PUBLIC SERVICE ENTERPRISE GROUP INC - Annual Report: 2014 (Form 10-K)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

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, 2014

¨ 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
001-00973	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
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

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
	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
PSEG Power LLC	8 ⁵/8% Senior Notes, due 2031	New York Stock Exchange

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Securities registered pursuant to Section 12(g) of the Act:
Registrant		Title of Each Class
Public Service Electric and Gas Company		Medium-Term Notes

PSEG Power LLC		Limited Liability Company Membership Interest

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 ¨
Public Service Electric and Gas Company	Yes x	No ¨
PSEG Power LLC	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 (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See 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 ¨
Public Service Electric and Gas Company	Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer x
PSEG Power LLC	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, 2014 was $20,598,517,672 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 30, 2015 was 506,179,029.

As of January 30, 2015, 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 2015 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 9, 2015, 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	22
	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	38
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	39
Item 6.	Selected Financial Data	41
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42
	Executive Overview of 2014 and Future Outlook	42
	Results of Operations	47
	Liquidity and Capital Resources	54
	Capital Requirements	58
	Off-Balance Sheet Arrangements	61
	Critical Accounting Estimates	61
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	65
Item 8.	Financial Statements and Supplementary Data	67
	Report of Independent Registered Public Accounting Firm	68
	Consolidated Financial Statements	71
	Notes to Consolidated Financial Statements
	Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies	89
	Note 2. Recent Accounting Standards	93
	Note 3. Variable Interest Entities	94
	Note 4. Property, Plant and Equipment and Jointly-Owned Facilities	95
	Note 5. Regulatory Assets and Liabilities	96
	Note 6. Long-Term Investments	101
	Note 7. Financing Receivables	103
	Note 8. Available-for-Sale Securities	104
	Note 9. Goodwill and Other Intangibles	110
	Note 10. Asset Retirement Obligations (AROs)	110
	Note 11. Pension, Other Postretirement Benefits (OPEB) and Savings Plans	111
	Note 12. Commitments and Contingent Liabilities	121
	Note 13. Schedule of Consolidated Debt	130
	Note 14. Schedule of Consolidated Capital Stock	135
	Note 15. Financial Risk Management Activities	136
	Note 16. Fair Value Measurements	142
	Note 17. Stock Based Compensation	148
	Note 18. Other Income and Deductions	152
	Note 19. Income Taxes	153
	Note 20. Accumulated Other Comprehensive Income (Loss), Net of Tax	161
	Note 21. Earnings Per Share (EPS) and Dividends	164
	Note 22. Financial Information by Business Segment	164
	Note 23. Related-Party Transactions	166
	Note 24. Selected Quarterly Data (Unaudited)	168
	Note 25. Guarantees of Debt	169
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	173
Item 9A.	Controls and Procedures	173
Item 9B.	Other Information	173
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	178
Item 11.	Executive Compensation	179
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	180
Item 13.	Certain Relationships and Related Transactions, and Director Independence	180
Item 14.	Principal Accounting Fees and Services	180
PART IV
Item 15.	Exhibits, Financial Statement Schedules	180
	Schedule II - Valuation and Qualifying Accounts	188
	Glossary of Terms	190
	Signatures	193
	Exhibit Index	196

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FORWARD-LOOKING STATEMENTS

Certain of the matters discussed in this report about our and our subsidiaries' future performance, including, without limitation, future revenues, earnings, strategies, prospects, consequences and all other statements that are not purely historical 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 12. Commitments and Contingent Liabilities, and other factors discussed in filings we make with the United States Securities and Exchange Commission (SEC) including our subsequent reports on Form 10-Q and Form 8-K and available on our website: http://www.pseg.com. 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 regulations, including market structures and transmission planning,


•	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 and enforcement 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 manage our energy obligations, available supply and risks,


•	adverse outcomes of any legal, regulatory or other proceeding, settlement, investigation or claim applicable to us and/or the energy industry,


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


•	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, and any inability to obtain sufficient insurance coverage or recover proceeds of insurance with respect to such events,


•	acts of terrorism, cybersecurity attacks or intrusions that could adversely impact our businesses,


•	increases in competition in energy supply markets as well as for 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,


•	changes in technology, such as distributed generation and micro grids, and greater reliance on these technologies, and


•	changes in customer behaviors, including increases in energy efficiency, net-metering and demand response.

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), Public Service Electric and Gas Company (PSE&G) and PSEG Power LLC (Power). Information relating to any individual company is filed by such company on its own behalf. PSE&G and Power are each only responsible for information about itself and its subsidiaries.

Discussions throughout the document refer to PSEG and its direct operating subsidiaries, PSE&G and Power. Depending on the context of each section, references to “we,” “us,” and “our” relate to PSEG or to the specific company or companies being discussed. In addition, certain key acronyms and definitions are summarized in a glossary beginning on page 190.

WHERE TO FIND MORE INFORMATION

We file annual, quarterly and current 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 two direct wholly owned subsidiaries, Power and PSE&G, each of which also has its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102.

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 two principal direct operating subsidiaries.



	PSE&G		Power

	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 regulated demand response and energy efficiency programs and invested in solar generation within New Jersey.		A Delaware limited liability company formed in 1999 that integrates its merchant nuclear, fossil and renewable 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, emissions credits and a series of energy-related products used to optimize the operation of the energy grid.

Our other direct wholly owned subsidiaries are: PSEG Energy Holdings L.L.C. (Energy Holdings), which earns its revenues primarily from its portfolio of lease investments; PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority's (LIPA) transmission and distribution (T&D) system under a contractual agreement; and PSEG Services Corporation (Services), which provides us and our operating subsidiaries with certain management, administrative and general services at cost.

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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

PSE&G

Our regulated transmission and distribution 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 Federal Energy Regulatory Commission (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 New Jersey Board of Public Utilities (BPU).

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The commodity portion of our utility business’ electric and gas sales is managed by basic generation service (BGS) and basic gas supply service (BGSS) suppliers. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for our utility operations.

We also earn margins through competitive services, such as appliance repair.

In addition to our current utility products and services, we have implemented several programs to increase the level of regulated solar generation within New Jersey, including:


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


•	programs 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—State Regulation and Part II, Item 8. Financial Statements and Supplementary Data—Note 5. Regulatory Assets and Liabilities.

How PSE&G Operates

We are a transmission owner in PJM Interconnection, L.L.C. (PJM) and we 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 cost of service and 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 current 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, see Regulatory Issues—Federal Regulation—Transmission Regulation.




Transmission Statistics

December 31, 2014
Network Circuit Miles	Billing Peak Megawatt (MW)	Historical Annual Load Growth 2010-2014
1,659	9,515	(0.4)%

In April 2014, we completed our North Central Reliability project, an upgrade of 55 circuit miles of 138 kilovolts (kV) transmission line to 230 kV and conversion of six existing stations to 230 kV operation and our Burlington-Camden project, an upgrade of 37 circuit miles of 138 kV transmission line to 230 kV.

During 2014, we continued to execute four major regional transmission projects for which we were assigned construction responsibility by PJM:




Major Transmission Projects
As of December 31, 2014
Project	Total Estimated Project Costs Up To	Total Project Spend	Expected In-Service Date
	Millions
Susquehanna-Roseland 500 kV (A)	$790	$775	June 2015
Northeast Grid Reliability 230 kV	$907	$569	June-December 2015
Mickleton-Gloucester-Camden 230 kV	$435	$278	June 2015
Bergen-Linden Corridor 345 kV	$1,200	$40	June 2018


(A)	On April 1, 2014, Phase One was completed on schedule, placing into service the eastern part of the transmission line from Hopatcong to Roseland, New Jersey. Construction of the transmission line from New Jersey to the Pennsylvania border was completed in 2014.

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Distribution

PSE&G distributes gas and electricity to end users in our respective franchised service territories. Our approved rates, established in our most recent gas and electric base rate proceeding completed in mid-2010, provide for an allowed ROE of 10.3% on distribution rate base. The BPU has also approved a series of PSE&G infrastructure, energy efficiency and renewable energy investment programs with cost recovery through various clause mechanisms, with allowed ROEs ranging from 9.75% to 10.3%. Our load requirements are split among residential, commercial and industrial customers, as described in the following table for 2014.




	% of 2014 Sales
Customer Type	Electric	Gas
Commercial	58%	36%
Residential	32%	60%
Industrial	10%	4%
Total	100%	100%

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




Electric and Gas Distribution Statistics

	December 31, 2014
	Number of Customers		Electric Sales and Gas Firm Sales (A)		Historical Annual Load Growth 2010-2014
Electric	2.2	Million	40,737	Gigawatt hours (GWh)	(0.6)%
Gas	1.8	Million	2,628	Million Therms	2.0%

(A)Excludes Contract Service Gas (CSG) rate class sales, which do not impact margin.

The decline in electric sales is the result of changes in customer usage patterns, including conservation and more energy efficient appliances. Gas firm sales increased to all customer classes as a result of lower gas prices and more favorable weather. Only gas firm sales impact margin.

Solar Generation

In order to support New Jersey's Energy Master Plan and the state's renewable energy goals, we have undertaken two major solar initiatives at PSE&G, the Solar Loan Program and the Solar 4 All and Solar 4 All Extension Programs. Our Solar Loan Program provides solar system financing to our residential and commercial customers. The loans are repaid with cash or solar renewable energy certificates (SRECs). We sell the SRECs used to repay the loans through a periodic auction, the proceeds of which are used to offset program costs. Our Solar 4 All Programs invest in utility-owned solar photovoltaic (PV) centralized solar systems installed on PSE&G property and third party sites, including landfill facilities, and solar panels installed on distribution system poles in our electric service territory. We sell the energy and capacity from the systems in the PJM wholesale electricity market. In addition, we sell SRECs generated by the projects through the same periodic auction used in the loan program, the proceeds of which are used to offset program costs. As of December 31, 2014, we have invested an aggregate of approximately $765 million in both solar programs.

Supply

Although commodity revenues make up almost 43% of our revenues, we make no margin on the default supply of electricity and gas 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 BPU requirements, we serve as the supplier of last resort for two types of electric and gas customers within our service territory that are not served by another 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-Residential Small Commercial Pricing (RSCP)). 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).

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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 electric distribution companies (EDCs). Once validated by the BPU, electricity prices for BGS service are set. Approximately one-third of PSE&G’s total BGS-RSCP eligible load is auctioned each year for a three-year term. For information on current prices, see Part II, Item 8. Financial Statements and Supplementary Data—Note 12. Commitments and Contingent Liabilities.

PSE&G procures the supply requirements of its 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. 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 5% and also may reduce the BGSS rate at any time. See Part II, Item 8. Financial Statements and Supplementary Data—Note 5. Regulatory Assets and Liabilities for information on recent self-implementing credits. 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 select 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 Part II, Item 7. MD&A—Executive Overview of 2014 and Future Outlook.

Power

Through Power, we seek to produce low-cost electricity by efficiently operating our nuclear, coal, gas, oil-fired and renewable generation assets, while balancing generation output, fuel requirements and supply obligations through energy portfolio management. We use the generation we own combined with commodity contracts and financial instruments to cover our commitments for 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 open 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—distinct from energy, capacity is a market commitment that a given generation unit will be available to an Independent System Operator (ISO) for dispatch when it is needed to meet system demand. Capacity is typically priced in dollars per MW for a given sale period (e.g. day or month).

•

Ancillary Services—related activities supplied by generation unit owners to the wholesale market that are 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 collected from 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.

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Power also sells wholesale natural gas, primarily through a full-requirements BGSS contract with PSE&G to meet the gas supply requirements of PSE&G's customers. This long-term arrangement had been for an initial period which extended through March 31, 2012 and continued on a year-to-year basis unless terminated by either party with a one year notice. On March 19, 2014, the BPU approved an extension of the BGSS contract to March 31, 2019 and then year to year thereafter unless terminated by either party with a two year notice.

Approximately 46% of PSE&G’s peak daily gas requirements is provided from Power’s firm gas 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 the availability of natural gas beyond PSE&G's daily needs, Power also sells gas to others and uses it in its generation fleet.

In addition to its nuclear and fossil generation fleet, Power owns and operates 109 MW direct current (dc) of PV solar generation facilities and has a 50% ownership interest in a 208 MW oil-fired generation facility in Hawaii.

The remainder of this section about Power covers our nuclear and fossil fleet in the Mid-Atlantic and Northeast regions which comprise the vast majority of Power’s operations and financial performance.

How Power Operates

Nearly all of our generation capacity consists of nuclear and fossil generation (13,146 MW) that is located in the Northeast and Mid-Atlantic regions of the United States in some of the country’s largest and most developed electricity markets. For additional information see Item 2. Properties.

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


•	Generation Capacity

Our nuclear and fossil installed capacity utilizes a diverse mix of fuels: 46% gas, 28% nuclear, 18% coal, 7% 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 2014 was approximately 54,000 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 in place of our coal units. The following table indicates the proportionate share of generating output by fuel type in 2014.

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Generation by Fuel Type (A)	Actual 2014
Nuclear:
New Jersey facilities	37%
Pennsylvania facilities	17%
Fossil:
Coal:
Pennsylvania facilities	9%
Connecticut facilities	2%
Coal and Natural Gas:
New Jersey facilities	3%
Natural Gas and Oil:
New Jersey facilities	24%
New York facilities	8%
Connecticut facilities	—%	(B)
Total	100%

(A) Excludes pumped storage, solar facilities and fossil generation in Hawaii

(B) 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 34% base load, 44% load following and 22% 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 are called to 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 2014, our base load capacity factors were as follows:




	Unit		2014 Capacity Factor
	Nuclear
	Salem Unit 1		85.8%
	Salem Unit 2 (A)		72.6%
	Hope Creek		97.9%
	Peach Bottom Unit 2		84.7%
	Peach Bottom Unit 3		99.2%
	Coal
	Keystone		77.4%
	Conemaugh		73.9%

(A) Salem Unit 2’s capacity factor in 2014 was negatively affected by an extended outage to make repairs to the unit’s reactor coolant pumps.


•	Load Following Units typically operate between 20% and 70% of the time. The operating costs are higher per unit of output than for base load units due to the use of higher-cost fuels such as oil, natural gas and, in some cases, coal or lower overall unit efficiency. They operate less frequently than base load units and derive revenues from energy, capacity and ancillary services.

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•

Peaking Units run the least amount of time and may 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 given the combination of higher heat rates and fuel costs. The majority of revenues are from capacity and ancillary service sales. The characteristics of these units enable them to capture energy revenues during periods of high energy prices.

In the energy markets in which we operate, owners of power plants specify to the ISO prices at which they are prepared to generate and sell energy based on the marginal cost of generating energy from each individual unit. The ISOs will generally 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 reliably. 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 may 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 unconstrained merit order of dispatch of our units in PJM, the ISO in the region 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-fired generation to displace some coal-fired generation in the load-following portion of the curve.


(A)	The National Park, Sewaren 6, Mercer 3, Salem 3, Burlington 8 and 11, Bergen 3, Edison 1, 2 and 3 and Essex 10, 11 and 12 peaking units are scheduled to be retired in June 2015. Salem 3 is expected to continue to be used as an emergency backup generator for the Salem nuclear site.

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

Typically, 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 a situation where natural gas prices often have a major influence on the price that generators will receive for their output, especially in periods of relatively strong demand. Therefore, changes in the price of natural gas will often translate into changes in the wholesale price of electricity. This can be seen in the following

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graphs which present historical annual spot prices and forward calendar prices as averaged over each year at two liquid trading hubs.

Historical data implies 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 preceding graphs 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, such as the availability of natural gas from the Marcellus and other shale-gas regions, which can be considerable. While these prices provide some perspective on past and future prices, the forward prices are 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—We have long-term contracts for nuclear fuel. These contracts provide for:

•purchase of uranium (concentrates and uranium hexafluoride),

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•conversion of uranium concentrates to uranium hexafluoride,

•enrichment of uranium hexafluoride, and

•fabrication of nuclear fuel assemblies.


•	Coal Supply—Our Keystone, Conemaugh and Bridgeport stations operate on coal. Our Hudson and Mercer stations have the ability to 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 and ocean shipments.

In order to control 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 were not available for this facility, its long-term operations would be adversely impacted since additional material capital expenditures would be required to modify this 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 which we have contracted. In addition, we have firm gas transportation contracts to serve a portion of the gas requirements for our Bethlehem Energy Center (BEC) station in New York.

We have 1.3 billion cubic feet-per-day of firm transportation capacity and 0.9 billion cubic feet-per-day of firm storage delivery under contract to meet our obligations under the BGSS contract. This capacity includes approximately 0.6 billion cubic feet-per-day of access to the northeast Pennsylvania Marcellus shale gas region. On an as-available basis, this firm transportation capacity may also be used to serve the gas supply needs of our generation fleet.

In September 2014, Power obtained an equity interest with an expected investment of $100 million-$120 million in the approximately 110 mile PennEast Pipeline to transport natural gas from eastern Pennsylvania to New Jersey with a targeted in-service date of November 2017. Power has contracted for approximately 125 million cubic feet-per-day of delivery capability on the PennEast Pipeline.


•	Oil—Oil is used as the primary fuel for one load following steam unit and six 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 Part II, Item 7. MD&A—Executive Overview of 2014 and Future Outlook and Item 8. Financial Statements and Supplementary Data—Note 12. Commitments and Contingent Liabilities.

Markets and Market Pricing

The vast majority of 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 FERC:

•

PJM Regional Transmission Organization—PJM conducts the largest centrally dispatched energy market in North America. It serves over 61 million people, nearly 20% of the total United States population, and has a peak demand of 165,492 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 New York ISO (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 20 million and a peak demand of 33,956 MW. Our BEC station operates in New York.


•	New England—The ISO-New England (ISO-NE) is the market coordinator for the New England Power Pool and for administering its energy marketplace which covers Maine, New Hampshire, Vermont, Massachusetts, Connecticut and Rhode Island. This service area has a population of about 14 million and a peak demand of 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 may increase or decrease our profitability.

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Commodity prices, such as electricity, gas, coal, oil and emissions, as well as the availability of our diverse fleet of generation units to operate, 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, lower wholesale natural gas prices have resulted in lower electric energy prices. One of the reasons for the lower natural gas prices is greater supply from more recently-developed sources, such as shale gas. This trend has reduced margin on forward sales as we re-contract our expected generation output.

In addition to energy sales, we earn revenue from capacity payments for our generating assets. These payments are compensation for committing our generating capacity to the ISO for dispatch at its discretion. Capacity payments reflect the value to the ISO of assurance that there will be 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 which raise concerns about reliability and create 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 and provide a 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. 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.

Our PJM generating units are located in several zones and Power expects to realize the following average capacity prices from the base auctions which have been completed:




	Delivery Year		MW-day
	June 2014 to May 2015		$166
	June 2015 to May 2016		$167
	June 2016 to May 2017		$169
	June 2017 to May 2018		$165

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.

We have obtained price certainty for our PJM capacity through May 2018 and New England capacity through May 2019 through the RPM and FCM pricing mechanisms, respectively.

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


•	load and demand,


•	available amounts of demand response resources,


•	capacity imports from external regions,


•	availability of generating capacity (including retirements, additions, derates, forced outage rates, etc.),


•	transmission capability between zones,

•

pricing mechanisms, 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, including PJM’s recent proposal that provides the opportunity for additional energy and capacity market compensation to generators like Power that certify their availability during emergency system conditions, and

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•	legislative and/or regulatory actions 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

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 and similar full-requirements 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-RSCP 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 BPU. The volume of BGS contracts and the mix of electric utilities that our generation operations serve will vary from year to year. Pricing for the BGS contracts, including a capacity component, for recent and future periods by purchasing utility is as follows:




Load Zone ($/MWh)	2012-2015	2013-2016	2014-2017	2015-2018
PSE&G	$83.88	$92.18	$97.39	$99.54
Jersey Central Power & Light Company (JCP&L)	$81.76	$83.70	$84.44	$80.42
Atlantic City Electric Company	$85.10	$87.27	$87.80	$86.06
Rockland Electric Company	$92.51	$92.58	$95.61	$90.66

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 other 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 EDC, that is, the load that remains after some customers have chosen to be served directly either by third party suppliers or through municipal aggregation. 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 are served by a third party supplier, as well as by other factors such as weather and the economy.

In recent years, as market prices declined from previous levels, there was an incentive for more of the smaller commercial and industrial electric customers to switch to third party suppliers. 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. As average BGS rates have declined to a level that more closely resembles current market prices, customers may see less of 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 should market prices fall or rise significantly.

As of February 12, 2015, we had contracted for the following percentages of our anticipated base load generation output for the next three years with modest amounts beyond 2017.




Base Load Generation	2015	2016	2017
Generation Sales	100%	80%-85%	40%-45%

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 had no hedging activity 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.

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. Additionally, the recent development of low-cost gas supplies in the Marcellus region presents opportunities during certain portions of the year to procure gas for our generating units at attractive prices.

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Our fuel 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 our estimated uranium, enrichment and fabrication requirements through 2017 and a significant portion through 2019. 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 in general to enter into contracts for our fuel supply in comparable volumes to our sales contracts.

Other

Energy Holdings primarily owns and manages a portfolio of lease investments. 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.

The majority of Energy Holdings' remaining $836 million of domestic lease investments are primarily energy-related leveraged leases. As of December 31, 2014, 69% of our total leveraged lease investments were rated as below investment grade by Standard & Poor's.

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

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

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

For additional information on leases, including the credit, tax and accounting risks, see Item 1A. Risk Factors, Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Credit Risk, and Item 8. Financial Statements and Supplementary Data—Note 7. Financing Receivables.

In accordance with a twelve year Amended and Restated Operations Services Agreement (OSA) entered into by PSEG LI and the LIPA, PSEG LI commenced operating LIPA’s electric T&D system in Long Island, New York on January 1, 2014. As required by the OSA, PSEG LI also provides certain administrative support functions to LIPA. PSEG LI uses its brand in the Long Island T&D service area. Pursuant to the OSA, PSEG LI acts as LIPA's agent in performing many of its obligations and in return (a) receives reimbursement for pass-through operating expenditures, (b) receives a fixed management fee and (c) is eligible to receive an incentive fee contingent on meeting established performance metrics. In addition, there is the opportunity for the parties to extend the contract for an additional eight years subject to the achievement by PSEG LI of certain performance levels during the initial term of the OSA. Also, as of January 2015, Power began providing fuel procurement and power management services to LIPA under separate agreements.

On July 1, 2014, PSEG LI submitted a proposal to LIPA to invest up to $200 million of capital in equipment at customer facilities that would improve energy efficiency and reduce peak load. PSEG LI proposed to make the investments from 2015 through 2018 and recover its investment and earn a return over approximately ten years. On October 6, 2014, PSEG LI filed an interim update which increased the size of the proposed program to approximately $345 million, reaffirmed its original investment proposal to fund up to $200 million of the program and also offered an alternate economic structure which included a performance incentive mechanism rather than utilizing PSEG LI’s capital. The New York State Department of Public Service will review the proposal and make a recommendation to LIPA which is expected to take action on the proposal in 2015.

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COMPETITIVE ENVIRONMENT

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. Increased reliance by customers on net-metered generation, including solar, and changes in customer behaviors can result in decreased reliance on our system and impact our revenues and investment opportunities. 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 previously provided us a “right of first refusal” (ROFR) to construct projects in our service territory, could result in third party construction of transmission lines in our area in the future and also allow us to seek opportunities to build in other service territories. These implementing rules within the regions are still in flux so both the extent of the risk within our service territory and the opportunities for our transmission business elsewhere remain difficult to assess. For additional information, see the discussion in Regulatory Issues—Federal Regulation—Transmission Regulation, below.

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

Power

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


•	merchant generators,


•	domestic and multi-national utility generators,


•	energy marketers,


•	banks, funds and other financial entities,


•	fuel supply companies, and


•	affiliates of other industrial companies.

New additions of lower-cost or more efficient generation capacity could make our plants less economic 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, municipal aggregation and other customer migration and other factors. In addition, how resources such as demand response and capacity imports are permitted to bid into the capacity markets also affects the prices paid to generators such as Power in these markets. It is also possible that advances in technology, such as distributed generation and micro grids, 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 electric 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 selected to build transmission and who will pay the costs of future transmission could also impact our revenues.

Adverse changes in energy industry law, policies and regulation, including market structures and a potential shift away from competitive markets toward subsidized market mechanisms, would have the effect of artificially depressing prices in the competitive wholesale market and thus have the potential to harm competitive markets, on both a short-term and a long-term basis. At the same time, changes such as that proposed by PJM and discussed more fully in Regulatory Issues—Federal Regulation provide the opportunity for additional compensation in both the energy and capacity markets for being available (and making the necessary investments to ensure availability) during emergency conditions.

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 or regulations were to require our competitors to meet the

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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 (MISO), the PJM region and the California ISO, 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.

EMPLOYEE RELATIONS

As of December 31, 2014, we had 12,689 employees within our subsidiaries, including 7,958 covered under collective bargaining agreements. Four of our collective bargaining union agreements will expire in April 2017, two in October 2017 and one in May 2018. Effective January 1, 2014, in connection with our management contract with LIPA, we assumed the collective bargaining agreement between National Grid Electric Services LLC, LIPA's previous management contractor, and a labor union. That union contract will expire in November, 2016. We believe we maintain satisfactory relationships with our employees.




