for any further insurance recoveries at this time.

Effect if Different Assumptions Used: If we were to use different assumptions regarding additional insurance proceeds, there would be a dollar for dollar effect on Operation and Maintenance Expense and Operating Income for Power. If we were to recognize any additional insurance proceeds for PSE&G, we would allocate those proceeds between Operation and Maintenance Expense and costs that have been deferred for regulatory recovery or capitalized. In either case, we would not recognize insurance proceeds in excess of actual costs incurred.

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

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.

MTM VaR consists of MTM derivatives that are economic hedges, some of which qualify for hedge accounting. The 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 VaR models used are variance/covariance models adjusted for the change of positions with 95% and 99.5% confidence levels and a one-day holding period for the MTM activities. The models assume no new positions throughout the holding periods; however, we actively manage our portfolio.

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Year Ended December 31, 2012	MTM VaR (A)
	Millions
95% Confidence Level,
Loss could exceed VaR one day in 20 days
Period End	$	18
Average for the Period	$	16
High	$	29
Low	$	7
99.5% Confidence Level,
Loss could exceed VaR one day in 200 days
Period End	$	28
Average for the Period	$	25
High	$	46
Low	$	11


(A)	As of December 31, 2012 and December 31, 2011, there was no trading VaR since we discontinued trading activities in the second quarter of 2011.

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

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, 2012, 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 $223 million decrease in the fair value of debt, including a $56 million decrease at Power and a $166 million decrease at PSE&G.

Debt and Equity Securities

We have $4.6 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 $1.5 billion as of December 31, 2012. As of December 31, 2012, the portfolio includes $789 million of equity securities and $627 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, 2012, a hypothetical 10% change in the equity market would impact the value of the equity securities in the NDT Fund by approximately $79 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 duration of 4.31 years and a yield of 1.24%. The portfolio’s value will appreciate or depreciate by the duration with a 1% change in interest rates. As of December 31, 2012, a hypothetical 1% increase in interest rates would result in a decline in the market value for the fixed income portfolio of approximately $27 million.

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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, which totaled $117 million, net of deferred taxes of $723 million, as of December 31, 2012. These leveraged leases are 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 outstanding 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.

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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, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012. 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.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, 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, 2012, 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 25, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey

February 25, 2013

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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, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, member’s equity, and cash flows for each of the three years in the period ended December 31, 2012. 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, 2012 and 2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, 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 25, 2013

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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, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2012. 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, 2012 and 2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, 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 25, 2013

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF OPERATIONS

Millions




	Years Ended December 31,
	2012			2011			2010
OPERATING REVENUES	$	9,781		$	11,079		$	11,793
OPERATING EXPENSES
Energy Costs	3,719			4,747			5,261
Operation and Maintenance	2,632			2,481			2,504
Depreciation and Amortization	1,054			976			955
Taxes Other Than Income Taxes	98			133			136
Total Operating Expenses	7,503			8,337			8,856
OPERATING INCOME	2,278			2,742			2,937
Income from Equity Method Investments	12			4			4
Other Income	260			220			221
Other Deductions	(98		)	(85		)	(63		)
Other-Than-Temporary Impairments	(18		)	(22		)	(11		)
Interest Expense	(423		)	(475		)	(472		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	2,011			2,384			2,616
Income Tax (Expense) Benefit	(736		)	(977		)	(1,059		)
INCOME FROM CONTINUING OPERATIONS	1,275			1,407			1,557
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax (expense) benefit of $0, $(51) and $(8) for the years ended 2012, 2011 and 2010, respectively	—			96			7
NET INCOME	$	1,275		$	1,503		$	1,564
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):
BASIC	505,933			505,949			505,985
DILUTED	507,086			506,982			507,045
EARNINGS PER SHARE:
BASIC
INCOME FROM CONTINUING OPERATIONS	$	2.52		$	2.78		$	3.08
NET INCOME	$	2.52		$	2.97		$	3.09
DILUTED
INCOME FROM CONTINUING OPERATIONS	$	2.51		$	2.77		$	3.07
NET INCOME	$	2.51		$	2.96		$	3.08
DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	1.42		$	1.37		$	1.37

See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions




	Years Ended December 31,
		2012			2011			2010
NET INCOME		$	1,275		$	1,503		$	1,564
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(24), $43 and $(12) for the years ended 2012, 2011 and 2010, respectively		19			(39		)	6
Change in Fair Value of Derivative Instruments, net of tax (expense) benefit of $(11), $(33) and $(42) for the years ended 2012, 2011 and 2010, respectively		17			47			60
Reclassification Adjustments for Net Amounts included in Net Income, net of tax (expense) benefit of $29, $87 and $90 for the years ended 2012, 2011 and 2010, respectively		(41		)	(127		)	(129		)
Pension/OPEB adjustment, net of tax (expense) benefit of $32, $44 and $(18) for the years ended 2012, 2011 and 2010, respectively		(46		)	(62		)	23
Other Comprehensive Income (Loss), net of tax		(51		)	(181		)	(40		)
COMPREHENSIVE INCOME		$	1,224		$	1,322		$	1,524

See Notes to Consolidated Financial Statements.

Table of Contents

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2012			2011
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	379		$	834
Accounts Receivable, net of allowances of $56 and $56 in 2012 and 2011, respectively	1,069			967
Tax Receivable	227			16
Unbilled Revenues	314			289
Fuel	583			685
Materials and Supplies, net	422			367
Prepayments	283			308
Derivative Contracts	138			156
Deferred Income Taxes	49			—
Regulatory Assets	349			167
Other	56			122
Total Current Assets	3,869			3,911
PROPERTY, PLANT AND EQUIPMENT	27,402			25,080
Less: Accumulated Depreciation and Amortization	(7,666		)	(7,231		)
Net Property, Plant and Equipment	19,736			17,849
NONCURRENT ASSETS
Regulatory Assets	3,830			3,805
Regulatory Assets of Variable Interest Entities (VIEs)	713			925
Long-Term Investments	1,324			1,303
Nuclear Decommissioning Trust (NDT) Fund	1,540			1,349
Other Special Funds	191			172
Goodwill	16			16
Other Intangibles	34			131
Derivative Contracts	153			106
Restricted Cash of VIEs	23			22
Other	296			232
Total Noncurrent Assets	8,120			8,061
TOTAL ASSETS	$	31,725		$	29,821

See Notes to Consolidated Financial Statements.

Table of Contents

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2012			2011
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year (includes $50 at fair value in 2011)	$	1,026		$	417
Securitization Debt of VIEs Due Within One Year	226			216
Commercial Paper and Loans	263			—
Accounts Payable	1,304			1,184
Derivative Contracts	46			131
Accrued Interest	91			97
Accrued Taxes	17			30
Deferred Income Taxes	72			170
Clean Energy Program	153			214
Obligation to Return Cash Collateral	122			107
Regulatory Liabilities	67			100
Other	390			291
Total Current Liabilities	3,777			2,957
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	6,542			5,458
Regulatory Liabilities	209			228
Regulatory Liabilities of VIEs	10			9
Asset Retirement Obligations	627			489
Other Postretirement Benefit (OPEB) Costs	1,285			1,127
Accrued Pension Costs	876			734
Clean Energy Program	—			39
Environmental Costs	537			643
Derivative Contracts	122			26
Long-Term Accrued Taxes	164			292
Other	108			86
Total Noncurrent Liabilities	10,480			9,131
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt	6,148			6,694
Securitization Debt of VIEs	496			723
Project Level, Non-Recourse Debt	43			44
Total Long-Term Debt	6,687			7,461
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000,000,000 shares; issued, 2012 and 2011—533,556,660 shares	4,833			4,823
Treasury Stock, at cost, 2012—27,664,188 shares; 2011—27,611,374 shares	(607		)	(601		)
Retained Earnings	6,942			6,385
Accumulated Other Comprehensive Loss	(388		)	(337		)
Total Common Stockholders’ Equity	10,780			10,270
Noncontrolling Interest	1			2
Total Stockholders’ Equity	10,781			10,272
Total Capitalization	17,468			17,733
TOTAL LIABILITIES AND CAPITALIZATION	$	31,725		$	29,821

See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions




	Years Ended December 31,
	2012			2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	1,275		$	1,503		$	1,564
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Gain on Disposal of Discontinued Operations	—			(122		)	—
Depreciation and Amortization	1,054			982			974
Amortization of Nuclear Fuel	173			153			136
Provision for Deferred Income Taxes (Other than Leases) and ITC	721			811			1,106
Non-Cash Employee Benefit Plan Costs	271			175			315
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes	93			(55		)	(336		)
Loss on Leases, net of tax	—			170			—
Net (Gain) Loss on Lease Investments	(49		)	(55		)	(56		)
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	63			(165		)	50
Deferred Storm Costs	(90		)	(60		)	(8		)
Net Change in Regulatory Assets and Liabilities	(132		)	(130		)	(58		)
Cost of Removal	(116		)	(62		)	(58		)
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(118		)	(117		)	(106		)
Net Change in Tax Receivable	(211		)	673			(689		)
Net Change in Certain Current Assets and Liabilities	97			247			(221		)
Employee Benefit Plan Funding and Related Payments	(314		)	(508		)	(508		)
Other	70			117			59
Net Cash Provided By (Used In) Operating Activities	2,787			3,557			2,164
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(2,574		)	(2,083		)	(2,160		)
Proceeds from Sale of Discontinued Operations	—			687			—
Proceeds from Sale of Capital Leases and Investments	58			179			496
Proceeds from Sales of Available-for-Sale Securities	1,666			1,355			1,116
Investments in Available-for-Sale Securities	(1,700		)	(1,386		)	(1,140		)
Other	(75		)	(21		)	19
Net Cash Provided By (Used In) Investing Activities	(2,625		)	(1,269		)	(1,669		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	263			(64		)	(466		)
Issuance of Long-Term Debt	900			794			1,728
Redemption of Long-Term Debt, including Securitization Debt	(1,003		)	(1,720		)	(972		)
Repayment of Non-Recourse Debt	(1		)	(1		)	(32		)
Cash Dividend Paid on Common Stock	(718		)	(693		)	(693		)
Redemption of Preferred Securities	—			—			(80		)
Other	(58		)	(50		)	(50		)
Net Cash Provided By (Used In) Financing Activities	(617		)	(1,734		)	(565		)
Net Increase (Decrease) in Cash and Cash Equivalents	(455		)	554			(70		)
Cash and Cash Equivalents at Beginning of Period	834			280			350
Cash and Cash Equivalents at End of Period	$	379		$	834		$	280
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	121		$	(219	)	$	1,070
Interest Paid, Net of Amounts Capitalized	$	402		$	479		$	444
Accrued Property, Plant and Equipment Expenditures	$	370		$	336		$	235

See the Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

Millions




	Common Stock			Treasury Stock					Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest
	Shs.	Amount		Shs.		Amount			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total
Balance as of January 1, 2010	534	$	4,788	(28	)	$	(588	)	$	4,704		$	(116	)	$	10		$	8,798
Net Income	—	—		—		—			1,564			—			—			1,564
Other Comprehensive Income (Loss), net of tax (expense) benefit of $18	—	—		—		—			—			(40		)	—			(40		)
Comprehensive Income																		1,524
Cash Dividends on Common Stock	—	—		—		—			(693		)	—			—			(693		)
Noncontrolling Interest in Losses of Consolidated Entity	—	—		—		—			—			—			(2		)	(2		)
Other	—	19		—		(5		)	—			—			—			14
Balance as of December 31, 2010	534	$	4,807	(28	)	$	(593	)	$	5,575		$	(156	)	$	8		$	9,641
Net Income	—	—		—		—			1,503			—			—			1,503
Other Comprehensive Income (Loss), net of tax (expense) benefit of $141	—	—		—		—			—			(181		)	—			(181		)
Comprehensive Income																		1,322
Cash Dividends on Common Stock	—	—		—		—			(693		)	—			—			(693		)
Noncontrolling Interest in Losses of Consolidated Entity	—	—		—		—			—			—			(6		)	(6		)
Other	—	16		—		(8		)	—			—			—			8
Balance as of December 31, 2011	534	$	4,823	(28	)	$	(601	)	$	6,385		$	(337	)	$	2		$	10,272
Net Income	—	—		—		—			1,275			—			—			1,275
Other Comprehensive Income (Loss), net of tax (expense) benefit of $26	—	—		—		—			—			(51		)	—			(51		)
Comprehensive Income																		1,224
Cash Dividends on Common Stock	—	—		—		—			(718		)	—			—			(718		)
Noncontrolling Interest in Losses of Consolidated Entity	—	—		—		—			—			—			(1		)	(1		)
Other	—	10		—		(6		)	—			—			—			4
Balance as of December 31, 2012	534	$	4,833	(28	)	$	(607	)	$	6,942		$	(388	)	$	1		$	10,781

See Notes to Consolidated Financial Statements.

Table of Contents

PSEG POWER LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

Millions




	Years Ended December 31,
	2012			2011			2010
OPERATING REVENUES	$	4,865		$	6,143		$	6,558
OPERATING EXPENSES
Energy Costs	2,383			3,046			3,374
Operation and Maintenance	1,122			1,102			1,046
Depreciation and Amortization	237			224			175
Total Operating Expenses	3,742			4,372			4,595
OPERATING INCOME	1,123			1,771			1,963
Other Income	199			190			170
Other Deductions	(90		)	(79		)	(53		)
Other-Than-Temporary Impairments	(18		)	(20		)	(9		)
Interest Expense	(134		)	(175		)	(157		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	1,080			1,687			1,914
Income Tax (Expense) Benefit	(433		)	(685		)	(778		)
INCOME FROM CONTINUING OPERATIONS	647			1,002			1,136
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax (expense) benefit of $0, $(51) and $(8) for the years ended 2012, 2011 and 2010, respectively	—			96			7
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	647		$	1,098		$	1,143

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

Table of Contents

PSEG POWER LLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions




	Years Ended December 31,
		2012			2011			2010
NET INCOME		$	647		$	1,098		$	1,143
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(24), $45 and $(17) for the years ended 2012, 2011 and 2010, respectively		18			(42		)	15
Change in Fair Value of Derivative Instruments, net of tax (expense) benefit of $(11), $(33) and $(42) for the years ended 2012, 2011 and 2010, respectively		17			47			60
Reclassification Adjustments for Net Amounts included in Net Income, net of tax (expense) benefit of $29, $87, and $90 for the years ended 2012, 2011 and 2010, respectively		(41		)	(127		)	(129		)
Pension/OPEB adjustment, net of tax (expense) benefit of $32, $40, and $(15) for the years ended 2012, 2011 and 2010, respectively		(46		)	(59		)	21
Other, net of tax (expense) benefit of $0 for the year ended 2010		—			—			(1		)
Other Comprehensive Income (Loss), net of tax		(52		)	(181		)	(34		)
COMPREHENSIVE INCOME		$	595		$	917		$	1,109

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

Table of Contents

PSEG POWER LLC

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2012			2011
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	7		$	12
Accounts Receivable	269			267
Accounts Receivable—Affiliated Companies, net	340			381
Short-Term Loan to Affiliate	574			907
Fuel	583			685
Materials and Supplies, net	307			272
Derivative Contracts	118			139
Prepayments	17			24
Other	19			—
Total Current Assets	2,234			2,687
PROPERTY, PLANT AND EQUIPMENT	9,697			9,191
Less: Accumulated Depreciation and Amortization	(2,679		)	(2,460		)
Net Property, Plant and Equipment	7,018			6,731
NONCURRENT ASSETS
Nuclear Decommissioning Trust (NDT) Fund	1,540			1,349
Goodwill	16			16
Other Intangibles	34			131
Other Special Funds	36			33
Derivative Contracts	49			55
Other	105			85
Total Noncurrent Assets	1,780			1,669
TOTAL ASSETS	$	11,032		$	11,087

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

Table of Contents

PSEG POWER LLC

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2012			2011
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	300		$	66
Accounts Payable	498			541
Derivative Contracts	46			124
Deferred Income Taxes	16			53
Accrued Interest	26			32
Other	81			86
Total Current Liabilities	967			902
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	1,575			1,266
Asset Retirement Obligations	369			259
Other Postretirement Benefit (OPEB) Costs	221			180
Derivative Contracts	15			24
Accrued Pension Costs	272			236
Long-Term Accrued Taxes	50			8
Other	84			83
Total Noncurrent Liabilities	2,586			2,056
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13)
LONG-TERM DEBT
Total Long-Term Debt	2,040			2,685
MEMBER’S EQUITY
Contributed Capital	2,028			2,028
Basis Adjustment	(986		)	(986		)
Retained Earnings	4,725			4,678
Accumulated Other Comprehensive Loss	(328		)	(276		)
Total Member’s Equity	5,439			5,444
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	11,032		$	11,087

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

Table of Contents

PSEG POWER LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions




	Years Ended December 31,
	2012			2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	647		$	1,098		$	1,143
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Gain on Disposal of Discontinued Operations	—			(122		)	—
Depreciation and Amortization	237			231			194
Amortization of Nuclear Fuel	173			153			136
Provision for Deferred Income Taxes and ITC	342			231			650
Interest Accretion on Asset Retirement Obligation	21			18			18
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	63			(165		)	50
Non-Cash Employee Benefit Plan Costs	70			41			71
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(118		)	(117		)	(106		)
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies	47			(26		)	135
Margin Deposit	(116		)	49			(91		)
Accounts Receivable	24			197			(105		)
Accounts Payable	92			(154		)	17
Accounts Receivable/Payable-Affiliated Companies, net	(40		)	459			(386		)
Accrued Interest Payable	(6		)	(8		)	(3		)
Other Current Assets and Liabilities	(16		)	38			(63		)
Employee Benefit Plan Funding and Related Payments	(72		)	(129		)	(132		)
Other	31			18			38
Net Cash Provided By (Used In) Operating Activities	1,379			1,812			1,566
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(646		)	(757		)	(825		)
Proceeds from Sale of Discontinued Operations	—			687			—
Proceeds from Sales of Available-for-Sale Securities	1,478			1,355			989
Investments in Available-for-Sale Securities	(1,506		)	(1,380		)	(1,013		)
Short-Term Loan—Affiliated Company, net	333			(509		)	(398		)
Other	(7		)	26			42
Net Cash Provided By (Used In) Investing Activities	(348		)	(578		)	(1,205		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Recourse Long-Term Debt	—			544			594
Cash Dividend Paid	(600		)	(500		)	(549		)
Redemption of Long-Term Debt	(414		)	(1,250		)	(248		)
Short-Term Loan—Affiliated Company, net	—			—			(194		)
Cash Payment on Debt Redemption/Exchange	(15		)	(17		)	(13		)
Other	(7		)	(10		)	(4		)
Net Cash Provided By (Used In) Financing Activities	(1,036		)	(1,233		)	(414		)
Net Increase (Decrease) in Cash and Cash Equivalents	(5		)	1			(53		)
Cash and Cash Equivalents at Beginning of Period	12			11			64
Cash and Cash Equivalents at End of Period	$	7		$	12		$	11
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	136		$	171		$	539
Interest Paid, Net of Amounts Capitalized	$	119		$	176		$	151
Accrued Property, Plant and Equipment Expenditures	$	95		$	132		$	111

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

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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, 2010	$	2,028	$	(986	)	$	3,486		$	(61	)	$	4,467
Net Income	—		—			1,143			—			1,143
Other Comprehensive Income (Loss), net of tax (expense) benefit of $16	—		—			—			(34		)	(34		)
Comprehensive Income												1,109
Cash Dividends Paid	—		—			(549		)	—			(549		)
Balance as of December 31, 2010	$	2,028	$	(986	)	$	4,080		$	(95	)	$	5,027
Net Income	—		—			1,098			—			1,098
Other Comprehensive Income (Loss), net of tax (expense) benefit of $139	—		—			—			(181		)	(181		)
Comprehensive Income												917
Cash Dividends Paid	—		—			(500		)	—			(500		)
Balance as of December 31, 2011	$	2,028	$	(986	)	$	4,678		$	(276	)	$	5,444
Net Income	—		—			647			—			647
Other Comprehensive Income (Loss), net of tax (expense) benefit of $26	—		—			—			(52		)	(52		)
Comprehensive Income												595
Cash Dividends Paid	—		—			(600		)	—			(600		)
Balance as of December 31, 2012	$	2,028	$	(986	)	$	4,725		$	(328	)	$	5,439

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

Table of Contents

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

Millions




	Years Ended December 31,
	2012			2011			2010
OPERATING REVENUES	$	6,626		$	7,326		$	7,869
OPERATING EXPENSES
Energy Costs	3,159			3,951			4,655
Operation and Maintenance	1,508			1,372			1,442
Depreciation and Amortization	778			719			750
Taxes Other Than Income Taxes	98			133			136
Total Operating Expenses	5,543			6,175			6,983
OPERATING INCOME	1,083			1,151			886
Other Income	52			25			26
Other Deductions	(5		)	(4		)	(3		)
Other-Than-Temporary Impairments	—			(1		)	—
Interest Expense	(295		)	(310		)	(318		)
INCOME BEFORE INCOME TAXES	835			861			591
Income Tax (Expense) Benefit	(307		)	(340		)	(232		)
NET INCOME	528			521			359
Preferred Stock Dividends	—			—			(1		)
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	528		$	521		$	358