Employees as of December 31, 2014
	PSE&G	Power	PSEG LI	Other
Non-Union	1,693	1,282	725	1,031
Union	4,832	1,691	1,427	8
Total Employees	6,525	2,973	2,152	1,039

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 Power. 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 FERC regulation fall into five general categories:


•	Regulation of Wholesale Sales—Generation/Market Issues


•	Energy Clearing Prices


•	Capacity Market Issues


•	Transmission Regulation


•	Compliance

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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 their market power has been sufficiently mitigated and report in the interim to the 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, PSEG Nuclear LLC and PSEG New Haven LLC all have been granted MBR authority from the FERC. Each of these companies, except PSEG New Haven LLC (which received MBR authority in May 2012), filed a market power update with the FERC at the end of 2013. In an order issued in October 2014, the FERC accepted these filings as having satisfied the requirements for retention of MBR authority.

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.

As a result of the polar vortex and related cold weather events in January 2014, there were both gas and electric price spikes in the Northeast markets, including in PJM. The FERC has examined the facts surrounding these price spikes, as well as “lessons learned” from the various Regional Transmission Operators/Independent System Operators (RTO/ISO) and potential changes in market rules intended to encourage dual fuel capability of generating units, the purchase of firm fuel to operate these units and the construction of additional natural gas pipeline capacity. As discussed below, PJM has proposed changes to its capacity market construct to develop a new capacity product that would be compensated in both the energy and capacity markets for availability during emergency conditions on the system. The FERC is also examining price formation issues, focusing on levels of compensation to generators in the energy and ancillary services markets, and we are advocating in this context for changes in market rules that would provide more transparency about energy market prices. We cannot predict what action the FERC might ultimately take, but such an examination could lead to future rule changes.

Capacity Market Issues

PJM, the NYISO and the ISO-NE each have capacity markets that have been approved by the FERC. The FERC regulates these markets and continues to examine whether the market design for each of these three capacity markets is working optimally. Specific issues being considered by the FERC are whether capacity market rules properly address and foster the development of state public policies, demand response (DR) and emerging technologies and whether generators are being sufficiently compensated in the capacity market. We cannot predict what action, if any, the FERC might take with regard to capacity market design.

PJM—The RPM is the locational installed capacity market design for the PJM region, including a forward auction for installed capacity. Under the 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 the RPM in PJM continue to evolve and be refined in stakeholder proceedings and FERC proceedings in which we are active. There is currently significant activity concerning three topics: (i) the future role of DR in the RPM market in light of a decision by the D.C. Circuit Court of Appeals (D.C. Court) holding that DR is not a FERC-jurisdictional product, (ii) PJM’s development of a new capacity product called a Capacity Performance (CP) product, and (iii) the setting of the Cost of New Entry (CONE) value for the RPM demand curve for the auctions to be conducted in the next four years.

In May 2014, in a case involving the proper level of compensation for DR resources in the energy markets, the D.C. Court held that DR is not a FERC-jurisdictional product, thereby calling into question DR resources’ ability to participate in either the energy or capacity markets in the future. In January 2015, the FERC filed a petition to the U.S. Supreme Court to review the D.C. Court's ruling. The D.C. Court's decision has been stayed until the U.S. Supreme Court acts on this petition, which is not expected to occur until the end of April. In the meantime, FirstEnergy Corp. has filed a complaint at the FERC which argues that DR resources should no longer participate in the PJM capacity market and seeks to invalidate the results of the last RPM Base Residual Auction that was conducted in May 2014. In addition, PJM has recently submitted a filing at the FERC, conditioned on denial by the U.S. Supreme Court of the FERC's petition for review, that if accepted by the FERC, would only

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allow DR to participate in the capacity market through adjustment of the demand curve rather than as a capacity resource that receives a revenue stream. Should the FERC accept PJM's filing, this new model would be in effect for the upcoming May 2015 Base Residual Auction and could have an upward effect on the auction's clearing prices.

In September 2014, PJM filed at the FERC to re-set the Variable Resource Requirement (VRR) curve for the RPM, as going forward will be done every four years. Establishment of the VRR curve is a critical component in determining how generators are paid in the capacity auction. In November 2014, the FERC accepted PJM’s filing, which we believe represents an improvement over the status quo in terms of appropriately setting the demand curve. However, we and other generators have challenged the FERC’s approval order on rehearing, taking exception with the FERC’s approval of the manner in which PJM calculated the cost of capital and labor costs that form the basis for the CONE component of the demand curve, which we believe have been set too low and do not accurately reflect the costs of building a new generating unit in PJM. The rehearing request remains pending at the FERC.

On December 12, 2014, PJM filed a proposal at the FERC to implement a CP mechanism. Under this mechanism, PJM has created a more robust capacity product definition with enhanced incentives for performance during emergency conditions and significant penalties for non-performance. While there is no specific eligibility requirement, the CP resource must represent that it has made, or will make, the necessary investments to ensure that the resource has the capability to provide energy when emergency conditions on the system exist. CP resources will be able to offer into the capacity market up to Net CONE (the CONE value including offsets for expected energy and ancillary services revenues), but risk remains that bids up to Net CONE may be challenged by regulatory authorities from the standpoint of bidding behavior even when supported by a commercially reasonable assessment of costs. This new product, if accepted by the FERC, will be phased in over the next few years, with full implementation for the 2020-2021 delivery year. PJM’s approach may provide the opportunity for enhanced capacity market revenue streams for Power. However, there may be requirements for additional investment and there are additional performance risks, as well as risks associated with our ability to bid in a manner that would ensure recovery of any capital investment.

MISO—MISO does not have a mandatory capacity market in place, as load serving entities may submit Fixed Resource Adequacy Plans in lieu of participating in the capacity auction. In the May 2013 RPM auction, the difference between the MISO and PJM capacity markets was highlighted, as significant amounts of MISO generation were bid as imports into PJM and cleared in RPM. MISO is seeking to facilitate additional exports. The FERC tightened the rules in 2014 and permitted PJM to establish annual capacity import limits, which were then incorporated into the 2017/2018 planning parameters for the May 2014 base residual auction. We believe that this action had a resultant upward effect on prices in PJM. The FERC continues to examine this "capacity portability" issue and, in response to a complaint filed by a utility company in Indiana, the FERC is also examining whether current PJM/MISO rules regarding capacity imports and exports entered into under the Joint Operating Agreement between the regions are appropriate.

ISO-NE—ISO-NE’s market for installed capacity in New England provides fixed capacity payments for generators, imports and DR. The market design consists of a forward-looking auction for installed capacity that is intended to recognize the locational value of resources on the system and contains incentive mechanisms to encourage availability during stressed system conditions. In May 2014, the FERC issued an order requiring the implementation of a downward sloping demand curve, similar to the design in place in PJM, for use in ISO-NE's ninth capacity market auction, which was recently held and effective in the 2018-2019 delivery year. This action decreased volatility in capacity prices and, in conjunction with an ISO-established seven-year locked-in clearing price for new resources (other than certain subsidized renewable resources) incented the clearing of new generation in the auction. One aspect of this May 2014 FERC order that we did not support was the exemption from the Minimum Offer Price Rule afforded annually up to 600 MW of renewable resources. We challenged this portion of the order on rehearing on the grounds that we believe that it is unduly discriminatory and will suppress capacity prices. In an order issued in January 2015, the FERC denied our rehearing request.

In addition, in the FERC order referenced above, the FERC directed the ISO-NE to develop demand curves for each capacity zone in the market. The ISO-NE is currently conducting a stakeholder proceeding and expects to make a filing with the FERC in the next few months. The shape of the demand curve in the zones will have a significant impact upon the revenues our generation can expect to receive in the capacity market in New England.

NYISO—NYISO operates a short-term capacity market that provides a forward price signal only for six months into the future. Prior to 2013, the NYISO capacity model had recognized only two separate zones that potentially may separate in price: New York City and Long Island. In August 2013, the FERC issued an order approving a third capacity zone that would encompass the super zone that includes the lower Hudson Valley and New York City which took effect on May 1, 2014.

In January 2014, the FERC issued an order accepting the NYISO’s proposed reference unit (a generation unit with no environmental controls) that should be used for the purposes of establishing the CONE in the “rest of State” zone (excluding the lower Hudson Valley, New York City and Long Island), which may have the effect of depressing capacity prices. This order will set the demand curve on which future capacity prices paid to generators will be based for the period May 1, 2014 through April 30, 2017. That order was upheld by the FERC on rehearing in May 2014 and the federal appellate court subsequently denied motions for a stay of the effect of the order.

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Discussions at the FERC 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 enacted the LCAPP to subsidize approximately 2,000 MW of new natural gas-fired generation. The LCAPP provided that subsidies would be offered through long-term standard offer capacity agreements (SOCAs) between selected generators and the New Jersey 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 three SOCAs as directed by the State, but did so under protest reserving their rights.

In 2013, the U.S. District Court in New Jersey found that the LCAPP was unconstitutional and declared the LCAPP null and void. As a result of that decision, PSE&G terminated its SOCA contracts. This federal court decision was subsequently challenged on appeal in the U.S. Third Circuit Court of Appeals. The State of Maryland also took similar action to subsidize above-market new generation. This action was also determined to be unconstitutional in 2013 in the U.S. District Court in Maryland and such decision was challenged in the U.S. Fourth Circuit Court of Appeals. Both appeals were denied, with the U.S. Fourth Circuit Court of Appeals denying the appeal regarding the State of Maryland’s action in June 2014 and the U.S. Third Circuit Court of Appeals denying the LCAPP appeal in September 2014. These denials have now been challenged on appeal to the U.S. Supreme Court, which action remains pending.

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 subsequently trued up to reflect actual annual expenses and 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 2015 Formula Rate Update with the FERC for approximately $182 million in increased annual transmission revenues went into effect on January 1, 2015. Each year, transmission revenues are adjusted to reflect items such as updating estimates used in the filing with actual data. The adjustment for 2015 will include the impact of the extension of bonus depreciation, which was enacted after the filing was made, and is estimated to reduce our 2015 revenue increase as filed by approximately $21 million. For additional information about our transmission formula rate, see Part II, Item 8. Financial Statements and Supplementary Data—Note 5. Regulatory Assets and Liabilities.

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Transmission Policy Developments—The FERC concluded in Order 1000 that the incumbent transmission owner should not always have a ROFR to construct and own transmission projects in its service territory. We had challenged the FERC's elimination of the ROFR in federal court. In August 2014, our challenge was rejected by the D.C. Court. PJM is currently implementing its rules under which the construction of certain types of transmission projects will no longer be subject to a ROFR for incumbents. In May 2014, the FERC approved PJM’s rules, which retain carve-outs for projects that will continue to default to incumbents for construction responsibility, including projects being built on existing right-of-way and whose construction would interfere with incumbents’ use of their right-of-way. Several companies, including PSE&G, have appealed various aspects of this approval order.

The FERC has also approved the “state agreement approach” to cost allocation under which transmission projects being built to address public policy concerns may be placed into PJM's planning process if the state sponsoring the project agrees to pay the costs of the project. To date, no such projects have been placed into the planning process but this mechanism could potentially facilitate transmission projects that are not needed for reliability or market efficiency under PJM standards for transmission, including potential offshore wind projects proposed by third parties, should a state or states agree to fund the costs of such projects.

In addition, in September 2014, PJM filed at the FERC to add another category of project - the “multi-driver” project - to its planning process. This type of project would contain reliability, economic and/or public policy elements. Projects falling within this category would be required to independently satisfy all of the different drivers in order to be approved. However, this category could also serve as a vehicle for the development of large, public policy-driven projects. In October 2014, the FERC issued a deficiency letter regarding PJM’s “multi-driver” filing seeking additional information and clarification with respect to the filing, to which PJM responded in December 2014. We have protested the filing on the grounds that this new project category is not needed for reliability and that the rules to allocate costs for these projects are unclear. The FERC has recently issued an order accepting PJM’s filing. We are currently considering whether to seek rehearing.

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PJM's first action toward complying with Order 1000 began in April 2013, when it initiated its first "open window" solicitation process to allow both incumbents and non-incumbents the opportunity to submit transmission project proposals to address identified high voltage issues at Artificial Island. PJM has not yet concluded this process. On January 30, 2015, PSE&G filed a complaint against PJM at the FERC, asserting that PJM had failed to follow its tariff rules governing the process and requesting that the FERC direct PJM to do so. If the FERC grants the complaint, one outcome could be that PJM will be required to re-start the entire selection process for this project. The FERC could also require PJM to make changes to the rules governing future competitive solicitations.

In addition, the FERC is currently considering two significant transmission cost allocation matters. The first involves a November 2014 complaint brought by Con Edison against PJM at the FERC challenging PJM's allocation of costs for two PSE&G projects in northern New Jersey, including the Bergen-Linden Corridor Project (BLC Project) discussed below. We have opposed Con Edison's complaint. The other proceeding is a matter remanded from a federal appellate court concerning the appropriate cost allocation for certain 500 kV projects in PJM that either have been built or are in the process of being built, including the Susquehanna-Roseland project. This matter is currently in settlement discussions at the FERC. Resolution of these two proceedings could ultimately impact the amount of costs borne by ratepayers in New Jersey.

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Transmission Rate Proceedings—In December 2013, PSE&G was assigned construction responsibility by PJM of a new transmission project that will provide a double-circuit 345 kV line in the BLC Project to maintain reliability. Phases One through Three of the BLC Project are scheduled to be in service in 2016, 2017 and 2018, respectively, with certain components of Phase One required to be in service as early as June 2015. The estimated construction costs of the BLC Project are $1.2 billion. On March 28, 2014, we filed a petition with the FERC seeking incentives for the BLC Project, specifically recovery of Construction Work in Progress in rate base and authorization to recover 100% of all prudently incurred development and construction costs if the BLC Project is abandoned or canceled, in whole or in part, for reasons beyond the control of PSE&G. In May 2014, the FERC issued an order granting our petition requesting incentives. A merchant transmission company has challenged its allocated cost responsibility for the BLC Project and the order granting PSE&G's request for incentives related to that project.

There are several complaints pending at the FERC against transmission owners around the country, challenging those transmission owners’ base ROEs. While we are not the subject of a challenge to the ROE employed in PSE&G’s transmission formula rate, the results of these other proceedings could set precedents for other transmission owners with formula rates in place, including PSE&G.

Compliance

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FERC Audit—In November 2012, the FERC commenced an audit of each of the PSEG companies that have MBR authority from the FERC. The companies were audited by the FERC for compliance with its rules for (i) receiving and retaining MBR authority, (ii) the filing of electric quarterly reports (EQRs), and (iii) our generating units' receipt of payments from the RTO/ISO when they are required to run for reliability reasons when it is not economical for them to do so. On October 16, 2014, the FERC issued a final, public audit report that contained two findings and recommendations for enhanced review and reporting of our EQRs. In November 2014, we submitted a compliance plan to the FERC explaining how we intend to implement the FERC’s recommendations and we are providing quarterly updates to the FERC until we have implemented all such recommendations.

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FERC—In the first quarter of 2014, Power discovered that it incorrectly calculated certain components of its cost-based bids for its New Jersey fossil generating units in the PJM energy market. Upon discovery of the errors, we retained outside counsel to assist in the conduct of an investigation into the matter. As the investigation proceeded, additional pricing errors in the bids were identified and it was further determined that the quantity of energy that Power offered into the energy market for its fossil peaking units differed from the amount for which Power was compensated in the capacity market for those units. On September 2, 2014, the FERC staff initiated a preliminary, non-public staff investigation into the matter. This investigation, which is ongoing, could result in the FERC seeking disgorgement of any over-collected amounts, civil penalties and non-financial remedies. It is not possible at this time to reasonably estimate the ultimate impact or predict any resulting penalties, other costs associated with this matter, or the applicability of mitigating factors. See Part II, Item 8. Financial Statements and Supplementary Data. Note 12. Commitments and Contingent Liabilities—FERC Compliance for further discussion of this matter.

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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 (grid) and to prevent major system blackouts. There has been considerable focus recently on physical security in light of, among other things, a substation attack in California that occurred in 2013. As a result, the FERC directed the NERC to draft a physical security standard intended to further protect assets deemed “critical” to reliability of the grid. In November 2014, the FERC issued an order approving the NERC’s proposed physical security standard. Under the standard, utilities will be required to identify critical substations as well as develop threat assessment plans to be reviewed by independent third parties. In our case, the third party is PJM. As part of these plans, utilities could decide or be required to build additional redundancy into their systems. This standard will supplement the Critical Infrastructure Protection standards that are already in place and that establish physical and cybersecurity protections for critical systems.

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. We are currently subject to record keeping and data reporting requirements applicable to commercial end users. The CFTC has also proposed rules establishing position limits for trading in certain commodities, such as natural gas, and we are currently analyzing the potential impact of these rules on our business.

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 in the following table:




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

As a result of events at the Fukushima Daiichi nuclear facility in Japan following the earthquake and tsunami in 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, a 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.

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

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named 23 of the then total 104 active commercial nuclear reactors in the United States. In March 2014, the NRC formally closed the petition without opting to conduct further proceedings.

The NRC issued letters and orders to licensees implementing the Tier 1 recommendations in March 2012. In March 2013, the NRC initiated a rulemaking process for improvements to venting systems at 31 U.S. BWRs with “Mark I” and “Mark II” containments (similar to those at Fukushima), which include our Hope Creek and Peach Bottom units. In June 2013, the NRC issued orders requiring Mark I and Mark II licensees to upgrade or replace their reliable hardened vents with containment venting systems designed and installed to remain functional during severe accident conditions. We are implementing the diverse and flexible strategies and spent fuel pool level indication modifications in accordance with the regulatory requirements at the Salem, Hope Creek and Peach Bottom nuclear units. For our Hope Creek and Peach Bottom units, final installation of the required modifications is expected to occur during the planned refueling outages in 2016-2018.

The NRC is currently developing the regulatory basis for drywell filtration strategies rulemaking. The NRC expects to complete its evaluation and vote on a final rule in 2017. The NRC continues to evaluate potential revisions to its requirements in connection with its operational and safety reviews of nuclear facilities in the United States as a result of the Fukushima Daiichi incident.

We are unable to predict the final outcome of these reviews or the cost of any actions we would need to take to comply with any new regulations, including possible modifications to our Salem, Hope Creek and Peach Bottom facilities, but such cost could be material.

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. We are also subject to various other states’ regulations due to our operations in those states.

Our New Jersey 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 must file electric and gas rate cases with the BPU in order to change our utility base distribution rates. Our last base rate case was settled in 2010. As a result of our Energy Strong order discussed below, we are required to file our next base rate case proceeding no later than November 1, 2017. In addition to base rates, we recover certain costs or earn on certain investments pursuant to mechanisms known as adjustment clauses. These clauses permit 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 Part II, Item 8. Financial Statements and Supplementary Data—Note 5. Regulatory Assets and Liabilities.

Energy Strong 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 improve resiliency for the future. The changes that were described, designated as the “Energy Strong Program,” would be made over a ten-year period. In this petition, we sought 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. In May 2014, the BPU issued an Order approving the settlement of our Energy Strong program. Under the settlement, PSE&G will invest $1.22 billion to (1) upgrade all of its electric substations that were damaged by water in recent storms; make investments that will create redundancy in the electric distribution system, reducing outages when damage occurs; and deploy technologies to better monitor system operations, enabling PSE&G to restore customers more quickly in the event of an electric outage, and (2) with respect to PSE&G’s gas system, replace and modernize 250 miles of low-pressure cast iron gas mains in or near flood areas; and upgrade five natural gas metering stations and a liquefied natural gas station recently affected by severe weather or located in flood zones. The settlement provides for cost recovery at a 9.75% rate of ROE on the first $1.0 billion of the investment, plus associated Allowance for Funds Used Under Construction, and will occur for completed projects on a semi-annual (for electric investments) or annual (for gas investments) basis. We will seek recovery of the remaining $220 million of investment in PSE&G's next base rate case, which as noted above, is to be filed no later than November 1, 2017.

In September 2014, PSE&G filed its initial Energy Strong cost recovery petition, seeking BPU approval to recover in base rates capitalized Energy Strong electric investment costs expected to be in service through November 30, 2014. This request was updated in December 2014 for actual costs and recovery of an estimated annual revenue increase of $1.1 million effective March 1, 2015.

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Energy Efficiency Economic Stimulus Extension II (EEE Ext II)—In August 2014, we filed for approval from the BPU of an EEE Ext II Program to extend three EEE subprograms (multi-family, direct install and hospital efficiency). We proposed to extend the subprograms’ offerings under the same clause recovery process as currently approved while seeking additional capital expenditures of approximately $96 million and additional administrative costs of $14 million. The matter is pending.

Consolidated Tax Adjustments (CTA)—New Jersey is one of only a few states that make CTA in setting rates for regulated utilities. These adjustments to rate base are made during the rate setting process and are intended to allocate to utility customers a portion of the tax benefits realized from the filing of a consolidated federal tax return by the utility’s parent corporation. The BPU has been considering the appropriateness of the adjustment and the methodology and mechanics of the calculation for some time. On October 22, 2014, the BPU approved a proposal by its Staff that limits the tax benefit period to be considered in the calculation to five years, sets the rate base adjustment at 25% of any such tax benefit and eliminates from the process any tax benefits tied to transmission earnings. In accordance with this October action, this CTA policy will be applied only with respect to future rate cases. The adoption of these modifications by the BPU is not expected to have a material impact on PSE&G’s current earnings nor in its next rate case filing. On November 5, 2014, the New Jersey Division of Rate Counsel appealed the BPU's decision. The appeal remains pending.

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. While not having the force of law, the EMP provides an overview of energy policy in New Jersey and may provide both opportunities and challenges for PSEG. The most recent EMP was finalized in December 2011 and placed an emphasis on expanding in-state electricity resources, reducing energy costs, recognizing the impact of climate change and setting new targets for a renewable portfolio standard and goals for energy supplies from clean energy sources.

Additional matters are discussed in Part II, Item 8. Financial Statements and Supplementary Data—Note 5. Regulatory Assets and Liabilities.

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 Part II, Item 8. Financial Statements and Supplementary Data—Note 12. 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.


•	Hazardous Air Pollutants Regulation—In February 2012, the Environmental Protection Agency (EPA) published under the National Emission Standard for Hazardous Air Pollutants provisions of the Clean Air Act, Mercury Air

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Toxics Standards (MATS) for both newly-built and existing electric generating sources. The impact to our fossil generation fleet in New Jersey and Connecticut and our jointly-owned coal-fired generating facilities in Pennsylvania is further discussed in Part II, Item 8. Financial and Supplementary Data—Note 12. Commitments and Contingent Liabilities.

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Demand Response (DR) Reciprocating Internal Combustion Engines (RICE) Litigation—In March 2013, Power filed a petition at the EPA challenging the National Emission Standards for Hazardous Air Pollutants (NESHAP) for RICE issued in January 2013. In April 2013, Power, along with several other energy companies, filed a petition for review at the D.C. Court which remains pending. Among other things, the final EPA rule allows owners and operators of stationary emergency RICE to operate their engines as part of an emergency DR program without the installation and operation of emission controls or compliance with emission limits otherwise applicable to non-emergency counterparts. This waiver of NESHAP standards results in disparate treatment of different generation technology types. In its appeal, Power sought more stringent emission control standards for RICE to support more competitive markets, particularly the PJM capacity market. In August 2014, the EPA denied the March 2013 petition and in October 2014, Power appealed the EPA's denial to the D.C. Court.

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Cross-State Air Pollution Rule (CSAPR)—In July 2011, the EPA issued the final CSAPR, which 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). In August 2012, the D.C. Court vacated CSAPR and ordered that the existing Clean Air Interstate Rule (CAIR) requirements remain in effect until an appropriate substitute rule has been promulgated. 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. In April 2014, the Supreme Court overturned the D.C. Court's ruling. In October 2014, the D.C. Court lifted the stay on CSAPR. On November 21, 2014, the EPA issued a notice to implement CSAPR effective January 1, 2015. We do not anticipate any material impact on our earnings or financial condition due to the CSAPR.

Climate Change

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CO₂ Regulation Under the CAA—In April 2012, the EPA published the proposed New Source Performance Standards (NSPS) under the CAA for greenhouse gas (GHG) emissions for new power plants only. In June 2013, the President directed the EPA to propose revised NSPS for new power plants by September 20, 2013, propose GHG regulations for existing power plants by June 1, 2014, finalize such regulations by June 1, 2015 and require states to submit GHG implementation regulations by June 30, 2016.

In January 2014, the EPA proposed revised NSPS for new power plants. The revised NSPS establish three emission standards for CO₂ for the following categories: (i) fossil fuel-fired utility boilers and integrated gasification combined cycle (IGCC) units, (ii) large natural gas combustion turbines, and (iii) small natural gas combustion turbines. The EPA is requesting comment on use of an electric output sales threshold to determine applicability to the NSPS. This electric output sales threshold would eliminate the outright exclusion of simple cycle combustion turbines which was proposed in the initial April 2012 NSPS. We cannot predict the final outcome of these proposed standards.

In June 2014, the EPA issued a proposed GHG emissions regulation for existing power plants. The regulation establishes state-specific emission rate targets based on implementation of the best system of emission reduction (BSER). The BSER consists of four components: (i) heat rate improvements at existing coal-fired power plants, (ii) increased use of existing natural gas combined cycle capacity, (iii) operation of zero-emitting generation (renewables and nuclear), and (iv) increased use of demand-side energy efficiency. States may choose these or other methodologies to achieve the necessary reductions of CO₂ emissions.