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

Table of Contents

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions




	Years Ended December 31,
		2012		2011		2010
NET INCOME		$	528	$	521	$	359
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0, $(1) and $3 for the years ended 2012, 2011 and 2010, respectively		—		2		(5		)
COMPREHENSIVE INCOME		$	528	$	523	$	354

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

Table of Contents

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2012			2011
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	116		$	143
Accounts Receivable, net of allowances of $56 and $56 in 2012 and 2011, respectively	783			691
Tax Receivable	—			16
Unbilled Revenues	314			289
Materials and Supplies	114			94
Prepayments	29			117
Regulatory Assets	349			167
Derivative Contracts	5			—
Deferred Income Taxes	49			—
Other	24			21
Total Current Assets	1,783			1,538
PROPERTY, PLANT AND EQUIPMENT	17,006			15,306
Less: Accumulated Depreciation and Amortization	(4,726		)	(4,539		)
Net Property, Plant and Equipment	12,280			10,767
NONCURRENT ASSETS
Regulatory Assets	3,830			3,805
Regulatory Assets of VIEs	713			925
Long-Term Investments	348			280
Other Special Funds	61			57
Derivative Contracts	62			4
Restricted Cash of VIEs	23			22
Other	123			89
Total Noncurrent Assets	5,160			5,182
TOTAL ASSETS	$	19,223		$	17,487

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

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2012		2011
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	725	$	300
Securitization Debt of VIEs Due Within One Year	226		216
Commercial Paper and Loans	263		—
Accounts Payable	630		498
Accounts Payable—Affiliated Companies, net	73		280
Accrued Interest	65		65
Clean Energy Program	153		214
Derivative Contracts	—		7
Deferred Income Taxes	60		32
Obligation to Return Cash Collateral	122		107
Regulatory Liabilities	67		100
Other	269		186
Total Current Liabilities	2,653		2,005
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	4,223		3,675
Other Postretirement Benefit (OPEB) Costs	1,011		900
Accrued Pension Costs	463		355
Regulatory Liabilities	209		228
Regulatory Liabilities of VIEs	10		9
Clean Energy Program	—		39
Environmental Costs	486		592
Asset Retirement Obligations	250		226
Derivative Contracts	107		—
Long-Term Accrued Taxes	32		83
Other	38		35
Total Noncurrent Liabilities	6,829		6,142
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt	4,070		3,970
Securitization Debt of VIEs	496		723
Total Long-Term Debt	4,566		4,693
STOCKHOLDER’S EQUITY
Common Stock; 150,000,000 shares authorized; issued and outstanding, 2012 and 2011—132,450,344 shares	892		892
Contributed Capital	420		420
Basis Adjustment	986		986
Retained Earnings	2,875		2,347
Accumulated Other Comprehensive Income	2		2
Total Stockholder’s Equity	5,175		4,647
Total Capitalization	9,741		9,340
TOTAL LIABILITIES AND CAPITALIZATION	$	19,223	$	17,487

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

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions




	Years Ended December 31,
	2012			2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	528		$	521		$	359
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	778			719			750
Provision for Deferred Income Taxes and ITC	442			571			444
Non-Cash Employee Benefit Plan Costs	179			118			217
Cost of Removal	(116		)	(62		)	(58		)
Deferred Storm Costs	(90		)	(60		)	(8		)
Net Change in Regulatory Assets and Liabilities	(132		)	(130		)	(58		)
Net Change in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues	(54		)	252			(21		)
Materials and Supplies	(20		)	(4		)	(20		)
Prepayments	88			—			(31		)
Net Change in Tax Receivable	16			(16		)	—
Accounts Receivable/Payable-Affiliated Companies, net	(132		)	197			(286		)
Other Current Assets and Liabilities	12			(40		)	68
Employee Benefit Plan Funding and Related Payments	(213		)	(330		)	(327		)
Other	(30		)	40			(18		)
Net Cash Provided By (Used In) Operating Activities	1,256			1,776			1,011
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(1,770		)	(1,302		)	(1,257		)
Proceeds from Sales of Available-for-Sale Securities	77			—			54
Investments in Available-for-Sale Securities	(77		)	—			(54		)
Solar Loan Investments	(74		)	(51		)	(27		)
Other	(1		)	(1		)	4
Net Cash Provided By (Used In) Investing Activities	(1,845		)	(1,354		)	(1,280		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt	263			—			—
Issuance of Long-Term Debt	900			250			1,114
Redemption of Long-Term Debt	(373		)	(264		)	(400		)
Redemption of Securitization Debt	(216		)	(206		)	(197		)
Redemption of Preferred Securities	—			—			(80		)
Cash Dividend Paid	—			(300		)	(150		)
Other	(12		)	(4		)	(13		)
Net Cash Provided By (Used In) Financing Activities	562			(524		)	274
Net Increase (Decrease) in Cash and Cash Equivalents	(27		)	(102		)	5
Cash and Cash Equivalents at Beginning of Period	143			245			240
Cash and Cash Equivalents at End of Period	$	116		$	143		$	245
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(30	)	$	(514	)	$	73
Interest Paid, Net of Amounts Capitalized	$	280		$	297		$	294
Accrued Property, Plant and Equipment Expenditures	$	275		$	204		$	124

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

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

Millions




	Common Stock		Contributed Capital		Basis Adjustment		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance as of January 1, 2010	$	892	$	420	$	986	$	1,918		$	5		$	4,221
Net Income	—		—		—		359			—			359
Other Comprehensive Income, net of tax (expense) benefit of $3	—		—		—		—			(5		)	(5		)
Comprehensive Income													354
Cash Dividends on Preferred Stock	—		—		—		(1		)	—			(1		)
Cash Dividends on Common Stock	—		—		—		(150		)	—			(150		)
Balance as of December 31, 2010	$	892	$	420	$	986	$	2,126		$	—		$	4,424
Net Income	—		—		—		521			—			521
Other Comprehensive Income, net of tax (expense) benefit of $(1)	—		—		—		—			2			2
Comprehensive Income													523
Cash Dividends on Common Stock	—		—		—		(300		)	—			(300		)
Balance as of December 31, 2011	$	892	$	420	$	986	$	2,347		$	2		$	4,647
Net Income	—		—		—		528			—			528
Other Comprehensive Income, net of tax (expense) benefit of $0	—		—		—		—			—			—
Comprehensive Income													528
Cash Dividends on Common Stock	—		—		—		—			—			—
Balance as of December 31, 2012	$	892	$	420	$	986	$	2,875		$	2		$	5,175

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

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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 and energy trading 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 the FERC. PSE&G also invests in solar generation projects and has implemented energy efficiency and demand response programs, which are regulated by the BPU.

•

PSEG Energy Holdings L.L.C. (Energy Holdings)—which primarily has investments in leveraged leases and solar generation projects through its direct wholly owned subsidiaries. Certain Energy Holdings’ subsidiaries are subject to regulation by the FERC and the states in which they operate. Energy Holdings has also been awarded a contract to manage the transmission and distribution assets of the Long Island Power Authority (LIPA) starting in 2014.


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

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 and PSE&G consolidated their portion of any revenues and expenses related to these facilities 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 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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) 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 in Operating Revenues 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 20 years


•	fossil production assets—10 years to 79 years


•	nuclear generation assets—approximately 60 years


•	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 the FERC. The depreciation rate stated as a percentage of original cost of depreciable property was as follows:




	2012		2011		2010
	Avg Rate		Avg Rate		Avg Rate
PSE&G Depreciation Rate	2.48	%	2.46	%	2.46	%

Taxes Other Than Income Taxes

Excise taxes and transitional energy facilities assessment (TEFA) collected from PSE&G’s customers are presented in the financial statements on a gross basis. For the years ended December 31, 2012, 2011 and 2010, TEFA is included in the following captions in the Consolidated Statements of Operations:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




	Years Ended December 31,
	2012		2011		2010
			Millions
TEFA included in:
Operating Revenues	$	108	$	146	$	149
Taxes Other Than Income Taxes	$	98	$	133	$	136

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 and Energy Holdings. 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, 2012, 2011 and 2010 were as follows:




	IDC/AFUDC Capitalized
	2012				2011				2010
	Millions		Avg Rate		Millions		Avg Rate		Millions		Avg Rate
Power	$	27	5.16	%	$	30	5.91	%	$	78	6.57	%
PSE&G	$	33	8.43	%	$	13	6.56	%	$	7	6.22	%

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.

Uncertain income tax positions are accounted for 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.

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 or asset group’s carrying amount may not be recoverable. In such an event, an undiscounted cash flow analysis is performed to determine if an impairment exists. When a long-lived asset's carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset's fair value is less than its carrying amount. 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Realized gains and losses on available-for-sale securities 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 and 2010. See Note 4. Discontinued Operations and Dispositions.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 2. Recent Accounting Standards

New Standards Adopted during 2012

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

This accounting standard updates 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.

We adopted this standard prospectively effective January 1, 2012. Upon adoption there was no material impact on our consolidated financial position, results of operations or cash flows; however, it has resulted in expanded disclosures. For additional information, see Note 17. Fair Value Measurements.

Presentation of Comprehensive Income

This accounting standard addresses 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.

We adopted this standard retrospectively effective January 1, 2012. Upon adoption of the new amended guidance, there was no impact on our consolidated financial position, results of operations or cash flows, but there was a change in the presentation of the components of other comprehensive income.

New Accounting Standards Issued But Not Yet Adopted

Disclosures about Offsetting Assets and Liabilities

This accounting standard requires balance sheet offsetting disclosures to facilitate comparability between financial statements prepared on the basis of GAAP and 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 applicable to certain financial instruments (i.e. derivatives, repurchase agreements and reverse repurchase agreements) and securities borrowing and lending transactions. It 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.

Reclassification Adjustments out of Accumulated Other Comprehensive Income (AOCI)

This accounting standard requires entities to disclose the following information about reclassification adjustments related to AOCI:


•	changes in AOCI balances by components; and


•	significant amounts reclassified out of AOCI by respective line items of net income (for amounts that are required by GAAP to be reclassified to net income in their entirety in the same reporting period). For other types of reclassifications, reference to other note disclosures would be required.

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.

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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 for these bonds. 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, 2012 and 2011. 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 2012 or 2011. 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 years ended December 31, 2011 and 2010, which were reclassified to Discontinued Operations, are summarized below:




	Years Ended December 31,
	2011		2010
	Millions
Operating Revenues	$	112	$	402
Income Before Income Taxes	$	26	$	15
Net Income (Loss)	$	17	$	7

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.




		Years Ended December 31,
		2011		2010
	Millions
Net Proceeds from Sales		$	175	$	433
Gain (Loss) on Sales, after-tax		$	34	$	30

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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, 2012 and 2011 is detailed below:




	Power		PSE&G		Other		PSEG Consolidated
	Millions
2012
Generation:
Fossil Production	$	6,886	$	—	$	—	$	6,886
Nuclear Production	1,415		—		—		1,415
Nuclear Fuel in Service	853		—		—		853
Other Production-Solar	—		434		217		651
Construction Work in Progress	450		7		—		457
Total Generation	9,604		441		217		10,262
Transmission and Distribution:
Electric Transmission	—		3,053		—		3,053
Electric Distribution	—		6,807		—		6,807
Gas Transmission	—		89		—		89
Gas Distribution	—		5,065		—		5,065
Construction Work in Progress	—		1,048		—		1,048
Plant Held for Future Use	—		6		—		6
Other	—		380		—		380
Total Transmission and Distribution	—		16,448		—		16,448
Other	93		117		482		692
Total	$	9,697	$	17,006	$	699	$	27,402

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




	Power		PSE&G		Other		PSEG Consolidated
	Millions
2011
Generation:
Fossil Production	$	6,415	$	—	$	—	$	6,415
Nuclear Production	1,138		—		—		1,138
Nuclear Fuel in Service	774		—		—		774
Other Production-Solar	—		345		89		434
Construction Work in Progress	784		19		—		803
Total Generation	9,111		364		89		9,564
Transmission and Distribution:
Electric Transmission	—		2,441		—		2,441
Electric Distribution	—		6,522		—		6,522
Gas Transmission	—		91		—		91
Gas Distribution	—		4,858		—		4,858
Construction Work in Progress	—		546		—		546
Plant Held for Future Use	—		9		—		9
Other	—		386		—		386
Total Transmission and Distribution	—		14,853		—		14,853
Other	80		89		494		663
Total	$	9,191	$	15,306	$	583	$	25,080

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, 2012	Interest		Plant		Depreciation
			Millions
Power:
Coal Generating
Conemaugh	23	%	$	321	$	132
Keystone	23	%	$	387	$	128
Nuclear Generating
Peach Bottom	50	%	$	730	$	193
Salem	57	%	$	865	$	209
Nuclear Support Facilities	Various		$	191	$	29
Pumped Storage Facilities
Yards Creek	50	%	$	35	$	23
Merrill Creek Reservoir	14	%	$	1	$	—
PSE&G:
Transmission Facilities	Various		$	156	$	63

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	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	$	—
PSE&G:
Transmission Facilities	Various		$	152	$	61

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.

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 provides oversight. Proposed Operation and Maintenance (O&M) budgets and requests for major capital expenditures are reviewed and approved as part of the normal Power governance process.

GenOn Northeast Management Company is a co-owner and the operator for Keystone Generating Station and Conemaugh Generating Station. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part of the normal Power governance process.

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 O&M budgets, subject to Power's approval as part of the normal Power governance process.

Power is a minority owner in the Merrill Creek Reservoir and Environmental Preserve in Warren County, New Jersey. Merrill Creek Owners Group is the owner-operator of this facility. The operator submits separate capital and O&M budgets, subject to Power's approval as part of the normal Power governance process.

Note 6. Regulatory Assets and Liabilities

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 the FERC or PSE&G’s experience with prior rate cases. Most of PSE&G’s Regulatory Assets and Liabilities as of December 31, 2012 are supported by written 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.

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PSE&G had the following Regulatory Assets and Liabilities:




	As of December 31,
	2012		2011		Recovery/Refund Period
	Millions
Regulatory Assets
Current:
Underrecovered Electric Energy Costs—Basic Generation Service (BGS)	$	—	$	28	Various (1) (2)
Societal Benefits Charges (SBC)	74		87		Annual filing for recovery (1) (2)
Solar and Energy Efficiency Recovery Charges (RRC)	33		6		Annual filing for recovery (1) (2)
Solar Pilot Recovery Charge (SPRC)	14		4		Annual filing for recovery (1) (2)
Capital Stimulus Undercollection	34		21		Annual filing for recovery (1) (2)
Weather Normalization Clause (WNC)	30		2		Annual filing for recovery (2)
New Jersey Clean Energy Program	154		—		Annual filing for recovery (1) (2)
Other	10		19		Various
Total Current Regulatory Assets	$	349	$	167
Noncurrent
Stranded Costs To Be Recovered	$	1,112	$	1,460	Through December 2016 (1) (2)
Manufactured Gas Plant (MGP) Remediation Costs	588		635		Various (2)
Pension and Other Postretirement	1,550		1,280		Various
Deferred Income Taxes	405		393		Various
Remediation Adjustment Charge (RAC) (Other SBC)	88		92		Through 2019 (1) (2)
New Jersey Clean Energy Program	—		253		Through February 2013 (1) (2)
Mark-to-Market (MTM) Contracts	107		110		Various
Unamortized Loss on Reacquired Debt and Debt Expense	89		96		Over remaining debt life (1)
Conditional Asset Retirement Obligation	110		84		Various
Gas Margin Adjustment Clause	7		29		Through July 2015 (2)
RRC	142		140		Various (2)
WNC Deferral	27		—		Annual filing for recovery (2)
Storm Damage Deferral	244		68		To be determined
Other	74		90		Various
Total Noncurrent Regulatory Assets	$	4,543	$	4,730
Total Regulatory Assets	$	4,892	$	4,897

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	As of December 31,
	2012		2011		Recovery/Refund Period
	Millions
Regulatory Liabilities
Current:
Market Transition Charge (MTC) Refund, net	$	—	$	23	Through June 2012 (2)
Deferred Income Taxes	32		39		Various
Overrecovered Gas and Electric Costs—Basic Gas Supply Service (BGSS) and Basic Generation Service (BGS)	21		30		Annual filing for recovery (1) (2)
FERC Formula Rate True-up	5		1		Annual filing for recovery (1) (2)
Non-Utility Generation Charge (NGC)	9		5		Annual filing for recovery (1) (2)
Other	—		2		Various
Total Current Regulatory Liabilities	$	67	$	100
Noncurrent:
Electric Cost of Removal	$	166	$	222	Reduced as cost is incurred
MTM Contracts	40		—		Various
Other	13		15		Various
Total Noncurrent Regulatory Liabilities	$	219	$	237
Total Regulatory Liabilities	$	286	$	337


(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:


•	Underrecovered Electric Energy Costs: These costs represent the underrecovered amounts associated with 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 USF; 2) Energy Efficiency and Renewable Energy Programs; 3) Social Programs (electric only) which include electric bad debt expense; and 4) the RAC for incurred MGP remediation expenditures. All components accrue interest on both over and underrecoveries.


•	RRC: These costs are amounts associated with various renewable energy and energy efficiency programs. Components of the RRC include: Carbon Abatement, Energy Efficiency Economic Stimulus Program, Energy Efficiency Economic Extension Program, the Demand Response Program, Solar Generation Investment Program (Solar 4 All) and Solar Loan II Program.

•

SPRC: This charge is designed to recover the revenue requirements associated with the PSE&G Solar Pilot Program (Solar Loan I) per the BPU Order, less the net proceeds from the sale of associated Solar Renewable Energy Certificates (SRECs) or cash received in lieu of SRECs. The net recovery is subject to deferred accounting. Interest at the two-year constant maturity treasury rate plus 60 basis points will be accrued monthly on any under- or over-recovered balances.


•	Capital Stimulus Undercollection: PSE&G has 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 reliability of PSE&G's infrastructure and New Jersey's economy through job creation.


•	WNC Deferral: This represents the over or under collection of gas margin refundable or recoverable under the BPU's weather normalization clause. The WNC requires PSE&G to calculate, at the end of each October-to-May period, the level by which margin revenues differed from what would have resulted if normal weather had occurred.

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•	New Jersey Clean Energy Program: The BPU approved future funding requirements for Energy Efficiency and Renewable Energy Programs through the first half of 2013. Once the rates are measured, they are recovered through the SBC.

•

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. Collected 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 cleanup costs for manufactured gas plants that are probable of recovery in future rates. Once these costs are incurred, they are recovered through the RAC 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 are 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.


•	RAC (Other SBC): Costs incurred to clean up manufactured gas plants which are recovered over seven years.


•	MTM Contracts: The estimated fair value of long-term standard offer capacity agreements (SOCAs), gas hedge contracts and gas cogeneration supply contracts. The regulatory asset/liability is offset by a derivative asset/liability and, with respect to the gas hedge contracts only, an intercompany receivable/payable on the Consolidated Balance Sheets.


•	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.


•	Gas Margin Adjustment Clause: PSE&G defers the margin differential received from Transportation Gas Service Non-Firm Customers versus bill credits provided to BGSS-Firm customers.


•	Storm Damage Deferral: Costs incurred in the cleanup of 2012, 2011 and 2010 storms, as approved by the BPU under an Order received in December 2012 authorizing the deferral of incremental costs.


•	MTC Refund, net: These costs represent the overrecovered amounts associated with MTC.


•	Overrecovered Gas and Electric Costs: These costs represent the overrecovered amounts associated with BGSS and BGS, as approved by the BPU. Interest is accrued on overrecovered balances.


•	FERC Formula Rate True-up: Overcollection or undercollection of transmission earnings calculated using a FERC approved formula.


•	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.


•	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.

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Significant 2012 orders and pending rate filings are as follows:

•

Storm Damage Deferral—In December 2012, the BPU granted PSE&G's request to defer on its books actually incurred, uninsured, incremental storm restoration costs to its gas and electric distribution systems associated with extraordinary storms, including Hurricane Irene and Superstorm Sandy. In February 2013, the BPU announced that it would initiate a generic proceeding to evaluate the prudency of extraordinary, storm-related costs incurred by all of the regulated utilities as a result of the natural disasters experienced in New Jersey in 2011 and 2012 and in this proceeding will consider the manner in which such prudent costs shall be recovered.


•	Transmission Formula Rates—PSE&G's 2012 Annual Formula Rate Update with the FERC provided for approximately $94 million in increased annual transmission revenues effective January 1, 2012. PSE&G filed its 2013 Annual Formula Rate Update with FERC in October 2012, which provides for approximately $174 million in increased annual transmission revenues effective January 1, 2013.