Since the EPA has requested comments on many aspects of the proposal, the final rule may look considerably different than the proposal. We continue to work with state and federal regulators, as well as industry partners, to determine the potential impact. A final rule is expected in mid-summer 2015.

The FERC will hold a series of technical conferences early in 2015 to discuss the implications of compliance approaches to the EPA’s proposed GHG regulation for existing power plants. The conferences will focus on issues related to electric reliability, wholesale electric markets and operations and energy infrastructure.

In August 2014, an Ohio-based energy company and several states filed petitions for review with the D.C. Circuit Court. The parties are challenging the EPA's authority to regulate existing electric generating units under the existing source performance standards section of the CAA. The matter is pending.

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Climate-Related Legislation or Regulation—The federal government may consider legislative and/or regulatory 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 or regulation 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. Certain northeastern states (RGGI States), including New York and Connecticut where we have generation facilities, have state-specific rules in place to enable the RGGI regulatory mandate in each state to cap and reduce CO₂ emissions.

These 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. Allowances are available through the auction or through secondary markets.

In February 2013, the RGGI States released an updated Model Rule that, among other things, reduced the amount of available regional CO₂ allowances beginning in 2014. Each RGGI State must implement the changes through state-specific regulations. We do not expect these changes, or any future changes, to the RGGI rules will have a material impact on us.

New Jersey withdrew from RGGI beginning in 2012. As a result, our New Jersey facilities are no longer obligated to acquire CO₂ emission allowances. This action has been challenged by environmental groups in the New Jersey state court. In March 2014, the Appellate Division of the New Jersey Superior Court ruled that the New Jersey Department of Environmental Protection (NJDEP) improperly withdrew its regulation under which RGGI had been implemented. The Court gave the NJDEP 60 days to initiate a public process to either repeal or amend that regulation to provide that it is applicable only when New Jersey is a participant in a regional or other established greenhouse gas program. In July 2014, the NJDEP published its intent to formally repeal the rules implementing RGGI in New Jersey. We cannot predict the outcome of this matter.

New Jersey also adopted the Global Warming Response Act in 2007, which calls for stabilizing its GHG 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 action. We also have ownership interests in facilities in other jurisdictions that have their own laws and implement regulations to control discharges to their surface waters and ground waters that directly govern our facilities in those jurisdictions.

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Steam Electric Effluent Guidelines—In April 2013, the EPA issued notice of a proposed rule that would further limit the discharge of pollutants in wastewater from the operation of coal-fired generating facilities. Our co-owned Keystone and Conemaugh facilities continue to use technologies that generate these wastewater discharges. However, our other coal-fired facilities no longer discharge many of these types of wastewater pollutants. We are unable to predict the impact on Keystone and Conemaugh but do not believe there would be any material impact on our other coal-fired facilities. The EPA is expected to finalize the rule in September 2015.

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 and do not use 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.

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Cooling Water Intake Structure Regulation—In 2011, the EPA published a new proposed rule under Section 316(b) which did not establish any particular technology as the best technology available (e.g. closed-cycle cooling). Instead, the proposed rule established marine life mortality standards for existing cooling water intake structures with a design flow of more than 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. In June 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. The EPA also 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 initial rule proposal. We and industry trade associations submitted comments on both NODAs in July 2012. In May 2014, the EPA issued a final cooling water intake rule under Section 316(b) of the Clean Water Act that establishes new requirements for the regulation of cooling water intakes at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day.

The EPA did not mandate closed cycle cooling as “Best Technology Available.” Instead, the EPA set a fish impingement mortality standard that relies on a technology-based approach. Under this standard, power facilities have the flexibility to select one of several options as their method of compliance. The rule also requires that entrainment BTA decisions rely on site-specific analysis that includes an assessment of social costs-social benefits.

The EPA has structured the rule so that each state will continue to consider renewal permits for existing power facilities on a case by case basis. In connection with the assessment of the BTA of each facility that seeks permit renewal, the rule requires that facilities conduct a wide range of studies related to impingement mortality and entrainment and submit the results with their permit applications. In August 2014, the EPA established October 14, 2014 as the effective date for each state to implement the provisions of the rule going forward when considering the renewal of permits for existing facilities on a case by case basis. In September 2014, several environmental non-governmental groups and certain energy industry groups filed motions to litigate the provisions of the rule. This case is pending at the U.S. Second Circuit Court of Appeals. In two related actions on October 17, 2014 and November 20, 2014, several environmental non-governmental groups initiated challenges to the Endangered Species Act provisions of the 316 (b) rule.

We are assessing the potential impact of the rule on each of our affected facilities and are unable to predict the outcome of permitting decisions 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 Part II, Item 8. Financial Statements and Supplementary Data— Note 12. Commitments and Contingent Liabilities for additional information.

In October 2013, the Delaware Riverkeeper Network and several other environmental groups filed a lawsuit in the Superior Court of New Jersey seeking to force the NJDEP to take action on our pending application for permit renewal at Salem either by denying the application or issuing a draft for public comment. An application for renewal of the permit was submitted in January 2006 and the NJDEP had delayed action pending the EPA’s finalization of the Clean Water Act 316(b) regulations. In November 2014, the environmental groups announced settlement of the lawsuit filed with the NJDEP and that the NJDEP has committed to issue a draft permit by June 30, 2015.

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Waters of the United States—In April 2014, the EPA Administrator and the Assistant Secretary of the Army (Civil Works) jointly published a proposed rule to clarify the definition of waters of the U.S. under the Clean Water Act (CWA) programs in order to protect the streams and wetlands that form the foundation of the nation’s water resources. This definition will have broad application to all areas of compliance under the CWA, including permitted discharges and construction activities. On November 14, 2014, we participated with other energy companies in submitting comments on the proposed rule. Given the broad nature of the proposed rule, we are unable to determine the materiality of the impacts that might result from the final rule.

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. See Item 3. Legal Proceedings. 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 Part II, Item 8. Financial Statements and Supplementary Data—Note 12. 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. In accordance with the Nuclear Waste Policy Act of 1982, in 2009 the U.S. Department of Energy (DOE) conducted its annual review of the adequacy of the Nuclear Waste Fee and concluded that the current fee of 1/10 cent per kWh was adequate to recover program costs. In 2011, we joined the Nuclear Energy Institute (NEI) and fifteen other nuclear plant operators in a lawsuit in federal court seeking suspension of the Nuclear Waste Fee. In June 2012, the court ruled that the DOE failed to justify continued payments by electricity consumers into the Nuclear Waste Fund and ordered the DOE to conduct a complete reassessment of this fee. 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. In May 2014, the DOE advised us that as of May 16, 2014, the nuclear waste fee was being suspended/reduced to zero. The elimination of this fee is expected to result in an annualized pre-tax benefit of approximately $30 million.

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 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 2010, the EPA published a proposed rule offering three main options for the management of CCRs under the Resource Conservation and Recovery Act (RCRA). One of these options regulates CCRs as a hazardous waste while the other two options would continue to regulate the disposal of CCRs as a non-hazardous waste. In 2012, several environmental organizations and CCR marketers brought a citizens' suit against the EPA in federal court arguing that the EPA failed to perform its mandatory duty under RCRA to review and revise, if necessary, the RCRA rule applicable to CCRs. The EPA issued a final rule on December 19, 2014 which regulates CCRs as non-hazardous and requires that facility owners implement a series of actions to close or upgrade existing CCR surface impoundments and/or landfills. It also establishes new provisions for the construction of new surface impoundments and landfills. Our Hudson and Mercer generating stations, along with our co-owned Keystone and Conemaugh stations, are subject to the provisions of this rule. The scope of the work entailed to comply has not yet been finalized but we expect that the impacts of this rule will not be material to our results of operations, financial condition or cash flows.

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SEGMENT INFORMATION

Financial information with respect to our business segments is set forth in Part II, Item 8. Financial Statements and Supplementary Data—Note 22. Financial Information by Business Segments.

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 report.

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:

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Obtain fair and timely rate relief—PSE&G'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, they 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 adverse impact on our business.

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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 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.

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Comply with regulatory requirements—There are federal standards, including mandatory NERC and Critical Infrastructure Protection 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 and are subject to penalties for non-compliance with applicable NERC standards.

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.

In addition, Power is currently being investigated by the FERC Staff with respect to errors in certain of its bids submitted for its fossil-generating units into the PJM market. See Item 1. Federal Regulation—Compliance—FERC for further information on this matter.

We are 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

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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 combined management audit and 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:

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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,


•	variation in the relative prices of electricity and gas at the hubs within the markets,


•	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 receive for their output, especially in periods of relatively strong demand. Therefore, significant changes in the price of natural gas 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 reason 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 economic 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.),


•	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 regarding compensation for generators that certify their availability during emergency conditions.

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

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, 2014, it may have had to provide approximately $945 million in additional collateral.

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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 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. 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.

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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 of 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:

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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. The current direction in this area is the EPA’s proposed regulation of existing fossil-fueled generating facilities under the existing source performance standards section of the CAA. 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. Multiple states are developing or have developed state-specific or regional initiatives to obtain CO₂ emissions reductions in the electric power industry. The RGGI is such a program in the Northeast. 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.

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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. 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 our fossil generation operations 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. The renewal filing has not been updated since the 2006 filing.

The EPA issued a proposed rule in 2011 regarding regulation of cooling water intake structures. Following the receipt of extensive comments on its proposed rule, the EPA finalized this rule on May 19, 2014 with an effective date of October 14, 2014. The EPA did not mandate closed cycle cooling as the BTA. Instead, the EPA set a fish

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impingement mortality standard that relies on a technology-based approach. Under this standard, power facilities have the flexibility to select one of several options as their method of compliance. The rule also requires that entrainment BTA decisions rely on site-specific analysis that includes an assessment of social costs-social benefits.

If the NJDEP or 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.

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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. New Jersey law places 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, impacting the speed by which we will need to investigate contaminated properties, which could adversely impact cash flow. 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. However, exposure to natural resource damages could subject us to additional potentially material liability.

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:

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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.

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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.

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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 approximately half 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. Further, as a licensed nuclear operator subject to the Price-Anderson Act and a member of a

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nuclear industry mutual insurance company, Power is subject to potential retroactive assessments as a result of a nuclear incident or retroactive adverse loss experience.

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 January 2011, New Jersey enacted a law establishing a LCAPP which provided for the construction of subsidized base load or mid-merit electric power generation. The LCAPP legislation was invalidated on constitutional grounds by a federal court order issued in October 2013 and a subsequent challenge in the U.S. Court of Appeals for the Third Circuit upheld that decision. that decision has now been filed with the U.S. Supreme Court for consideration on appeal. However, future state actions in New Jersey and elsewhere to subsidize the construction of new generation could have the effect of artificially depressing prices in the competitive wholesale market on both a short-term and long-term basis.

We could also be impacted by a number of other events, including regulatory or legislative actions, including, among other things, direct and indirect subsidies, favoring non-competitive markets and/or technologies 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 capacity and energy revenues could be adversely affected. Moreover, through changes encouraged by the FERC to transmission planning processes, or through RTO/ISO initiatives to change their planning processes, such as the recently accepted multi-driver project category in PJM, more transmission may ultimately be built to facilitate renewable generation or support other public policy initiatives.

The FERC has also eliminated the ROFR, which will have the effect of allowing third parties to build certain types of transmission projects in the service territories of incumbent utilities such as PSE&G. As a result, we could face competitive pressures for our transmission business in New Jersey, as well as in in other utilities’ service territories where we will be able to seek opportunities to build. Changes to FERC policies regarding transmission planning and rate treatment for transmission investment, including ROEs and incentive rates, could also have an impact on our transmission business. In addition, certain PJM cost allocation determinations have been recently challenged at the FERC, the resolution of which could impact costs borne by New Jersey ratepayers and increase customer bills.

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,


•	affiliates of other industrial companies, and


•	distributed generation.

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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.

Changes in customer usage patterns and technology could adversely impact us.


•	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 behaviors—It is possible that advances in technology will reduce the cost of alternative methods of producing electricity, including distributed generation, such as fuel cells, micro turbines, micro grids, windmills and net-metered PV (solar) cells, to a level that is competitive with that of most central station electric production. Large customers, such as universities and hospitals, continue to explore potential micro grid installation. Substantial micro grid penetration can impact energy costs, system performance and demand growth. It is also possible that electric customers may significantly decrease their electric consumption due to demand-side energy conservation programs. Changes in technology and usage, such as municipal aggregation, could also alter the channels through which retail electric customers buy electricity, which could adversely affect our financial results. Increased reliance by customers on on-site generation, including solar, and changes in customer behaviors can result in decreased reliance on our system and impact our revenues and investment opportunities.

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

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

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

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 and results of operations.

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 or financing for projects and investments.

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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 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 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 and could result in substantial financial losses.

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 equipment failures, accidents, severe weather events, or other incidents which could result in damage to or destruction of our facilities or damage to persons or property. For instance, equipment failures in our natural gas distribution could give rise to a variety of hazards and operating risks, such as leaks, accidental explosions and mechanical problems, which could cause substantial financial losses. PSE&G operates and maintains more than 17,700 miles of distribution mains that transport gas to 1.8 million customers. PSE&G also operates and maintains the largest cast iron infrastructure in any one state in the country at approximately 4,000 miles.

In addition, the physical risks of severe weather events, such as experienced from Hurricane Irene and Superstorm Sandy, and of climate change, changes in sea level, temperature and precipitation patterns and other related phenomena have further 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 adversely affect our costs, competitiveness and future investments, which could be material to our financial position, results of operations and cash flow.

Acts of war or terrorism 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, could be direct or indirect targets or be affected by terrorist or other criminal activity. Such events could severely disrupt business operations and prevent us from servicing our customers. In addition, new or updated security regulations may require us to make changes to our current measures which could also result in additional expenses.

Cybersecurity attacks or intrusions could adversely impact our businesses.

We own and/or operate generating stations, transmission and distribution facilities, which are dependent on the operation of our computing systems. Our ability to market our generation output and acquire and hedge fuel and power are also dependent on our computing systems. Our computing systems may be impacted by cybersecurity attacks, hostile technological intrusions or inadvertent disclosure of company and/or customer information or a cybersecurity attack may leverage our information technology to cause disruptions at another company. Cybersecurity threats to our operations include:


•	Disruption of the operation of our assets and the power grid,


•	Theft of confidential company, employee, shareholder, vendor or customer information,


•	General business system and process interruption or compromise, including preventing us from servicing our customers, collecting revenues or the ability to record, process and/or report financial information correctly, and


•	Breaches of vendors' infrastructures where our confidential information is stored.

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If a significant cybersecurity event or breach should occur, it could result in material costs for repair and remediation, breach notification, operations and increased capital costs. Such a cybersecurity incident could also cause us to be non-compliant with applicable laws, regulations or contracts that require us to securely maintain confidential data, causing us to incur costs related to legal claims or proceedings, regulatory fines and increased scrutiny and possible damage to our reputation and brand, resulting in a reduction in customer confidence. We devote resources to network and application security, encryption and other measures to protect our computing systems and infrastructure from unauthorized access or misuse and interface with numerous external entities to improve our cybersecurity situational awareness. However, given the ever changing nature of cybersecurity threats, there can be no assurance the steps we take can protect us against all possible occurrences.

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 obtain necessary regulatory approvals, 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, information technology, 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.

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.

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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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

PSEG, PSE&G and Power

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 Part II, Item 8. Financial Statements and Supplementary Data—Note 12. Commitments and Contingent Liabilities.

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Generation Facilities

Power

As of December 31, 2014, Power’s share of summer installed fossil and nuclear 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	443	100%	443	Oil	Load Following
Total Steam		5,953		3,307
Nuclear:
Hope Creek	NJ	1,178	100%	1,178	Nuclear	Base Load
Salem 1 & 2	NJ	2,307	57%	1,324	Nuclear	Base Load
Peach Bottom 2 & 3 (B)	PA	2,242	50%	1,121	Nuclear	Base Load
Total Nuclear		5,727		3,623
Combined Cycle:
Bergen	NJ	1,198	100%	1,198	Gas	Load Following
Linden	NJ	1,300	100%	1,300	Gas	Load Following
Bethlehem	NY	774	100%	774	Gas	Load Following
Kalaeloa	HI	208	50%	104	Oil	Load Following
Total Combined Cycle		3,480		3,376
Combustion Turbine (C):
Essex	NJ	623	100%	623	Gas	Peaking
Edison	NJ	516	100%	516	Gas	Peaking
Kearny	NJ	452	100%	452	Gas	Peaking
Burlington	NJ	376	100%	376	Oil/Gas	Peaking
Linden	NJ	347	100%	347	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 3	NJ	38	57%	22	Oil	Peaking
New Haven Harbor	CT	129	100%	129	Gas/Oil	Peaking
Bridgeport Harbor	CT	17	100%	17	Oil	Peaking
Total Combustion Turbine		2,760		2,744
Pumped Storage:
Yards Creek (D)	NJ	400	50%	200		Peaking
Total Power Plants		18,320		13,250


(A)	Operated by GenOn Northeast Management Company


(B)	Operated by Exelon Generation. In March 2015, our share of Peach Bottom 2's installed generation capacity is expected to increase by 65 MW as a result of an extended power uprate completed in 2014. A similar increase is expected to occur in the first quarter of 2016 at Peach Bottom 3 after work is completed in late 2015.


(C)	1,545 MW of owned installed combustion turbine capacity will be retired in 2015.


(D)	Operated by JCP&L Company

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As of December 31, 2014, Power also owned and operated 109 MW direct current (dc) of photovoltaic solar generation facilities in various states.

PSE&G

As of December 31, 2014, PSE&G had 99 MWdc of installed solar capacity throughout New Jersey.

Transmission and Distribution Facilities

PSE&G

As of December 31, 2014, PSE&G’s electric transmission and distribution system included 23,872 circuit miles, of which 8,191 circuit miles were underground, and 846,058 poles, of which 548,854 poles were jointly-owned. Approximately 100% of this property is located in New Jersey.

In addition, as of December 31, 2014, PSE&G owned four electric distribution headquarters and five subheadquarters in four operating divisions, all located in New Jersey.

As of December 31, 2014, 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 2,790,420 therms (270,914,563 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	772,500
Camden LPG	Camden, NJ	384,000
Central LPG	Edison, NJ	839,040
Harrison LPG	Harrison, NJ	794,880
Total		2,790,420

As of December 31, 2014, PSE&G owned and operated 17,792 miles of gas mains, owned 12 gas distribution headquarters and two sub-headquarters, 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, 2014, PSE&G owned 43 switching stations in New Jersey with an aggregate installed capacity of 28,777 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 Part II, Item 8. Financial Statements and Supplementary Data—Note 12. Commitments and Contingent Liabilities.

Superstorm Sandy

For a discussion of the lawsuit in New Jersey state court related to recoveries for property damage under PSEG's insurance policies, see Part II, Item 8. Financial Statements and Supplementary Data—Note 12. Commitments and Contingent Liabilities.

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 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.

(2)

The EPA sent PSE&G, Power 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 cost 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 in 2008 to conduct the RI/FS, which is estimated to be completed in 2017/2018.


(3)	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 the NJDEP Solid Waste Regulations. Power has retained an environmental consultant to prepare a closure plan acceptable to the NJDEP.

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, 2014, there were 69,735 registered holders.

The graph below shows a comparison of the five-year cumulative return assuming $100 invested on December 31, 2009 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.




	2009		2010		2011		2012		2013		2014
PSEG	$	100.00	$	99.91	$	108.11	$	104.82	$	114.62	$	153.80
S&P 500	$	100.00	$	115.03	$	117.47	$	136.18	$	180.18	$	204.75
DJ Utilities	$	100.00	$	106.44	$	127.30	$	129.32	$	145.70	$	190.13
S&P Electrics	$	100.00	$	103.42	$	124.99	$	124.24	$	133.97	$	175.52

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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
2014
First Quarter	$	38.44	$	31.25	$	0.37
Second Quarter	$	41.38	$	36.91	$	0.37
Third Quarter	$	40.68	$	34.05	$	0.37
Fourth Quarter	$	43.77	$	36.37	$	0.37
2013
First Quarter	$	34.34	$	29.78	$	0.36
Second Quarter	$	36.61	$	31.21	$	0.36
Third Quarter	$	34.53	$	31.66	$	0.36
Fourth Quarter	$	34.32	$	31.65	$	0.36

On February 17, 2015, our Board of Directors approved a $0.39 per share common stock dividend for the first quarter of 2015. This reflects an indicated annual dividend rate of $1.56 per share.

The following table indicates our common share repurchases in the open market during the fourth quarter of 2014 to satisfy obligations under various equity compensation award grants:




Three Months Ended December 31, 2014	Total Number of Shares Purchased	Average Price Paid per Share
October 1-October 31	—	$	—
November 1-November 30	245,942	$	41.35
December 1-December 31	11,050	$	41.77

The following table indicates the securities authorized for issuance under equity compensation plans as of December 31, 2014:




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
Long-Term Incentive Plan	2,075,850	$	35.35	15,925,279
Employee Stock Purchase Plan	—	$	—	3,589,032
Total	2,075,850	$	35.35	19,514,311

For additional discussion of specific plans concerning equity-based compensation, see Item 8. Financial Statements and Supplementary Data—Note 17. Stock Based Compensation.

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—Executive Overview of 2014 and Future Outlook.

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—Executive Overview of 2014 and Future Outlook.

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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
Years Ended December 31,	2014		2013		2012		2011		2010
	Millions, except Earnings per Share
Operating Revenues (A)	$	10,886	$	9,968	$	9,781	$	11,079	$	11,793
Income from Continuing Operations (B)	$	1,518	$	1,243	$	1,275	$	1,407	$	1,557
Net Income	$	1,518	$	1,243	$	1,275	$	1,503	$	1,564
Earnings per Share:
Income from Continuing Operations
Basic (A)	$	3.00	$	2.46	$	2.52	$	2.78	$	3.08
Diluted (A)	$	2.99	$	2.45	$	2.51	$	2.77	$	3.07
Net Income
Basic	$	3.00	$	2.46	$	2.52	$	2.97	$	3.09
Diluted	$	2.99	$	2.45	$	2.51	$	2.96	$	3.08
Dividends Declared per Share	$	1.48	$	1.44	$	1.42	$	1.37	$	1.37
As of December 31,
Total Assets	$	35,333	$	32,522	$	31,725	$	29,821	$	29,909
Long-Term Obligations (C)	$	8,264	$	7,872	$	6,701	$	7,482	$	7,847


(A)	Operating Revenues for 2014 includes $389 million for Long Island Electric Utility Servco, LLC (Servco), a wholly owned subsidiary of PSEG LI. See Item 8. Financial Statements and Supplementary Data—Note 3. Variable Interest Entities for additional information.


(B)	Income from Continuing Operations for 2011 includes an after-tax charge of $170 million related to certain leveraged leases.


(C)	Includes capital lease obligations.

PSE&G and Power

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

PSEG's business consists of two reportable segments, our principal direct wholly owned subsidiaries, which are:


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


•	Power, our wholesale energy supply company that integrates its nuclear, fossil and renewable 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.

PSEG's other direct wholly owned subsidiaries are: PSEG Energy Holdings L.L.C. (Energy Holdings), which earns its revenues primarily from its portfolio of lease investments; PSEG Long Island LLC (PSEG LI), which effective January 1, 2014, operates the Long Island Power Authority's (LIPA) transmission and distribution (T&D) system under a contractual agreement; and PSEG Services Corporation (Services), which provides us and these operating subsidiaries with certain management, administrative and general services at cost.

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. Risk Factors 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 2014 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.

EXECUTIVE OVERVIEW OF 2014 AND FUTURE OUTLOOK

2014 Overview

Our business plan seeks to achieve growth while managing risks. We continue our focus on operational excellence, financial strength and disciplined investment. These guiding principles have provided the base from which we have been able to execute our strategic initiatives, including:


•	Growing our utility operations through continued investment in T&D infrastructure projects with greater diversity of regulatory oversight, and


•	Maintaining a reliable generation fleet with the flexibility to utilize a diverse mix of fuels to allow us to respond to market volatility and capitalize on opportunities as they arise in the locations in which we operate.

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Financial Results

The results for PSEG, PSE&G and Power for the years ended December 31, 2014 and 2013 are presented below:




	Years Ended December 31,
	2014		2013
Earnings (Losses)	Millions, except per share data
PSE&G	$	725	$	612
Power	760		644
Other	33		(13		)
PSEG Net Income	$	1,518	$	1,243

PSEG Net Income Per Share (Diluted)	$	2.99	$	2.45

Our $275 million 2014 over 2013 increase in Net Income was due primarily to higher transmission revenues at PSE&G and mark-to-market gains in 2014 as compared to losses in 2013 and higher volumes of gas sales under the BGSS contract and to third party customers at Power. In addition, the increase was also due to lower Operations and Maintenance (O&M) costs at PSE&G and Power, principally related to a reduction in pension and other postretirement employee benefit (OPEB) costs. These factors were partially offset by lower volumes of electricity sold under the BGS contract and higher fuel costs incurred to generate electricity at Power. For a more detailed discussion of our financial results, see Results of Operations.

At PSE&G, our regulated utility, we continued to invest capital in T&D infrastructure projects aimed at maintaining the reliability of our service to our customers. PSE&G’s results for 2014 reflect the favorable impacts from these investments as well as a slowly improving economy. Effective January 1, 2014, PSE&G's formula rate increased our annual transmission revenues by approximately $171 million. In October 2014, we filed our 2015 Formula Rate Update with the Federal Energy Regulatory Commission (FERC) for approximately $182 million in increased annual transmission revenues which went into effect on January 1, 2015. Each year, transmission revenues are adjusted to reflect items such as updating estimates used in the filing with actual data. The adjustment for 2015 will include the impact of the extension of bonus depreciation, which was enacted after the filing was made, and is estimated to reduce our 2015 revenue increase as filed by approximately $21 million. Over the past few years, these types of investments have altered the business mix of our overall results of operations to reflect a higher percentage contribution by PSE&G.

Power’s results benefited from access to natural gas supplies through its existing firm pipeline transportation contracts during the cold weather experienced in the first quarter of 2014. Power manages these contracts for the benefit of PSE&G’s customers through the BGSS arrangement. The contracts are sized to ensure delivery of a reliable gas supply to PSE&G customers on peak winter days. When pipeline capacity beyond the customers’ needs is available, Power can use it to make third party sales and supply gas to its generating units in New Jersey.

Power’s 2014 results were unfavorably impacted by an extended refueling outage at Salem Unit 2. A planned refueling outage began on April 12, 2014 but was extended due to repairs to the reactor coolant pump turning vanes. Salem Unit 2 returned to service on July 14, 2014.

Regulatory, Legislative and Other Developments

In our pursuit of operational excellence, financial strength and disciplined investment, we closely monitor significant regulatory and legislative developments. Transmission planning rules and wholesale power market design are of particular importance to our results and we continue to advocate for policies and rules that promote fair and efficient electricity markets.

Transmission Planning

The FERC’s rule under Order 1000 altered the right of first refusal (ROFR) previously held by incumbent utilities to build all transmission within their respective service territories. Our challenge to the rule itself was rejected by the federal court. However, the FERC's action presents opportunities for us to construct transmission outside of our service territory as long as the applicable rules are clear to all participating transmission developers. In April 2013, PJM Interconnection, L.L.C. (PJM) initiated a solicitation process pursuant to Order 1000 to review technical solutions to improve the operational performance in the Artificial Island area, consisting of our Salem and Hope Creek nuclear generation facilities. PJM has not yet made a decision in this process. On January 30, 2015, PSE&G filed a complaint against PJM at the FERC, arguing that PJM had failed to follow its rules during this process and requesting that the FERC order PJM to do so. If the FERC grants this complaint, the FERC could order PJM to re-start the entire process or make changes to the rules governing future competitive solicitations.

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PJM filed with the FERC, and the FERC has recently accepted, a new “multi-driver” category of transmission projects, which projects may include a combination of reliability, economic and public policy elements. Changes to the factors used in making determinations in the PJM project planning and cost-allocation processes could have significant implications for the types of projects selected and the utility customers ultimately charged for the costs of such new transmission facilities. See Part I, Item 1. Business—Federal Regulation—Transmission Regulation—Transmission Policy Developments.

Wholesale Power Market Design

Capacity market design, including the Reliability Pricing Model (RPM), remains an important focus for us. In May 2014, a federal court issued a rule that vacated a FERC Order in which the FERC had determined that demand response (DR) providers should receive full market compensation for power and held that the FERC has no jurisdiction over DR. A subsequent challenge to the participation of DR as a resource in the PJM capacity market is pending at the FERC as is a filing made by PJM at the FERC that would remove DR as a supply resource in upcoming auctions. In addition, PJM has filed at the FERC to reset the demand curve for the RPM, which FERC subsequently accepted. We generally supported PJM’s approach in the filing but sought rehearing on certain issues, including the proper level of labor costs required to build new generation in New Jersey, which is pending. Further, in December 2014, PJM filed at the FERC its proposal for a capacity performance product to include generators, DR and energy efficiency providers who would certify as to availability during emergency conditions, as a supplement to base capacity and with enhanced performance-based incentives and penalties. The implications of these developments could be significant for the capacity market. See Part I, Item 1. Business—Regulatory Issues—Federal Regulation—Capacity Market Issues—PJM for additional information.

Under the PJM capacity auction conducted in May 2014, Power cleared 8,693 MW of its generating capacity at an average price of $164.61 MW-day for the 2017-2018 delivery period, a price consistent with what has been realized in the past three auctions. For a more detailed discussion on the RPM capacity auction, refer to Part I, Item 1. Business—Federal Regulation—Capacity Market Issues—PJM.

In 2014, appeals to challenge the federal court rulings that the New Jersey Long-Term Capacity Agreement Pilot Program Act to subsidize above-market new generation and a similar action taken by Maryland were unconstitutional and null and void were each denied. The appellants subsequently sought review at the U.S. Supreme Court and the U.S. Supreme Court has not yet acted. For additional information, refer to Part I, Item 1. Business—Regulatory Issues—Federal Regulation—Capacity Market Issues—Long-Term Capacity Agreement Pilot Program Act.

A critical aspect of our wholesale energy marketing business is the continued retention of market-based rate (MBR) authority from the FERC for our operating subsidiaries that engage in such activities. On October 14, 2014, the FERC issued an Order that accepted our triennial market power update, concluding that our submission satisfied its requirements for retention of MBR authority.

Environmental Regulation

We also advocate for the development and implementation of fair and reasonable rules by the U.S. Environmental Protection Agency (EPA) and state environmental regulators. On May 19, 2014, the EPA released the final Clean Water Act Section 316(b) rule on cooling water intake that establishes new requirements for the regulation of cooling water intakes at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. Eight of Power’s generating facilities and three of its jointly-owned generating facilities are subject to the rule. As adopted by the EPA, the rule requires that cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts, primarily by reducing the amount of fish and shellfish that are impinged or entrained at a cooling water intake structure. Under this standard, power facilities have the flexibility to select one of several options as their method of compliance. However, the EPA has structured the rule so that each state will continue to consider renewal permits for existing power facilities on a case by case basis, and will require facilities to conduct a wide range of studies related to impingement mortality and entrainment and submit the results with their permit applications. A federal court challenge to the EPA rule is pending. We are unable to predict the outcome that these permitting decisions may take and the effect, if any, that they may have on us although such impacts could be material. See Item 8. Financial Statements and Supplementary Data—Note 12. Commitments and Contingent Liabilities and Part I, Item 1. Business—Environmental Matters—Water Pollution Control for additional information.

In June 2014, the EPA issued a proposed greenhouse gas emissions regulation for existing power plants. The regulation establishes state-specific emission rate targets based on implementation of the best system of emission reduction. States may choose these or other methodologies to achieve the necessary reductions of carbon dioxide emissions. The EPA had requested comment on many aspects of the proposal and therefore, the final rule may look considerably different than the proposal. We continue to work with state and federal regulators, as well as industry partners, to determine the potential impact of the regulation. See Part I, Item 1. Business—Environmental Matters—Climate Change for additional information.

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In addition, Clean Air Act (CAA) regulations governing hazardous air pollutants under the EPA's Maximum Achievable Control Technology rules are also of significance; however, we believe our generation business remains well-positioned for such air pollution control regulations if and when they are implemented.

Other Developments

In recent years we have been impacted by severe weather conditions, including Hurricane Irene in 2011 and Superstorm Sandy in 2012, the latter storm resulting in the highest level of customer outages in our history. For more detailed information, refer to Item 8. Financial Statements and Supplementary Data—Note 12. Commitments and Contingent Liabilities—Superstorm Sandy. We have begun work in our gas and electric distribution systems to improve resiliency. The New Jersey Board of Public Utilities (BPU) approved the settlement of our Energy Strong Proposal in a total amount of $1.22 billion. The settlement provides for cost recovery at a 9.75% rate of return on equity on the first $1.0 billion of the investment, plus associated allowance for funds used during construction, through an accelerated recovery mechanism. We will seek recovery of the remaining $220 million of investment in PSE&G's next base rate case, which is to be filed no later than November 1, 2017. We filed our initial Energy Strong cost recovery petition, seeking BPU approval to recover in base rates an estimated annual revenue increase of $1.1 million effective March 1, 2015. This increase represents capitalized Energy Strong electric investment costs in service through November 30, 2014. For additional information, refer to Part I, Item 1. Business—Regulatory Issues—State Regulation—Energy Strong Program.

In September 2014, the BPU approved substantially our entire request for a determination that our storm related costs, in the total amount of $366 million, were prudently incurred and recoverable in a future base rate proceeding, subject to offset for the amount of insurance proceeds received. For additional information, refer to Item 8. Financial Statements and Supplementary Data—Note 5. Regulatory Assets and Liabilities.

On January 1, 2014, we commenced operation of the LIPA T&D system under a twelve-year contract with opportunity to extend for an additional eight years. In addition, in January 2015, Power assumed responsibility for fuel procurement and power management services to LIPA under separate agreements.

In the first and second quarters of 2014, Power discovered and further investigated (i) incorrect calculations for certain components of its cost-based bids for its New Jersey fossil generating units in the PJM energy market and (ii) differences in the quantity of energy that Power offered into the energy market for its fossil peaking units from the amount for which Power was compensated in the capacity market for those units. We informed the FERC, PJM and the PJM Independent Market Monitor of these issues, and have corrected these errors. Power has an ongoing process of implementing improved procedures to help mitigate the risk of similar issues occurring in the future. In the third quarter of 2014, the FERC Staff initiated a preliminary, non-public staff investigation into the matter. This investigation could result in the FERC seeking disgorgement of any over-collected amounts, civil penalties and non-financial remedies. It is not possible at this time to reasonably estimate the ultimate impact or predict any resulting penalties, other costs associated with this matter, or the applicability of mitigating factors. For more detailed information regarding this matter, refer to Item 8. Financial Statements and Supplementary Data—Note 12. Commitments and Contingent Liabilities—FERC Compliance.

Operational Excellence

We emphasize operational performance while developing opportunities in both our competitive and regulated businesses. Flexibility in our generating fleet has allowed us to take advantage of market opportunities presented during the year as we remain diligent in managing costs. In 2014, our


•	diverse fuel mix and dispatch flexibility allowed us to generate approximately 54,000 GWh, while addressing unit outages and balancing fuel availability and price volatility,


•	Bergen 1 and 2 and Linden 1 Units and our combined cycle gas turbine fleet overall achieved record generation,


•	Hope Creek Unit achieved its second best generation ever,


•	construction of transmission and solar projects proceeded on schedule and within budget, and


•	utility ranked highest in electric and gas service business customer satisfaction among large utilities in the eastern United States.

Financial Strength

Our financial strength is predicated on a solid balance sheet, positive cash flow and reasonable risk-adjusted returns on increased investment. Our financial position remained strong during 2014 as we:


•	had cash on hand of $402 million as of December 31, 2014,

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•	extended the expiration dates of PSEG's $500 million and Power's $1.6 billion five-year credit facilities from 2017 to 2019, and maintained substantial liquidity,


•	maintained solid investment grade credit ratings, and


•	paid an annual dividend of $1.48 and increased our indicated annual dividend for 2015 to $1.56 per share.

We expect to be able to fund our transmission projects required under PJM's reliability program, our Energy Strong program and other projects with internally generated cash and external debt financing.

Disciplined Investment

We utilize rigorous investment criteria when deploying capital and seek to invest in areas that complement our existing business and provide reasonable 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. In 2014 we:


•	placed into service our 230 kV Burlington-Camden and 230 kV North Central Reliability transmission projects,


•	made additional investments in transmission infrastructure projects,


•	continued to execute our existing BPU-approved utility programs,


•	completed installation of equipment to increase output and improve efficiency at our Linden combined cycle gas generating plant and continue to plan for the installation of such equipment at our Bergen 2 and Bethlehem Energy Center (BEC) combined cycle gas units,


•	completed the physical upgrades for the extended power uprate at Peach Bottom Unit 2,


•	acquired an equity interest with an expected investment of $100 million-$120 million in the approximately 110 mile PennEast Pipeline to transport natural gas from eastern Pennsylvania to New Jersey, and


•	acquired rights to solar energy facilities located near El Paso, Texas and Burlington, Vermont, totaling 16.6 MWdc which became operational in late 2014 and a 12.9 MWdc solar energy facility located near Waldorf, Maryland which we expect to be operational before June 2015.

Future Outlook

Our future success will depend on our ability to continue to maintain strong operational and financial performance in a slow-moving economy and a cost-constrained environment, to capitalize on or otherwise address appropriately regulatory and legislative developments that impact our business and to respond to the issues and challenges described below. In order to do this, we must continue to


•	focus on controlling costs while maintaining safety and reliability and complying with applicable standards and requirements,


•	successfully manage our energy obligations and re-contract our open supply positions,


•	execute our capital investment program, including our Energy Strong program and other investments for growth that yield contemporaneous and reasonable risk-adjusted returns, while enhancing the resiliency of our infrastructure and maintaining the reliability of the service we provide to our customers,


•	advocate for measures to ensure the implementation by PJM and the FERC of market design rules that continue to promote fair and efficient electricity markets,


•	engage multiple stakeholders, including regulators, government officials, customers and investors, and


•	successfully operate the LIPA T&D system.

For 2015 and beyond, the key issues and challenges we expect our business to confront include:


•	regulatory and political uncertainty, both with regard to future energy policy, design of energy and capacity markets, transmission policy and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other proceeding, settlement, investigation or claim, applicable to us and/or the energy industry,


•	uncertainty in the slowly improving national and regional economic recovery, continuing customer conservation efforts, changes in energy usage patterns and evolving technologies, which impact customer behaviors and demand,

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


•	delays and other obstacles that might arise in connection with the construction of our T&D projects, including in connection with permitting and regulatory approvals.

RESULTS OF OPERATIONS




	Years Ended December 31,
	2014		2013			2012
Earnings (Losses)	Millions
PSE&G (A)	$	725	$	612		$	528
Power (A)	760		644			666
Other (B)	33		(13		)	81
PSEG Net Income	$	1,518	$	1,243		$	1,275

PSEG Net Income Per Share (Diluted)	$	2.99	$	2.45		$	2.51

(A)

PSE&G's results in 2012 include after-tax expenses of $24 million for O&M costs and Power's results in 2014, 2013 and 2012 include after-tax expenses of $17 million, $32 million and $39 million, respectively, for O&M costs net of insurance recoveries in 2013 and 2012, due to severe damage caused by Superstorm Sandy. See Item 8. Financial Statements and Supplementary Data—Note 12. Commitments and Contingent Liabilities.


(B)	Other includes after-tax activities at the parent company, PSEG LI and Energy Holdings as well as intercompany eliminations.

The 2014 year-over-year increase in our Net Income was driven primarily by:


•	mark-to-market (MTM) gains in 2014 resulting from a decrease in prices on forward positions, as compared to MTM losses in 2013,


•	higher sales volumes under the basic gas supply service (BGSS) contract due to colder average temperatures in the 2014 winter heating season,


•	higher volumes of gas sold to third party customers,


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


•	lower O&M expense at PSE&G and Power, largely due to a reduction in pension and OPEB costs.

These increases were partially offset by


•	lower volumes of electricity sold under Power's basic generation service (BGS) contracts resulting from serving fewer tranches in 2014, and


•	higher generation costs due to higher fuel costs.

The 2013 year-over-year decrease in our Net Income was driven by:


•	lower volumes of electricity sold under Power's BGS contracts at lower average prices,


•	lower volumes of wholesale load contracts in the PJM and New England (NE) regions,


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


•	higher generation costs due to higher fuel costs,


•	higher planned outage and maintenance costs at certain of our fossil and nuclear plants, partially offset by cost control measures,


•	the absence of the gain on the Dynegy leveraged lease settlement in 2012, and

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•	higher Income Tax Expense due to the absence of tax benefits related to the settlement of the 1997-2006 IRS audits in 2012 (see Item 8. Financial Statements and Supplementary Data—Note 19. Income Taxes).

These decreases were largely offset by


•	higher capacity revenues in the PJM region resulting from higher average prices as well as higher generation sold primarily in the PJM region,


•	higher average gas prices on increased sales to third party customers, and


•	higher revenues due to increased investments in transmission projects.

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 and the depreciation related to the ARO asset is recorded in Depreciation and Amortization Expense. In 2014 and 2012, we restructured portions of our NDT Fund and realized gains of $65 million and $59 million, respectively.

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

The combined after-tax impact on Net Income for the years ended December 31, 2014, 2013 and 2012 include the changes related to NDT Fund and MTM activity shown in the chart below:




Years Ended December 31,	2014		2013			2012
	Millions, after tax
NDT Fund and Related Activity	$	68	$	40		$	52
Non-Trading MTM Gains (Losses)	$	66	$	(74	)	$	(10	)

PSEG

Our results of operations are primarily comprised of the results of operations of our principal operating subsidiaries, Power and PSE&G, excluding charges related to intercompany transactions, which are eliminated in consolidation. For additional information on intercompany transactions, see Item 8. Financial Statements and Supplementary Data—Note 23. Related-Party Transactions.




							Increase / (Decrease)					Increase / (Decrease)
	Years Ended December 31,						Increase / (Decrease)					Increase / (Decrease)
	2014		2013		2012		2014 vs. 2013					2013 vs. 2012
	Millions						Millions			%		Millions			%
Operating Revenues	$	10,886	$	9,968	$	9,781	$	918		9		$	187		2
Energy Costs	3,886		3,536		3,719		350			10		(183		)	(5	)
Operation and Maintenance	3,150		2,887		2,632		263			9		255			10
Depreciation and Amortization	1,227		1,178		1,054		49			4		124			12
Income from Equity Method Investments	13		11		12		2			18		(1		)	(8	)
Other Income and (Deductions)	229		159		162		70			44		(3		)	(2	)
Other-Than-Temporary Impairments	20		12		18		8			67		(6		)	(33	)
Interest Expense	389		402		423		(13		)	(3	)	(21		)	(5	)
Income Tax Expense	938		812		736		126			16		76			10

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The 2014 amounts in the preceding table for Operating Revenues and O&M Costs each include $389 million for Servco. These amounts represent the O&M pass-through costs for the Long Island operations, the full reimbursement of which is reflected in Operating Revenues. See Item 8. Financial Statements and Supplementary Data—Note 3. Variable Interest Entities for further explanation. The following discussions for Power and PSE&G provide a detailed explanation of their respective variances.

PSE&G




	Years Ended December 31,						Increase / (Decrease)					Increase / (Decrease)
PSE&G	2014		2013		2012		2014 vs. 2013					2013 vs. 2012
	Millions						Millions			%		Millions			%
Operating Revenues	$	6,766	$	6,655	$	6,626	$	111		2		$	29		—
Energy Costs	2,909		2,841		3,159		68			2		(318		)	(10	)
Operation and Maintenance	1,558		1,639		1,508		(81		)	(5	)	131			9
Depreciation and Amortization	906		872		778		34			4		94			12
Taxes Other Than Income Taxes	—		68		98		(68		)	(100	)	(30		)	(31	)
Other Income (Deductions)	58		51		47		7			14		4			9
Interest Expense	277		293		295		(16		)	(5	)	(2		)	(1	)
Income Tax Expense	449		381		307		68			18		74			24

Year Ended December 31, 2014 as compared to 2013

Operating Revenues increased $111 million due primarily to changes in delivery, clause, commodity and other operating revenues.

Delivery Revenues increased $88 million due primarily to an increase in transmission revenues.


•	Transmission revenues were $138 million higher due to increased investments in transmission projects.

•

Gas distribution revenues decreased $5 million due primarily to lower Weather Normalization Clause (WNC) revenue of $32 million due to more normal weather compared to the prior year, lower Transitional Energy Facilities Assessment (TEFA) revenue of $22 million due to elimination of the TEFA tax effective January 1, 2014, lower Capital Infrastructure Program (CIP) related revenue of $11 million, partially offset by higher sales volumes of $54 million, and higher revenue from Solar and Energy Efficiency Recovery Charges (formerly RRC and currently Green Program Recovery Charges (GPRC)) of $6 million.


•	Electric distribution revenues decreased $45 million due primarily to a $45 million decrease due to elimination of the TEFA tax in 2014, lower sales volumes of $17 million and lower CIP related revenue of $5 million, partially offset by higher GPRC of $22 million.

Clause Revenues decreased $51 million due primarily to lower Societal Benefit Charges (SBC) of $32 million, lower Securitization Transition Charge (STC) revenues of $18 million, and lower Margin Adjustment Clause (MAC) of $7 million, partially offset by higher Solar Pilot Recovery Charge (SPRC) of $6 million. The changes in SBC, STC, MAC and SPRC 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, STC, MAC or SPRC collections.

Commodity Revenue increased $68 million due to higher Electric and Gas revenues. This is entirely offset with increased Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.


•	Electric revenues increased $22 million due primarily to $64 million in higher BGS revenues, partially offset by $42 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 increased 2% due primarily to weather.


•	Gas revenues increased $46 million due to higher BGSS volumes of $93 million, partially offset by lower BGSS prices of $47 million. The average price of natural gas was 5% lower in 2014 than in 2013.

Other Operating Revenues increased $6 million due primarily to increased revenues from our appliance repair business and miscellaneous electric operating revenues.

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Operating Expenses

Energy Costs increased $68 million. This is entirely offset by Commodity Revenue.


•	Electric costs increased $22 million or 1% due to $75 million of increased deferred cost recovery, $30 million in higher BGS volumes and a $2 million increase in NUG prices, partially offset by $78 million in lower NUG volumes and $7 million from lower BGS prices. BGS volume increased 2% due to customer migration from third party suppliers (TPS).


•	Gas costs increased $46 million or 5% due to $93 million or 10% in higher sales volumes due primarily to weather, partially offset by $47 million or 5% in lower prices.

Operation and Maintenance decreased $81 million, of which the most significant components were decreases of


•	$73 million in pension and other postretirement benefits (OPEB) expenses, and


•	$21 million in costs related to SBC, GPRC and CIP,


•	partially offset by a $12 million net increase in operational expenses due primarily to increases in storm related costs of $8 million, wages of $6 million and transmission related costs of $2 million, partially offset by a $4 million decrease in general operating expenses, and


•	a $1 million increase in gas bad debt expense.

Depreciation and Amortization increased $34 million due primarily to increases of


•	$47 million in additional plant in service, and


•	$2 million in software amortization,


•	partially offset by a $15 million decrease in amortization of Regulatory Assets.

Taxes Other Than Income Taxes decreased $68 million due to the elimination of the TEFA tax in 2014.

Other Income and (Deductions) net increase of $7 million was due primarily to increases of


•	$7 million in Allowance for Funds Used During Construction, and


•	$1 million in solar loan interest income,


•	partially offset by a $1 million decrease in Rabbi Trust interest and gains.

Interest Expense decreased $16 million primarily due to decreases of


•	$16 million due to partial redemption of securitization debt in 2014,


•	$25 million due to maturities of $725 million in 2013, and


•	$5 million due to maturities of $500 million in 2014,


•	partially offset by an increase of $14 million due to the issuance of $1,250 million of debt in 2014, and


•	an increase of $17 million due to the issuance of $1,500 million of debt in 2013.

Income Tax Expense increased $68 million due primarily to higher pre-tax income.

Year ended December 31, 2013 as compared to 2012

Operating Revenues increased $29 million due primarily to changes in delivery, clause, commodity and other operating revenues.

Delivery Revenues increased $223 million due primarily to an increase in transmission revenues.


•	Transmission revenues were $184 million higher due to increased investments in transmission projects.


•	Gas distribution revenues increased $24 million due primarily to higher sales volumes of $70 million, higher CIP related revenue of $23 million and higher revenue from Solar and Energy Efficiency Recovery Charges of $5 million, partially offset by lower WNC revenue of $67 million due to more normal weather compared to the prior year and lower TEFA revenue of $7 million due to a lower TEFA rate.

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•	Electric distribution revenues increased $15 million due primarily to higher GPRC of $37 million and higher CIP related revenue of $11 million, partially offset by lower TEFA revenue of $23 million due to a lower TEFA rate and lower sales volumes of $10 million.

Clause Revenues increased $110 million due primarily to STC revenues of $51 million, higher SBC of $47 million and a higher SPRC of $11 million. The changes in STC, SBC and SPRC 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 STC, SBC or SPRC collections.

Commodity Revenue decreased $318 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 $308 million due primarily to $169 million in lower BGS revenues and $139 million in lower revenues from the sale of NUG energy and collections of NGC due primarily to lower prices. BGS sales decreased 4% due primarily to customer migration to TPS and weather.


•	Gas revenues decreased $10 million due to lower BGSS prices of $121 million, partially offset by higher BGSS volumes of $111 million. The average price of natural gas was 12% lower in 2013 than in 2012.

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

Operating Expenses

Energy Costs decreased $318 million. This is entirely offset by Commodity Revenue.


•	Electric costs decreased $308 million or 14% due to $214 million in lower BGS and NUG volumes, $35 million of lower BGS prices, and $59 million for decreased deferred cost recovery. BGS and NUG volumes decreased 10% due primarily to customer migration to TPS.


•	Gas costs decreased $10 million or 1% due to $121 million or 12% in lower prices, partially offset by $111 million or 11% in higher sales volumes due primarily to weather.

Operation and Maintenance increased $131 million, of which the most significant components were increases of


•	$131 million in costs related to SBC, GPRC and CIP,


•	$24 million in transmission related costs, and


•	$10 million in appliance service costs,


•	partially offset by the absence of $40 million in transmission and distribution storm damages in 2012,


•	a $10 million decrease in pension and OPEB expenses, and


•	an $11 million decrease in gas bad debt expense.

Depreciation and Amortization increased $94 million due primarily to increases of


•	$59 million in amortization of Regulatory Assets, and


•	$33 million in additional plant in service.