•	SBC/NGC—In March 2012, PSE&G made an annual SBC/NGC filing requesting a $5 million electric increase and a $29 million gas increase. PSE&G updated the filing with actual data through August 31, 2012, resulting in a decrease of $77 million for electric customers while the gas increase remained unchanged. A Stipulation signed by the Parties was approved by the BPU effective February 1, 2013.

•

Universal Service Fund (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 separate mandated energy assistance program to provide payment assistance to elderly and disabled customers. In June 2012, New Jersey's electric and gas utilities, including PSE&G, filed requests to reset the statewide rates for the USF and the Lifeline program. The filed USF rates were set to recover approximately $230 million on a statewide basis. Of this amount, the statewide electric rates are set to recover $173 million with the remaining $57 million recovered through gas rates. The rates for the Lifeline program were set to recover $66 million, $46 million for electric and $20 million for gas. The filed rates were subsequently updated and approved effective October 1, 2012. PSE&G earns no margin on the collection of the USF and Lifeline programs resulting in no impact on Net Income.


•	Capital Infrastructure Programs (CIP I and CIP II)—In December 2012, the BPU approved stipulations regarding our CIP I and CIP II filings resulting in a combined increase of $40 million and $23 million for electric and gas customers, respectively effective January 1, 2013.

•

WNC— In June 2012, PSE&G filed a petition and testimony with the BPU, including eight months of actual and four months of forecasted data, which sought BPU approval to recover $41 million in deficiency revenues from its customers during the 2012-2013 Winter Period (October 1 to May 31) and a carryover deficiency of $16 million to the 2013-2014 Winter Period. In September 2012, an Order approving the stipulation for provisional rates was signed. In December 2012, PSE&G made a supplemental filing incorporating twelve months of actual financial data, which would, if approved by the BPU, result in no change to customer rates during the 2012-2013 Winter Period. The supplemental filing would, however, result in an increase of the carryover deficiency to the 2013-2014 Winter Period from $16 million to $24 million. PSE&G is awaiting a final Order.

•

RAC—In November 2011, PSE&G filed a RAC 19 petition with the BPU requesting a decrease in electric and gas RAC revenues on an annual basis of $9 million and $10 million, respectively. In October 2012, PSE&G received the Administrative Law Judge's (ALJ) Initial Decision allowing full recovery of RAC 19 costs including costs of the Passaic River and Newark Bay Superfund (CERCLA) matters and the Occidental litigation that were allocated to PSE&G and included in this request. In October 2012, the BPU issued a final Order approving the ALJ's Initial Decision.


•	RRC—In July 2012, PSE&G filed a petition with the BPU requesting an increase in the RRC seeking to recover approximately $62 million in electric revenue and $8 million in gas revenue on an annual basis. The discovery phase of this proceeding is underway.


•	SPRC—In July 2012, the BPU approved a Stipulation regarding our March 2010 SPRC (Solar Loan I) filing authorizing an increase in rates of $3 million for PSE&G's electric customers effective August 1, 2012. In July 2012, PSE&G filed a petition with the BPU for an annual increase in the electric SPRC of $17 million. The discovery phase of this proceeding is underway.

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Note 7. Long-Term Investments

Long-Term Investments as of December 31, 2012 and 2011 included the following:




	As of December 31,
	2012		2011
	Millions
Power
Partnerships and Corporate Joint Ventures (Equity Method Investments)	$	40	$	32
PSE&G
Life Insurance and Supplemental Benefits	161		162
Solar Loan Investments	180		111
Other Investments	7		7
Energy Holdings
Leveraged Leases	840		881
Partnerships and Corporate Joint Ventures:
Equity Method Investments (A)	94		106
Cost Method Investments (B)	2		4
Total Long-Term Investments	$	1,324	$	1,303


(A)	During the three years ended December 31, 2012, 2011 and 2010, the amount of dividends from these investments was $17 million, $3 million and $5 million, respectively. Energy Holdings’ share of income and cash flow distribution percentages were at 50% as of December 31, 2012.


(B)	Reflects Energy Holdings' 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 following table shows Energy Holdings’ gross and net lease investment as of December 31, 2012 and 2011, respectively.




	As of December 31,
	2012			2011
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	721		$	763
Estimated Residual Value of Leased Assets	535			553
	1,256			1,316
Unearned and Deferred Income	(416		)	(435		)
Gross Investments in Leases	840			881
Deferred Tax Liabilities	(723		)	(716		)
Net Investments in Leases	$	117		$	165

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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,
	2012		2011			2010
	Millions
Pre-Tax Income (Loss) from Leases	$	78	$	(228	)	$	45
Income Tax Expense (Benefit) on Pre-Tax Income from Leases	$	34	$	(77	)	$	14

Equity Method Investments

Power and Energy Holdings had the following equity method investments as of December 31, 2012:




		%
Name	Location	Owned
Power
Keystone Fuels, LLC	PA	23	%
Conemaugh Fuels, LLC	PA	23	%
Energy Holdings
Kalaeloa	HI	50	%
GWF	CA	50	%
Hanford L. P. (Hanford)	CA	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 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	2012		2011
	Millions
Commercial/Industrial	$	174	$	106
Residential	15		10
	$	189	$	116

Energy Holdings

Energy Holdings had a net investment in domestic energy and real estate assets subject primarily to leveraged lease accounting of $117 million and $165 million as of December 31, 2012 and 2011, respectively (See Note 7. Long-Term Investments).

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.

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	Lease Receivables, Net of Non-Recourse Debt
	As of December 31,
Counterparties’ Credit Rating (S&P) as of December 31, 2012	2012		2011
	Millions
AA	$	21	$	21
AA-	73		110
BBB+ - BBB-	316		316
B	166		299
D	134		—
Not Rated	11		17
	$	721	$	763

The “B” and “D” ratings above represent lease receivables related to coal-fired assets in Illinois and Pennsylvania. As of December 31, 2012, the gross investment in the leases of such assets, net of non-recourse debt, was $559 million ($19 million, net of deferred taxes). A more detailed description of such assets under lease is presented in the following table.




Asset	Location	Gross Investment		% Owned		Total	Fuel Type	Counterparties’ S&P Credit Ratings	Counterparty
		Millions				MW
Powerton Station Units 5 and 6	IL	$	134	64	%	1,538	Coal	D	Edison Mission Energy
Joliet Station Units 7 and 8	IL	$	84	64	%	1,044	Coal	D	Edison Mission Energy
Keystone Station Units 1 and 2	PA	$	116	17	%	1,711	Coal	B	GenOn REMA, LLC
Conemaugh Station Units 1 and 2	PA	$	116	17	%	1,711	Coal	B	GenOn REMA, LLC
Shawville Station Units 1, 2, 3 and 4	PA	$	109	100	%	603	Coal	B	GenOn REMA, LLC

The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease transactions. These credit enhancement features vary from lease to lease and may include letters of credit or affiliate guarantees. Upon the occurrence of certain defaults, indirect subsidiary companies of Energy Holdings would exercise their rights and attempt to seek recovery of their investment, potentially including stepping into the lease directly to protect their investments. While these actions could ultimately protect or mitigate the loss of value, they could require the use of significant capital investments and trigger certain material tax obligations. A bankruptcy of a lessee would likely delay any efforts on the part of the lessors to assert their rights upon default and could delay the monetization of claims. Failure to recover adequate value could ultimately lead to a foreclosure on the lease by the lenders. 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.

Of facilities under lease by indirect subsidiary companies of Energy Holdings to GenOn REMA, LLC (GenOn REMA), a subsidiary of GenOn Energy Inc. (GenOn), which was acquired by NRG Energy, Inc. in December 2012. Keystone has installed flue gas desulfurization control for sulfur dioxide (SO₂₎, selective catalytic reduction (SCR) equipment for nitrogen oxide (NOx) and mercury control to meet current environmental requirements. Conemaugh has flue gas desulfurization control, while SCR and mercury control are scheduled to be installed and operational in the first quarter of 2015. GenOn's plan for the coal-fired units at the Shawville facility is to place them in a “long-term protective layup” by April 2015 while continuing to pay the required rent and maintaining the facility in accordance with the lease terms or terminating the lease for obsolescence in which case the lessee would be required, among other things, to pay the contractual termination value structured to recover Energy Holdings' indirect subsidiaries' lease investment as specified in the lease agreement.

Although all lease payments from the GenOn REMA leases are current, no assurances can be given that future payments in accordance with the lease contracts will continue. Factors which may impact future lease cash flows include, but are not limited

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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.

With respect to Edison Mission Energy's (EME) Midwest Generation (MWG) leases on the Powerton and Joliet coal units in Illinois, the lessee, MWG, substantially completed investments in mercury removal (Activated Carbon Injection) and NOx emission controls (low NOx burners and Selective Non-Catalytic Reduction systems), and plans to invest in SO₂ emission controls (Dry Sorbent Injection (Trona) systems). EME does not anticipate a material change in this current approach in order to comply with existing federal and Illinois environmental rules. On November 30, 2012, MWG filed a variance request with the Illinois Pollution Control Board seeking two additional years to meet upcoming air emission compliance deadlines under Illinois law. EME and MWG remain in litigation with the U.S. Environmental Protection Agency (EPA) and the State of Illinois regarding certain air emissions. On March 16, 2011, the federal district court dismissed new source review claims in reference to Powerton and Joliet, but certain opacity claims remain pending against MWG. The EPA and the State of Illinois have appealed the dismissal of the new source review claims. On November 11, 2011, the federal district court stayed proceedings in connection with the opacity claims until the appeal by the EPA and the State of Illinois is resolved.

On December 17, 2012, EME and MWG filed for relief under Chapter 11 of the U.S. Bankruptcy Code. Immediately prior to that filing, EME, MWG, Nesbitt Asset Recovery, LLC (which is an indirect, wholly owned subsidiary of Energy Holdings), and Associates Capital Investments, L.L.P., as well as certain affiliated owner lessors and owner participants, entered into a forbearance agreement with holders of a majority of the lease debt that financed the original sale-leaseback transaction. The forbearance agreement, which was approved by the bankruptcy court and limited the ability of the lease indenture trustee to accelerate or exercise other remedies with respect to that nonrecourse debt, expired on February 15, 2013. A new forbearance agreement is currently being negotiated by the parties. MWG has not determined whether to assume or reject those leases. MWG did not make its scheduled rent payments (which related to the prior six month period) totaling approximately $48 million on the Powerton and Joliet leases due on January 2, 2013, most of which is a pre-petition bankruptcy claim. Rental for the utilization of the facilities by MWG during pendency of the bankruptcy will likely be treated as an administrative expense in bankruptcy. In mid-February, pursuant to the terms of the forbearance agreement, a rental payment of approximately $5 million was received covering the period from the date of the petition filing through January 2, 2013.

On December 13, 2011, indirect subsidiary companies of Energy Holdings and Dynegy Incorporated (Dynegy) reached a settlement agreement resolving disputes that had arisen between them with regard to Dynegy Holding’s (DH) rejection of the Dynegy leases. The settlement agreement resolved certain disputes regarding Energy Holdings' Dynegy leases, including claims under Tax Indemnity Agreements that indirect subsidiaries of Energy Holdings have with DH. The original terms of the settlement agreement included a cash payment to Energy Holdings of $7.5 million, which was received on January 4, 2012, and an allowed claim in Bankruptcy Court of $110 million against DH. On December 30, 2011, the effective date of the court order authorizing the Dynegy lease rejections, the leases no longer qualified for leveraged lease accounting treatment under GAAP. As a result, Energy Holdings wrote off the $264 million gross lease investment against the previously recorded reserve. The Energy Holdings' indirect subsidiary companies that are owners/lessors of the two plants 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).

On June 1, 2012, an amended and restated settlement agreement entered into by DH, Dynegy and their creditors (including indirect subsidiary companies of Energy Holdings) was approved by the Bankruptcy Court. The agreement allocated proceeds from the sale of the facilities to pay DH’s creditors, including the lease bondholders, and grants the lease bondholders claims in agreed upon amounts against DH in its bankruptcy proceedings. The settlement agreement also included an exchange of releases by various settling claimants, including parties to the leases with respect to claims arising out of the leases. On October 1, 2012, Dynegy emerged from bankruptcy and distributed cash and stock settlements to the claimants. The total recovery of Energy Holdings' indirect subsidiary companies from the Dynegy leases was approximately $63 million, of which $50 million was recorded in Operating Revenues in the fourth quarter of 2012.

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.

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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 to be between $2.2 billion and $2.4 billion, including contingencies. The liability for decommissioning recorded on a discounted basis as of December 31, 2012 was approximately $348 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. In September 2012, Power revised the asset structure for a portion of its NDT Fund and realized gains of $59 million. The investments were transitioned to new investment managers to remove under-performing managers.

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, 2012
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	648	$	147	$	(6	)	$	789
Debt Securities
Government Obligations	274		11		—			285
Other Debt Securities	320		22		—			342
Total Debt Securities	594		33		—			627
Other Securities	124		—		—			124
Total NDT Available-for-Sale Securities	$	1,366	$	180	$	(6	)	$	1,540




	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		—			359
Other Debt Securities	268		15		(2		)	281
Total Debt Securities	611		31		(2		)	640
Other Securities	24		—		—			24
Total NDT Available-for-Sale Securities	$	1,217	$	157	$	(25	)	$	1,349

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, 2012		As of December 31, 2011
	Millions
Accounts Receivable	$	18	$	27
Accounts Payable	$	53	$	22

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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, 2012									As of December 31, 2011
	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
	Millions
Equity Securities (A)	$	139	$	(6	)	$	—	$	—	$	183	$	(23	)	$	—	$	—
Debt Securities
Government Obligations (B)	34		—			1		—		20		—			3		—
Other Debt Securities (C)	31		—			6		—		56		(1		)	4		(1		)
Total Debt Securities	65		—			7		—		76		(1		)	7		(1		)
NDT Available-for-Sale Securities	$	204	$	(6	)	$	7	$	—	$	259	$	(24	)	$	7	$	(1	)


(A)	Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily 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, 2012.

(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 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, 2012.

(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, 2012.

The proceeds from the sales of and the net realized gains on securities in the NDT Fund were:




	Years Ended December 31,
	2012			2011			2010
	Millions
Proceeds from Sales	$	1,433		$	1,355		$	958
Net Realized Gains:
Gross Realized Gains	$	153		$	144		$	119
Gross Realized Losses	(52		)	(45		)	(39		)
Net Realized Gains (Losses) on NDT Fund	$	101		$	99		$	80

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 $84 million (after-tax) are included in Accumulated Other Comprehensive Loss on Power’s Consolidated Balance Sheet as of December 31, 2012.

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The available-for-sale debt securities held as of December 31, 2012 had the following maturities:




Time Frame	Fair Value
	Millions
Less than one year	$	18
1 - 5 years	136
6 - 10 years	176
11 - 15 years	42
16 - 20 years	10
Over 20 years	245
Total NDT Available-for-Sale Debt Securities	$	627

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 2012, other-than-temporary impairments of $18 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.

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 a “Rabbi Trust.”

In March 2012, PSEG restructured the fixed income component of its Rabbi Trust and realized a gain of $5 million. 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.

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, 2012
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	Millions
Equity Securities	$	13	$	5	$	—	$	18
Debt Securities
Government Obligations	114		3		—		117
Other Debt Securities	45		2		—		47
Total Debt Securities	159		5		—		164
Other Securities	3		—		—		3
Total Rabbi Trust Available-for-Sale Securities	$	175	$	10	$	—	$	185

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	As of December 31, 2011
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	Millions
Equity Securities	$	16	$	3	$	—	$	19
Debt Securities	148		5		—		153
Total Rabbi Trust Available-for-Sale Securities	$	164	$	8	$	—	$	172

As of December 31, 2012, amounts in the above table do not include Accounts Receivable of $4 million and Accounts Payable of $5 million for Rabbi Trust Fund transactions which had not yet settled. These amounts are included on the Consolidated Balance Sheets.




	Years Ended December 31,
	2012		2011		2010
	Millions
Proceeds from Rabbi Trust Sales	$	233	$	—	$	158
Net Realized Gains (Losses):
Gross Realized Gains	$	6	$	—	$	31
Gross Realized Losses	—		—		—
Net Realized Gains (Losses) on Rabbi Trust	$	6	$	—	$	31

Gross realized gains disclosed in the above table were recognized in Other Income in the Consolidated Statements of Operations. Net unrealized gains of $6 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets as of December 31, 2012. The Rabbi Trust available-for-sale debt securities held as of December 31, 2012 had the following maturities:




Time Frame	Fair Value
	Millions
Less than one year	$	—
1 - 5 years	60
6 - 10 years	31
11 - 15 years	9
16 - 20 years	5
Over 20 years	59
Total Rabbi Trust Available-for-Sale Debt Securities	$	164

The cost of these securities was determined on the basis of specific identification.

PSEG 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, the Rabbi Trust is invested in a commingled indexed mutual fund. Due to the commingled nature of this fund, 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. 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). 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. In 2012, there were no other-than-temporary impairments recognized on investments of the Rabbi Trust.

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




	As of December 31, 2012		As of December 31, 2011
	Millions
Power	$	36	$	33
PSE&G	61		57
Other	88		82
Total Rabbi Trust Available-for-Sale Securities	$	185	$	172

Note 10. Goodwill and Other Intangibles

As of each of December 31, 2012 and 2011, Power had goodwill of $16 million related to the Bethlehem Energy Center. Power conducted an annual review for goodwill impairment as of October 31, 2012 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, 2012 and 2011, Power had intangible assets of $34 million and $131 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. As load is served under contracts requiring energy from renewable sources, the related expense is recorded. Such expenses for the years ended December 31, 2012, 2011 and 2010 were as follows:




	Years Ended December 31,
	2012		2011		2010
	Millions
Emissions Expense	$	5	$	35	$	52
Renewable Energy Expense	$	34	$	43	$	50

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 in accordance with NRC requirements. To estimate this decommissioning obligation related to its nuclear power plants, Power uses a probability weighted, discounted cash flow model which, on a unit by unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning studies, cost escalation rates, inflation rates and discount rates. 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 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.

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The changes to the ARO liabilities for PSEG, Power and PSE&G during 2011 and 2012 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		)	—
Liabilities Incurred	2			—			2			—
Accretion Expense	19			18			—			1
Accretion Expense Deferred and Recovered in Rate Base (A)	13			—			13			—
ARO Liability as of December 21, 2011	$	489		$	259		$	226		$	4
Liabilities Settled	(5		)	(1		)	(5		)	1
Liabilities Incurred	11			1			7			3
Accretion Expense	21			21			—			—
Accretion Expense Deferred and Recovered in Rate Base (A)	14			—			14			—
Revisions to Present Values of Estimated Cash Flows	97			89			8			—
ARO Liability as of December 31, 2012	$	627		$	369		$	250		$	8


(A)	Not reflected as expense in Consolidated Statements of Operations

During 2012, Power recorded an increase in its ARO liabilities, primarily due to an increase in the estimated cost to decommission its nuclear power plants and increased accretion. The increase in the estimated costs to decommission Power's nuclear plants resulted primarily from the receipt of updated decommissioning cost studies in 2012 and the impact of lower discount rates. This change in the ARO did not result in any material impact in Power's Consolidated Statement of Operations.

Note 12. Pension, 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.

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, 2012 and 2011. It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years.

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	Pension Benefits						Other Benefits
	2012			2011			2012				2011
	Millions
Change in Benefit Obligation:
Benefit Obligation at Beginning of Year	$	4,572		$	4,353		$	1,338			$	1,162
Service Cost	101			92			17				14
Interest Cost	223			228			65				61
Actuarial (Gain) Loss	586			300			182				179
Gross Benefits Paid	(248		)	(236		)	(69		)		(67		)
Medicare Subsidy Receipts	—			—			5				6
Plan Amendments	—			(165		)	—				(17		)
Special Termination Benefits	1			—			—				—
Benefit Obligation at End of Year	$	5,235		$	4,572		$	1,538			$	1,338
Change in Plan Assets:
Fair Value of Assets at Beginning of Year	$	3,831		$	3,555		$	211			$	195
Actual Return on Plan Assets	541			87			31				5
Employer Contributions	233			425			75				72
Gross Benefits Paid	(248		)	(236		)	(69		)		(67		)
Medicare Subsidy Receipts	—			—			5				6
Fair Value of Assets at End of Year	$	4,357		$	3,831		$	253			$	211
Funded Status:
Funded Status (Plan Assets less Benefit Obligation)	$	(878	)	$	(741	)	$	(1,285	)		$	(1,127	)
Additional Amounts Recognized in the Consolidated Balance Sheets:
Noncurrent Assets	$	6		$	—		$	—		—	$	—
Current Accrued Benefit Cost	(8		)	(7		)	—				—
Noncurrent Accrued Benefit Cost	(876		)	(734		)	(1,285		)		(1,127		)
Amounts Recognized	$	(878	)	$	(741	)	$	(1,285	)		$	(1,127	)
Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (A):
Net Transition Obligation	$	—		$	—		$	—			$	2
Prior Service Cost	(139		)	(158		)	(67		)		(81		)
Net Actuarial Loss	2,174			1,991			527				390
Total	$	2,035		$	1,833		$	460			$	311


(A)	Includes $827 million ($485 million, after-tax) and $745 million ($438 million, after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2012 and 2011, 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, 2012, PSEG had funded approximately 83% of its projected benefit obligation. This percentage does not include $185 million of assets in the Rabbi Trust as of December 31, 2012, 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.