Taxes Other Than Income Taxes decreased $30 million due to a lower TEFA rate, partially offset by higher sales volumes for gas.

Other Income and (Deductions) net increase of $4 million was due primarily to


•	a $5 million increase in solar loan interest income,


•	partially offset by a $1 million decrease in Rabbi Trust interest and gains.

Interest Expense experienced no material change.

Income Tax Expense increased $74 million due primarily to higher pre-tax income and the absence of tax benefits related to the settlement of the 1997-2006 IRS audits in 2012.

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Power




	Years Ended December 31,						Increase / (Decrease)					Increase / (Decrease)
Power	2014		2013		2012		2014 vs. 2013					2013 vs. 2012
	Millions						Millions			%		Millions			%
Operating Revenues	$	5,434	$	5,063	$	4,873	$	371		7		$	190		4
Energy Costs	2,747		2,496		2,381		251			10		115			5
Operation and Maintenance	1,186		1,224		1,127		(38		)	(3	)	97			9
Depreciation and Amortization	292		273		242		19			7		31			13
Income from Equity Method Investments	14		16		15		(2		)	(13	)	1			7
Other Income (Deductions)	170		105		111		65			62		(6		)	(5	)
Other-Than-Temporary Impairments	20		12		18		8			67		(6		)	(33	)
Interest Expense	122		116		132		6			5		(16		)	(12	)
Income Tax Expense	491		419		433		72			17		(14		)	(3	)

Year Ended December 31, 2014 as compared to 2013

Operating Revenues increased $371 million due to changes in generation, gas supply and other operating revenues.

Generation Revenues increased $263 million due primarily to


•	higher revenues of $366 million due primarily to MTM gains in 2014 resulting from a decrease in prices on forward positions and higher energy volumes sold in the New York and New England (NE) regions, and


•	a net increase of $27 million due primarily to higher volumes on wholesale load contracts in the PJM region, offset in part by lower wholesale load volumes in the NE region,


•	partially offset by a decrease of $89 million due to lower volumes of electricity sold as a result of serving fewer tranches in 2014 under our BGS contracts and lower average pricing, and


•	a net decrease of $41 million due primarily to a decrease in operating reserve revenue, partially offset by higher ancillary revenue in the PJM region.

Gas Supply Revenues increased $93 million due primarily to


•	a net increase of $44 million in sales under the BGSS contract, substantially comprised of higher sales volumes due to colder average temperatures during the 2014 winter heating season, partially offset by lower average gas prices, and


•	a net increase of $49 million due to higher sales volumes to third party customers.

Other Operating Revenues increased $15 million due to transition fees related to fuel management and power supply management contracts with LIPA.

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 increased $251 million due to


•	Generation costs increased $252 million due primarily to higher fuel costs, reflecting higher average realized natural gas prices, the unfavorable MTM impact from lower average natural gas prices on forward positions and the utilization of higher volumes of gas and oil. These increased costs were partially offset by lower congestion costs in the PJM region.


•	Gas costs decreased $1 million related to a decrease of $137 million in average gas inventory costs, substantially offset by $136 million of higher volumes sold under the BGSS contract and to third party customers due to colder average temperatures during the 2014 winter heating season.

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Operation and Maintenance decreased $38 million due primarily to


•	lower pension and OPEB costs of $42 million,


•	a decrease of $15 million due primarily to the outage of our 100%-owned Hope Creek nuclear facility in the fall of 2013, which was partially offset by the extension of our 57%-owned nuclear Salem Unit 2 refueling outage in 2014, and


•	a decrease of $27 million due to lower storm costs related to Superstorm Sandy,


•	partially offset by an increase of $40 million related primarily to higher planned outage and maintenance costs at our fossil plants, including maintenance and installation of upgraded technology at our Linden combined cycle gas generating plant and outages at our Keystone and Hudson facilities.

Depreciation and Amortization increased $19 million due primarily to a higher depreciable fossil and nuclear asset base.

Income from Equity Method Investments experienced no material change.

Other Income (Deductions) increased $65 million due primarily to higher realized gains from the NDT Fund due to the restructuring of the portfolio in 2014.

Other-Than-Temporary Impairments increased $8 million due to an increase in impairments of the NDT Fund.

Interest Expense increased $6 million due primarily to the issuance of a $250 million 2.45% Senior Note and a $250 million 4.30% Senior Note in November 2013, partially offset by the maturity of $300 million of 2.50% Senior Notes in April 2013.

Income Tax Expense increased $72 million in 2014 due primarily to higher pre-tax income.

Year ended December 31, 2013 as compared to 2012

Operating Revenues increased $190 million due to changes in generation and supply revenues.

Generation Revenues increased $102 million due primarily to


•	an increase of $341 million due to higher capacity revenues resulting from higher average auction prices and an increase in operating reserve revenues in PJM, and


•	higher net revenues of $36 million due primarily to higher generation sold in the PJM and NE regions partly offset by higher MTM losses in 2013 resulting from an increase in prices on forward positions in the PJM and NE regions,


•	partially offset by a decrease of $155 million due primarily to lower volumes of electricity sold under our BGS contracts and lower average pricing, and


•	a net decrease of $120 million due to lower volumes on wholesale load contracts in the PJM and NE regions.

Gas Supply Revenues increased $88 million due primarily to


•	a net increase of $40 million in sales under the BGSS contract, substantially comprised of higher sales volumes due to colder average temperatures during the 2013 winter heating season, partially offset by lower average gas prices, and


•	a net increase of $48 million due primarily to higher average gas prices and higher sales volumes to third party customers.

Operating Expenses


•	Generation costs increased $75 million due primarily to $84 million of higher fuel costs, reflecting higher average realized natural gas prices, higher nuclear fuel costs and the utilization of higher volumes of coal and oil, partially offset by lower average coal prices and lower average unrealized natural gas prices on forward positions.


•	Gas costs increased $40 million, principally related to obligations under the BGSS contract, reflecting higher sales volumes in 2013 due to colder average temperatures during the 2013 winter heating season and higher volumes on third party sales, partially offset by lower average gas inventory costs.

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Operation and Maintenance increased $97 million due primarily to


•	higher planned outage and maintenance costs in 2013, mainly at our gas-fired BEC plant in New York, Bergen gas-fired plant in New Jersey, Linden gas-fired plant in New Jersey and 23%-owned Conemaugh coal-fired plant in Pennsylvania, partially offset by lower storm costs in 2013, and


•	higher outage costs at our nuclear generating facilities, primarily at our 100%-owned Hope Creek station.

Depreciation and Amortization increased $31 million due primarily to a higher depreciable asset base at Fossil and Nuclear, including placing into service the new gas-fired peaking units at Kearny, New Jersey and New Haven, Connecticut in June 2012, completion of the steam path retrofit upgrade at our co-owned Peach Bottom Unit 2 in October 2012, and placing two solar facilities into service in the fourth quarter of 2012. In addition, an update to the nuclear asset retirement obligation became effective in November 2012, causing higher depreciation in 2013.

Income from Equity Method Investments experienced no material change.

Other Income (Deductions) decreased $6 million due primarily to lower NDT Fund realized gains in 2013, partially offset by lower NDT Fund realized losses in 2013. In addition, we recognized a loss on the extinguishment of debt in 2012.

Other-Than-Temporary Impairments decreased $6 million due to lower impairments on the NDT Fund in 2013.

Interest Expense decreased $16 million due primarily to a decrease of $23 million resulting from the maturity of $300 million of 2.50% of Senior Notes in April 2013, and the early redemptions of $250 million of 5.00% medium term notes and various tax-exempt bonds in December 2012, partially offset by higher interest costs of $6 million in 2013 since interest capitalization ceased for our Kearny and New Haven gas-fired peaking projects on their June 2012 in-service date.

Income Tax Expense decreased $14 million in 2013 due primarily to lower pre-tax income.

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 two direct major 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 the commercial paper and letters of credit 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, PSEG LI and Services participate in a corporate money pool, an aggregation of daily cash balances designed to efficiently manage their respective short-term liquidity needs. Servco does not participate in the corporate money pool. Servco's short-term liquidity needs are met through an account funded and owned by LIPA.

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 $2.6 billion of syndicated multi-year credit facilities. Additionally, from time to time, Power maintains bilateral credit agreements designed to enhance its liquidity position. Power has $100 million of bilateral credit agreements that are scheduled to expire in September 2015. Credit capacity is primarily used to provide collateral in support of Power's forward energy sale and forward fuel purchase contracts as the market prices for energy and fuel fluctuate, 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.

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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, 2014, our operating cash flow increased by $2 million. For the year ended December 31, 2013, our operating cash flow increased by $371 million. The net changes were primarily due to net changes from our subsidiaries as discussed below and tax payments at the parent company and Energy Holdings.

PSE&G

PSE&G’s operating cash flow increased $188 million from $1,645 million to $1,833 million for the year ended December 31, 2014, as compared to 2013, due primarily to


•	higher earnings,


•	an increase of $188 million due to an increase from a net change in regulatory deferrals, primarily related to over collections of BGSS gas costs, the over collection of gas revenues due to the Gas Weather Normalization clause and GPRC rate recoveries,


•	an increase of $83 million due to decrease in employee benefit plan funding,


•	partially offset by $199 million related to higher tax payments.

PSE&G’s operating cash flow increased $389 million from $1,256 million to $1,645 million for the year ended December 31, 2013, as compared to 2012, due primarily to


•	higher earnings,


•	an increase of $134 million due to an increase from a net change in regulatory deferrals, primarily related to over collections of BGSS gas costs and the collection of prior year deficiency revenues under the Gas Weather Normalization clause mechanism, and


•	a decrease of $47 million in benefit plan funding,


•	partially offset by $114 million related to higher tax payments.

Power

Power’s operating cash flow increased $78 million from $1,347 million to $1,425 million for the year ended December 31, 2014, as compared to 2013, primarily resulting from


•	lower tax payments,


•	partially offset by increase of $87 million in payments to counterparties, and


•	a decrease of $11 million due to collection of counterparty receivables.

Power’s operating cash flow decreased $106 million from $1,453 million to $1,347 million for the year ended December 31, 2013, as compared to 2012, primarily resulting from


•	lower earnings, and


•	higher tax payments,


•	partially offset by a decrease of $73 million related to margin deposits, and


•	a decrease of $26 million in employee benefit plan funding.

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, 2014 were as follows:

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Company/Facility	As of December 31, 2014
Company/Facility	Total Facility		Usage		Available Liquidity
	Millions
PSEG	$	1,000	$	8	$	992
PSE&G	600		14		586
Power	2,700		197		2,503
Total	$	4,300	$	219	$	4,081

As of December 31, 2014, our credit facility capacity was 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, 2014, no amounts were outstanding. Most of our credit facilities expire in 2018 and 2019. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 12. Commitments and Contingent Liabilities and Note 13. Schedule of Consolidated Debt.

Long-Term Debt Financing

PSE&G has $300 million of 2.70%, Series G Medium Term Notes maturing in May 2015.

Power has a $300 million of 5.50% Senior Notes maturing in December 2015.

For a discussion of our long-term debt transactions during 2014 and into 2015, see Item 8. Financial Statements and Supplementary Data—Note 13. 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, 2014, PSE&G’s Mortgage coverage ratio was 5.6 to 1 and the Mortgage would permit up to approximately $3.8 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 PSE&G and Power cease to be wholly owned by PSEG.

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

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.

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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.

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.

Common Stock Dividends




	Years Ended December 31,
Dividend Payments on Common Stock	2014		2013		2012
Per Share	$	1.48	$	1.44	$	1.42
in Millions	$	748	$	728	$	718

On February 17, 2015, our Board of Directors approved a $0.39 per share common stock dividend for the first quarter of 2015. This reflects an indicated annual dividend rate of $1.56 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. Credit Ratings shown are for securities that we typically issue. Outlooks are shown for Corporate Credit Ratings (S&P) and Issuer Credit Ratings (Moody’s and Fitch) and can be Stable, Negative, or Positive. 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 2014, Moody’s published updated research reports on PSEG, PSE&G and Power and the existing ratings and outlooks were unchanged. In May 2014, S&P published updated research reports and revised the outlook to positive from stable for PSEG’s Corporate Credit Rating. S&P also affirmed the senior unsecured rating of BBB+ at Power and mortgage bond rating of A at PSE&G. In October 2014, Fitch affirmed the ratings and outlooks for PSEG, PSE&G and Power.




	Moody’s (A)	S&P (B)	Fitch (C)
PSEG
Outlook	Stable	Positive	Stable
Commercial Paper	P2	A2	F2
PSE&G
Outlook	Stable	Positive	Stable
Mortgage Bonds	Aa3	A	A+
Commercial Paper	P1	A2	F2
Power
Outlook	Stable	Positive	Stable
Senior Notes	Baa1	BBB+	BBB+


(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.

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(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. The Corporate Credit Rating outlook does not apply to PSEG’s or PSE&G’s Commercial Paper Rating or PSE&G’s Mortgage Bond rating.


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

Other Comprehensive Income

For the year ended December 31, 2014, we had Other Comprehensive Loss of $188 million on a consolidated basis. Other Comprehensive Loss was due primarily to a $173 million increase in our consolidated liability for pension and postretirement benefits and a $27 million decrease in net unrealized gains related to Available-for-Sale Securities, and was partially offset by $12 million of unrealized gains on derivative contracts accounted for as hedges. See Item 8. Financial Statements and Supplementary Data—Note 20. Accumulated Other Comprehensive Income (Loss), Net of Tax for additional information.

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.




	2015		2016		2017
			Millions
PSE&G:
Transmission
Reliability Enhancements	$	1,420	$	1,230	$	1,185
Facility Replacement	165		185		200
Support Facilities	5		35		15
Environmental/Regulatory	5		5		5
Distribution
Reliability Enhancements	285		435		295
Facility Replacement	385		235		225
Support Facilities	55		50		55
New Business	155		160		160
Environmental/Regulatory	40		50		55
Renewables	100		80		80
Total PSE&G	$	2,615	$	2,465	$	2,275
Power:
Baseline	$	225	$	220	$	190
Environmental/Regulatory	60		50		45
Fossil Growth Opportunities	20		—		20
Nuclear Expansion	95		20		10
Solar Expansion	155		105		—
Total Power	$	555	$	395	$	265
Services	$	50	$	35	$	35
Total PSEG	$	3,220	$	2,895	$	2,575

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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 maintain 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 2014, PSE&G made $2,170 million of capital expenditures, including $2,164 million of investment in plant, primarily for transmission and distribution system reliability and $6 million in solar loan investments. This does not include expenditures for cost of removal, net of salvage, of $98 million, which are included in operating cash flows.

Power

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


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


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


•	Fossil Growth Opportunities—investments associated with upgrades to increase efficiency and output at combined cycle plants.


•	Nuclear Expansion—investments associated with certain Nuclear capital projects, primarily at existing facilities designed to increase operating output.


•	Solar Expansion—investments associated with the construction of utility-scale photovoltaic facilities.

In 2014, Power made $460 million of capital expenditures, excluding $166 million for nuclear fuel, primarily related to various projects at Fossil and Nuclear.

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. 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 13. 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 19. 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
PSE&G	$	6,329	$	300	$	171	$	1,250	$	4,608
Transition Funding (PSE&G)	251		251		—		—		—
Transition Funding II (PSE&G)	8		8		—		—		—
Power	2,553		300		553		294		1,406
Long-Term Non-Recourse Project Financing
Other	16		16		—		—		—
Interest on Recourse Debt
PSE&G	4,113		248		473		427		2,965
Transition Funding (PSE&G)	11		11		—		—		—
Transition Funding II (PSE&G)	—		—		—		—		—
Power	1,142		131		207		179		625
Interest on Non-Recourse Project Financing
Other	1		1		—		—		—
Capital Lease Obligations
Power	5		2		1		1		1
Services	5		5		—		—		—
Operating Leases
PSE&G	95		12		16		12		55
Power	32		2		3		4		23
Services	215		5		25		26		159
Other	4		2		2		—		—
Energy-Related Purchase Commitments
Power	3,222		892		1,119		559		652
Total Contractual Cash Obligations	$	18,002	$	2,186	$	2,570	$	2,752	$	10,494
Commercial Commitments
Standby Letters of Credit
PSEG	$	8	$	8	$	—	$	—	$	—
PSE&G	14		14		—		—		—
Power	242		242		—		—		—
Guarantees and Equity Commitments
Power	80		79		—		—		1
Total Commercial Commitments	$	344	$	343	$	—	$	—	$	1
Liability Payments for Uncertain Tax Positions
PSEG	$	59	$	59	$	—	$	—	$	—
PSE&G	2		2		—		—		—
Power	23		23		—		—		—

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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 12. Commitments and Contingent Liabilities for further discussion.

Other

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 6. Long-Term Investments.

In the event that collection 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

PSEG sponsors several qualified and nonqualified pension plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. The market-related value of plan assets held for the qualified pension plan is equal to the fair value of these assets as of year-end. The plan assets are comprised of investments in both debt and equity securities which are valued using quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. 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	2014		2013		2012
Discount Rate	4.20	%	5.00	%	4.20	%
Rate of Return on Plan Assets	8.00	%	8.00	%	8.00	%

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.

In selecting the annual discount rate to calculate benefit obligations, we utilize a hypothetical portfolio of high quality corporate bonds with cash flows that match the benefit plan liability. The composite yield on the hypothetical bond portfolio reflects the rate at which the obligations could effectively be settled.

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

Based on the above assumptions, we have estimated net periodic pension expense of approximately $55 million, net of amounts capitalized.

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We utilize a corridor approach that reduces the volatility of reported pension expense /income. The corridor requires differences between actuarial assumptions and plan results be deferred and amortized as part of expense/income. This occurs only when the accumulated differences exceed 10% of the greater of the pension benefit obligation or the fair value of plan assets as of each year-end. The excess would be amortized over the average remaining service period of the active employees, which is approximately eight years.

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 2015. Actual future pension expense/income 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, 2014		Increase to Pension Expense in 2015
Assumption		Millions
Discount Rate	(1)%	$	888	$	100
Rate of Return on Plan Assets	(1)%	$	—	$	52

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.

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 15. 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 6. Long-Term Investments and Note 7. 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 comprises 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. 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. Realized gains, losses and dividend and interest income are recorded in our Consolidated Statements of Operations as Other Income and Other Deductions.

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 16. 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)

PSE&G, Power 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 rate-making 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 triennially 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 93% of Power’s total AROs as of December 31, 2014. 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 decrease of 1% in the discount rate would result in a $141 million increase in the Nuclear ARO as of December 31, 2014. An increase of 1% in the inflation rate would result in a $372 million increase in the Nuclear ARO as of December 31, 2014. 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 $302 million at December 31, 2014.

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 5. Regulatory Assets and Liabilities for a description of the amounts and nature of regulatory balance sheet amounts.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT

MARKET RISK

The 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.




	MTM VaR
	Millions
Years Ended December 31,	2014		2013

95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	36	$	12
Average for the Period	$	30	$	15
High	$	195	$	29
Low	$	14	$	8

99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	56	$	18
Average for the Period	$	46	$	23
High	$	306	$	46
Low	$	22	$	13

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See Item 8. Financial Statements and Supplementary Data—Note 15. 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, 2014, 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 $288 million decrease in the fair value of debt, including a $233 million decrease at PSE&G and a $55 million decrease at Power.

Debt and Equity Securities

We have $5.7 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 $1,780 million as of December 31, 2014. As of December 31, 2014, the portfolio includes $897 million of equity securities and $777 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, 2014, a hypothetical 10% change in the equity market would impact the value of the equity securities in the NDT Fund by approximately $90 million.

We use duration to measure the interest rate sensitivity of the fixed income portfolio. Duration is a summary statistic of the effective average maturity of the fixed income portfolio. The benchmark for the fixed income component of the NDT Fund currently has a duration of 5.56 years and a yield of 2.25%. The portfolio’s value will appreciate or depreciate by the duration with a 1% change in interest rates. As of December 31, 2014, a hypothetical 1% increase in interest rates would result in a decline in the market value for the fixed income portfolio of approximately $43 million.

Credit Risk

See Item 8. Financial Statements and Supplementary Data—Note 15. Financial Risk Management Activities for a discussion of credit risk and a discussion about Power’s and PSE&G's credit risk.

Energy Holdings has credit risk related to its investments in leases, which totaled $98 million, net of deferred taxes of $738 million, as of December 31, 2014. These leveraged leases are concentrated in the United States energy industry. See Item 8. Financial Statements and Supplementary Data—Note 7. 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

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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, PSE&G and Power. Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G and Power 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, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, common stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2014. 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, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, 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, 2014, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2015 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey

February 25, 2015

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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, 2014 and 2013, 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, 2014. 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 financial statements and financial statement schedules based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, 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, present fairly in all material respects the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey

February 25, 2015

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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, 2014 and 2013, 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, 2014. 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.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, 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, 2015

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF OPERATIONS

Millions, except per share data




	Years Ended December 31,
	2014			2013			2012
OPERATING REVENUES	$	10,886		$	9,968		$	9,781
OPERATING EXPENSES
Energy Costs	3,886			3,536			3,719
Operation and Maintenance	3,150			2,887			2,632
Depreciation and Amortization	1,227			1,178			1,054
Taxes Other Than Income Taxes	—			68			98
Total Operating Expenses	8,263			7,669			7,503
OPERATING INCOME	2,623			2,299			2,278
Income from Equity Method Investments	13			11			12
Other Income	290			213			260
Other Deductions	(61		)	(54		)	(98		)
Other-Than-Temporary Impairments	(20		)	(12		)	(18		)
Interest Expense	(389		)	(402		)	(423		)
INCOME BEFORE INCOME TAXES	2,456			2,055			2,011
Income Tax (Expense) Benefit	(938		)	(812		)	(736		)
NET INCOME	$	1,518		$	1,243		$	1,275
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC	506			506			506
DILUTED	508			508			507
NET INCOME PER SHARE:
BASIC	$	3.00		$	2.46		$	2.52
DILUTED	$	2.99		$	2.45		$	2.51

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,
		2014			2013			2012
NET INCOME		$	1,518		$	1,243		$	1,275
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $26, $(54) and $(24) for the years ended 2014, 2013 and 2012, respectively		(27		)	55			19
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $(8), $7 and $18 for the years ended 2014, 2013 and 2012, respectively		12			(9		)	(24		)
Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $120, $(172) and $32 for years ended 2014, 2013 and 2012, respectively		(173		)	247			(46		)
Other Comprehensive Income (Loss), net of tax		(188		)	293			(51		)
COMPREHENSIVE INCOME		$	1,330		$	1,536		$	1,224

See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2014			2013
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	402		$	493
Accounts Receivable, net of allowances of $52 and $56 in 2014 and 2013, respectively	1,254			1,203
Tax Receivable	211			109
Unbilled Revenues	284			300
Fuel	538			545
Materials and Supplies, net	484			479
Prepayments	108			89
Derivative Contracts	240			98
Deferred Income Taxes	11			24
Regulatory Assets	323			243
Regulatory Assets of Variable Interest Entities (VIEs)	249			—
Other	15			31
Total Current Assets	4,119			3,614
PROPERTY, PLANT AND EQUIPMENT	32,196			29,713
Less: Accumulated Depreciation and Amortization	(8,607		)	(8,068		)
Net Property, Plant and Equipment	23,589			21,645
NONCURRENT ASSETS
Regulatory Assets	3,192			2,612
Regulatory Assets of VIEs	—			476
Long-Term Investments	1,307			1,313
Nuclear Decommissioning Trust (NDT) Fund	1,780			1,701
Long-Term Receivable of VIEs	580			—
Other Special Funds	212			613
Goodwill	16			16
Other Intangibles	84			33
Derivative Contracts	77			163
Restricted Cash of VIEs	24			24
Other	353			312
Total Noncurrent Assets	7,625			7,263
TOTAL ASSETS	$	35,333		$	32,522

See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2014			2013
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	624		$	544
Securitization Debt of VIEs Due Within One Year	259			237
Commercial Paper and Loans	—			60
Accounts Payable	1,178			1,222
Derivative Contracts	132			76
Accrued Interest	95			95
Accrued Taxes	21			37
Deferred Income Taxes	173			—
Clean Energy Program	142			142
Obligation to Return Cash Collateral	121			119
Regulatory Liabilities	186			43
Other	547			488
Total Current Liabilities	3,478			3,063
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	7,303			7,107
Regulatory Liabilities	258			233
Regulatory Liabilities of VIEs	39			11
Asset Retirement Obligations	743			677
Other Postretirement Benefit (OPEB) Costs	1,277			1,095
OPEB Costs of Servco	452			—
Accrued Pension Costs	440			121
Accrued Pension Costs of Servco	126			—
Environmental Costs	417			414
Derivative Contracts	33			31
Long-Term Accrued Taxes	208			180
Other	112			119
Total Noncurrent Liabilities	11,408			9,988
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 12)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt	8,261			7,587
Securitization Debt of VIEs	—			259
Project Level, Non-Recourse Debt	—			16
Total Long-Term Debt	8,261			7,862
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000,000,000 shares; issued, 2014 and 2013— 533,556,660 shares	4,876			4,861
Treasury Stock, at cost, 2014— 27,720,068 shares; 2013— 27,699,398 shares	(635		)	(615		)
Retained Earnings	8,227			7,457
Accumulated Other Comprehensive Loss	(283		)	(95		)
Total Common Stockholders’ Equity	12,185			11,608
Noncontrolling Interest	1			1
Total Stockholders’ Equity	12,186			11,609
Total Capitalization	20,447			19,471
TOTAL LIABILITIES AND CAPITALIZATION	$	35,333		$	32,522

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,
	2014			2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	1,518		$	1,243		$	1,275
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	1,227			1,178			1,054
Amortization of Nuclear Fuel	200			192			173
Provision for Deferred Income Taxes (Other than Leases) and ITC	515			270			721
Non-Cash Employee Benefit Plan Costs	47			243			271
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes	(4		)	31			93
Net (Gain) Loss on Lease Investments	(3		)	2			(49		)
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	(93		)	79			63
Change in Accrued Storm Costs	(3		)	(90		)	(90		)
Net Change in Regulatory Assets and Liabilities	190			2			(132		)
Cost of Removal	(98		)	(93		)	(116		)
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(166		)	(104		)	(118		)
Net Change in Tax Receivable	30			19			(211		)
Net Change in Certain Current Assets and Liabilities	(209		)	299			97
Employee Benefit Plan Funding and Related Payments	(95		)	(231		)	(314		)
Other	104			118			70
Net Cash Provided By (Used In) Operating Activities	3,160			3,158			2,787
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(2,820		)	(2,811		)	(2,574		)
Proceeds from Sale of Capital Leases and Investments	25			50			58
Proceeds from Sales of Available-for-Sale Securities	1,915			1,159			1,666
Investments in Available-for-Sale Securities	(1,934		)	(1,170		)	(1,700		)
Other	(78		)	(29		)	(75		)
Net Cash Provided By (Used In) Investing Activities	(2,892		)	(2,801		)	(2,625		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	(60		)	(203		)	263
Issuance of Long-Term Debt	1,250			2,000			900
Redemption of Long-Term Debt	(500		)	(1,025		)	(787		)
Redemption of Securitization Debt	(237		)	(226		)	(216		)
Repayment of Non-Recourse Debt	—			—			(1		)
Cash Dividend Paid on Common Stock	(748		)	(728		)	(718		)
Other	(64		)	(61		)	(58		)
Net Cash Provided By (Used In) Financing Activities	(359		)	(243		)	(617		)
Net Increase (Decrease) in Cash and Cash Equivalents	(91		)	114			(455		)
Cash and Cash Equivalents at Beginning of Period	493			379			834
Cash and Cash Equivalents at End of Period	$	402		$	493		$	379
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	538		$	241		$	121
Interest Paid, Net of Amounts Capitalized	$	382		$	385		$	402
Accrued Property, Plant and Equipment Expenditures	$	382		$	336		$	370

See 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, 2012	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
Net Income	—	—		—		—			1,243			—			—			1,243
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(219)	—	—		—		—			—			293			—			293
Comprehensive Income																		1,536
Cash Dividends on Common Stock	—	—		—		—			(728		)	—			—			(728		)
Other	—	28		—		(8		)	—			—			—			20
Balance as of December 31, 2013	534	$	4,861	(28	)	$	(615	)	$	7,457		$	(95	)	$	1		$	11,609
Net Income	—	—		—		—			1,518			—			—			1,518
Other Comprehensive Income (Loss), net of tax (expense) benefit of $138	—	—		—		—			—			(188		)	—			(188		)
Comprehensive Income																		1,330
Cash Dividends on Common Stock	—	—		—		—			(748		)	—			—			(748		)
Other	—	15		—		(20		)	—			—			—			(5		)
Balance as of December 31, 2014	534	$	4,876	(28	)	$	(635	)	$	8,227		$	(283	)	$	1		$	12,186

See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

Millions




	Years Ended December 31,
	2014			2013			2012
OPERATING REVENUES	$	6,766		$	6,655		$	6,626
OPERATING EXPENSES
Energy Costs	2,909			2,841			3,159
Operation and Maintenance	1,558			1,639			1,508
Depreciation and Amortization	906			872			778
Taxes Other Than Income Taxes	—			68			98
Total Operating Expenses	5,373			5,420			5,543
OPERATING INCOME	1,393			1,235			1,083
Other Income	61			54			52
Other Deductions	(3		)	(3		)	(5		)
Interest Expense	(277		)	(293		)	(295		)
INCOME BEFORE INCOME TAXES	1,174			993			835
Income Tax (Expense) Benefit	(449		)	(381		)	(307		)
NET INCOME	$	725		$	612		$	528

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 COMPREHENSIVE INCOME

Millions




	Years Ended December 31,
		2014		2013			2012
NET INCOME		$	725	$	612		$	528
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0, $1 and $0 for the years ended 2014, 2013 and 2012, respectively		1		(1		)	—
COMPREHENSIVE INCOME		$	726	$	611		$	528

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,
	2014			2013
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	310		$	18
Accounts Receivable, net of allowances of $52 and $56 in 2014 and 2013, respectively	864			832
Accounts Receivable-Affiliated Companies	274			—
Unbilled Revenues	284			300
Materials and Supplies	133			115
Prepayments	42			24
Regulatory Assets	323			243
Regulatory Assets of VIEs	249			—
Derivative Contracts	18			25
Deferred Income Taxes	24			16
Other	7			12
Total Current Assets	2,528			1,585
PROPERTY, PLANT AND EQUIPMENT	21,103			19,071
Less: Accumulated Depreciation and Amortization	(5,183		)	(4,964		)
Net Property, Plant and Equipment	15,920			14,107
NONCURRENT ASSETS
Regulatory Assets	3,192			2,612
Regulatory Assets of VIEs	—			476
Long-Term Investments	348			361
Other Special Funds	53			354
Derivative Contracts	8			69
Restricted Cash of VIEs	24			24
Other	150			132
Total Noncurrent Assets	3,775			4,028
TOTAL ASSETS	$	22,223		$	19,720

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,
	2014		2013
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	300	$	500
Securitization Debt of VIEs Due Within One Year	259		237
Commercial Paper and Loans	—		60
Accounts Payable	574		535
Accounts Payable—Affiliated Companies	379		190
Accrued Interest	68		67
Clean Energy Program	142		142
Deferred Income Taxes	165		30
Obligation to Return Cash Collateral	121		119
Regulatory Liabilities	186		43
Other	381		314
Total Current Liabilities	2,575		2,237
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	4,575		4,406
Other Postretirement Benefit (OPEB) Costs	967		839
Accrued Pension Costs	173		27
Regulatory Liabilities	258		233
Regulatory Liabilities of VIEs	39		11
Environmental Costs	364		363
Asset Retirement Obligations	290		274
Long-Term Accrued Taxes	116		72
Other	67		47
Total Noncurrent Liabilities	6,849		6,272
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 12)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt	6,012		5,066
Securitization Debt of VIEs	—		259
Total Long-Term Debt	6,012		5,325
STOCKHOLDER’S EQUITY
Common Stock; 150,000,000 shares authorized; issued and outstanding, 2014 and 2013—132,450,344 shares	892		892
Contributed Capital	695		520
Basis Adjustment	986		986
Retained Earnings	4,212		3,487
Accumulated Other Comprehensive Income	2		1
Total Stockholder’s Equity	6,787		5,886
Total Capitalization	12,799		11,211
TOTAL LIABILITIES AND CAPITALIZATION	$	22,223	$	19,720

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,
	2014			2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	725		$	612		$	528
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	906			872			778
Provision for Deferred Income Taxes and ITC	310			198			442
Non-Cash Employee Benefit Plan Costs	27			156			179
Cost of Removal	(98		)	(93		)	(116		)
Change in Accrued Storm Costs	(3		)	(90		)	(90		)
Net Change in Regulatory Assets and Liabilities	190			2			(132		)
Net Change in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues	63			(5		)	(54		)
Materials and Supplies	(18		)	(1		)	(20		)
Prepayments	(18		)	5			88
Net Change in Tax Receivable	—			—			16
Accounts Payable	(3		)	19			(25		)
Accounts Receivable/Payable-Affiliated Companies, net	(167		)	100			(132		)
Other Current Assets and Liabilities	6			40			37
Employee Benefit Plan Funding and Related Payments	(83		)	(166		)	(213		)
Other	(4		)	(4		)	(30		)
Net Cash Provided By (Used In) Operating Activities	1,833			1,645			1,256
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(2,164		)	(2,175		)	(1,770		)
Proceeds from Sales of Available-for-Sale Securities	103			38			77
Investments in Available-for-Sale Securities	(101		)	(20		)	(77		)
Solar Loan Investments	7			(15		)	(74		)
Other	—			—			(1		)
Net Cash Provided By (Used In) Investing Activities	(2,155		)	(2,172		)	(1,845		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt	(60		)	(203		)	263
Issuance of Long-Term Debt	1,250			1,500			900
Redemption of Long-Term Debt	(500		)	(725		)	(373		)
Redemption of Securitization Debt	(237		)	(226		)	(216		)
Contributed Capital	175			100			—
Other	(14		)	(17		)	(12		)
Net Cash Provided By (Used In) Financing Activities	614			429			562
Net Increase (Decrease) in Cash and Cash Equivalents	292			(98		)	(27		)
Cash and Cash Equivalents at Beginning of Period	18			116			143
Cash and Cash Equivalents at End of Period	$	310		$	18		$	116
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	283		$	84		$	(30	)
Interest Paid, Net of Amounts Capitalized	$	259		$	275		$	280
Accrued Property, Plant and Equipment Expenditures	$	292		$	246		$	275

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, 2012	$	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
Balance as of December 31, 2012	$	892	$	420	$	986	$	2,875	$	2		$	5,175
Net Income	—		—		—		612		—			612
Other Comprehensive Income, net of tax (expense) benefit of $1	—		—		—		—		(1		)	(1		)
Comprehensive Income												611
Contributed Capital	—		100		—		—		—			100
Balance as of December 31, 2013	$	892	$	520	$	986	$	3,487	$	1		$	5,886
Net Income	—		—		—		725		—			725
Other Comprehensive Income, net of tax (expense) benefit of $0	—		—		—		—		1			1
Comprehensive Income												726
Contributed Capital	—		175		—		—		—			175
Balance as of December 31, 2014	$	892	$	695	$	986	$	4,212	$	2		$	6,787

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

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PSEG POWER LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

Millions




	Years Ended December 31,
	2014			2013			2012
OPERATING REVENUES	$	5,434		$	5,063		$	4,873
OPERATING EXPENSES
Energy Costs	2,747			2,496			2,381
Operation and Maintenance	1,186			1,224			1,127
Depreciation and Amortization	292			273			242
Total Operating Expenses	4,225			3,993			3,750
OPERATING INCOME	1,209			1,070			1,123
Income from Equity Method Investments	14			16			15
Other Income	222			154			201
Other Deductions	(52		)	(49		)	(90		)
Other-Than-Temporary Impairments	(20		)	(12		)	(18		)
Interest Expense	(122		)	(116		)	(132		)
INCOME BEFORE INCOME TAXES	1,251			1,063			1,099
Income Tax (Expense) Benefit	(491		)	(419		)	(433		)
NET INCOME	$	760		$	644		$	666

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,
		2014			2013			2012
NET INCOME		$	760		$	644		$	666
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $28, $(55) and $(24) for the years ended 2014, 2013 and 2012, respectively		(30		)	57			18
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $(8), $7 and $18 for the years ended 2014, 2013 and 2012, respectively		12			(10		)	(24		)
Pension/OPEB adjustment, net of tax (expense) benefit of $101, $(151) and $32 for the years ended 2014, 2013 and 2012, respectively		(147		)	218			(46		)
Other Comprehensive Income (Loss), net of tax		(165		)	265			(52		)
COMPREHENSIVE INCOME		$	595		$	909		$	614

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

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PSEG POWER LLC

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2014			2013
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	9		$	6
Accounts Receivable	334			338
Tax Receivable	3			—
Accounts Receivable—Affiliated Companies	313			333
Short-Term Loan to Affiliate	584			790
Fuel	538			545
Materials and Supplies, net	350			362
Derivative Contracts	207			57
Prepayments	17			13
Deferred Taxes	—			30
Other	4			2
Total Current Assets	2,359			2,476
PROPERTY, PLANT AND EQUIPMENT	10,732			10,278
Less: Accumulated Depreciation and Amortization	(3,217		)	(2,911		)
Net Property, Plant and Equipment	7,515			7,367
NONCURRENT ASSETS
Nuclear Decommissioning Trust (NDT) Fund	1,780			1,701
Long-Term Investments	121			123
Goodwill	16			16
Other Intangibles	84			33
Other Special Funds	49			139
Derivative Contracts	62			72
Other	60			75
Total Noncurrent Assets	2,172			2,159
TOTAL ASSETS	$	12,046		$	12,002

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,
	2014			2013
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	300		$	44
Accounts Payable	424			516
Accounts Payable—Affiliated Companies	118			—
Derivative Contracts	132			76
Deferred Income Taxes	43			—
Accrued Interest	27			28
Other	140			136
Total Current Liabilities	1,184			800
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	2,065			2,031
Asset Retirement Obligations	450			400
Other Postretirement Benefit (OPEB) Costs	248			206
Derivative Contracts	33			31
Accrued Pension Costs	153			35
Long-Term Accrued Taxes	41			53
Other	71			91
Total Noncurrent Liabilities	3,061			2,847
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 12)
LONG-TERM DEBT
Total Long-Term Debt	2,243			2,497
MEMBER’S EQUITY
Contributed Capital	2,214			2,214
Basis Adjustment	(986		)	(986		)
Retained Earnings	4,558			4,693
Accumulated Other Comprehensive Loss	(228		)	(63		)
Total Member’s Equity	5,558			5,858
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	12,046		$	12,002

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

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PSEG POWER LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions




	Years Ended December 31,
	2014			2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	760		$	644		$	666
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	292			273			242
Amortization of Nuclear Fuel	200			192			173
Provision for Deferred Income Taxes and ITC	221			122			397
Interest Accretion on Asset Retirement Obligation	30			23			21
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	(93		)	79			63
Non-Cash Employee Benefit Plan Costs	13			66			70
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(166		)	(104		)	(118		)
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies	19			(8		)	47
Margin Deposit	(22		)	(43		)	(116		)
Accounts Receivable	(15		)	(4		)	24
Accounts Payable	(59		)	28			93
Accounts Receivable/Payable-Affiliated Companies, net	220			—			(40		)
Accrued Interest Payable	—			2			(6		)
Other Current Assets and Liabilities	(6		)	70			(17		)
Employee Benefit Plan Funding and Related Payments	(7		)	(46		)	(72		)
Other	38			53			26
Net Cash Provided By (Used In) Operating Activities	1,425			1,347			1,453
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(626		)	(609		)	(770		)
Proceeds from Sales of Available-for-Sale Securities	1,557			1,084			1,478
Investments in Available-for-Sale Securities	(1,573		)	(1,102		)	(1,506		)
Short-Term Loan—Affiliated Company, net	206			(216		)	333
Other	(88		)	(18		)	(7		)
Net Cash Provided By (Used In) Investing Activities	(524		)	(861		)	(472		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Recourse Long-Term Debt	—			500			—
Cash Dividend Paid	(895		)	(705		)	(619		)
Redemption of Long-Term Debt	—			(300		)	(414		)
Contributed Capital	—			24			69
Cash Payment on Debt Redemption/Exchange	—			—			(15		)
Other	(3		)	(6		)	(7		)
Net Cash Provided By (Used In) Financing Activities	(898		)	(487		)	(986		)
Net Increase (Decrease) in Cash and Cash Equivalents	3			(1		)	(5		)
Cash and Cash Equivalents at Beginning of Period	6			7			12
Cash and Cash Equivalents at End of Period	$	9		$	6		$	7
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	68		$	291		$	81
Interest Paid, Net of Amounts Capitalized	$	119		$	106		$	119
Accrued Property, Plant and Equipment Expenditures	$	91		$	90		$	95

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

Table of Contents

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, 2012	$	2,121	$	(986	)	$	4,707		$	(276	)	$	5,566
Net Income	—		—			666			—			666
Other Comprehensive Income (Loss), net of tax (expense) benefit of $26	—		—			—			(52		)	(52		)
Comprehensive Income												614
Contributed Capital	69		—			—			—			69
Cash Dividends Paid	—		—			(619		)				(619		)
Balance as of December 31, 2012	$	2,190	$	(986	)	$	4,754		$	(328	)	$	5,630
Net Income	—		—			644			—			644
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(199)	—		—			—			265			265
Comprehensive Income												909
Contributed Capital	24		—			—			—			24
Cash Dividends Paid	—		—			(705		)	—			(705		)
Balance as of December 31, 2013	$	2,214	$	(986	)	$	4,693		$	(63	)	$	5,858
Net Income	—		—			760			—			760
Other Comprehensive Income (Loss), net of tax (expense) benefit of $121	—		—			—			(165		)	(165		)
Comprehensive Income												595
Cash Dividends Paid	—		—			(895		)	—			(895		)
Balance as of December 31, 2014	$	2,214	$	(986	)	$	4,558		$	(228	)	$	5,558

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

Table of Contents

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:

•

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 Federal Energy Regulatory Commission (FERC). PSE&G also invests in solar generation projects and has implemented energy efficiency and demand response programs in New Jersey, which are regulated by the BPU.

•

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 its principal direct wholly owned subsidiaries. Power’s subsidiaries are subject to regulation by the FERC, the Nuclear Regulatory Commission (NRC) and the states in which they operate.

PSEG's other direct wholly owned subsidiaries include PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; PSEG Long Island LLC (PSEG LI), which, effective January 1, 2014, operates the Long Island Power Authority's (LIPA) transmission and distribution (T&D) system under a twelve-year Amended and Restated Operations Services Agreement (OSA); and PSEG Services Corporation (Services), which provides certain 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 intercompany accounts and transactions are eliminated in consolidation, except as discussed in Note 23. Related-Party Transactions.

PSE&G and Power 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. PSE&G and Power consolidated their portion of any revenues and expenses related to their respective jointly-owned 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 reflect the economic effects of regulation. PSE&G defers the recognition of costs (a Regulatory Asset) or records 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 becomes 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 5. Regulatory Assets and Liabilities.

Derivative Financial Instruments

Each company uses derivative financial instruments to manage risk pursuant to its business plans and prudent practices.

Derivative instruments, not designated as normal purchases or sales, are recognized on the balance sheet at their fair value. Changes in the fair value of a derivative that is highly effective as and that is designated and qualifies as a fair value hedge,

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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 or are not designated as cash flow or fair value hedges or 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 15. Financial Risk Management Activities.

Revenue Recognition

PSE&G’s revenues are recorded primarily 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.

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. See Note 15. Financial Risk Management Activities for further discussion.

PSEG LI is the primary beneficiary of Long Island Electric Utility Servco, LLC (Servco). For transactions in which Servco acts as principal, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and Operations and Maintenance (O&M) Expense, respectively. See Note 3. Variable Interest Entities for further information.

Depreciation and Amortization

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:




	2014		2013		2012
	Avg Rate		Avg Rate		Avg Rate
PSE&G Depreciation Rate	2.47	%	2.48	%	2.48	%

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—19 years to 79 years


•	nuclear generation assets—approximately 60 years


•	pumped storage facilities—76 years


•	solar assets—25 years

Taxes Other Than Income Taxes

Excise taxes and the transitional energy facilities assessment (TEFA) collected from PSE&G’s customers are presented in the financial statements on a gross basis. Effective January 1, 2014, the TEFA was eliminated. For the years ended December 31, 2013 and 2012, the TEFA is included in the following captions in the Consolidated Statements of Operations:

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	Years Ended December 31,
	2013		2012
	Millions
TEFA included in:
Operating Revenues	$	74	$	108
Taxes Other Than Income Taxes	$	68	$	98

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

AFUDC represents the cost of debt and equity funds used to finance the construction of new utility assets at PSE&G. IDC represents the cost of debt used to finance construction at Power. The amount of AFUDC or IDC 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 AFUDC or IDC for the years ended December 31, 2014, 2013 and 2012 were as follows:




	AFUDC/IDC Capitalized
	2014				2013				2012
	Millions		Avg Rate		Millions		Avg Rate		Millions		Avg Rate
PSE&G	$	44	8.09	%	$	34	8.11	%	$	33	8.43	%
Power	$	24	5.14	%	$	23	5.36	%	$	29	5.16	%

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 19. Income Taxes for further discussion.

Impairment of Long-Lived Assets

In accordance with GAAP, 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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Materials and Supplies and Fuel

PSE&G’s materials and supplies are carried at average cost consistent with the rate-making process. Materials and supplies for Power are valued at cost and charged to inventory when purchased and expensed or capitalized to Property, Plant and Equipment, as appropriate, when installed or used. Fuel inventory at Power is valued at the lower of average cost or market and includes 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 to Energy Costs when used or sold. The cost of nuclear fuel is capitalized within Property, Plant and Equipment and amortized to fuel expense using the unit-of-production method.

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

PSE&G’s additions to and replacements of existing property, plant and equipment are capitalized at 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.

Power capitalizes costs, including those related to its jointly-owned facilities, 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.

Available-for-Sale Securities

These securities comprise 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 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 losses on debt securities which are recorded in earnings). Securities with unrealized losses that are deemed to be other-than-temporarily impaired are recorded in earnings. See Note 8. Available-for-Sale Securities for further discussion.

Pension and Other Postretirement Benefits (OPEB) Plans

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 date (December 31) for all plan assets.

PSEG recognizes a long-term receivable primarily related to future funding by LIPA of Servco’s recognized pension and OPEB liabilities. This receivable is presented separately on the Consolidated Balance Sheet of PSEG as a noncurrent asset because it is restricted.

Pursuant to the OSA, Servco records expense only to the extent of its contributions to its pension plan trusts and for OPEB payments made to retirees.

See Note 11. Pension and Other Postretirement Benefits for further discussion.

Basis Adjustment

PSE&G and Power 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 PSE&G’s and Power's Consolidated Balance Sheets. The $986 million is an addition to PSE&G’s Common Stockholder’s Equity and a reduction of Power’s Member’s Equity. These amounts are eliminated on PSEG’s consolidated financial statements.

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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.

Note 2. Recent Accounting Standards

New Standards Adopted during 2014

Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists

This accounting standard was issued to address diversity in practice related to the presentation of an unrecognized tax benefit in certain cases. This standard requires entities to present an unrecognized tax benefit or a portion thereof on the Balance Sheet as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward.

However, the unrecognized tax benefit will be presented on the Balance Sheet as a liability and will not be combined with deferred tax assets in cases where that tax benefit cannot or will not, if permissible, be used to settle any additional income taxes that would result from the disallowance of a tax position.

The standard was effective for fiscal years and interim periods beginning after December 15, 2013. The impact of adopting this standard was immaterial.

Business Combinations: Pushdown Accounting

The amendments in this standard provide an acquired entity with an option to apply pushdown accounting in its separate financial statements when an acquirer obtains control of the acquired entity. Pushdown accounting provides for the use of the acquirer’s basis, including fair value adjustments and goodwill as applicable, in the preparation of the acquiree’s separate financial statements. An acquired entity may elect the option to apply pushdown accounting in the reporting period in which the change-in-control event occurs. An acquired entity can elect whether to apply pushdown accounting for each individual change-in-control event in which an acquirer obtains control of the acquired entity. An election to apply pushdown accounting in a reporting period after the reporting period in which the change-in-control event occurred should be considered a change in accounting principle. If an acquired entity elects the option to apply pushdown accounting in its separate financial statements, it should disclose information in the current reporting period.

The update became effective on November 18, 2014. We will evaluate all future acquisitions under the new guidance.

New Standards Issued but Not Yet Required to be Adopted

Revenue from Contracts with Customers

This accounting standard was issued to clarify the principles for recognizing revenue and to develop a common standard that would remove inconsistencies in revenue requirements; improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets; and provide improved disclosures.

The guidance provides a five-step model to be used for recognizing revenue for the transfer of promised goods and services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services.

The update is effective for annual and interim reporting periods beginning after December 15, 2016. Early application is not permitted. We are currently analyzing the impact of this standard on our financial statements.

Presentation of Financial Statements and Property, Plant and Equipment: Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity

This accounting standard was issued to change the criteria for reporting discontinued operations. The standard requires that a component of an entity be reported in discontinued operations if the disposal represents a strategic shift that has, or will have, a major effect on the entity’s operations and financial results, including a disposal of a major geographical area, a major line of business, a major equity method investment or other major parts of an entity.

The amendment should be applied prospectively for all disposals of an entity that occur within interim and annual periods beginning on or after December 15, 2014; and all businesses that, on acquisition, are classified as held for sale that occur within interim and annual periods beginning on or after December 15, 2014. We will evaluate all future disposals under the new guidance beginning on January 1, 2015.

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Transfers and Servicing - Repurchase-to-Maturity Transactions, Repurchase-Financings and Disclosures

This standard changes the accounting for repurchase-to-maturity transactions and linked repurchase-financings to secured borrowing accounting, which is consistent with the accounting for other repurchase agreements. It also requires disclosures for repurchase agreements, securities lending transactions and repurchase-to-maturity transactions that are accounted for as secured borrowings.

This standard is effective for the first interim or annual period beginning after December 15, 2014.

We are currently analyzing this standard but do not expect its impact to be material to our financial statements.

Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern

The amendments in this standard provide guidance about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. Substantial doubt about an entity’s ability to continue as a going concern exists when relevant conditions and events, considered in the aggregate, indicate that it is probable that the entity will be unable to meet its obligations as they become due within one year after the date that its financial statements are issued.

The update is effective for annual and interim reporting periods beginning after December 15, 2016.