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Accumulated Benefit Obligation

The accumulated benefit obligation for all PSEG’s defined benefit pension plans was $4.9 billion as of December 31, 2012 and $4.3 billion as of December 31, 2011.

The following table provides the components of net periodic benefit cost for the years ended December 31, 2012, 2011 and 2010.




	Pension Benefits Years Ended December 31,									Other Benefits Years Ended December 31,
	2012			2011			2010			2012			2011			2010
	Millions
Components of Net Periodic Benefit Cost:
Service Cost	$	101		$	92		$	87		$	17		$	14		$	16
Interest Cost	223			228			231			65			61			72
Expected Return on Plan Assets	(306		)	(334		)	(266		)	(17		)	(18		)	(14		)
Amortization of Net
Transition Obligation	—			—			—			2			4			27
Prior Service Cost	(18		)	(11		)	—			(14		)	(13		)	13
Actuarial Loss	167			119			122			31			14			8
Net Periodic Benefit Cost	$	167		$	94		$	174		$	84		$	62		$	122
Special Termination Benefits	1			—			—			—			—			—
Effect of Regulatory Asset	—			—			—			19			19			19
Total Benefit Costs, Including Effect of Regulatory Asset	$	168		$	94		$	174		$	103		$	81		$	141

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,
	2012		2011		2010		2012		2011		2010
	Millions
Power	$	52	$	29	$	54	$	18	$	12	$	17
PSE&G	97		51		97		82		67		120
Other	19		14		23		3		2		4
Total Benefit Costs	$	168	$	94	$	174	$	103	$	81	$	141

The following table provides the pre-tax changes recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Deferred Assets:




	Pension						OPEB
	2012			2011			2012			2011
	Millions
Net Actuarial (Gain) Loss in Current Period	$	350		$	547		$	169		$	192
Amortization of Net Actuarial Gain (Loss)	(167		)	(119		)	(32		)	(14		)
Prior Service Credit in Current Period	—			(165		)	—			(17		)
Amortization of Prior Service Credit	19			11			14			13
Amortization of Transition Asset	—			—			(2		)	(4		)
Total	$	202		$	274		$	149		$	170

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Amounts that are expected to be amortized from Accumulated Other Comprehensive Loss, Regulatory Assets and Deferred Assets into Net Periodic Benefit Cost in 2013 are as follows:




	Pension Benefits			Other Benefits
	2013			2013
	Millions
Actuarial (Gain) Loss	$	188		$	43
Prior Service Cost	$	(19	)	$	(14	)

The following assumptions were used to determine the benefit obligations and net periodic benefit costs:




	Pension Benefits						Other Benefits
	2012		2011		2010		2012			2011			2010
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31:
Discount Rate	4.20	%	5.00	%	5.51	%	4.20		%	5.00		%	5.50		%
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	5.00	%	5.40	%	5.91	%	5.00		%	5.38		%	5.90		%
Expected Return on Plan Assets	8.00	%	8.50	%	8.50	%	8.00		%	8.50		%	8.50		%
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							3.00		%	5.00		%	5.00		%
Dental Costs							6.00		%	6.00		%	6.00		%
Pre-65 Medical Costs
Immediate Rate							8.88		%	8.00		%	7.75		%
Ultimate Rate							5.00		%	5.00		%	5.00		%
Year Ultimate Rate Reached							2023			2016			2015
Post-65 Medical Costs
Immediate Rate							7.98		%	8.25		%	8.75		%
Ultimate Rate							5.00		%	5.00		%	5.00		%
Year Ultimate Rate Reached							2019			2017			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							$	12		$	11		$	10
Postretirement Benefit Obligation							$	180		$	155		$	122
Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs:
Total of Service Cost and Interest Cost							$	(9	)	$	(9	)	$	(8	)
Postretirement Benefit Obligation							$	(149	)	$	(128	)	$	(102	)

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. The investments in the pension and OPEB plans are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. 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 relationship of the interest of each plan to the total of the interests of the participating

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plans. As of December 31, 2012, the pension plan interest and OPEB plan interest in such assets of the Master Trust were approximately 94% and 6%, respectively.

The following tables present information about the investments measured at fair value on a recurring basis as of December 31, 2012 and 2011, including the fair value measurements and the levels of inputs used in determining those fair values.




	Recurring Fair Value Measurements as of December 31, 2012
			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)	$	67	$	—	$	67	$	—
Common Stocks (B)
Commingled—United States	1,928		1,928		—		—
Commingled—International	839		839		—		—
Other	431		431		—		—
Bonds (C)
Government (United States & Foreign)	623		—		623		—
Other	691		—		691		—
Private Equity (E)	31		—		—		31
Total	$	4,610	$	3,198	$	1,381	$	31




	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	$	—	$	32	$	—
Common Stocks (B)
Commingled—United States	1,653		1,653		—		—
Commingled—International	603		603		—		—
Other	356		356		—		—
Bonds (C)
Government (United States & Foreign)	662		—		662		—
Other	663		—		663		—
Pooled Real Estate (D)	36		—		—		36
Private Equity (E)	37		—		—		37
Total	$	4,042	$	2,612	$	1,357	$	73


(A)	Certain temporary investment funds are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (primarily Level 2).


(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).

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(D)	The fair value of real estate investments is based on 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, 2012 and 2011 follow:




	Balance as of January 1, 2012		Purchases/ (Sales)			Transfer In/ (Out)		Actual Return on Asset Sales		Actual Return on Assets Still Held			Balance as of December 31, 2012
	Millions
Pooled Real Estate	$	36	$	(38	)	$	—	$	2	$	—		$	—
Private Equity	$	37	$	(6	)	$	—	$	5	$	(5	)	$	31




	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	$	—		$	(23	)	$	—	$	—		$	—
Commingled Bonds—United States	$	8	$	(8	)	$	—		$	—	$	—		$	—
Pooled Real Estate	$	48	$	(18	)	$	—		$	1	$	5		$	36
Private Equity	$	38	$	(5	)	$	—		$	7	$	(3	)	$	37


(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).

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	2012		2011
Equity Securities	69	%	64	%
Fixed Income Securities	29		33
Real Estate Assets	—		1
Other Investments	2		2
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

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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 8.00% as of December 31, 2012 and will remain unchanged for 2013. 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 9.3%.

Plan Contributions

PSEG may contribute up to $145 million into its pension plans and $14 million into its OPEB plan for calendar year 2013.

Estimated Future Benefit Payments

The following pension benefit and postretirement benefit payments are expected to be paid to plan participants.





Year	Pension Benefits		Other Benefits
	Millions
2013	$	254	$	79
2014	260		80
2015	267		82
2016	274		84
2017	284		85
2018-2022	1,592		459
Total	$	2,931	$	869

401(k) Plans

PSEG sponsors two 401(k) plans, which are Employee Retirement Income Security Act defined contribution retirement plans. Eligible represented employees of PSEG's subsidiaries participate in the PSEG Employee Savings Plan (Savings Plan), while eligible non-represented employees of PSEG's subsidiaries participate in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). Eligible employees may contribute up to 50% of their compensation to these plans. PSEG matches 50% of such employee contributions up to 7% of pay for Savings Plan participants and up to 8% of pay for Thrift Plan participants.

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,
	2012		2011		2010
	Millions
Power	$	10	$	8	$	5
PSE&G	18		14		9
Other	4		2		3
Total Employer Matching Contributions	$	32	$	24	$	17

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.

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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.

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.

In addition to the guarantees discussed above, Power has also provided payment guarantees to third parties on behalf of its affiliated companies. These guarantees support various other non-commodity related contractual obligations.

The face value of outstanding guarantees, current exposure and margin positions as of December 31, 2012 and 2011 are shown below:




	As of December 31, 2012			As of December 31, 2011
	Millions
Face Value of Outstanding Guarantees	$	1,508		$	1,756
Exposure under Current Guarantees	$	226		$	315
Letters of Credit Margin Posted	$	124		$	135
Letters of Credit Margin Received	$	69		$	91
Cash Deposited and Received
Counterparty Cash Margin Deposited	$	15		$	20
Counterparty Cash Margin Received	$	(4	)	$	(7	)
Net Broker Balance Deposited (Received)	$	26		$	(92	)
In the Event Power were to Lose its Investment Grade Rating:
Additional Collateral that could be Required	$	654		$	812
Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral	$	3,531		$	3,415
Additional Amounts Posted
Other Letters of Credit	$	45		$	52

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 PSEG's 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 are 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 S&P ratings or a three level downgrade from its current Moody’s and Fitch ratings, many of these agreements allow the counterparty to demand further performance assurance. See table above.

During 2012, the SEC and the Commodity Futures Trading Commission (CFTC) continued efforts to implement new rules to enact stricter regulation over swaps and derivatives. The CFTC has issued Final Rules regarding the definition of a swap dealer

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and the definition of a swap. However, in September 2012, a federal court vacated the CFTC's rule on monitoring of position limits for several commodities, including natural gas, thereby indefinitely delaying the effectiveness of these position limits rules. The CFTC has appealed the court's decision to vacate the position limits rules. PSEG is carefully monitoring all of these new rules as they are issued to analyze the potential impact on its swap and derivatives transactions, including any potential increase in its collateral requirements.

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.

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 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 certain 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 Remedial Investigation and Feasibility Study (RI/FS) would greatly exceed the original estimated cost of $20 million. The total cost of the RI/FS is now estimated at approximately $110 million. Seventy-three PRPs, including Power and PSE&G, agreed to assume responsibility for the RI/FS and formed the Cooperating Parties Group (CPG) to divide the associated costs according to a mutually agreed upon formula. The CPG group, currently 70 members, is presently executing the RI/FS. Approximately five percent of the RI/FS 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 EPA estimated costs for the proposed remedy range from $1.3 billion to $3.7 billion. The work contemplated by the FFS is not subject to the cost sharing agreement discussed above. The EPA's revised proposed FFS may be released for public comment as early as April 2013.

In June 2008, an agreement was announced between the EPA and Tierra Solutions, Inc. and Maxus Energy Corporation (Tierra/Maxus) for removal of a portion of the contaminated sediment in the Passaic River at an estimated cost of $80 million. Phase I of the removal work has been completed. Phase II is contingent on the approval of an appropriate sediment disposal facility. Tierra/Maxus 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 will require removal in advance of the completion of the RI/FS. The CPG members, with the exception of Tierra/Maxus, which are no longer members, have agreed to fund the removal, currently estimated at approximately $30 million. PSEG’s share of that effort is approximately three percent.

Except for the Passaic River 10.9 mile removal, Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to the Passaic River matters.

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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 of the clean-up costs for the hazardous substances it 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 complaints in June 2010. A special master for discovery has been appointed by the court and document production has commenced. In October 2012, the Court issued a 90 day stay of discovery for the third party defendants to explore a possible settlement of this matter with the State of New Jersey. The original stay has been extended, most recently until March 23, 2013, and is likely to be extended again, to permit the parties to continue forward with a settlement process. 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 $588 million and $675 million through 2021. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $588 million as of December 31, 2012. Of this amount, $113 million was recorded in Other Current Liabilities and $475 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $588 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 (CAA), require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets, in some circumstances, when those sources undergo a “major modification,” as defined in the regulations. The federal government may order companies that are not in compliance with the PSD/NSR regulations to install the best available 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.

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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 CAA. The notice of violation states that the EPA may issue an order requiring compliance with the relevant CAA 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 ruling of the U.S. Court of Appeals of the District of Columbia (Court of Appeals), the EPA published a Maximum Achievable Control Technology (MACT) regulation on February 16, 2012. These Mercury Air Toxics Standards (MATS) are scheduled to go into effect on April 16, 2015 and establish allowable emission levels for mercury as well as other hazardous air pollutants pursuant to the CAA. In February 2012, members of the electric generating industry filed a petition challenging the existing source National Emission Standard for Hazardous Air Pollutants (NESHAP), new source NESHAP and the New Source Performance Standard (NSPS). In March 2012, PSEG filed a motion to intervene with the Court of Appeals in support of the EPA's implementation of MATS. Litigation of these matters remains pending and the impact on the implementation schedule is unknown at this time.

Power believes that it will not be necessary to install any material controls at its other New Jersey facilities. Additional controls may be necessary at Power’s Bridgeport Harbor coal-fired unit at an immaterial cost. In December 2011, to comply with the MACT regulators, 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 first quarter of 2015. Power's share of this investment is approximately $147 million.

NOx Regulation

In April 2009, the NJDEP finalized revisions to NO_xemission control regulations that impose new NO_xemission reduction requirements and limits for New Jersey fossil fuel-fired electric generation units. The rule has an impact on Power’s generation fleet, as it imposes NO_x emissions limits that will require capital investment for controls or the retirement of up to 86 combustion turbines (approximately 1,750 MW) and four older New Jersey steam electric generation units (approximately 400 MW) by May 30, 2015. Retirement notifications for the combustion turbines, except for Salem Unit 3, have been filed with PJM. The Salem Unit 3 combustion turbine (38 MW) will be transitioning to an emergency generator. Evaluations are ongoing for the steam electric generation units.

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.

Clean Water Act Permit Renewals

Pursuant to the Federal Water Pollution Control Act (FWPCA), National Pollutant Discharge Elimination System (NPDES) 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. States with delegated federal authority for this program manage these permits. The New Jersey Department of Environmental Protection manages the permits under the New Jersey Pollutant Discharge Elimination System (NJPDES) program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs.

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.

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 late 2010, the EPA entered into a settlement agreement with environmental groups that established a schedule to develop a new 316(b) rule by July 27, 2012. 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

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mortality standards for existing cooling water intake structures with a design flow of more than two million gallons per day. In June 2012, the EPA posted two Notices of Data Availability (NODA) requesting comment on aspects of the April 2011 proposed rule. In July 2012, PSEG and industry trade associations submitted comments on both NODAs and the EPA and environmental groups agreed to delay the deadline for finalization of the Rule to June 27, 2013 to allow for more time to address public comments and analyze data submitted in response to the NODAs.

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, results of operations or cash flows. 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.

Capital Expenditures

The construction programs of PSEG and its subsidiaries are currently estimated to include a base level total investment of approximately $6.1 billion for the three years ended 2015. The three year capital expenditures for PSEG, Power and PSE&G are as follows:




	2013		2014		2015
	Millions
Power	$	400	$	365	$	305
PSE&G	2,040		1,680		1,180
Other	95		40		30
Total PSEG	$	2,535	$	2,085	$	1,515

Power's projected capital expenditures include baseline maintenance, investments in response to environmental or legal mandates and nuclear expansion. PSE&G's projections include material additions and replacements in its transmission and distribution systems to meet expected growth and manage reliability.

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.

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.

PSE&G has contracted for its anticipated BGS-Fixed Price eligible load, as follows:




	Auction Year
	2010	2011	2012	2013
36-Month Terms Ending	May 2013	May 2014	May 2015	May 2016	(A)
Load (MW)	2,800	2,800	2,900	2,800
$ per kWh	0.09577	0.09430	0.08388	0.09218


(A)	Prices set in the 2013 BGS auction will become effective on June 1, 2013 when the 2010 BGS auction agreements expire.

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PSE&G has a full requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. 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. 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. For additional information, see Note 23. Related-Party Transactions.

Minimum Fuel Purchase Requirements

Power has various long-term fuel purchase commitments for coal through 2017 to support its fossil generation stations and for supply of nuclear fuel for the Salem, Hope Creek and Peach Bottom nuclear generating stations and for firm transportation and storage capacity for natural gas.

Power’s strategy is to maintain certain levels of uranium and to make periodic purchases to support such levels. As such, the commitments referred to in the following table 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 through 2017 at Salem, Hope Creek and Peach Bottom.

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.

As of December 31, 2012, the total minimum purchase requirements included in these commitments were as follows:




Fuel Type	Power’s Share of Commitments through 2017
	Millions
Nuclear Fuel
Uranium	$	518
Enrichment	$	453
Fabrication	$	146
Natural Gas	$	939
Coal	$	555

Regulatory Proceedings

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. In late 2012, the BPU approved additional funding requirements for these programs for the first half of 2013. The aggregate funding for the first half of 2013 is $195 million. PSE&G’s share is $153 million which it recorded as a current liability as of December 31, 2012. 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 recovered from PSE&G ratepayers through the 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 2011, New Jersey enacted the LCAPP Act that resulted in the selection of three generators to build a total of approximately 2,000 MW of new combined-cycle generating facilities located in New Jersey. Each of the New Jersey EDCs, including PSE&G, was directed to execute a standard offer capacity agreement (SOCA) with the three selected generators, but did so under protest preserving their legal rights. The SOCA provides for the EDCs to guarantee specified annual capacity payments to the generators subject to the terms and conditions of the agreement. Legal challenges to the BPU’s implementation of the LCAPP Act were filed in New Jersey appellate court and this appeal is pending. In addition, the LCAPP Act itself has been challenged on constitutional grounds in federal court.

In May 2012, two of the three generators cleared the Reliability Pricing Model auction for the 2015/2016 delivery year in the aggregate notional amount of approximately 1,300 MW of installed capacity. SOCA payments are for a 15 year term, which are scheduled to commence for one of the generators in the 2015/2016 delivery year and for the other generator in the 2016/2017

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delivery year. Based upon the expected percentage of state load that PSE&G will be serving during the term of these contracts, PSE&G would be responsible for approximately 52% or 676 MW of this amount.

Under current accounting guidance, the current estimated fair value of the SOCAs is recorded as a Derivative Asset or Liability with an offsetting Regulatory Asset or Liability on PSE&G’s Consolidated Balance Sheets. See Note 17. Fair Value Measurements for additional information.

Superstorm Sandy

In late October 2012, Superstorm Sandy caused severe damage to PSE&G's transmission and distribution system throughout its service territory as well as to some of Power's generation infrastructure in the northern part of New Jersey. Strong winds resulted in a storm surge that caused damage to switching stations, substations and generating infrastructure.

As of December 31, 2012, Power had incurred approximately $85 million in costs related to Superstorm Sandy, primarily comprised of repairs at certain generating stations and damage to materials and supplies, both at our fossil fleet. All the costs were recognized in Operation and Maintenance Expense, offset by $19 million of a pending future recovery of insurance proceeds. Power expects that it will incur additional future costs, primarily relating to repairs to, and replacement of, equipment and property, which could be material.

PSEG maintains insurance coverage against loss or damage to plants and certain properties, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost. PSEG is seeking recovery from its insurers for the property damage, above its self-insured retentions; however, no assurances can be given relative to the timing or amount of such recovery. PSEG received an authorization for $25 million from its insurance carriers as an advance payment which was recorded in 2012. PSEG believes that additional insurance recoveries are not estimable as of December 31, 2012. PSEG is at the early stages of documenting its insurance claim which then will need to be submitted to and reviewed by its insurers. PSEG does not believe that it has a basis for estimating additional probable insurance recoveries at this time.

Leveraged Lease Investments

On January 31, 2012, PSEG entered into a specific matter closing agreement with the Internal Revenue Service (IRS) settling all matters related to cross border lease transactions. This agreement settles the leasing dispute with finality for all tax periods in which PSEG realized tax deductions from these transactions. On January 31, 2012, PSEG also signed a Form 870-AD settlement agreement covering all audit issues for tax years 1997 through 2003. On March 26, 2012, PSEG executed a Form 870-AD settlement agreement covering all audit issues for tax years 2004 through 2006. These two agreements conclude ten years of audits for PSEG and the leasing issue for all tax years. For PSEG, the impact of these agreements is an increase in financial statement Income Tax Expense of approximately $175 million. In prior periods, PSEG had established financial statement tax liabilities for uncertain tax positions in the amount of $246 million with respect to these tax years. Accordingly, the settlement resulted in a net $71 million decrease in the Income Tax Expense of PSEG.

Cash Impact

For tax years 1997 through 2003, the tax and interest PSEG owes the IRS as a result of this settlement will be reduced by the $320 million PSEG has on deposit with the IRS for this matter. PSEG paid a net deficiency for these years of approximately $4 million during the second quarter of 2012. Based upon the closing agreement and the Form 870-AD for tax years 2004 through 2006, PSEG owes the IRS approximately $620 million in tax and interest for tax years from 2004 through 2006. Based on the settlement of the leasing dispute, for tax years 2007 through 2010, the IRS owes PSEG approximately $676 million. PSEG has filed amended returns for tax years 2007-2010 reflecting the impact of the settlement. These returns have been audited by the IRS and accepted as filed. As required by statute, the IRS presented the refund claim to the Joint Committee on Taxation for approval. On October 16, 2012, PSEG was notified that the Joint Committee took no exception to the refund claim. The IRS is now processing those claims and preparing interest computations. In spite of the progress noted above, it is still possible that PSEG would have to pay $620 million over the next year to the IRS and wait while the IRS processes the $676 million refund claim 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

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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 United States 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 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)	$	—
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		$	22
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		$	35
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 United States 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

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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.

(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

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, 2012 are:




	PSEG		Power		PSE&G		Energy Holdings
	Millions
2013	$	—	$	—	$	7	$	2
2014	—		1		6		2
2015	3		1		3		2
2016	12		1		3		2
2017	13		1		3		1
Thereafter	186		4		32		12
Total Minimum Lease Payments	$	214	$	8	$	54	$	21

Note 14. Schedule of Consolidated Debt

Long-Term Debt




	As of December 31,
	2012			2011
	Millions
PSEG (Parent)
Fair Value of Swaps (A)	$	57		$	62
Unamortized Discount Related to Debt Exchange (B)	(19		)	(23		)
Total Long-Term Debt of PSEG (Parent)	$	38		$	39

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		As of December 31,
	Maturity	2012			2011
		Millions
Power
Senior Notes:
2.50%	2013	$	300		$	300
5.00%	2014	—			250
5.50%	2015	300			300
5.32%	2016	303			303
2.75%	2016	250			250
5.13%	2020	406			406
4.15%	2021	250			250
8.63%	2031	500			500
Total Senior Notes		2,309			2,559
Pollution Control Notes:
Floating Rate (C)	2014	44			44
5.00%	2012	—			66
5.50%	2020	—			14
5.85%	2027	—			19
5.75%	2031	—			25
5.75%	2037	—			40
Total Pollution Control Notes		44			208
Principal Amount Outstanding		2,353			2,767
Amounts Due Within One Year		(300		)	(66		)
Net Unamortized Discount		(13		)	(16		)
Total Long-Term Debt of Power		$	2,040		$	2,685

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		As of December 31,
	Maturity	2012			2011
		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
5.45%	2032	—			50
Floating rate (C)	2033	50			—
Floating rate (C)	2046	50			—
Total Pollution Control Bonds		100			73
Medium-Term Notes (MTNs) (D):
5.13%	2012	—			300
5.00%	2013	150			150
5.38%	2013	300			300
6.33%	2013	275			275
0.85%	2014	250			250
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
3.95%	2042	450			—
3.65%	2042	350			—
Total MTNs		4,384			3,884
Principal Amount Outstanding		4,804			4,277
Amounts Due Within One Year		(725		)	(300		)
Net Unamortized Discount		(9		)	(7		)
Total Long-Term Debt of PSE&G (excluding Transition Funding and Transition Funding II)		$	4,070		$	3,970

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		As of December 31,
	Maturity	2012			2011
		Millions
Transition Funding (PSE&G)
Securitization Bonds:
6.61%	2011-2013	$	100		$	305
6.75%	2013-2014	220			220
6.89%	2014-2015	370			370
Principal Amount Outstanding		690			895
Amounts Due Within One Year		(214		)	(205		)
Total Securitization Debt of Transition Funding		476			690
Transition Funding II (PSE&G)
Securitization Bonds:
4.34%	2011-2012	—			1
4.49%	2012-2013	9			20
4.57%	2013-2015	23			23
Principal Amount Outstanding		32			44
Amounts Due Within One Year		(12		)	(11		)
Total Securitization Debt of Transition Funding II		20			33
Total Long-Term Debt of PSE&G		$	4,566		$	4,693




		As of December 31,
Energy Holdings	Maturity	2012			2011
		Millions
Non-Recourse Project Debt (E):
Resources - 5.00% to 8.75%	2011-2020	$	44		$	45
Resources - Other (F)	2012	—			50
Principal Amount Outstanding		44			95
Amounts Due Within One Year		(1		)	(51		)
Total Non-Recourse Project Debt		43			44
Total Long-Term Debt of Energy Holdings		$	43		$	44


(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 and The Pollution Control Financing Authority of Salem County bonds for Power and PSE&G, respectively, are variable rate bonds that are in weekly reset mode.


(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.

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(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. Upon settlement of the claims against Dynegy in 2012, Energy Holdings was released from this debt.

Long-Term Debt Maturities

The aggregate principal amounts of maturities for each of the five years following December 31, 2012 are as follows:




			PSE&G						Energy Holdings
Year	Power		PSE&G		Transition Funding		Transition Funding II		Non-Recourse Debt		Total
	Millions
2013	$	300	$	725	$	214	$	12	$	1	$	1,252
2014	44		500		225		12		1		782
2015	300		300		251		8		17		876
2016	553		171		—		—		7		731
2017	—		—		—		—		1		1
Thereafter	1,156		3,108		—		—		17		4,281
Total	$	2,353	$	4,804	$	690	$	32	$	44	$	7,923

Long-Term Debt Financing Transactions

During 2012, PSEG and its subsidiaries had the following Long-Term Debt issuances, maturities and redemptions:

Power


•	redeemed $250 million of 5.00% Senior Notes due April 1, 2014,

•

redeemed and retired Pollution Control Notes servicing and securing $98 million of tax-exempt financings, including $14 million of 5.50% York County Industrial Development Authority Pollution Control Revenue Refunding Bonds due September 1, 2020; $19 million of 5.85% Indiana County Industrial Development Authority Pollution Control Revenue Refunding Bonds due June 1, 2027; $25 million of 5.75% Pollution Control Financing Authority of Salem County Pollution Control Revenue Refunding Bonds due April 1, 2031; and $40 million of 5.75% Connecticut Development Authority Solid Waste Disposal Facility Revenue Bonds due November 1, 2037,


•	paid $66 million of 5.00% Pollution Control Revenue Refunding Notes at maturity, and


•	paid cash dividends of $600 million to PSEG.

PSE&G


•	remarketed $50 million of weekly-reset variable rate demand bonds of the Pollution Control Financing Authority of Salem County due November 1, 2033, which are serviced and secured by PSE&G's First and Refunding Mortgage Bonds of like tenor,


•	paid $300 million of 5.13% Secured Medium-Term Notes at maturity,


•	issued $350 million of 3.65% Secured Medium-Term Notes, Series H due September 2042,

•

refinanced at par $50 million of 5.45% fixed rate Pollution Control Financing Authority of Salem County Authority Bonds due February 1, 2032, which were serviced and secured by PSE&G’s First and Refunding Mortgage Bonds of like tenor, with $50 million of weekly-reset variable rate demand bonds due April 1, 2046, which are serviced and secured by PSE&G’s First and Refunding Mortgage Bonds of like tenor,


•	redeemed and retired at par $23 million of 5.20% fixed rate Pollution Control Financing Authority of Salem County Authority Bonds due March 1, 2025, which were serviced and secured by PSE&G’s First and Refunding Mortgage Bonds of like tenor,


•	issued $450 million of 3.95% Secured Medium-Term Notes, Series H due May 2042,


•	paid $205 million of Transition Funding’s securitization debt, and

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•	paid $11 million of Transition Funding II’s securitization debt.

Energy Holdings


•	was released from $50 million of nonrecourse project debt related to the Dynegy Leases, and


•	paid cash dividends of $500 million to PSEG.

PSE&G

In January 2013, PSE&G issued $400 million of 3.80% Secured Medium-Term Notes, Series H, due January 2043, and paid $150 million of 5.00% Secured Medium-Term Notes, at maturity.

Short-Term Liquidity

PSEG meets its short-term liquidity requirements 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 our credit facilities are provided by a diverse bank group. As of December 31, 2012, no single institution represented more than 8% of the total commitments in our credit facilities.

As of December 31, 2012, our total credit capacity was in excess of our anticipated maximum 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, 2012 were as follows:




	As of December 31, 2012
Company/Facility	Total Facility		Usage			Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facility	$	500	$	4	(A)	$	496	Mar 2017	Commercial Paper (CP) Support/Funding/Letters of Credit
5-year Credit Facility	500		—			500		Apr 2016	CP Support/Funding/Letters of Credit
Total PSEG	$	1,000	$	4		$	996
Power
5-year Credit Facility	$	1,600	$	65	(A)	$	1,535	Mar 2017	Funding/Letters of Credit
5-year Credit Facility	1,000		—			1,000		Apr 2016	Funding/Letters of Credit
Bilateral Credit Facility	100		100		(A)	—		Sept 2015	Letters of Credit
Total Power	$	2,700	$	165		$	2,535
PSE&G
5-year Credit Facility	$	600	$	276	(B)	$	324	Apr 2016	CP Support/Funding/Letters of Credit
Total PSE&G	$	600	$	276		$	324
Total	$	4,300	$	445		$	3,855


(A)	Includes amounts related to letters of credit outstanding.


(B)	Includes amounts related to CP and letters of credit outstanding

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, 2012 and 2011. See Note 17. Fair Value Measurements for more information on fair value guidance and the hierarchy that prioritizes the inputs to fair value measurements into three levels.

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	December 31, 2012				December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A)	$	38	$	57	$	39	$	62
Power -Recourse Debt (B)	2,340		2,818		2,751		3,158
PSE&G (B)	4,795		5,606		4,270		4,905
Transition Funding (PSE&G) (B)	690		765		895		1,016
Transition Funding II (PSE&G) (B)	32		34		44		47
Energy Holdings:
Project Level, Non-Recourse Debt (C)	44		44		95		95
	$	7,939	$	9,324	$	8,094	$	9,283


(A)	Fair value represents net offsets to debt resulting from adjustments from interest rate swaps entered into to hedge certain debt at Power. Carrying amount represents such fair value reduced by the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings.


(B)	The debt fair valuation is based on the present value of each bond’s future cash flows. The discount rates used in the present value analysis are based on an estimate of new issue bond yields across the treasury curve. When a bond has embedded options, an interest rate model is used to reflect the impact of interest rate volatility into the analysis (primarily Level 2 measurements).

(C)

Fair value amounts as of December 31, 2011 include $50 million of non-recourse project debt related to Dynegy which is classified as a Level 3 measurement. As of the June 5, 2012, the effective date of the amended settlement agreement, the $50 million of Notes Payable was written off. See the Fair Value Option Section of Note 17. Fair Value Measurements for additional information. Non-recourse project debt of $44 million is valued as equivalent to the amortized cost and is classified as a Level 3 measurement.

Note 15. Schedule of Consolidated Capital Stock




	As of December 31,
	Outstanding Shares		Book Value
	2012	2011	2012		2011
			Millions
PSEG Common Stock (no par value) (A)
Authorized 1,000,000,000 shares	505,892,472	505,945,286	$	4,226	$	4,222


(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 2012 or 2011. Total authorized and unissued shares of common stock available for issuance through PSEG’s DRASPP, ESPP and various employee benefit plans amounted to 7 million shares as of December 31, 2012.

As of December 31, 2012, 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.

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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 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 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,


•	the price of fuel to meet its fuel purchase requirements, and


•	certain forecasted natural gas sales and purchases made to support the BGSS contract with PSE&G.

These derivative transactions are designated and effective as cash flow hedges. During the second quarter of 2012, Power de-designated certain of its commodity derivative transactions that had previously qualified as cash flow hedges as they were deemed to no longer be highly effective as required by the relevant accounting guidance. As a result, since June 1, 2012, Power recognizes all gains and losses from changes in the fair value of these derivatives immediately in earnings rather than deferring any such amounts in Accumulated Other Comprehensive Income (Loss). The fair values of Power’s de-designated hedges were frozen in Accumulated Other Comprehensive Income (Loss) as the original forecasted transactions are still expected to occur and are reclassified into earnings as the original derivative transactions settle.

As of December 31, 2012 and 2011, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with accounting hedge activity was as follows:




	As of December 31,
	2012		2011
	Millions
Fair Value of Cash Flow Hedges	$	3	$	57
Impact on Accumulated Other Comprehensive Income (Loss) (after tax)	$	9	$	33

The expiration date of the longest-dated cash flow hedge at Power is in 2014. Power’s after-tax unrealized gains on these derivatives that are expected to be reclassified to earnings during the next 12 months are $8 million. There was no ineffectiveness associated with qualifying hedges as of December 31, 2012.

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 it serves. 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 has not entered into any trading derivative contracts and anticipates that it will not do so in the future.

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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 its 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.

PSE&G is a party to certain long-term natural gas sales contracts to optimize its pipeline capacity utilization. In addition, as further described in Note 13. Commitments and Contingent Liabilities, PSE&G was directed to execute long-term SOCAs with certain generators to support the LCAPP Act. Two of the three generators cleared the Reliability Pricing Model auction for the 2015/2016 delivery year. These two SOCA contracts qualify as derivatives and are marked to fair value with the offset recorded to Regulatory Assets and Liabilities.

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 given period or interest rate environment. In addition, they 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 $250 million of 5% Senior Notes due April 2014 in December 2012, PSEG terminated its $250 million interest rate swap that had converted this debt into variable-rate. As of December 31, 2012, PSEG had seven interest rate swaps outstanding totaling $850 million. These swaps convert 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 forecasted interest payments of the debt. As of December 31, 2012 and 2011, the fair value of all the underlying hedges was $57 million and $62 million, respectively.

Cash Flow Hedges

PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. The Accumulated Other Comprehensive Income (Loss) (after tax) related to interest rate derivatives designated as cash flow hedges was $(2) million as of December 31, 2012 and 2011.

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Fair Values of Derivative Instruments

The following are the fair values of derivative instruments on the Consolidated Balance Sheets:




	As of December 31, 2012
	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	$	3	$	332		$	(217	)	$	118		$	5		$	15	$	138
Noncurrent Assets	—		75			(26		)	49			62			42		153
Total Mark-to-Market Derivative Assets	$	3	$	407		$	(243	)	$	167		$	67		$	57	$	291
Derivative Contracts
Current Liabilities	$	—	$	(265	)	$	219		$	(46	)	$	—		$	—	$	(46	)
Noncurrent Liabilities	—		(41		)	26			(15		)	(107		)	—		(122		)
Total Mark-to-Market Derivative (Liabilities)	$	—	$	(306	)	$	245		$	(61	)	$	(107	)	$	—	$	(168	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	3	$	101		$	2		$	106		$	(40	)	$	57	$	123




	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		$	—		$	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	)	$	—		$	(131	)
Noncurrent Liabilities	(1		)	(76		)	53			(24		)	—			(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

(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, 2012 and December 31, 2011, net cash collateral paid of $2 million and net cash collateral received of $82 million, respectively, was netted against the corresponding net derivative contract positions. Of the $2 million as of December 31, 2012, cash collateral of $(3) million was netted against current assets and cash collateral of $5 million was netted against current liabilities. 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,

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respectively, and cash collateral of $16 million and $2 million were netted against current liabilities and noncurrent liabilities, respectively.

Certain of Power’s derivative instruments contain provisions that require Power to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Power’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 Power were to be downgraded or lose its investment grade credit rating, it would be required to provide additional collateral. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. Power 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 the NYMEX and ICE must adhere to comprehensive collateral and margin 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 the NYMEX and ICE that are fully collateralized) was $98 million and $285 million as of December 31, 2012 and 2011, respectively. As of December 31, 2012 and 2011, Power had the contractual right of offset of $61 million and $149 million, respectively, related to derivative instruments that are assets with the same counterparty under master agreements and net of margin posted. If Power had been downgraded or lost its investment grade rating, it would have had additional collateral obligations of $37 million and $136 million as of December 31, 2012 and 2011, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral. This potential additional collateral is included in the $654 million and $812 million as of December 31, 2012 and 2011, 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, 2012, 2011 and 2010:




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)
Derivatives in Cash Flow Hedging Relationships	Years Ended December 31,									Years Ended December 31,									Years Ended December 31,
	2012			2011			2010			2012			2011			2010			2012		2011			2010
	Millions
PSEG (A)
Energy-Related Contracts	$	32		$	84		$	101	Operating Revenues	$	79		$	213		$	222		$	1	$	(2	)	$	1
Energy-Related Contracts	(4		)	(4		)	1		Energy Costs	(9		)	2			(2		)	—		—			—
Interest Rate Swaps	—			—			—		Interest Expense	—			(1		)	(1		)	—		—			—
Total PSEG	$	28		$	80		$	102		$	70		$	214		$	219		$	1	$	(2	)	$	1
Power
Energy-Related Contracts	$	32		$	84		$	101	Operating Revenues	$	79		$	213		$	222		$	1	$	(2	)	$	1
Energy-Related Contracts	(4		)	(4		)	1		Energy Costs	(9		)	2			(2		)	—		—			—
Total Power	$	28		$	80		$	102		$	70		$	215		$	220		$	1	$	(2	)	$	1


(A)	Includes amounts for PSEG parent.

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The following reconciles the AOCI for derivative activity included in the Accumulated Other Comprehensive Loss of PSEG on a pre-tax and after-tax basis:




AOCI	Pre-Tax			After-Tax
	Millions
Balance as of December 31, 2010	$	188		$	111
Gain Recognized in AOCI	80			47
Less: Gain Reclassified into Income	(214		)	(127		)
Balance as of December 31, 2011	$	54		$	31
Gain Recognized in AOCI	28			17
Less: Gain Reclassified into Income	(70		)	(41		)
Balance as of December 31, 2012	$	12		$	7

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, 2012, 2011 and 2010:




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,
		2012			2011			2010
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	232		$	205		$	(53	)
Energy-Related Contracts	Energy Costs	(19		)	(42		)	(9		)
Total PSEG and Power		$	213		$	163		$	(62	)

Power’s derivative contracts reflected in the preceding tables include contracts to hedge the purchase and sale of electricity and natural gas 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 $22 million, $25 million and $24 million for the years ended December 31, 2012, 2011 and 2010, respectively.

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The following reflects the gross volume, on an absolute value basis, of derivatives as of December 31, 2012 and 2011:




Type	Notional	Total	PSEG	Power	PSE&G
	Millions
As of December 31, 2012
Natural Gas	Dth	596	—	404	192
Electricity	MWh	208	—	208	—
Capacity	MW days	4	—	—	4
FTRs	MWh	19	—	19	—
Interest Rate Swaps	U.S. Dollars	850	850	—	—
Coal	Tons	1	—	1	—
As of December 31, 2011
Natural Gas	Dth	612	—	377	235
Electricity	MWh	137	—	137	—
FTRs	MWh	12	—	12	—
Interest Rate Swaps	U.S. Dollars	1,100	1,100	—	—
Coal	Tons	1	—	1	—

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, 2012, 94% 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, 2012. 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	$	317	$	61	$	313	2	$	165	(A)
Non-Investment Grade—External Rating	22		—		22		—	—
Investment Grade—No External Rating	10		—		10		—	—
Non-Investment Grade—No External Rating	—		—		—		—	—
Total	$	349	$	61	$	345	2	$	165


(A)	Includes net exposure of $119 million with PSE&G. The remaining net exposure of $46 million is with a nonaffiliated power purchaser which is a regulated investment grade counterparty.

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.

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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, 2012, Power had 174 active counterparties.

Note 17. Fair Value Measurements

PSEG, Power and PSE&G adopted accounting standard update “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in GAAP and International Financial Reporting Standards (IFRS)” effective January 1, 2012. This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about 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, 2012, these consisted primarily of electric swaps whose basis is deemed significant to the fair value measurement, electric load deals, long-term electric capacity contracts and long-term gas supply contracts.

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, 2012 and December 31, 2011, 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.