The update requires that we identify, assess and evaluate uncertainties and their impact, if any, on our ability to meet financial obligations. However, we do not expect this standard to impact our financial statements.

Note 3. Variable Interest Entities (VIEs)

VIEs for which PSE&G is the Primary Beneficiary

PSE&G is the primary beneficiary 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 a trustee. PSE&G acts as the servicer for these entities to collect securitization transition charges authorized by the BPU. These funds are remitted to Transition Funding and Transition Funding II and are used for interest and principal payments on the transition bonds and related costs.

The assets and liabilities of Transition Funding and Transition Funding II are presented separately on the face of the Consolidated Balance Sheets of PSEG and PSE&G because the assets of these VIEs are restricted and can only be used to settle their respective obligations. No Transition Funding or Transition Funding II creditor has 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 or Transition Funding II.

PSE&G’s maximum exposure to loss is equal to its equity investment in these VIEs which was $16 million as of December 31, 2014 and 2013. The risk of actual loss to PSE&G is considered remote. PSE&G did not provide any financial support to Transition Funding or Transition Funding II in 2014 or 2013. PSE&G does not have any contractual commitments or obligations to provide financial support to Transition Funding and Transition Funding II.

VIE for which PSEG LI is the Primary Beneficiary

PSEG LI consolidates Servco, a marginally capitalized VIE, which was created for the purpose of operating LIPA's T&D system in Long Island, New York as well as providing administrative support functions to LIPA. PSEG LI is the primary beneficiary of Servco because it directs the operations of Servco, the activity that most significantly impacts Servco's economic performance and it has the obligation to absorb losses of Servco that could potentially be significant to Servco. Such losses would be immaterial to PSEG.

Pursuant to the OSA, Servco's operating costs are reimbursable entirely by LIPA, and therefore, PSEG LI's risk is limited related to the activities of Servco. PSEG LI has no current obligation to provide direct financial support to Servco. In addition to reimbursement of Servco’s operating costs as provided for in the OSA, PSEG LI receives an annual contract management fee. PSEG LI’s annual contractual management fee, in certain situations, could be partially offset by Servco's annual storm costs not approved by the Federal Emergency Management Agency, limited contingent liabilities and penalties for failing to meet certain performance metrics.

For transactions in which Servco acts as principal, such as transactions with its employees for labor and labor-related activities, including pension and OPEB related transactions, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and O&M Expense, respectively. In 2014, Servco recorded $389 million of O&M costs, the full reimbursement of which was reflected in Operating Revenues. For transactions in which Servco acts as an agent for LIPA, it records revenues and the related expenses on a net basis, resulting in no impact on PSEG's Consolidated Statement of Operations.

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Note 4. Property, Plant and Equipment and Jointly-Owned Facilities

Information related to Property, Plant and Equipment as of December 31, 2014 and 2013 is detailed below:




	PSE&G		Power		Other		PSEG Consolidated
	Millions
2014
Transmission and Distribution:
Electric Transmission	$	5,845	$	—	$	—	$	5,845
Electric Distribution	7,295		—		—		7,295
Gas Transmission	89		—		—		89
Gas Distribution	5,479		—		—		5,479
Construction Work in Progress	1,304		—		—		1,304
Plant Held for Future Use	15		—		—		15
Other	401		—		—		401
Total Transmission and Distribution	20,428		—		—		20,428
Generation:
Fossil Production	—		6,964		—		6,964
Nuclear Production	—		1,751		—		1,751
Nuclear Fuel in Service	—		889		—		889
Other Production-Solar	521		314		—		835
Construction Work in Progress	—		714		—		714
Total Generation	521		10,632		—		11,153
Other	154		100		361		615
Total	$	21,103	$	10,732	$	361	$	32,196




	PSE&G		Power		Other		PSEG Consolidated
	Millions
2013
Transmission and Distribution:
Electric Transmission	$	4,037	$	—	$	—	$	4,037
Electric Distribution	7,109		—		—		7,109
Gas Transmission	89		—		—		89
Gas Distribution	5,230		—		—		5,230
Construction Work in Progress	1,605		—		—		1,605
Plant Held for Future Use	3		—		—		3
Other	372		—		—		372
Total Transmission and Distribution	18,445		—		—		18,445
Generation:
Fossil Production	—		6,924		—		6,924
Nuclear Production	—		1,636		—		1,636
Nuclear Fuel in Service	—		857		—		857
Other Production-Solar	469		273		—		742
Construction Work in Progress	—		489		—		489
Total Generation	469		10,179		—		10,648
Other	157		99		364		620
Total	$	19,071	$	10,278	$	364	$	29,713

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PSE&G and Power 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 PSE&G’s and Power’s jointly-owned projects and the corresponding direct expenses are included in the Consolidated Statements of Operations as operating expenses.




			As of December 31,
			2014				2013
	Ownership				Accumulated				Accumulated
	Interest		Plant		Depreciation		Plant		Depreciation
			Millions
PSE&G:
Transmission Facilities	Various		$	162	$	69	$	161	$	66
Power:
Coal Generating
Conemaugh	23	%	$	397	$	142	$	374	$	139
Keystone	23	%	$	396	$	151	$	388	$	140
Nuclear Generating
Peach Bottom	50	%	$	1,087	$	236	$	886	$	215
Salem	57	%	$	916	$	236	$	897	$	254
Nuclear Support Facilities	Various		$	218	$	49	$	205	$	37
Pumped Storage Facilities
Yards Creek	50	%	$	41	$	24	$	36	$	23
Merrill Creek Reservoir	14	%	$	1	$	—	$	1	$	—

Power holds undivided ownership interests in the jointly-owned facilities above. 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 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 5. Regulatory Assets and Liabilities

PSE&G prepares its financial statements in accordance with GAAP for regulated utilities as described in Note 1. Organization and Basis of Presentation and Summary of Significant Accounting Policies. PSE&G has deferred certain costs based on rate orders issued by the BPU or the FERC or based on PSE&G’s experience with prior rate cases. Most of PSE&G’s Regulatory Assets and Liabilities as of December 31, 2014 are supported by written orders, either explicitly or implicitly through the BPU’s treatment of various cost items. These costs will be recovered and amortized over various future periods.

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,
	2014		2013		Recovery/Refund Period
	Millions
Regulatory Assets
Current
Non-Utility Generation Charge (NGC)	$	—	$	6	Annual filing for recovery (1) (2)
Societal Benefits Charges (SBC)	—		16		Annual filing for recovery (1) (2)
Solar and Energy Efficiency Recovery Charges (formerly RRC and currently Green Program Recovery Charges (GPRC))	13		41		Annual filing for recovery (1) (2)
Solar Pilot Recovery Charge (SPRC)	—		12		Annual filing for recovery (1) (2)
Capital Stimulus Undercollection	—		3		Annual filing for recovery (1) (2)
Weather Normalization Clause (WNC)	—		20		Annual filing for recovery (2)
New Jersey Clean Energy Program	142		142		Annual filing for recovery (1) (2)
Stranded Costs (including $249 in 2014 related to VIEs)	412		—		Through December 2015 (2)
Other	5		3		Various
Total Current Regulatory Assets	$	572	$	243
Noncurrent
Stranded Costs (including $476 in 2013 related to VIEs)	$	—	$	701	Through December 2016 (1) (2)
Manufactured Gas Plant (MGP) Remediation Costs	434		445		Various (2)
Pension and OPEB Costs	1,265		637		Various
Deferred Income Taxes	473		444		Various
Remediation Adjustment Charge (RAC) (Other SBC)	164		144		Through 2021 (1) (2)
Mark-to-Market (MTM) Contracts	75		—		Through 2017
Unamortized Loss on Reacquired Debt and Debt Expense	74		81		Over remaining debt life (1)
Conditional Asset Retirement Obligation	138		123		Various
GPRC	134		151		Various (2)
Electric Cost of Removal	91		23		Reduced as cost is incurred
Storm Damage Deferrals	245		245		To be determined
Other	99		94		Various
Total Noncurrent Regulatory Assets	$	3,192	$	3,088
Total Regulatory Assets	$	3,764	$	3,331

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	As of December 31,
	2014		2013		Recovery/Refund Period
	Millions
Regulatory Liabilities
Current
Deferred Income Taxes	$	28	$	31	Various
Overrecovered Gas and Electric Costs—Basic Gas Supply Service (BGSS) and Basic Generation Service (BGS)	80		9		Annual filing for recovery (1) (2)
WNC	31		—		Annual filing for recovery (2)
Gas Margin Adjustment Clause	28		—		Annual filing for recovery (1) (2)
Other	19		3		Various
Total Current Regulatory Liabilities	$	186	$	43
Noncurrent
Electric Cost of Removal	$	133	$	137	Reduced as cost is incurred
MTM Contracts	—		74		Various
Stranded Costs (including $39 and $11 in 2014 and 2013, respectively, related to VIEs)	134		11		Through December 2016 (1) (2)
FERC Formula Rate True-up	26		—		Through December 2016 (1) (2)
Other	4		22		Various
Total Noncurrent Regulatory Liabilities	$	297	$	244
Total Regulatory Liabilities	$	483	$	287


(1)	Recovered/Refunded with interest.


(2)	Recoverable/Refundable per specific rate order.

All Regulatory Assets and Liabilities are excluded from PSE&G’s rate base unless otherwise noted. The Regulatory Assets and Liabilities in the table above are defined as follows:


•	NGC: Represents the difference between the cost of non-utility generation and the amounts realized from selling that energy at market rates through PJM Interconnection, L.L.C. (PJM) and ratepayer collections.

•

SBC: The SBC, as authorized by the BPU and the New Jersey Electric Discount and Energy Competition Act, includes costs related to PSE&G's electric and gas business as follows: (1) the Universal Service Fund (USF); (2) Energy Efficiency and Renewable Energy Programs; (3) Electric bad debt expense; and (4) the RAC for incurred MGP remediation expenditures. All components accrue interest on both over and underrecoveries.


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

•

SPRC: This charge is designed to recover the revenue requirements associated with the PSE&G Solar Pilot Program (Solar Loan I) per a 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: 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 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's 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 OPEB Costs: 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.


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


•	MTM Contracts: The estimated fair value of 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 and expenses associated with issuances of new 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.


•	Storm Damage Deferrals: Costs incurred in the cleanup of major storms in 2010 through 2014. This includes $240 million of storm costs, primarily as a result of Hurricane Irene and Superstorm Sandy, approved for future recovery under a BPU Order received in September 2014.


•	Overrecovered Gas and Electric Costs: These costs represent the net overrecovered amounts associated with BGSS and BGS, as approved by the BPU. For BGS, interest is accrued on both overrecovered and underrecovered balances. For BGSS, interest is accrued only on overrecovered balances from residential customers.


•	Gas Margin Adjustment Clause: This mechanism credits Firm delivery customers for net distribution margin revenue collected from Transportation Gas Service Non-Firm (TSG-NF) delivery customers. The balance represents the difference between the net margin collected from the TSG-NF Customers versus bill credits provided to Firm delivery customers.


•	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.


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

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Significant 2014 regulatory orders received and currently pending rate filings with the FERC and the BPU by PSE&G are as follows:


•	RAC—On February 11, 2015, the BPU approved PSE&G’s filing with respect to its RAC 21 petition allowing recovery of $66 million related to net MGP expenditures from August 1, 2012 through July 31, 2013.


•	BGSS—In January and February 2014, PSE&G filed self-implementing one-month BGSS residential customer bill credits with the BPU for 25 cents per therm for the months of February and March 2014. These credits provided approximately $93 million in total credits to residential customers, reducing the BGSS deferred balance. On April 1, 2014, the BGSS rate reverted back to the current rate.

In May 2014, PSE&G made its annual BGSS filing with the BPU requesting a reduction of $112 million in annual BGSS revenues. In September 2014, the BPU approved a Stipulation in this matter on a provisional basis and the BGSS rate was reduced from approximately 54 cents to 45 cents per therm effective October 1, 2014.

In October 2014, PSE&G filed a self-implementing three-month bill credit for residential customers to be effective during November and December 2014 and January 2015. This credit is 28 cents per therm for the three-month period and is estimated to provide approximately $160 million to customers. In January 2015, PSE&G filed a letter with the BPU to extend the three-month bill credit for two additional months through February and March 2015 which is estimated to provide an additional approximate $100 million to customers. The specific amount returned will depend on actual usage over that period.


•	Storm Damage Deferrals—In September 2014, the BPU approved a Stipulation finding that PSE&G's 2010 through 2012 major storm incremental O&M costs of $240 million (deferred as Regulatory Assets) and capital expenditures of $126 million were prudent and recoverable in a future base rate proceeding, subject to offset for the amount of insurance proceeds received.

•

WNC—In April 2014, the BPU approved PSE&G's filing with respect to deficiency revenues from the 2012-2013 Winter Period. The BPU’s approval of a final WNC resulted in no change to the provisional rate previously approved by the BPU and implemented effective October 1, 2013, which was set to recover $26 million from customers during the 2013-2014 Winter Period (October 1, 2013 through May 31, 2014).

In September 2014, the BPU provisionally approved PSE&G’s filing with respect to excess revenues collected during the colder than normal 2013-2014 Winter Period. Effective October 1, 2014, PSE&G is returning $45 million in revenues to its customers during the 2014-2015 Winter Period as a result of excess revenues collected during the colder than normal 2013-2014 Winter Period (October 1, 2014 through May 31, 2015).

•

USF/Lifeline—The USF is an energy assistance program mandated by the BPU and funded through the SBC clause mechanism 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 September 2014, the BPU approved rates set to recover costs incurred under the USF/Lifeline energy assistance programs effective October 1, 2014. PSE&G earns no margin on the collection of the USF and Lifeline programs resulting in no impact on Net Income.


•	Capital Stimulus Infrastructure Programs (CIP II)—In June 2014, the BPU approved PSE&G’s petition to recover annual revenue requirements of approximately $28 million for program costs incurred for its CIP II investments through September 30, 2013, which represents the final phase of the program. Base rates were adjusted effective July 1, 2014 to reflect the recovery.


•	SBC and NGC—In May 2014, the BPU approved PSE&G’s petition to recover actual SBC and NGC costs incurred through December 31, 2013 under its Energy Efficiency & Renewable Energy Programs, Social Programs and NGC. New rates were implemented on June 1, 2014 to recover approximately $400 million over the succeeding 12 months.

•

Transmission Formula Rate Filings—In May 2014, PSE&G filed its 2014 True-Up Adjustment pertaining to its formula rates in effect for 2013, which resulted in an adjustment of $5 million above the 2013 filed revenues. In accordance with PSE&G’s formula rate protocols, this Rate Year 2013 True-Up Adjustment has been incorporated into its Annual Formula Rate Update for the 2015 Rate Year. The 2015 Formula Rate Update filed with the FERC in October 2014 for approximately $182 million in increased annual transmission revenues went into effect on January 1, 2015.

•

Energy Strong Recovery Filing—In December 2014, PSE&G updated its initial Energy Strong cost recovery petition, seeking BPU approval to recover in base rates an estimated annual revenue increase of $1.1 million effective March 1, 2015. This increase represents capitalized Energy Strong electric investment costs in service through November 30, 2014. Pursuant to a Stipulation, the BPU approved PSE&G’s request on February 11, 2015.

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•

GPRC—In June 2014, PSE&G filed a petition with the BPU requesting recovery of costs and investments in the combined eight components of the electric and gas GPRC for the period October 1, 2014 through September 30, 2015. The rates proposed in our filing are designed to recover $111 million and $18 million in electric and gas revenues, respectively, on an annual basis. This matter is currently pending.


•	RAC—In December 2014, PSE&G filed a petition with the BPU requesting recovery of $86 million related to RAC 22 net MGP expenditures from August 1, 2013 through July 31, 2014. This matter is currently pending.

Note 6. Long-Term Investments

Long-Term Investments as of December 31, 2014 and 2013 included the following:




	As of December 31,
	2014		2013
	Millions
PSE&G
Life Insurance and Supplemental Benefits	$	156	$	158
Solar Loans	187		196
Other Investments	5		7
Power
Partnerships and Corporate Joint Ventures (Equity Method Investments) (A)	121		123
Energy Holdings
Lease Investments	836		825
Partnerships and Corporate Joint Ventures:
Equity Method Investments (A)	2		3
Cost Method Investments (B)	—		1
Total Long-Term Investments	$	1,307	$	1,313


(A)	During the three years ended December 31, 2014, 2013 and 2012, the amount of dividends from these investments was $17 million, $11 million and $17 million, respectively.


(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, 2014 and 2013, respectively.

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	As of December 31,
	2014			2013
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	691		$	701
Estimated Residual Value of Leased Assets	525			529
Total Investment in Rental Receivables	1,216			1,230
Unearned and Deferred Income	(380		)	(405		)
Gross Investments in Leases	836			825
Deferred Tax Liabilities	(738		)	(727		)
Net Investments in Leases	$	98		$	98

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,
	2014		2013		2012
	Millions
Pre-Tax Income (Loss) from Leases	$	24	$	11	$	78
Income Tax Expense (Benefit) on Pre-Tax Income from Leases	$	32	$	6	$	34

Equity Method Investments

Power and Energy Holdings had the following equity method investments as of December 31, 2014:




		%
Name	Location	Owned
Power
Keystone Fuels, LLC	PA	23%
Conemaugh Fuels, LLC	PA	23%
Kalaeloa	HI	50%
Energy Holdings
GWF	CA	50%
Hanford L. P. (Hanford)	CA	50%

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Note 7. 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 loans, including the noncurrent portion reported in Note 6. Long-Term Investments, 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	2014		2013
	Millions
Commercial/Industrial	$	188	$	192
Residential	13		15
	$	201	$	207

Energy Holdings

Energy Holdings had a net investment in domestic energy and real estate assets subject to leveraged lease accounting of $98 million as of December 31, 2014 and 2013 (See Note 6. 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. The “Not Rated” counterparty represents an investment in lease receivable related to a commercial real estate property.




	Lease Receivables, Net of Non-Recourse Debt
Counterparties’ Credit Rating (S&P) as of December 31, 2014	As of December 31, 2014
	Millions
AA	$	18
AA-	56
BBB+ - BBB-	317
BB-	134
B-	164
Not Rated	2
	$	691

The “BB-” and the "B-" ratings in the preceding table represent lease receivables related to coal-fired assets in Illinois and Pennsylvania, respectively. As of December 31, 2014, the gross investment in the leases of such assets, net of non-recourse debt, was $572 million, ($(20) million, net of deferred taxes). A more detailed description of such assets under lease is presented in the following table.

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Asset	Location	Gross Investment		% Owned		Total MW	Fuel Type	Counterparties’ S&P Credit Ratings	Counterparty
		Millions
Powerton Station Units 5 and 6	IL	$	134	64	%	1,538	Coal	BB-	NRG Energy, Inc.
Joliet Station Units 7 and 8	IL	$	84	64	%	1,044	Coal	BB-	NRG Energy, Inc.
Keystone Station Units 1 and 2	PA	$	121	17	%	1,711	Coal	B-	NRG REMA LLC
Conemaugh Station Units 1 and 2	PA	$	121	17	%	1,711	Coal	B-	NRG REMA LLC
Shawville Station Units 1, 2, 3 and 4	PA	$	112	100	%	603	Coal	B-	NRG 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 assets under 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 to the Internal Revenue Service (IRS).

Although all lease payments 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 to, new environmental legislation and regulation regarding air quality, water and other discharges in the process of generating electricity, market prices for fuel, electricity and capacity, overall financial condition of lease counterparties and the quality and condition of assets under lease.

NRG REMA LLC, an indirect subsidiary of NRG Energy, Inc. (NRG) notified PJM that it no longer intends to place the coal-fired units at the Shawville generating facility in long-term protective layup. Instead, those units will be shut down temporarily beginning in April 2015, with an expected return to service no later than June 2016 using an alternative fuel.

Nesbitt Asset Recovery, LLC (Nesbitt), (an indirect, wholly owned subsidiary of Energy Holdings), owns approximately 64% of the lease interest in the Powerton and Joliet coal units in Illinois. These facilities are leased to Midwest Generation (MWG), which was an indirect subsidiary of Edison Mission Energy (EME). In December 2012, EME and MWG filed for relief under Chapter 11 of the U.S. Bankruptcy Code. In October 2013, NRG, EME, MWG, Nesbitt and other creditor parties involved in the bankruptcy executed a new agreement under which NRG acquired substantially all of EME’s assets, including the Powerton and Joliet leased assets. In March 2014, the Bankruptcy Court approved the transaction. As part of the transaction, (i) the leases for the Powerton and Joliet coal units were assumed on their existing terms, (ii) all past due rent under the leases was paid in full, (iii) NRG assumed EME’s tax indemnity and guarantee obligations, and (iv) NRG agreed to invest up to $350 million in the Powerton and Joliet coal units so they can be operated in compliance with environmental regulations. On April 1, 2014, NRG and EME closed on the transaction in accordance with these terms, bringing the lease payments current.

Note 8. 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 its NDT Fund meets the formula-based minimum NRC funding requirements.

Power maintains an external master NDT to fund its share of decommissioning for its five nuclear facilities upon their respective termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. Power’s

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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, 2014 was approximately $419 million and is included in the Asset Retirement Obligation. The trust funds are managed by third-party investment advisors who operate under investment guidelines developed by Power.

Power classifies investments in the NDT Fund as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund:




	As of December 31, 2014
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	685	$	220	$	(8	)	$	897
Debt Securities
Government Obligations	430		9		(1		)	438
Other Debt Securities	333		9		(3		)	339
Total Debt Securities	763		18		(4		)	777
Other Securities	106		—		—			106
Total NDT Available-for-Sale Securities	$	1,554	$	238	$	(12	)	$	1,780




	As of December 31, 2013
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	609	$	290	$	(2	)	$	897
Debt Securities
Government Obligations	438		3		(12		)	429
Other Debt Securities	285		10		(4		)	291
Total Debt Securities	723		13		(16		)	720
Other Securities	84		—		—			84
Total NDT Available-for-Sale Securities	$	1,416	$	303	$	(18	)	$	1,701

These amounts in the preceding tables 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, 2014		As of December 31, 2013
	Millions
Accounts Receivable	$	10	$	39
Accounts Payable	$	2	$	36

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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, 2014										As of December 31, 2013
	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)	$	162	$	(8	)	$	1	$	—		$	30	$	(2	)	$	2	$	—
Debt Securities
Government Obligations (B)	95		—			28		(1		)	300		(11		)	1		(1		)
Other Debt Securities (C)	99		(1		)	30		(2		)	107		(4		)	3		—
Total Debt Securities	194		(1		)	58		(3		)	407		(15		)	4		(1		)
NDT Available-for-Sale Securities	$	356	$	(9	)	$	59	$	(3	)	$	437	$	(17	)	$	6	$	(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 companies with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of December 31, 2014.

(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, 2014.

(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, 2014.

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




	Years Ended December 31,
	2014			2013			2012
	Millions
Proceeds from Sales (A)	$	1,448		$	1,070		$	1,433
Net Realized Gains
Gross Realized Gains	$	177		$	112		$	153
Gross Realized Losses	(23		)	(26		)	(52		)
Net Realized Gains (Losses) on NDT Fund	$	154		$	86		$	101


(A)	Includes activity in accounts related to the liquidation of funds being transitioned to new managers.

Gross realized gains and gross realized losses disclosed in the above table were recognized in Other Income and Other Deductions, respectively, in PSEG’s and Power’s Consolidated Statements of Operations. Net unrealized gains of $110 million (after-tax) are included in Accumulated Other Comprehensive Loss on PSEG's and Power’s Consolidated Balance Sheets as of December 31, 2014.

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The available-for-sale debt securities held as of December 31, 2014 had the following maturities:




Time Frame	Fair Value
	Millions
Less than one year	$	10
1 - 5 years	271
6 - 10 years	179
11 - 15 years	54
16 - 20 years	49
Over 20 years	214
Total NDT Available-for-Sale Debt Securities	$	777

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 2014, other-than-temporary impairments of $20 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.”

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, 2014
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	Millions
Equity Securities	$	12	$	11	$	—	$	23
Debt Securities
Government Obligations	89		2		—		91
Other Debt Securities	74		1		—		75
Total Debt Securities	163		3		—		166
Other Securities	2		—		—		2
Total Rabbi Trust Available-for-Sale Securities	$	177	$	14	$	—	$	191

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	As of December 31, 2013
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	14	$	9	$	—		$	23
Debt Securities
Government Obligations	109		—		(2		)	107
Other Debt Securities	46		1		(1		)	46
Total Debt Securities	155		1		(3		)	153
Other Securities	3		—		—			3
Total Rabbi Trust Available-for-Sale Securities	$	172	$	10	$	(3	)	$	179

These amounts in the preceding tables do not include receivables and payables for Rabbi Trust 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 show in the following table.




	As of December 31, 2014		As of December 31, 2013
	Millions
Accounts Receivable	$	1	$	1
Accounts Payable	$	—	$	2

The following table shows the value of securities in the Rabbi Trust Fund that have been in an unrealized loss position for less than 12 months and greater than 12 months:




	As of December 31, 2014								As of December 31, 2013
	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)	$	—	$	—	$	—	$	—	$	—	$	—		$	—	$	—
Debt Securities
Government Obligations (B)	2		—		—		—		47		(2		)	2		—
Other Debt Securities (C)	24		—		—		—		18		(1		)	1		—
Total Debt Securities	26		—		—		—		65		(3		)	3		—
Rabbi Trust Available-for-Sale Securities	$	26	$	—	$	—	$	—	$	65	$	(3	)	$	3	$	—


(A)	Equity Securities—Investments in marketable equity securities within the Rabbi Trust Fund is through a mutual fund which invests primarily in common stocks within a broad range of industries and sectors. PSEG does not consider these securities to be other-than-temporarily impaired as of December 31, 2014.