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	Recurring Fair Value Measurements as of December 31, 2012
Description	Total			Cash Collateral Netting (E)			Quoted Market Prices for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	234		$	(3	)	$	—	$	157		$	80
Interest Rate Swaps (B)	$	57		$	—		$	—	$	57		$	—
NDT Fund (C)
Equity Securities	$	789		$	—		$	789	$	—		$	—
Debt Securities—Govt Obligations	$	285		$	—		$	—	$	285		$	—
Debt Securities—Other	$	342		$	—		$	—	$	342		$	—
Other Securities	$	124		$	—		$	—	$	124		$	—
Rabbi Trust (C)
Equity Securities—Mutual Funds	$	18		$	—		$	18	$	—		$	—
Debt Securities—Govt Obligations	$	117		$	—		$	—	$	117		$	—
Debt Securities—Other	$	47		$	—		$	—	$	47		$	—
Other Securities	$	3		$	—		$	—	$	3		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(168	)	$	5		$	—	$	(62	)	$	(111	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	167		$	(3	)	$	—	$	157		$	13
NDT Fund (C)
Equity Securities	$	789		$	—		$	789	$	—		$	—
Debt Securities—Govt Obligations	$	285		$	—		$	—	$	285		$	—
Debt Securities—Other	$	342		$	—		$	—	$	342		$	—
Other Securities	$	124		$	—		$	—	$	124		$	—
Rabbi Trust (C)
Equity Securities—Mutual Funds	$	3		$	—		$	3	$	—		$	—
Debt Securities—Govt Obligations	$	23		$	—		$	—	$	23		$	—
Debt Securities—Other	$	9		$	—		$	—	$	9		$	—
Other Securities	$	1		$	—		$	—	$	1		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(61	)	$	5		$	—	$	(62	)	$	(4	)
PSE&G
Assets:
Derivative Contracts:
Energy Related Contracts (A)	$	67		$	—		$	—	$	—		$	67
Rabbi Trust (C)
Equity Securities—Mutual Funds	$	6		$	—		$	6	$	—		$	—
Debt Securities—Govt Obligations	$	39		$	—		$	—	$	39		$	—
Debt Securities—Other	$	15		$	—		$	—	$	15		$	—
Other Securities	$	1		$	—		$	—	$	1		$	—
Liabilities:
Derivative Contracts:
Energy Related Contracts (A)	$	(107	)	$	—		$	—	$	—		$	(107	)

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	Recurring Fair Value Measurements as of December 31, 2011
Description	Total			Cash Collateral Netting (E)			Quoted Market Prices for 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	)	$	—	$	257		$	41
Interest Rate Swaps (B)	$	64		$	—		$	—	$	64		$	—
NDT Fund (C)
Equity Securities	$	685		$	—		$	685	$	—		$	—
Debt Securities—Govt Obligations	$	359		$	—		$	—	$	359		$	—
Debt Securities—Other	$	281		$	—		$	—	$	281		$	—
Other Securities	$	24		$	—		$	—	$	24		$	—
Rabbi Trust—Mutual Funds (C)	$	172		$	—		$	19	$	153		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(155	)	$	18		$	—	$	(153	)	$	(20	)
Interest Rate Swaps (B)	$	(2	)	$	—		$	—	$	(2	)	$	—
Non-Recourse Debt (D)	$	(50	)	$	—		$	—	$	—		$	(50	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	194		$	(100	)	$	—	$	257		$	37
NDT Fund (C)
Equity Securities	$	685		$	—		$	685	$	—		$	—
Debt Securities—Govt Obligations	$	359		$	—		$	—	$	359		$	—
Debt Securities—Other	$	281		$	—		$	—	$	281		$	—
Other Securities	$	24		$	—		$	—	$	24		$	—
Rabbi Trust—Mutual Funds (C)	$	33		$	—		$	4	$	29		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(148	)	$	18		$	—	$	(153	)	$	(13	)
PSE&G
Assets:
Derivative Contracts:
Energy Related Contracts (A)	$	4		$	—		$	—	$	—		$	4
Rabbi Trust—Mutual Funds (C)	$	57		$	—		$	6	$	51		$	—
Liabilities:
Derivative Contracts:
Energy Related Contracts (A)	$	(7	)	$	—		$	—	$	—		$	(7	)

(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.

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

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terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data.


(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)

The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in an S&P 500 index fund and various fixed income securities classified as “available for sale.” These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).

Level 1—Investments in marketable equity securities within the NDT 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). The Rabbi Trust equity index fund is valued based on quoted prices in an active market (Level 1).

Level 2—NDT and Rabbi Trust fixed income securities are limited to investment grade corporate bonds and United States Treasury obligations or Federal Agency mortgage-backed securities with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes, and issuer spreads (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).


(D)	For Non-Recourse Debt, see Fair Value Option discussion.


(E)	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.

Additional Information Regarding Level 3 Measurements

For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The Risk Management Committee reports to the Audit Committee of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by Power to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group and used for financial reporting purposes. PSEG considers credit and nonperformance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and nonperformance risk were not material to the financial statements.

The following table provides detail surrounding significant Level 3 valuations, of which the most significant positions are electric swaps and electric load deals for Power and long-term electric capacity contracts and long-term natural gas supply contracts for PSE&G. For Power, in general, electric swaps are valued based on at least two pricing inputs, basis and underlying. To the extent the basis component is based on a single broker quote and is significant to the fair value of the electric swap, it is categorized as Level 3. The remaining balance of Power’s Level 3 positions consist primarily of certain long-term electric capacity contracts, electric load deals in which load consumption may change hourly and certain long-term natural gas supply contracts. Long-term electric capacity contracts are measured at fair value using capacity auction prices. If the fair value for the unobservable tenor is significant, then the entire capacity contract is categorized as Level 3. Electric load deals are fair valued using certain unobservable inputs, such as historic load variability. For Power and PSE&G, long-term gas supply contracts are measured at fair value using both actively traded pricing points as well as unobservable inputs such as gas prices beyond observable periods and long-term basis quotes and accordingly, the fair value measurements are classified in Level 3. For PSE&G, long-term electric capacity contracts are measured at fair value using both observable capacity prices and unobservable inputs consisting of forecasts of future long-term electric capacity prices and include adjustments for contingencies, such as litigation risk and plant construction risk. Accordingly, the fair value measurements are classified as Level 3.

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The table below discloses the significant unobservable inputs used in developing the fair value of these Level 3 positions:




	Quantitative Information About Level 3 Fair Value Measurements
Commodity	Level 3 Position	Fair Value as of December 31, 2012					Valuation Technique(s)	Significant Unobservable Input	Range
		Assets		(Liabilities)
		Millions
Power
Electricity	Electric Swaps	$	7	$	(1	)	Discounted cash flow	Power Basis	$0 -$10/MWh
Electricity	Electric Load Deals	1		(2		)	Discounted cash flow	Historic Load Variability	-5% - +10%
Other	Various (A)	5		(1		)
Total Power		$	13	$	(4	)
PSE&G
Gas and Capacity	Forward Contracts (B)	$	67	$	(107	)	Discounted cash flow	Long-Term Gas Basis and Capacity Prices	(B)
Total PSE&G		$	67	$	(107	)
Total PSEG		$	80	$	(111	)


(A)	Includes long-term electric capacity and long-term gas supply positions which are immaterial.


(B)	Includes long-term gas supply and long-term electric capacity positions with various unobservable inputs. Significant unobservable inputs for the gas supply contracts include long-term basis prices in the range of $0 to $2/MMBTU of natural gas. Unobservable inputs for the long-term electric capacity contracts include forecasted capacity prices in the range of $100 to $400/MW day.

Significant unobservable inputs listed above would have a direct impact on the fair values of the above Level 3 instruments if they were adjusted. For energy-related contracts in cases where Power and PSE&G are sellers, an increase in either the power basis or the load variability or the longer-term basis amounts would decrease the fair value. For long-term electric capacity contracts where Power or PSE&G are buyers, an increase in the capacity price would increase the fair value.

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A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the years ended December 31, 2012 and 2011 follows:

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis

for the Year Ended December 31, 2012




				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2012			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, 2012
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	21		$	42	$	(37	)	$	—	$	(57	)	$	—	$	(31	)
Non-Recourse Debt	$	(50	)	$	50	$	—		$	—	$	—		$	—	$	—
Power
Net Derivative Assets (Liabilities)	$	24		$	42	$	—		$	—	$	(57	)	$	—	$	9
PSE&G
Net Derivative Assets (Liabilities)	$	(3	)	$	—	$	(37	)	$	—	$	—		$	—	$	(40	)

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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 (Liabilities)	$	47	$	22	$	(8	)	$	30	$	(37	)	$	(33	)	$	21
NDT Fund	$	8	$	—	$	—		$	—	$	—		$	(8	)	$	—
Non-Recourse Debt	$	—	$	—	$	—		$	—	$	(50	)	$	—		$	(50	)
Power
Net Derivative Assets (Liabilities)	$	42	$	22	$	—		$	30	$	(37	)	$	(33	)	$	24
NDT Fund	$	8	$	—	$	—		$	—	$	—		$	(8	)	—
PSE&G
Net Derivative Assets (Liabilities)	$	5	$	—	$	(8	)	$	—	$	—		$	—		$	(3	)

(A)

PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $42 million and $17 million in Operating Income in 2012 and 2011, $0 million and $2 million in OCI in 2012 and 2011, and $3 million in Income from Discontinued Operations in 2011. Of the $42 million in Operating Income in 2012, $(15) million is unrealized. Of the $17 million in Operating Income in 2011, $9 million is unrealized. Energy Holding's release from its obligations under the non-recourse debt is included in PSEG's Operating Income and is offset by the write-off of the related assets.


(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 in 2011.


(D)	Represents $(57) million in settlements for derivative contracts in 2012. 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 in 2011. See Fair Value Option discussion.

(E)

During the year ended December 31, 2012, there were no transfers among levels. 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.

As of December 31, 2012, PSEG carried $1.8 billion of net assets that are measured at fair value on a recurring basis, of which $31 million of net liabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

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.

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Fair Value Option

As of 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 Payable) associated with these leases at their respective fair values on the effective date of the rejection. Energy Holdings elected to record the Notes Payable 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 Payable are included in earnings each period. The $550 million of contractual principal outstanding on the Notes Payable was valued at $50 million as of December 31, 2011. Energy Holdings 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 Payable is included on PSEG’s Consolidated Balance Sheet as of December 31, 2011. The fair values of the Notes Payable include significant internal assumptions based on expected cash flows and the fair values of the underlying collateral. Changes to projected capacity factors, capacity and energy prices, fuel costs and other required cash outflows could significantly impact the fair value of the collateral which would increase or decrease the fair value of the Notes. These Notes Payable are classified as Level 3 in the fair value hierarchy as a result of mainly unobservable inputs. As of the June 5, 2012 effective date of the amended settlement agreement, the Notes Payable and related assets were written off.

The table of fair value of debt is included in Note 14. Schedule of Consolidated Debt.

Non-recurring Fair Value Measurements

2011

During the fourth quarter of 2011, DH filed for protection under Chapter 11 of the U.S. 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 as of 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).

Note 18. Stock Based Compensation

PSEG's 2004 Long-Term Incentive Plan (2004 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 2004 LTIP 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, 2012, there were approximately 17 million shares available for future awards under the 2004 LTIP.

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 over four 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.

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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 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 2012 and 2011 generally vest at the end of three years. Vesting may be accelerated upon certain events such as change-in-control or death. Prior to 2011, restricted stock unit grants generally vested over four years.

Performance Units

Under the 2004 LTIP, performance units were granted to officers and other key 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 and restricted stock units over the vesting period based on the grant date fair market value of the shares, which is equal to the market price of PSEG's common stock on the date of the grant.

PSEG recognizes compensation expense for performance units based on the grant date fair values of the award, which were determined using the Monte Carlo model. 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 accrual during the year of grant is estimated at 100% of the original grant. The accrual may be adjusted for subsequent changes in the estimated or actual outcome.




	2012		2011		2010
	Millions
Compensation Cost included in Operation and Maintenance Expense	$	25	$	23	$	29
Income Tax Benefit Recognized in Consolidated Statement of Operations	$	10	$	10	$	12

There was less than $1 million of excess tax benefits for 2012. The was $1 million of excess tax benefits included as financing cash flows on the Consolidated Statements of Cash Flow for each of the years ended December 31, 2011 and 2010, 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.

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Stock Options

Changes in stock options for 2012 are summarized as follows:




	Options	Weighted Average Exercise Price		Weighted Average Remaining Years Contractual Term	Aggregate Intrinsic Value
Outstanding as of January 1, 2012	3,272,300	$	32.78
Exercised	326,900	$	20.10
Outstanding as of December 31, 2012	2,945,400	$	34.19	5.3	$	1,509,670
Exercisable at December 31, 2012	2,750,325	$	34.24	5.2	$	1,506,268

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 2012, 2011 and 2010.

Activity for options exercised for the years ended December 31, 2012, 2011 and 2010 is shown below:




	2012		2011		2010
	Millions
Total Intrinsic Value of Options Exercised	$	4	$	2	$	1
Cash Received from Options Exercised	$	7	$	6	$	3
Tax Benefit Realized from Options Exercised	$	1	$	1	$	1

Less than one million options vested during each of the years ended December 31, 2012, 2011 and 2010. The total fair value of the stock options vested during the years ended December 31, 2012, 2011 and 2010 was $3 million, $5 million and $7 million, respectively.

As of December 31, 2012, there was approximately $1 million of unrecognized compensation cost related to stock options, which is to be recognized over a weighted average period of 0.5 years.

Restricted Stock

Changes in restricted stock for the year ended December 31, 2012 are summarized as follows:




	Shares	Weighted Average Grant Date Fair Value		Weighted Average Remaining Years Contractual Term	Aggregate Intrinsic Value
Non-vested as of January 1, 2012	70,300	$	32.83
Vested	1,500	$	44.44
Non-vested as of December 31, 2012	68,800	$	32.57	0.2	$	2,105,280

There were no restricted stock awards granted in 2012, 2011 and 2010.

The total intrinsic value of restricted stock vested during the years ended December 31, 2012, 2011 and 2010 was less than $1 million, $1 million and $3 million, respectively.

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Restricted Stock Units

Changes in restricted stock units for the year ended December 31, 2012 are summarized as follows:




	Shares	Weighted Average Grant Date Fair Value		Weighted Average Remaining Years Contractual Term	Aggregate Intrinsic Value
Non-vested as of January 1, 2012	648,551	$	31.17
Granted	345,440	$	30.95
Vested	125,838	$	30.87
Canceled/Forfeited	33,626	$	31.24
Non-vested as of December 31, 2012	834,527	$	31.12	1.2	$	25,536,532

The weighted average grant date fair value per share for restricted stock during the years ended December 31, 2012, 2011 and 2010 was $30.95, $32.03 and $31.13 per share, respectively.

The total intrinsic value of restricted stock units vested during the years ended December 31, 2012, 2011 and 2010 was $5 million, $7 million and $6 million, respectively.

As of December 31, 2012, 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 1.0 year. Dividend equivalents units of 40,044 accrued on the restricted stock units during the year.

Performance Share Units

Changes in Performance Share Units for the year ended December 31, 2012 are summarized as follows:




	Shares	Weighted Average Grant Date Fair Value		Weighted Average Remaining Years Contractual Term	Aggregate Intrinsic Value
Non-vested as of January 1, 2012	641,986	$	35.13
Granted	404,460	$	31.25
Vested	258,501	$	36.35
Canceled/Forfeited	37,952	$	33.51
Non-vested as of December 31, 2012	749,993	$	32.70	1.5	$	22,949,786

The weighted average grant date fair value per share for performance share units during the years ended December 31, 2012, 2011 and 2010 was $31.25, $35.33 and $34.29 per share, respectively.

The total intrinsic value of performance share units vested during the year ended December 31, 2012, 2011 and 2010 was $4 million, $9 million and $15 million, respectively.

As of December 31, 2012, there was approximately $13 million of unrecognized compensation cost related to the performance share units, which is expected to be recognized over a weighted average period of 1.0 year. Dividend equivalents units of 49,170 accrued on the performance share units during the year.

Outside Directors

Under the Directors Equity Plan, annually, on the first business day of May, each non-employee member of the Board of Directors is awarded stock units based on amount of annual compensation to be paid at the closing price of PSEG common stock on that date. 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, 2012, 2011 and 2010 was approximately $1 million.

Employee Stock Purchase Plan (ESPP)

PSEG maintains an ESPP for all eligible employees of PSEG and its subsidiaries. Under the ESPP, 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, 2012, 2011 and 2010,

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employees purchased 191,572, 183,338 and 178,684 shares at an average price of $31.32, $30.69 and $30.32 per share, respectively. As of December 31, 2012, 3.6 million shares were available for future issuance under this plan.

Note 19. Other Income and Deductions




Other Income	Power		PSE&G		Other (A)		Consolidated Total
	Millions
Year Ended December 31, 2012
NDT Fund Gains, Interest, Dividend and Other Income	$	194	$	—	$	—	$	194
Allowance of Funds Used During Construction	—		23		—		23
Rabbi Trust Realized Gains, Interest and Dividends	2		4		5		11
Solar Loan Interest	—		18		—		18
Other	3		7		4		14
Total Other Income	$	199	$	52	$	9	$	260
Year Ended December 31, 2011
NDT Fund Gains, Interest, Dividend and Other Income	$	186	$	—	$	—	$	186
Allowance of Funds Used During Construction	—		9		—		9
Solar Loan Interest	—		10		—		10
Other	4		6		5		15
Total Other Income	$	190	$	25	$	5	$	220
Year Ended December 31, 2010
NDT Fund Gains, Interest, Dividend and Other Income	$	159	$	—	$	—	$	159
Allowance of Funds Used During Construction	—		5		—		5
Rabbi Trust Realized Gains	7		11		13		31
Solar Loan Interest	—		6		—		6
Other	4		4		12		20
Total Other Income	$	170	$	26	$	25	$	221




Other Deductions	Power		PSE&G		Other (A)		Consolidated Total
	Millions
Year Ended December 31, 2012
NDT Fund Realized Losses and Expense	$	58	$	—	$	—	$	58
Loss on Early Extinguishment of Debt	15		—		—		15
Other	17		5		3		25
Total Other Deductions	$	90	$	5	$	3	$	98
Year Ended December 31, 2011
NDT Fund Realized Losses and Expense	$	50	$	—	$	—	$	50
Loss on Early Extinguishment of Debt	17		—		—		17
Other	12		4		2		18
Total Other Deductions	$	79	$	4	$	2	$	85
Year Ended December 31, 2010
NDT Fund Realized Losses and Expense	$	45	$	—	$	—	$	45
Other	8		3		7		18
Total Other Deductions	$	53	$	3	$	7	$	63


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

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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:




	Years Ended December 31,
	2012			2011			2010
	Millions
Net Income	$	1,275		$	1,503		$	1,564
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax benefit	—			96			7
Income from Continuing Operations	1,275			1,407			1,557
Preferred Dividends	—			—			(1		)
Income from Continuing Operations, excluding Preferred Dividends	$	1,275		$	1,407		$	1,558
Income Taxes:
Operating Income:
Current Expense:
Federal	$	(204	)	$	258		$	(166	)
State	(2		)	32			157
Total Current	(206		)	290			(9		)
Deferred Expense:
Federal	758			501			992
State	125			191			79
Total Deferred	883			692			1,071
Investment Tax Credit	59			(5		)	(3		)
Total Income Taxes	$	736		$	977		$	1,059
Pre-Tax Income	$	2,011		$	2,384		$	2,617
Tax Computed at Statutory Rate @ 35%	$	704		$	834		$	916
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)	115			146			154
Uncertain Tax Positions	4			19			30
Manufacturing Deduction	—			(15		)	(24		)
Nuclear Decommissioning Trust	10			14			10
Plant-Related Items	(5		)	(6		)	(3		)
Tax Credits	(10		)	(5		)	(2		)
Audit Settlement	(71		)	—			—
Other	(11		)	(10		)	(22		)
Sub-Total	32			143			143
Total Income Tax Provision	$	736		$	977		$	1,059
Effective Income Tax Rate	36.6		%	41.0		%	40.5		%

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The following is an analysis of deferred income taxes for PSEG:




	As of December 31,
	2012		2011
	Millions
Deferred Income Taxes
Assets:
Current (net)	$	49	$	—
Noncurrent:
Unrecovered Investment Tax Credit	$	30	$	15
Accumulated Other Comprehensive Income (Loss)	40		39
Cumulative Effect of a Change in Accounting Principle	11		11
OPEB	200		208
Cost of Removal	51		51
Contractual Liabilities & Environmental Costs	35		35
MTC	18		26
Related to Uncertain Tax Positions	75		104
Capital Loss	35		—
Other	82		44
Total Non-Current Assets	$	577	$	533
Total Assets	$	626	$	533
Liabilities:
Current (net)	$	72	$	170
Noncurrent:
Plant-Related Items	$	4,685	$	3,894
Nuclear Decommissioning	209		155
New Jersey Corporate Business Tax	343		180
Securitization	371		495
Leasing Activities	656		527
Partnership Activity	17		18
Conservation Costs	101		97
Pension Costs	180		129
AROs	297		302
Taxes Recoverable Through Future Rate (net)	165		158
Total Noncurrent Liabilities	$	7,024	$	5,955
Total Liabilities	$	7,096	$	6,125
Summary of Accumulated Deferred Income Taxes:
Net Current Deferred Income Tax Assets	$	49	$	—
Net Current Deferred Income Tax Liability	$	72	$	170
Net Noncurrent Deferred Income Tax Liabilities	$	6,447	$	5,422
Investment Tax Credit (ITC)	95		36
Net Total Noncurrent Deferred Income Taxes and ITC	$	6,542	$	5,458

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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:




	Years Ended December 31,
	2012			2011			2010
	Millions
Net Income	$	647		$	1,098		$	1,143
Income (Loss) from Discontinued Operations, net of tax	—			96			7
Income from Continuing Operations	$	647		$	1,002		$	1,136
Income Taxes:
Operating Income:
Current Expense:
Federal	$	83		$	400		$	12
State	53			40			127
Total Current	136			440			139
Deferred Expense:
Federal	262			151			598
State	35			94			41
Total Deferred	297			245			639
Total Income Taxes	$	433		$	685		$	778
Pre-Tax Income	$	1,080		$	1,687		$	1,914
Tax Computed at Statutory Rate @ 35%	$	378		$	591		$	670
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)	55			87			109
Manufacturing Deduction	—			(15		)	(24		)
Nuclear Decommissioning Trust	10			14			10
Uncertain Tax Positions	(6		)	11			10
Audit Settlement	(1		)	—			—
Other	(3		)	(3		)	3
Sub-Total	55			94			108
Total Income Tax Provision	$	433		$	685		$	778
Effective Income Tax Rate	40.1		%	40.6		%	40.6		%

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The following is an analysis of deferred income taxes for Power:




	As of December 31,
	2012		2011
	Millions
Deferred Income Taxes
Assets:
Noncurrent:
Cumulative Effect of a Change in Accounting Principle	$	11	$	11
Pension Costs	38		53
Accumulated Other Comprehensive Income (Loss)	40		39
Cost of Removal	51		51
Contractual Liabilities & Environmental Costs	35		35
Related to Uncertain Tax Positions	27		4
Capital Loss	12		—
Other	2		22
Total Noncurrent Assets	$	216	$	215
Total Assets	$	216	$	215
Liabilities:
Current (net)	$	16	$	53
Noncurrent:
Plant-Related Items	$	1,253	$	1,013
New Jersey Corporate Business Tax	28		7
Nuclear Decommissioning	209		155
AROs	297		302
Total Noncurrent Liabilities	$	1,787	$	1,477
Total Liabilities	$	1,803	$	1,530
Summary of Accumulated Deferred Income Taxes:
Net Current Deferred Income Tax Liabilities	$	16	$	53
Net Noncurrent Deferred Income Tax Liabilities	$	1,571	$	1,262
Investment Tax Credit (ITC)	4		4
Net Total Noncurrent Deferred Income Taxes and ITC	$	1,575	$	1,266

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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:




	Years Ended December 31,
	2012			2011			2010
	Millions
Net Income	$	528		$	521		$	358
Preferred Dividends	—			—			(1		)
Income from Continuing Operations, excluding Preferred Dividends	$	528		$	521		$	359
Income Taxes:
Operating Income:
Current Expense:
Federal	$	(217	)	$	(225	)	$	(211	)
State	9			(6		)	(1		)
Total Current	(208		)	(231		)	(212		)
Deferred Expense:
Federal	409			483			384
State	83			92			63
Total Deferred	492			575			447
Investment Tax Credit	23			(4		)	(3		)
Total Income Taxes	$	307		$	340		$	232
Pre-Tax Income	$	835		$	861		$	591
Tax Computed at Statutory Rate @ 35%	$	292		$	301		$	207
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)	52			56			40
Uncertain Tax Positions	7			(1		)	(1		)
Plant-Related Items	(4		)	(6		)	(3		)
Tax Credits	(3		)	(4		)	(2		)
Audit Settlement	(31		)	—			—
Other	(6		)	(6		)	(9		)
Sub-Total	15			39			25
Total Income Tax Provision	$	307		$	340		$	232
Effective Income Tax Rate	36.8		%	39.5		%	39.2		%

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The following is an analysis of deferred income taxes for PSE&G:




	As of December 31,
	2012		2011
	Millions
Deferred Income Taxes
Assets:
Current (net)	$	49	$	—
Noncurrent:
Unrecovered ITC	$	18	$	10
OPEB	189		197
MTC	18		26
Related to Uncertain Tax Positions	15		30
Other	42		13
Total Noncurrent Assets	$	282	$	276
Total Assets	$	331	$	276
Liabilities:
Current (net)	$	60	$	32
Noncurrent:
Plant-Related Items	$	3,374	$	2,875
New Jersey Corporate Business Tax	253		146
Securitization	371		495
Conservation Costs	101		97
Pension Costs	189		151
Taxes Recoverable Through Future Rate (net)	165		158
Total Noncurrent Liabilities	$	4,453	$	3,922
Total Liabilities	$	4,513	$	3,954
Summary of Accumulated Deferred Income Taxes:
Net Current Deferred Income Tax Assets	$	49	$	—
Net Current Deferred Income Tax Liability	$	60	$	32
Net Noncurrent Deferred Income Tax Liability	$	4,171	$	3,646
Investment Tax Credit (ITC)	52		29
Net Total Noncurrent Deferred Income Taxes and ITC	$	4,223	$	3,675

As of December 31, 2012, PSE&G had New Jersey State income tax net operating loss (NOL) carryforwards of $1.5 billion, on which a deferred tax asset of $87 million was recorded, which will expire between 2031 and 2033. 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.

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 non-cash after tax charges of $9 million for income tax expense to establish the related deferred tax liabilities,

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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 had a significant impact on PSEG’s cash position. The Small Business Jobs Act of 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 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 is eligible for 50% bonus depreciation for tax purposes. On January 2, 2013, the President signed into law the American Taxpayer Relief Act of 2012 that further extends 50% bonus depreciation for property placed in service before January 1, 2014. These provisions contain rules which afford certain projects which have a long production period, the benefit of bonus depreciation. These provisions will also generate cash for PSEG through tax benefits related to accelerated depreciation, most of which was realized in 2011. These tax benefits would have otherwise been received over an estimated average 20 year period.

With respect to ITC, for financial statement periods including 2010 and 2011, the law provided an option to claim either a grant or the ITC. Accordingly, in those periods, the ITC was accounted for as a reduction of the book basis of the related assets as opposed to being recorded in tax expense. In 2012 the law changed and the grant option is no longer available; as such, the accumulated deferred ITC generated in 2012 was recorded as a noncurrent deferred tax liability, which was included in Deferred Income Taxes and ITC on PSEG's and PSE&G's Consolidated Balance Sheets as of December 31, 2012.

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:




2012	PSEG			Power			PSE&G			Energy Holdings
	Millions
Total Amount of Unrecognized Tax Benefits as of January 1, 2012	$	825		$	121		$	113		$	555
Increases as a Result of Positions Taken in a Prior Period	92			27			55			9
Decreases as a Result of Positions Taken in a Prior Period	(173		)	(7		)	(47		)	(119		)
Increases as a Result of Positions Taken during the Current Period	47			3			42			—
Decreases as a Result of Positions Taken during the Current Period	—			—			—			—
Decreases as a Result of Settlements with Taxing Authorities	(389		)	(10		)	—			(344		)
Decreases due to Lapses of Applicable Statute of Limitations	—			—			—			—
Total Amount of Unrecognized Tax Benefits as of December 31, 2012	$	402		$	134		$	163		$	101
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits	(264		)	(93		)	(133		)	(35		)
Regulatory Asset—Unrecognized Tax Benefits	(30		)	—			(30		)	—
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties)	$	108		$	41		$	—		$	66

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2011	PSEG			Power			PSE&G			Energy Holdings
	Millions
Total Amount of Unrecognized Tax Benefits as of 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		)	—			(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		)	—
Decreases as a Result of Settlements with Taxing Authorities	—			—			—			—
Decreases due to Lapses of Applicable Statute of Limitations	—			—			—			—
Total Amount of Unrecognized Tax Benefits as of 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		)	—			(20		)	—
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties)	$	426		$	44		$	28		$	342




2010	PSEG			Power			PSE&G			Energy Holdings
	Millions
Total Amount of Unrecognized Tax Benefits as of 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		)	—			—
Decreases as a Result of Settlements with Taxing Authorities	—			—			—			—
Decreases due to Lapses of Applicable Statute of Limitations	—			—			—			—
Total Amount of Unrecognized Tax Benefits as of 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		)	—			(16		)	—
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties)	$	408		$	34		$	28		$	335

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 were fully refundable and were recorded in Current Accrued Taxes on PSEG’s Consolidated Balance Sheets in the years in which the deposits were made, 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 have been applied against tax and interest due pursuant to the closing agreement.

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:

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	Interest and Penalties on Uncertain Tax Positions Years Ended December 31,
	2012			2011			2010
	Millions
Power	$	(2	)	$	(11	)	$	(17	)
PSE&G	1			(24		)	(20		)
Energy Holdings	39			420			407
Other	—			10			9
Total	$	38		$	395		$	379

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	$	75
Power	$	5
PSE&G	$	—

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.

A 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	2007-2011	N/A	N/A
New Jersey	2006-2011	N/A	2006-2011
Pennsylvania	2001-2011	N/A	2000-2011
Connecticut	2002-2011	N/A	N/A
Texas	2007-2011	N/A	N/A
California	2003-2011	N/A	N/A
New York	2009-2011	2009-2011	N/A

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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:




	Years Ended December 31,
	2012				2011				2010
	Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator:
(Millions)
Continuing Operations	$	1,275	$	1,275	$	1,407	$	1,407	$	1,557	$	1,557
Discontinued Operations	—		—		96		96		7		7
Net Income	$	1,275	$	1,275	$	1,503	$	1,503	$	1,564	$	1,564
EPS Denominator:
(Thousands)
Weighted Average Common Shares Outstanding	505,933		505,933		505,949		505,949		505,985		505,985
Effect of Stock Based Compensation Awards	—		1,153		—		1,033		—		1,060
Total Shares	505,933		507,086		505,949		506,982		505,985		507,045
EPS:
Continuing Operations	$	2.52	$	2.51	$	2.78	$	2.77	$	3.08	$	3.07
Discontinued Operations	—		—		0.19		0.19		0.01		0.01
Net Income	$	2.52	$	2.51	$	2.97	$	2.96	$	3.09	$	3.08

There were approximately 1.8 million, 1.8 million and 1.9 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, 2012, 2011 and 2010, respectively. No other stock options had an antidilutive effect for the years ended December 31, 2012, 2011 or 2010.

Dividends




	Years Ended December 31,
Dividend Payments on Common Stock	2012		2011		2010
Per Share	$	1.42	$	1.37	$	1.37
in Millions	$	718	$	693	$	693

On February 19, 2013, PSEG’s Board of Directors approved a $0.36 per share common stock dividend for the first quarter of 2013.

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.

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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 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 the 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.




	Power		PSE&G		Energy Holdings			Other			Consolidated Total
	Millions
Year Ended December 31, 2012
Operating Revenues	$	4,865	$	6,626	$	113		$	(1,823	)	$	9,781
Depreciation and Amortization	237		778		19			20			1,054
Operating Income (Loss)	1,123		1,083		62			10			2,278
Income from Equity Method Investments	—		—		12			—			12
Interest Income	3		20		2			2			27
Interest Expense	134		295		1			(7		)	423
Income (Loss) before Income Taxes	1,080		835		78			18			2,011
Income Tax Expense (Benefit)	433		307		(8		)	4			736
Income (Loss) from Continuing Operations	647		528		86			14			1,275
Net Income (Loss)	647		528		86			14			1,275
Segment Earnings (Loss)	647		528		86			14			1,275
Gross Additions to Long-Lived Assets	$	646	$	1,770	$	127		$	31		$	2,574
As of December 31, 2012
Total Assets	$	11,032	$	19,223	$	1,454		$	16		$	31,725
Investments in Equity Method Subsidiaries	$	40	$	—	$	94		$	—		$	134

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	Power		PSE&G		Energy Holdings			Other			Consolidated Total
	Millions
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	—		—		4			—			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		—		—			—			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	$	—	$	106		$	—		$	137




	Power		PSE&G		Energy Holdings		Other			Consolidated Total
	Millions
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	—		—		4		—			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		—		—		—			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	$	—	$	105	$	—		$	130

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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	2012			2011			2010
	Millions
Revenue from Affiliates:
Billings to PSE&G through BGSS (A)	$	987		$	1,294		$	1,591
Billings to PSE&G through BGS (A)	815			921			1,139
Total Revenue from Affiliates	$	1,802		$	2,215		$	2,730
Expense Billings from Affiliates:
Administrative Billings from Services (B)	$	(154	)	$	(147	)	$	(145	)
Total Expense Billings from Affiliates	$	(154	)	$	(147	)	$	(145	)




	Years Ended December 31,
Related Party Transactions	2012			2011
	Millions
Receivables from PSE&G through BGS and BGSS Contracts (A)	$	238		$	247
Receivables from PSE&G Related to Gas Supply Hedges for BGSS (A)	27			109
Receivable from (Payable to) Services (B)	(31		)	(26		)
Tax Receivable from (Payable to) PSEG (C)	111			58
Receivable from (Payable to) PSEG	(5		)	(7		)
Accounts Receivable (Payable)—Affiliated Companies, net	$	340		$	381
Short-Term Loan to (from) Affiliate (demand Note to (from) PSEG) (D)	$	574		$	907
Working Capital Advances to Services (E)	$	17		$	17
Long-Term Accrued Taxes Receivable (Payable) (C)	$	(50	)	$	(8	)

PSE&G

The financial statements for PSE&G include transactions with related parties presented as follows:




	Years Ended December 31,
Related Party Transactions	2012			2011			2010
	Millions
Expense Billings from Affiliates:
Billings from Power through BGSS (A)	$	(987	)	$	(1,294	)	$	(1,591	)
Billings from Power through BGS (A)	(815		)	(921		)	(1,139		)
Administrative Billings from Services (B)	(230		)	(210		)	(206		)
Total Expense Billings from Affiliates	$	(2,032	)	$	(2,425	)	$	(2,936	)

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	Years Ended December 31,
Related Party Transactions	2012			2011
	Millions
Payable to Power through BGS and BGSS Contracts (A)	$	(238	)	$	(247	)
Payable to Power Related to Gas Supply Hedges for BGSS (A)	(27		)	(109		)
Payable to Power from SREC Liability (F)	(7		)	(7		)
Receivable from (Payable to) Services (B)	(65		)	(56		)
Tax Receivable from (Payable to) PSEG (C)	256			131
Receivable from (Payable to) PSEG	6			8
Receivable from Energy Holdings	2			—
Accounts Receivable (Payable)—Affiliated Companies, net	$	(73	)	$	(280	)
Working Capital Advances to Services (E)	$	33		$	33
Long-Term Accrued Taxes Receivable (Payable) (C)	$	(32	)	$	(83	)

(A)

PSE&G has a full requirements contract with Power to meet the supply requirements of default service gas customers. This long-term contract was for an initial period which extended through March 31, 2012 and continues on a year-to-year basis thereafter, unless terminated by either party with a one year notice. 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.

(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. On May 1, 2012, the BPU reaffirmed its earlier decision and on December 19, 2012, approved a settlement that defines requirements for review and reimbursement of incremental SREC costs to certain BGS suppliers. PSE&G has estimated and accrued a total liability for the excess SREC cost of $17 million as of December 31, 2012 and 2011, including approximately $7 million for Power’s share which is included in PSE&G’s Accounts Payable—Affiliated Companies as of December 31, 2012 and 2011. 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, 2012 and 2011.

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.

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	Quarter Ended
	March 31,				June 30,				September 30,				December 31,
	2012		2011		2012		2011		2012		2011		2012		2011
PSEG Consolidated:	Millions
Operating Revenues	$	2,875	$	3,354	$	2,098	$	2,469	$	2,402	$	2,620	$	2,406	$	2,636
Operating Income	$	783	$	856	$	433	$	621	$	594	$	556	$	468	$	709
Income (Loss) from Continuing Operations	$	493	$	462	$	211	$	320	$	347	$	265	$	224	$	360
Income (Loss) from Discontinued Operations, including Gain (Loss) on Disposal, net of tax	$	—	$	64	$	—	$	3	$	—	$	29	$	—	$	—
Net Income (Loss)	$	493	$	526	$	211	$	323	$	347	$	294	$	224	$	360
Earnings Per Share:
Basic:
Income (Loss) from Continuing Operations	$	0.97	$	0.91	$	0.42	$	0.63	$	0.69	$	0.52	$	0.44	$	0.71
Net Income (Loss)	$	0.97	$	1.04	$	0.42	$	0.63	$	0.69	$	0.58	$	0.44	$	0.71
Diluted:
Income (Loss) from Continuing Operations	$	0.97	$	0.91	$	0.42	$	0.63	$	0.68	$	0.52	$	0.44	$	0.71
Net Income (Loss)	$	0.97	$	1.04	$	0.42	$	0.63	$	0.68	$	0.58	$	0.44	$	0.71
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,
	2012		2011		2012		2011		2012		2011		2012		2011
Power:	Millions
Operating Revenues	$	1,561	$	1,967	$	985	$	1,285	$	1,038	$	1,398	$	1,281	$	1,493
Operating Income	$	441	$	501	$	196	$	355	$	267	$	483	$	219	$	432
Income (Loss) from Continuing Operations	$	253	$	298	$	104	$	205	$	181	$	273	$	109	$	226
Income (Loss) from Discontinued Operations, including Gain (Loss) on Disposal, net of tax	$	—	$	64	$	—	$	3	$	—	$	29	$	—	$	—
Net Income (Loss)	$	253	$	362	$	104	$	208	$	181	$	302	$	109	$	226




	Quarter Ended
	March 31,				June 30,				September 30,				December 31,
	2012		2011		2012		2011		2012		2011		2012		2011
PSE&G:	Millions
Operating Revenues	$	1,939	$	2,306	$	1,407	$	1,571	$	1,683	$	1,841	$	1,597	$	1,608
Operating Income	$	342	$	350	$	227	$	252	$	321	$	328	$	193	$	221
Net Income (Loss)	$	197	$	163	$	101	$	105	$	155	$	154	$	75	$	99

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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, 2012 and 2011 and for the years ended December 31, 2012, 2011 and 2010.




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Year Ended December 31, 2012
Operating Revenues	$	—		$	6,238		$	125		$	(1,498	)	$	4,865
Operating Expenses	7			5,118			115			(1,498		)	3,742
Operating Income (Loss)	(7		)	1,120			10			—			1,123
Equity Earnings (Losses) of Subsidiaries	688			(10		)	—			(678		)	—
Other Income	45			206			—			(52		)	199
Other Deductions	(31		)	(59		)	—			—			(90		)
Other-Than-Temporary Impairments	—			(18		)	—			—			(18		)
Interest Expense	(118		)	(51		)	(18		)	53			(134		)
Income Tax Benefit (Expense)	70			(501		)	(2		)	—			(433		)
Net Income (Loss)	$	647		$	687		$	(10	)	$	(677	)	$	647
Comprehensive Income (Loss)	$	595		$	681		$	(10	)	$	(671	)	$	595
As of December 31, 2012
Current Assets	$	3,922		$	8,084		$	940		$	(10,712	)	$	2,234
Property, Plant and Equipment, net	80			5,988			950			—			7,018
Investment in Subsidiaries	4,317			733			—			(5,050		)	—
Noncurrent Assets	201			1,660			60			(141		)	1,780
Total Assets	$	8,520		$	16,465		$	1,950		$	(15,903	)	$	11,032
Current Liabilities	$	482		$	10,187		$	1,010		$	(10,712	)	$	967
Noncurrent Liabilities	559			1,960			207			(140		)	2,586
Long-Term Debt	2,040			—			—			—			2,040
Member’s Equity	5,439			4,318			733			(5,051		)	5,439
Total Liabilities and Member’s Equity	$	8,520		$	16,465		$	1,950		$	(15,903	)	$	11,032
Year Ended December 31, 2012
Net Cash Provided By (Used In) Operating Activities	$	298		$	1,562		$	(7	)	$	(474	)	$	1,379
Net Cash Provided By (Used In) Investing Activities	$	715		$	(1,206	)	$	(27	)	$	170		$	(348	)
Net Cash Provided By (Used In) Financing Activities	$	(1,013	)	$	(361	)	$	33		$	305		$	(1,036	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Year Ended December 31, 2011
Operating Revenues	$	—		$	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			—			(1,267		)	—
Other Income	40			195			—			(45		)	190
Other Deductions	(28		)	(51		)	—			—			(79		)
Other-Than-Temporary Impairments	(1		)	(19		)	—			—			(20		)
Interest Expense	(146		)	(56		)	(18		)	45			(175		)
Income Tax Benefit (Expense)	63			(762		)	14			—			(685		)
Income (Loss) on Discontinued Operations, net of Tax Benefit	—			—			97			(1		)	96
Net Income (Loss)	$	1,098		$	1,178		$	89		$	(1,267	)	$	1,098
Comprehensive Income (Loss)	$	917		$	1,055		$	89		$	(1,144	)	$	917
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			—			6,731
Investment in Subsidiaries	4,185			804			—			(4,989		)	—
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			—			—			—			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
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	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Year Ended December 31, 2010
Operating Revenues	$	—		$	7,746		$	125		$	(1,313	)	$	6,558
Operating Expenses	9			5,760			139			(1,313		)	4,595
Operating Income (Loss)	(9		)	1,986			(14		)	—			1,963
Equity Earnings (Losses) of Subsidiaries	1,182			(15		)	—			(1,167		)	—
Other Income	45			170			—			(45		)	170
Other Deductions	(4		)	(49		)	—			—			(53		)
Other-Than-Temporary Impairments	—			(9		)	—			—			(9		)
Interest Expense	(113		)	(67		)	(22		)	45			(157		)
Income Tax Benefit (Expense)	42			(834		)	14			—			(778		)
Income (Loss) on Discontinued Operations, net of Tax Benefit	—			—			7			—			7
Net Income (Loss)	$	1,143		$	1,182		$	(15	)	$	(1,167	)	$	1,143
Comprehensive Income (Loss)	$	1,109		$	1,130		$	(15	)	$	(1,115	)	$	1,109
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	)

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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 (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, 2012, 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 173, 174 and 175, 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 176. Management has concluded that internal control over financial reporting is effective as of December 31, 2012.

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 2012 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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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, 2012 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, 2012.

PSEG’s external auditors, Deloitte & Touche LLP, have audited PSEG’s financial statements for the year ended December 31, 2012 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 25, 2013

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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.

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, 2012 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, 2012.




/s/ RALPH IZZO
Chief Executive Officer

/s/ CAROLINE DORSA
Chief Financial Officer February 25, 2013

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MANAGEMENT REPORT ON INTERNAL CONTROL OVER

FINANCIAL REPORTING—PSE&G

Management of Public Service Electric and Gas Company (PSE&G) 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.

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, 2012 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, 2012.




/s/ RALPH IZZO
Chief Executive Officer

/s/ CAROLINE DORSA
Chief Financial Officer February 25, 2013

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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, 2012, 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, 2012, 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, 2012 of the Company and our report dated February 25, 2013 expressed an unqualified opinion on those consolidated financial statements and consolidated financial statement schedule.

/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey

February 25, 2013

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE

GOVERNANCE

Executive Officers

PSEG



Name	Age as of December 31, 2012	Office	Effective Date First Elected to Present Position
Ralph Izzo	55	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	53	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	56	President and Chief Operating Officer (Power)	June 2007 to present
		President and Chief Nuclear Officer (Nuclear)	January 2007 to October 2008
Ralph LaRossa	49	President and Chief Operating Officer (PSE&G)	October 2006 to present

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Name	Age as of December 31, 2012	Office	Effective Date First Elected to Present Position
Derek M. DiRisio	48	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	57	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.	68	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 2013 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 8, 2013 and which information set forth under said heading is incorporated herein by this reference thereto.

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,

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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/info/investors/governance/document.jsp. 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/info/investors/governance/document.jsp:


•	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 2012, 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 2013 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 8, 2013 and such information set forth under such heading is incorporated herein by this reference thereto.

Section 16 Beneficial Ownership Reporting Compliance

During 2012, 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 Susan Tomasky, one of our Directors. Ms. Tomasky filed one late report on Form 3 to report any ownership by her of our Common Stock at the time of her election to the Board. At that time, Ms. Tomasky did not own any of our Common Stock.

Power and PSE&G

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

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 2013 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 8, 2013, 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.

179

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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 2013 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 8, 2013 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 2012 and 2011” in PSEG’s definitive Proxy Statement for the 2013 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 8, 2013. Such information set forth under such heading is incorporated herein by this reference hereto.

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, 2012 and 2011 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Stockholders’ Equity for the three years ended December 31, 2012 on pages 74 through 79.


b.	PSEG Power LLC’s Consolidated Balance Sheets as of December 31, 2012 and 2011 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Capitalization and Member’s Equity for the three years ended December 31, 2012 on pages 80 through 85.


c.	Public Service Electric and Gas Company’s Consolidated Balance Sheets as of December 31, 2012 and 2011 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Common Stockholders’ Equity for the three years ended December 31, 2012 on pages 86 through 91.

(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, 2012 (page 189).


b.	Power's Financial Statement Schedules:

Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2012 (page 189).


c.	PSE&G's Financial Statement Schedules:

180

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Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2012 (page 190).

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.

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⁾
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⁽⁷⁵⁾
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 17, 2012
10a(12)		Severance Agreement with Ralph Izzo dated December 16, 2008⁽¹⁶⁾
10a(13)		Employment Agreement with Randall Mehrberg dated June 30, 2008⁽¹⁷⁾
10a(14)		Employment Agreement with Caroline Dorsa dated March 11, 2009, as amended April 24, 2009⁽¹⁸⁾
10a(15)		Stock Plan for Outside Directors, as amended⁽¹⁹⁾
10a(16)		Compensation Plan for Outside Directors⁽²⁰⁾
10a(17)		2004 Long-Term Incentive Plan, amended effective December 1, 2009⁽²¹⁾
10a(18)		Form of Advancement of Expenses Agreement with Outside Directors⁽²²⁾
10a(19)		Equity Deferral Plan, effective November 1, 2011, amended December 9, 2011⁽⁷⁶⁾
10a(20)		Employment Agreement with J.A. Bouknight dated August 26, 2009⁽⁷⁷⁾
10a(21)		Amendment to Employment Agreement with Randall Mehrberg, dated May 3, 2011⁽⁷²⁾
10a(22)		Amendment to Employment Agreement with Caroline Dorsa, dated July 12, 2011⁽⁷³⁾
10a(23)		Amendment to Employment Agreement with Randall Mehrberg, dated June 8, 2011⁽⁷⁴⁾
10a(24)		Amendment to Employment Agreement with William Levis, dated September 19, 2011⁽¹²⁾

181

Table of Contents

LIST OF EXHIBITS:

10a(25)		Amendment to Employment Agreement with J.A. Bouknight dated November 19, 2012⁽⁷⁸⁾
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
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⁽²³⁾
3b		PSEG Power LLC Limited Liability Company Agreement⁽²⁴⁾
3c		Trust Agreement for PSEG Power Capital Trust I⁽²⁵⁾
3d		Trust Agreement for PSEG Power Capital Trust II⁽²⁶⁾
3e		Trust Agreement for PSEG Power Capital Trust III⁽²⁷⁾
3f		Trust Agreement for PSEG Power Capital Trust IV⁽²⁸⁾
3g		Trust Agreement for PSEG Power Capital Trust V⁽²⁹⁾
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⁽³⁰⁾
4b		First Supplemental Indenture, supplemental to Exhibit 4a, dated as of March 13, 2002⁽³¹⁾
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⁽⁷⁵⁾
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⁾

182

Table of Contents

LIST OF EXHIBITS:

10a(9)		Amended and Restated Key Executive Severance Plan, amended effective December 17, 2012
10a(10)		Severance Agreement with Ralph Izzo dated December 16, 2008⁽¹⁶⁾
10a(11)		Employment Agreement with Caroline Dorsa dated March 11, 2009, as amended April 24, 2009⁽¹⁸⁾
10a(12)		2004 Long-Term Incentive Plan, amended effective December 1, 2009⁽²¹⁾
10a(19)		Equity Deferral Plan, effective November 1, 2011, amended December 9, 2011⁽⁷⁶⁾
10a(20)		Employment Agreement with J.A. Bouknight dated August 26, 2009⁽⁷⁷⁾
10a(21)		Amendment to Employment Agreement with Caroline Dorsa, dated July 12, 2011⁽⁷³⁾
10a(22)		Amendment to Employment Agreement with William Levis, dated September 19, 2011⁽¹²⁾
10a(23)		Amendment to Employment Agreement with J.A. Bouknight dated November 19, 2012⁽⁷⁸⁾
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
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
c.		PSE&G
3a(1)		Restated Certificate of Incorporation of PSE&G⁽³²⁾
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⁽³³⁾
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⁽³⁴⁾
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⁽³⁵⁾
3a(5)		Certificate of Amendment of Restated Certificate of Incorporation of PSE&G filed January 27, 1994 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 a series of Preferred Stock⁽³⁶⁾
3b(1)		By-Laws of PSE&G as in effect April 17, 2007⁽³⁷⁾

183

Table of Contents

LIST OF EXHIBITS:

4a(1)		Indenture between PSE&G and Fidelity Union Trust Company (now, Wachovia Bank, National Association), as Trustee, dated August 1, 1924⁽³⁸⁾, 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⁽³⁹⁾
4a(3)		June 1, 1937⁽⁴⁰⁾
4a(4)		July 1, 1937⁽⁴¹⁾
4a(5)		December 19, 1939⁽⁴²⁾
4a(6)		March 1, 1942⁽⁴³⁾
4a(7)		June 1, 1991 (No. 1)⁽⁴⁴⁾
4a(8)		July 1, 1993⁽⁴⁵⁾
4a(9)		September 1, 1993⁽⁴⁶⁾
4a(10)		February 1, 1994⁽⁴⁷⁾
4a(11)		March 1, 1994 (No. 2)⁽⁴⁸⁾
4a(12)		May 1, 1994⁽⁴⁹⁾
4a(13)		October 1, 1994 (No. 2)⁽⁵⁰⁾
4a(14)		January 1, 1996 (No. 1)⁽⁵¹⁾
4a(15)		January 1, 1996 (No. 2)⁽⁵²⁾
4a(16)		May 1, 1998⁽⁵³⁾
4a(17)		September 1, 2002⁽⁵⁴⁾
4a(18)		August 1, 2003⁽⁵⁵⁾
4a(19)		December 1, 2003 (No. 1)⁽⁵⁶⁾
4a(20)		December 1, 2003 (No. 2)⁽⁵⁷⁾
4a(21)		December 1, 2003 (No. 3)⁽⁵⁸⁾
4a(22)		December 1, 2003 (No. 4)⁽⁵⁹⁾
4a(23)		June 1, 2004⁽⁶⁰⁾
4a(24)		August 1, 2004 (No. 1)⁽⁶¹⁾
4a(25)		August 1, 2004 (No. 2)⁽⁶²⁾
4a(26)		August 1, 2004 (No. 3)⁽⁶³⁾
4a(27)		August 1, 2004 (No. 4)⁽⁶⁴⁾
4a(28)		April 1, 2007⁽⁶⁵⁾
4a(29)		November 1, 2008⁽⁶⁶⁾
4a(30)		November 1, 2009⁽⁶⁷⁾
4a(31)		October 1, 2010⁽⁶⁸⁾
4a(32)		May 1, 2012
4a(33)		June 1, 2012
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⁽⁶⁹⁾
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⁽⁷⁰⁾
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⁾

184

Table of Contents

LIST OF EXHIBITS:

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, 2011
10a(7)		1989 Long-Term Incentive Plan, as amended⁽¹³⁾
10a(8)		2001 Long-Term Incentive Plan⁽¹⁴⁾
10a(9)		Senior Management Incentive Compensation Plan⁽¹⁵⁾
10a(10)		Amended and Restated Key Executive Severance Plan, amended effective December 17, 2012
10a(11)		Severance Agreement with Ralph Izzo dated December 16, 2008⁽¹⁶⁾
10a(12)		Employment Agreement with Caroline Dorsa dated March 11, 2009, as amended April 24, 2009⁽¹⁸⁾
10a(13)		Stock Plan for Outside Directors, as amended⁽¹⁹⁾
10a(14)		Compensation Plan for Outside Directors⁽²⁰⁾
10a(15)		2004 Long-Term Incentive Plan, amended effective December 1, 2009⁽²¹⁾
10a(16)		Form of Advancement of Expenses Agreement with Outside Directors⁽⁷¹⁾
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⁽⁷³⁾
10a(22)		Amendment to Employment Agreement with J.A. Bouknight dated November 19, 2012⁽⁷⁸⁾
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
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


(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.

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(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.


(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 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.


(17)	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.


(18)	Filed as Exhibit 10 with Quarterly Report on Form 10-Q, File No. 001-00973 on May 6, 2009 and incorporated herein by reference.


(19)	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.


(20)	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.


(21)	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.


(22)	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.


(23)	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.


(24)	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.


(25)	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.


(26)	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.


(27)	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.


(28)	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.


(29)	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.


(30)	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.

186

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(31)	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.


(32)	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.


(33)	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.


(34)	Filed as Exhibit 3a(3) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.


(35)	Filed as Exhibit 3a(4) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.


(36)	Filed as Exhibit 3a(5) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.


(37)	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.


(38)	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.


(39)	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.


(40)	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.


(41)	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.


(42)	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.


(43)	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.


(44)	Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on June 1, 1991 and incorporated herein by this reference.


(45)	Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973 on December 1, 1993 and incorporated herein by this reference.


(46)	Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on December 1, 1993 and incorporated herein by this reference.


(47)	Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973 on February 4, 1994 and incorporated herein by this reference.


(48)	Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on March 15, 1994 and incorporated herein by this reference.


(49)	Filed as Exhibit 4a(87) with Quarterly Report on Form 10-Q for the quarter ended September 30, 1994, File No. 001-00973 on November 8, 1994 and incorporated herein by this reference.


(50)	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.


(51)	Filed as Exhibit 4a(2) on Form 8-A, File No. 001-00973 on January 26, 1996 and incorporated herein by this reference.


(52)	Filed as Exhibit 4a(3) on Form 8-A, File No. 001-00973 on January 26, 1996 and incorporated herein by this reference.


(53)	Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on May 15, 1998 and incorporated herein by this reference.


(54)	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.


(55)	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.


(56)	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.


(57)	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.


(58)	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.


(59)	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.


(60)	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.


(61)	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.


(62)	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.


(63)	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.


(64)	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.

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(65)	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.


(66)	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.


(67)	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.


(68)	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.


(69)	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.


(70)	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.


(71)	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.


(72)	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.


(73)	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.


(74)	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.


(75)	Filed as Exhibit 10a(7) with Annual Report on Form 10-K for the year ended December 31, 2011, File No. 001-09120 on February 27, 2012.


(76)	Filed as Exhibit 10a(19) with Annual Report on Form 10-K for the year ended December 31, 2011, File No. 001-09120 on February 27, 2012.


(77)	Filed as Exhibit 10a(20) with Annual Report on Form 10-K for the year ended December 31, 2011, File No. 001-09120 on February 27, 2012.


(78)	Filed as Exhibit 10 with Current Report on Form 8-K, File No. 001-09120 on November 26, 2012 and incorporated herein by reference.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

Schedule II—Valuation and Qualifying Accounts Years Ended December 31, 2012—December 31, 2010




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
2012
Allowance for Doubtful Accounts	$	56	$	96	$	—	$	96	(A)	$	56
Materials and Supplies Valuation Reserve	3		21		—		2		(B)	22
2011
Allowance for Doubtful Accounts	$	68	$	102	$	—	$	114	(A)	$	56
Materials and Supplies Valuation Reserve	4		2		—		3		(B)	3
2010
Allowance for Doubtful Accounts	$	79	$	99	$	—	$	110	(A)	$	68
Materials and Supplies Valuation Reserve	5		—		—		1		(B)	4
Other Valuation Allowances	8		—		—		8		(C)	—


(A)	Accounts Receivable written off.


(B)	Reduced reserve to appropriate level and to remove obsolete inventory.


(C)	Valuation Allowance written off.

PSEG POWER LLC

Schedule II—Valuation and Qualifying Accounts Years Ended December 31, 2012—December 31, 2010




	Column A	Column B		Column C Additions				Column D			Column E
	Description	Balance at Beginning of Period		Charged to cost and expenses		Charged to other accounts- describe		Deductions- describe			Balance at End of Period
						Millions
2012
	Materials and Supplies Valuation Reserve	$	3	$	21	$	—	$	2	(A)	$	22
2011
	Materials and Supplies Valuation Reserve	$	4	$	2	$	—	$	3	(A)	$	3
2010
	Materials and Supplies Valuation Reserve	$	5	$	—	$	—	$	1	(A)	$	4


(A)	Reduced reserve to appropriate level and to remove obsolete inventory.

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

Schedule II—Valuation and Qualifying Accounts Years Ended December 31, 2012—December 31, 2010




	Column A	Column B		Column C Additions				Column D			Column E
	Description	Balance at Beginning of Period		Charged to cost and expenses		Charged to other accounts- describe		Deductions- describe			Balance at End of Period
2012						Millions
	Allowance for Doubtful Accounts	$	56	$	96	$	—	$	96	(A)	$	56
2011
	Allowance for Doubtful Accounts	$	67	$	102	$	—	$	113	(A)	$	56
2010
	Allowance for Doubtful Accounts	$	78	$	99	$	—	$	110	(A)	$	67


(A)	Accounts Receivable written off.

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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 public utilities doing business in New Jersey
Capacity		Amount of electricity that can be produced by a specific generating facility
CAA		Clean Air Act
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
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.
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.
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.
GHG		Greenhouse gas emissions (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

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Term Phrase/Description

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 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
NDT		Nuclear Decommissioning Trust
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
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
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

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Term Phrase/Description

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 cannot 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
SEC		U.S. Securities and Exchange Commission
Services		PSEG Services Corporation
Spill Act		New Jersey Spill Compensation and Control Act
TPS		Third Party Supplier
Transmission		The high-voltage wires and networks that move electricity through states and regions in large quantities -- from power plants where it is produced, to the distribution networks that deliver it to homes and businesses.

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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 25, 2013

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	Chairman of the Board, President, Chief Executive Officer and	February 25, 2013
Ralph Izzo	Director (Principal Executive Officer)

/s/ CAROLINE DORSA	Executive Vice President and Chief Financial Officer	February 25, 2013
Caroline Dorsa	(Principal Financial Officer)

/s/ DEREK M. DIRISIO	Vice President and Controller	February 25, 2013
Derek M. DiRisio	(Principal Accounting Officer)

/s/ ALBERT R. GAMPER, JR.	Director	February 25, 2013
Albert R. Gamper, Jr.

/s/ WILLIAM V. HICKEY	Director	February 25, 2013
William V. Hickey

/s/ SHIRLEY ANN JACKSON	Director	February 25, 2013
Shirley Ann Jackson

/s/ DAVID LILLEY	Director	February 25, 2013
David Lilley

/s/ THOMAS A. RENYI	Director	February 25, 2013
Thomas A. Renyi

/s/ HAK CHEOL SHIN	Director	February 25, 2013
Hak Cheol Shin

/s/ RICHARD J. SWIFT	Director	February 25, 2013
Richard J. Swift

/s/ SUSAN TOMASKY	Director	February 25, 2013
Susan Tomasky

/s/ ALFRED W. ZOLLAR	Director	February 25, 2013
Alfred W. Zollar

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SIGNATURES




			PSEG POWER LLC

		By:	/s/ WILLIAM LEVIS
			William Levis
			President and
			Chief Operating Officer

Date: February 25, 2013




Signature	Title	Date

/s/ RALPH IZZO	Chairman of the Board and Chief Executive Officer and	February 25, 2013
Ralph Izzo	Director (Principal Executive Officer)

/s/ CAROLINE DORSA	Executive Vice President and Chief Financial Officer and	February 25, 2013
Caroline Dorsa	Director (Principal Financial Officer)

/s/ DEREK M. DIRISIO	Vice President and Controller	February 25, 2013
Derek M. DiRisio	(Principal Accounting Officer)

/s/ J.A. BOUKNIGHT, JR.	Director	February 25, 2013
J.A. Bouknight, Jr.

/s/ WILLIAM LEVIS	Director	February 25, 2013
William Levis

/s/ RANDALL E. MEHRBERG	Director	February 25, 2013
Randall E. Mehrberg

/s/ MARGARET M. PEGO	Director	February 25, 2013
Margaret M. Pego

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SIGNATURES




			PUBLIC SERVICE ELECTRIC AND GAS COMPANY

		By:	/s/ RALPH LAROSSA
			Ralph LaRossa
			President and Chief Operating Officer

Date: February 25, 2013




Signature	Title	Date

/s/ RALPH IZZO	Chairman of the Board and Chief Executive Officer and	February 25, 2013
Ralph Izzo	Director (Principal Executive Officer)

/s/ CAROLINE DORSA	Executive Vice President and Chief Financial Officer	February 25, 2013
Caroline Dorsa	(Principal Financial Officer)

/s/ DEREK M. DIRISIO	Vice President and Controller	February 25, 2013
Derek M. DiRisio	(Principal Accounting Officer)

/s/ ALBERT R. GAMPER, JR.	Director	February 25, 2013
Albert R. Gamper Jr.

/s/ SHIRLEY ANN JACKSON	Director	February 25, 2013
Shirley Ann Jackson

/s/ RICHARD J. SWIFT	Director	February 25, 2013
Richard J. Swift

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EXHIBIT INDEX

The following documents are filed as a part of this report:



a. PSEG:
Exhibit 10a(11):		Amended and Restated Key Executive Severance Plan, amended effective December 17, 2012
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(9):		Amended and Restated Key Executive Severance Plan, amended effective December 17, 2012
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
c. PSE&G:
Exhibit 4a(32):		Supplemental Indenture to Mortgage Indenture, dated May 1, 2012

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Exhibit 4a(33):		Supplemental Indenture to Mortgage Indenture, dated June 1, 2012
Exhibit 10a(10):		Amended and Restated Key Executive Severance Plan, amended effective December 17, 2012
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

198