(B)

Debt Securities (Government)—Unrealized losses on PSEG’s Rabbi Trust 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 PSEG does not intend to sell nor will it be more-likely-than-not required to sell. PSEG does not consider these securities to be other-than-temporarily impaired as of December 31, 2014.

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(C)

Debt Securities (Corporate)—PSEG’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 PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2014.

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




	Years Ended December 31,
	2014			2013			2012
	Millions
Proceeds from Rabbi Trust Sales (A)	$	467		$	89		$	233
Net Realized Gains (Losses):
Gross Realized Gains	$	4		$	4		$	6
Gross Realized Losses	(3		)	(3		)	—
Net Realized Gains (Losses) on Rabbi Trust	$	1		$	1		$	6


(A)	Includes activity in accounts related to the liquidation of funds being transitioned to new managers

Gross realized gains and gross realized losses disclosed in the above table were recognized in Other Income and Other Deductions, respectively, in the Consolidated Statements of Operations. Net unrealized gains of $8 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets as of December 31, 2014. The Rabbi Trust available-for-sale debt securities held as of December 31, 2014 had the following maturities:




Time Frame	Fair Value
	Millions
Less than one year	$	—
1 - 5 years	49
6 - 10 years	31
11 - 15 years	9
16 - 20 years	7
Over 20 years	70
Total Rabbi Trust Available-for-Sale Debt Securities	$	166

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 2014, 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, PSE&G and Power are detailed as follows:




	As of December 31, 2014		As of December 31, 2013
	Millions
PSE&G	$	41	$	42
Power	45		39
Other	105		98
Total Rabbi Trust Available-for-Sale Securities	$	191	$	179

Note 9. Goodwill and Other Intangibles

As of December 31, 2014 and 2013, Power had goodwill of $16 million related to the Bethlehem Energy Center facility. Power conducted an annual review for goodwill impairment as of October 31, 2014 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, 2014 and 2013, Power had intangible assets of $84 million and $33 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, 2014, 2013 and 2012 were as follows:




	Years Ended December 31,
	2014		2013		2012
	Millions
Emissions Expense	$	10	$	6	$	5
Renewable Energy Expense	$	59	$	26	$	34

Note 10. Asset Retirement Obligations (AROs)

PSEG, PSE&G and Power have recorded various AROs which represent legal obligations to remove or dispose of an asset or some component of an asset at retirement.

PSE&G has conditional AROs primarily for legal obligations related to the removal of treated wood poles and the requirement to seal natural gas pipelines at all sources of gas when the pipelines are no longer in service. PSE&G does not record an ARO for its protected steel and poly-based natural gas lines, as management believes that these categories of gas lines have an indeterminable life.

Power’s ARO liability primarily relates to the decommissioning of its nuclear power plants in accordance with NRC requirements. 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 8. Available-for-Sale Securities. Power also identified conditional AROs primarily related to Power’s fossil generation units and solar facilities, including liabilities for removal of asbestos, stored hazardous liquid material and underground storage tanks from industrial power sites, and demolition of certain plants, and the restoration of the sites at which they reside, when the plants are no longer in service. To estimate the fair value of its AROs, 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 third party decommissioning cost estimates, cost escalation rates, inflation rates and discount rates.

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The changes to the ARO liabilities for PSEG, PSE&G and Power during 2013 and 2014 are presented in the following table:




	PSEG			PSE&G			Power			Other
	Millions
ARO Liability as of January 1, 2013	$	627		$	250		$	374		$	3
Liabilities Settled	(5		)	(4		)	(1		)	—
Liabilities Incurred	17			13			4			—
Accretion Expense	23			—			23			—
Accretion Expense Deferred and Recovered in Rate Base (A)	15			15			—			—
ARO Liability as of December 31, 2013	$	677		$	274		$	400		$	3
Liabilities Settled	(2		)	(2		)	—			—
Liabilities Incurred	23			3			20			—
Accretion Expense	30			—			30			—
Accretion Expense Deferred and Recovered in Rate Base (A)	15			15			—			—
ARO Liability as of December 31, 2014	$	743		$	290		$	450		$	3


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

Note 11. Pension, Other Postretirement Benefits (OPEB) and Savings Plans

PSEG sponsors several qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. Eligible employees 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, PSE&G and Power 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, GAAP 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 PSE&G, the Regulatory Asset is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations. 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.

Amounts for Servco are not included in any of the following pension and OPEB benefit information for PSEG and its affiliates but rather are separately disclosed later in this note.

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, 2014 and 2013. 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
	2014			2013			2014			2013
	Millions
Change in Benefit Obligation
Benefit Obligation at Beginning of Year (A)	$	4,812		$	5,235		$	1,414		$	1,538
Service Cost	104			116			18			21
Interest Cost	234			215			69			63
Actuarial (Gain) Loss (B)	838			(501		)	210			(144		)
Gross Benefits Paid	(266		)	(253		)	(73		)	(64		)
Benefit Obligation at End of Year (A) (B)	$	5,722		$	4,812		$	1,638		$	1,414
Change in Plan Assets
Fair Value of Assets at Beginning of Year	$	5,116		$	4,357		$	319		$	253
Actual Return on Plan Assets	433			857			28			52
Employer Contributions	10			155			87			78
Gross Benefits Paid	(266		)	(253		)	(73		)	(64		)
Fair Value of Assets at End of Year	$	5,293		$	5,116		$	361		$	319
Funded Status
Funded Status (Plan Assets less Benefit Obligation)	$	(429	)	$	304		$	(1,277	)	$	(1,095	)
Additional Amounts Recognized in the Consolidated Balance Sheets
Noncurrent Assets (included in Other Special Funds)	$	21		$	434		$	—		$	—
Current Accrued Benefit Cost	(10		)	(9		)	—			—
Noncurrent Accrued Benefit Cost	(440		)	(121		)	(1,277		)	(1,095		)
Amounts Recognized	$	(429	)	$	304		$	(1,277	)	$	(1,095	)
Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (C)
Prior Service Cost	$	(102	)	$	(120	)	$	(39	)	$	(53	)
Net Actuarial Loss	1,724			977			495			310
Total	$	1,622		$	857		$	456		$	257


(A)	Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits.

(B)

In October 2014, the Society of Actuaries’ Retirement Plans Experience Committee issued its final report on mortality tables (RP-2014 Mortality Tables Report). As of December 31, 2014, PSEG updated its mortality assumptions based on the information contained in this report. The impact of this change is reflected in Actuarial (Gain) Loss in 2014 and added $314 million and $79 million to the Benefit Obligations for Pension and OPEB, respectively, since December 31, 2013.


(C)	Includes $702 million ($411 million, after-tax) and $408 million ($238 million, after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2014 and 2013, 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, 2014, PSEG had funded approximately 93% of its projected benefit obligation. This percentage does not include $191 million of assets in the Rabbi Trust as of December 31, 2014 which were used partially to fund the nonqualified pension plans. As of December 31, 2014, the nonqualified pension plans included in the benefit obligation in the above table and in the projected benefit obligation were $161 million. The fair values of the Rabbi Trust assets are included in Other Special Funds on the Consolidated Balance Sheets.

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Accumulated Benefit Obligation

The accumulated benefit obligation for all PSEG’s defined benefit pension plans was $5.5 billion as of December 31, 2014 and $4.5 billion as of December 31, 2013.

The following table provides the components of net periodic benefit cost for the years ended December 31, 2014, 2013 and 2012.




	Pension Benefits Years Ended December 31,									Other Benefits Years Ended December 31,
	2014			2013			2012			2014			2013			2012
	Millions
Components of Net Periodic Benefit Cost (Credit)
Service Cost	$	104		$	116		$	101		$	18		$	21		$	17
Interest Cost	234			215			223			69			63			65
Expected Return on Plan Assets	(399		)	(348		)	(306		)	(26		)	(21		)	(17		)
Amortization of Net
Transition Obligation	—			—			—			—			—			2
Prior Service Cost	(18		)	(19		)	(18		)	(14		)	(14		)	(14		)
Actuarial Loss	56			188			167			23			42			31
Net Periodic Benefit Cost (Credit)	$	(23	)	$	152		$	167		$	70		$	91		$	84
Special Termination Benefits	—			—			1			—			—			—
Effect of Regulatory Asset	—			—			—			—			—			19
Total Benefit Costs (Credit), Including Effect of Regulatory Asset	$	(23	)	$	152		$	168		$	70		$	91		$	103

Pension costs and OPEB costs for PSEG, PSE&G and Power are detailed as follows:




	Pension Benefits Years Ended December 31,							Other Benefits Years Ended December 31,
	2014			2013		2012		2014		2013		2012
	Millions
PSE&G	$	(19	)	$	91	$	97	$	46	$	65	$	82
Power	(7		)	43		52		20		23		18
Other	3			18		19		4		3		3
Total Benefit Costs (Credit)	$	(23	)	$	152	$	168	$	70	$	91	$	103

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




	Pension						OPEB
	2014			2013			2014			2013
	Millions
Net Actuarial (Gain) Loss in Current Period	$	803		$	(1,009	)	$	208		$	(175	)
Amortization of Net Actuarial Gain (Loss)	(56		)	(188		)	(23		)	(42		)
Amortization of Prior Service Credit	18			19			14			14
Total	$	765		$	(1,178	)	$	199		$	(203	)

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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 2015 are as follows:




	Pension Benefits			Other Benefits
	2015			2015
	Millions
Actuarial (Gain) Loss	$	150		$	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
	2014		2013		2012		2014			2013			2012
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31
Discount Rate	4.20	%	5.00	%	4.20	%	4.21		%	5.01		%	4.20		%
Rate of Compensation Increase	3.61	%	4.61	%	4.61	%	3.61		%	4.61		%	4.61		%
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31
Discount Rate	5.00	%	4.20	%	5.00	%	5.01		%	4.20		%	5.00		%
Expected Return on Plan Assets	8.00	%	8.00	%	8.00	%	8.00		%	8.00		%	8.00		%
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		%	3.00		%	3.00		%
Dental Costs
Immediate Rate							5.25		%	5.50		%	6.00		%
Ultimate Rate							5.00		%	5.00		%	6.00		%
Year Ultimate Rate Reached							2016			2016			2013
Pre-65 Medical Costs
Immediate Rate							7.50		%	8.00		%	8.88		%
Ultimate Rate							5.00		%	5.00		%	5.00		%
Year Ultimate Rate Reached							2022			2021			2023
Post-65 Medical Costs
Immediate Rate							7.25		%	7.88		%	7.98		%
Ultimate Rate							5.00		%	5.00		%	5.00		%
Year Ultimate Rate Reached							2022			2021			2019
							Millions
Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs
Total of Service Cost and Interest Cost							$	13		$	12		$	12
Postretirement Benefit Obligation							$	201		$	161		$	180
Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs
Total of Service Cost and Interest Cost							$	(10	)	$	(9	)	$	(9	)
Postretirement Benefit Obligation							$	(165	)	$	(134	)	$	(149	)

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 16. 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 the 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, 2014, 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, 2014 and 2013, including the fair value measurements and the levels of inputs used in determining those fair values.




	Recurring Fair Value Measurements as of December 31, 2014
			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)	$	153	$	92	$	61	$	—
Common Stocks (B)
Commingled—United States	2,292		2,292		—		—
Commingled—International	1,005		1,005		—		—
Other	727		727		—		—
Bonds (C)
Government (United States & Foreign)	509		—		509		—
Other	943		—		943		—
Private Equity (D)	25		—		—		25
Total	$	5,654	$	4,116	$	1,513	$	25




	Recurring Fair Value Measurements as of December 31, 2013
			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)	$	93	$	52	$	41	$	—
Common Stocks (B)
Commingled—United States	2,264		2,264		—		—
Commingled—International	1,016		1,016		—		—
Other	704		704		—		—
Bonds (C)
Government (United States & Foreign)	596		—		596		—
Other	737		—		737		—
Private Equity (D)	25		—		—		25
Total	$	5,435	$	4,036	$	1,374	$	25


(A)	Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active market (Level 1). Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (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)

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, 2014 and 2013 are as follows:




	Balance as of January 1, 2014		Purchases/ (Sales)			Transfer In/ (Out)		Actual Return on Asset Sales		Actual Return on Assets Still Held		Balance as of December 31, 2014
	Millions
Private Equity	$	25	$	(5	)	$	—	$	3	$	2	$	25




	Balance as of January 1, 2013		Purchases/ (Sales)			Transfer In/ (Out)		Actual Return on Asset Sales		Actual Return on Assets Still Held			Balance as of December 31, 2013
	Millions
Private Equity	$	31	$	(11	)	$	—	$	11	$	(6	)	$	25

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	2014		2013
Equity Securities	71	%	73	%
Fixed Income Securities	26		25
Other Investments	3		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. PSEG's latest asset/liability study indicates 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 adjust the fixed income duration 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, 2014 and will remain unchanged for 2015. This expected return was determined based on the study discussed above, including a premium for active management and considered the plans’ historical annualized rate of return since inception, which was 9.5%.

Plan Contributions

PSEG may contribute up to $25 million into its pension plans and up to $14 million into its OPEB plan, respectively, during 2015.

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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
2015	$	282	$	79
2016	283		82
2017	294		84
2018	305		87
2019	318		90
2020-2024	1,770		495
Total	$	3,252	$	917

401(k) Plans

PSEG sponsors two 401(k) plans, which are Employee Retirement Income Security Act (ERISA) 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, PSE&G and Power are detailed as follows:




	Thrift Plan and Savings Plan
	Years Ended December 31,
	2014		2013		2012
	Millions
PSE&G	$	20	$	19	$	18
Power	11		$	10	10
Other	5		4		4
Total Employer Matching Contributions	$	36	$	33	$	32

Servco Pension and OPEB

At the direction of LIPA, effective January 1, 2014, Servco established benefit plans that provide substantially the same benefits to its employees as those previously provided by National Grid Electric Services LLC (NGES), the predecessor T&D system manager for LIPA. Since the vast majority of Servco's employees had worked under NGES' T&D operations services arrangement with LIPA, Servco's plans provide certain of those employees with pension and OPEB vested credit for prior years' services earned while working for NGES. The benefit plans cover all employees of Servco for current service. Under the OSA, all of these and any future employee benefit costs are to be funded by LIPA. See Note 3. Variable Interest Entities. These obligations, as well as the offsetting long-term receivable, are separately presented on the Consolidated Balance Sheet of PSEG.

The following table provides a roll-forward of the changes in Servco's benefit obligation and the fair value of its plan assets during the year ended December 31, 2014. 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 2014.

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	Pension Benefits			Other Benefits
	2014			2014
	Millions
Change in Benefit Obligation
Benefit Obligation at Beginning of Year	$	—		$	—
Service	20			13
Interest	7			17
Differences in Actuarial Assumptions versus Actual Experience	42			107
Plan Amendments	126			315
Benefit Obligation at End of Year (A)	$	195		$	452
Change in Plan Assets
Fair Value of Assets at Beginning of Year	$	—		$	—
Actual Return on Plan Assets	2			—
Employer Contributions	67			—
Fair Value of Assets at End of Year	$	69		$	—
Funded Status
Funded Status (Plan Assets less Benefit Obligation)	$	(126	)	$	(452	)
Additional Amounts Recognized in the Consolidated Balance Sheets
Accrued Pension Costs of Servco	$	(126	)	$	—
OPEB Costs of Servco	—			(452		)
Amounts Recognized (B)	$	(126	)	$	(452	)


(A)	Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits.


(B)	Amounts equal to the accrued pension and OPEB costs of Servco are offset in Long-Term Receivable of VIE on PSEG's Consolidated Balance Sheet.

Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. The pension-related revenues and costs for 2014 were $67 million. Servco has contributed its entire planned contribution amount to its pension plan trusts during 2014. The OPEB-related revenues earned or costs incurred in 2014 were immaterial.

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The following assumptions were used to determine the benefit obligations of Servco:




	Pension Benefits		Other Benefits
	December 31, 2014
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31, 2014
Discount Rate	4.50	%	4.60		%
Rate of Compensation Increase	3.25	%	3.25		%
Assumed Health Care Cost Trend Rates as of December 31, 2014
Administrative Expense			5.00		%
Dental Costs
Immediate Rate			8.00		%
Ultimate Rate			5.00		%
Year Ultimate Rate Reached			2018
Pre-65 Medical Costs
Immediate Rate			7.50		%
Ultimate Rate			5.00		%
Year Ultimate Rate Reached			2022
Post-65 Medical Costs
Immediate Rate			7.44		%
Ultimate Rate			5.00		%
Year Ultimate Rate Reached			2022
			Millions
Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs
Postretirement Benefit Obligation			$	160
Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs
Postretirement Benefit Obligation			$	(106	)

Plan Assets

All the investments of Servco's pension 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 are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 16. Fair Value Measurements for more information on fair value guidance. The Actuary 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 Actuary to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans.

The following table presents information about Servco's investments measured at fair value on a recurring basis as of December 31, 2014, including the fair value measurements and the levels of inputs used in determining those fair values.




	Recurring Fair Value Measurements as of December 31, 2014
			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)	$	1	$	—	$	1	$	—
Common Stocks (B)
Commingled—United States	48		48		—		—
Bonds (C)
Other	20		—		20		—
Total	$	69	$	48	$	21	$	—

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


(B)	Wherever possible, fair values of equity investments in commingled stock 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).

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 of Servco as of the measurement date, December 31:





Investments	As of December 31, 2014
Equity Securities	70	%
Fixed Income Securities	29
Other Investments	1
Total Percentage	100	%

Servco 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. The results from Servco's latest asset/liability study indicated that a long-term target asset allocation of 70% equities and 30% fixed income is consistent with the funds’ financial objectives. The expected long-term rate of return on plan assets was 7.70% as of December 31, 2014 and will remain unchanged for 2015. This expected return was determined based on the study discussed above, including a premium for active management and considered the plans’ 2014 rate of return, which was 6.3%.

Plan Contributions

Servco may contribute up to $30 million into its pension plan during 2015.

Estimated Future Benefit Payments

The following pension benefit and postretirement benefit payments are expected to be paid to Servco's plan participants:




Year	Pension Benefits		Other Benefits
	Millions
2015	$	—	$	2
2016	1		4
2017	2		6
2018	3		7
2019	4		9
2020-2024	49		74
Total	$	59	$	102

Servco 401(k) Plans

Servco sponsors two 401(k) plans, which are defined contribution retirement plans subject to the ERISA. Eligible non-represented employees of Servco participate in the Servco Incentive Thrift Plan I (Thrift Plan I), and eligible represented employees of Servco participate in the Servco Incentive Thrift Plan II. Eligible employees may contribute up to 50% of their compensation to these plans. For employees in Thrift Plan I, Servco matches 50% of such employee contributions up to 8% and provides core contributions (based on years of service and age) to employees who do not participate in Servco's pension plan.

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Note 12. Commitments and Contingent Liabilities

Guaranteed Obligations

Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees.

Power has unconditionally guaranteed payments to counterparties by its subsidiaries in commodity-related transactions in order to


•	support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and


•	obtain credit.

Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction.

In order for Power to incur a liability for the face value of the outstanding guarantees, its subsidiaries would have to


•	fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee, and


•	all of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties).

Power believes the probability of this result is unlikely. For this reason, Power believes that the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. This current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.

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.

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The face value of outstanding guarantees, current exposure and margin positions as of December 31, 2014 and 2013 are shown below:




	As of December 31, 2014			As of December 31, 2013
	Millions
Face Value of Outstanding Guarantees	$	1,814		$	1,639
Exposure under Current Guarantees	$	273		$	246

Letters of Credit Margin Posted	$	159		$	132
Letters of Credit Margin Received	$	40		$	25

Cash Deposited and Received
Counterparty Cash Margin Deposited	$	—		$	—
Counterparty Cash Margin Received	$	(13	)	$	—
Net Broker Balance Deposited (Received)	$	115		$	80

In the Event Power were to Lose its Investment Grade Rating
Additional Collateral that could be Required	$	945		$	691
Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral	$	3,495		$	3,522

Additional Amounts Posted
Other Letters of Credit	$	45		$	45

As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 15. 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 three level downgrade from its current S&P, Moody’s and Fitch ratings, many of these agreements allow the counterparty to demand further performance assurance. See table above.

The SEC and the Commodity Futures Trading Commission (CFTC) continue efforts to implement new rules to effect stricter regulation over swaps and derivatives, including imposing reporting and record-keeping requirements. In August 2013, PSEG began reporting its swap transactions to a CFTC-approved swap data repository. PSEG continues to monitor developments in this area, as the CFTC considers additional requirements such as a new position limits rule for physical commodity futures contracts and swaps that are economically equivalent to those contracts.

In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and Power had posted letters of credit to support Power's various other non-energy contractual and environmental obligations. See preceding table. PSEG had also issued a $106 million guarantee to support Power's payment obligations related to its equity interest in the PennEast natural gas pipeline. In the event that PSEG were to be downgraded to below investment grade and failed to meet minimum net worth requirements, this guarantee would have to be replaced by a letter of credit.

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 in violation of various statutes as discussed as follows.

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Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA)

In 2002, the U.S. Environmental Protection Agency (EPA) determined that a 17-mile stretch of the lower Passaic River from Newark to Clifton, New Jersey is a “Super Fund” site under CERCLA. This designation allows the EPA to clean up such sites and to compel responsible parties to perform cleanups or reimburse the government for cleanups led by the EPA.

The EPA further determined that there was a need to perform a comprehensive study of the entire 17-miles of the lower Passaic River. PSE&G and certain of its predecessors conducted operations at properties in this area of 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.

In early 2007, 73 Potentially Responsible Parties (PRPs), including PSE&G and Power, formed a Cooperating Parties Group (CPG) and agreed to assume responsibility for conducting a Remedial Investigation and Feasibility Study (RI/FS) of the 17 miles of the lower Passaic River. At such time, the CPG also agreed to allocate the associated costs of the RI/FS among its members on the basis of a mutually agreed upon formula. For the purpose of this allocation, approximately seven percent of the RI/FS costs were deemed attributable to PSE&G’s former MGP sites and approximately one percent was attributed to Power’s generating stations. These allocations are not binding on PSE&G or Power in terms of their respective shares of the costs that will be ultimately required to remediate the 17 miles of the lower Passaic River. Power has provided notice to insurers concerning this potential claim.

The CPG, which consisted of 61 members as of December 31, 2014, continues to conduct the RI/FS which is expected to be completed during the first quarter of 2015 at an estimated cost of approximately $136 million. Of the estimated $136 million, as of December 31, 2014, the CPG Group had spent approximately $130 million, of which PSEG's total share had been approximately $9 million.

In June 2008, the EPA, Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus) entered into an early action agreement whereby Tierra and Maxus agreed to remove a portion of the heavily dioxin-contaminated sediment located in the lower Passaic River. The portion of the Passaic River identified in this agreement was located immediately adjacent to Tierra/Maxus’ predecessor company’s (Diamond Shamrock) facility. Pursuant to the agreement among the EPA, Tierra and Maxus, the estimated cost for the work to remove the sediment in this location was $80 million. Phase I of the removal work has been completed. Pursuant to this agreement, Tierra/Maxus have reserved their rights to seek contribution for these removal costs from the other PRPs, including PSE&G and Power. This agreement and the work undertaken pursuant to the early action agreement has no impact on the ultimate remedy that the EPA will select for the remediation of the 17-mile stretch of the lower Passaic River.

In 2012, Tierra and Maxus withdrew from the CPG and refused to participate as members going forward, other than in respect of their obligation to fund the EPA’s portion of its RI/FS oversight costs. At such time, the remaining members of the CPG, in agreement with the EPA, commenced the removal of certain contaminated sediments at Passaic River Mile 10.9 at an estimated cost of $25 million to $30 million. PSEG’s share of the cost of that effort is approximately three percent. The remaining CPG members have reserved their rights to seek reimbursement from Tierra/Maxus for the costs of the River Mile 10.9 removal.

On April 11, 2014, the EPA released its revised “Focused Feasibility Study” (FFS) which contemplates the removal of 4.3 million cubic yards of sediment from the bottom of the lower eight miles of the 17-mile stretch of the Passaic River that had originally been designated as a Super Fund site. The FFS sets forth various alternatives for remediating this portion of the Passaic River. The EPA’s estimated costs to remediate the lower eight miles of the Passaic River range from $365 million for a targeted remedy to $3.25 billion for a deep dredge of this portion of the Passaic River. The EPA also identified in the FFS its preferred alternative, which would involve dredging the river bank to bank and installing an engineered cap. The estimated cost in the FFS for its preferred alternative is $1.7 billion. No provisional cost allocation has been made by the CPG for the work contemplated by the draft FFS, and the work contemplated by the FFS is not subject to the CPG’s cost sharing allocation agreed to in connection with the removal work for River Mile 10.9 or in connection with the conduct of the RI/FS.

The draft FFS was subject to a public comment period, and remains subject to the EPA’s response to comments submitted, a design phase and at least an estimated five years for completion of the work. The public comment period on the draft FFS closed on August 21, 2014. Over 300 comments were submitted by a variety of entities potentially impacted by the FFS, including the CPG, individual companies, municipalities, public officials, citizens groups, Amtrak, NJ Transit and others. The EPA will consider the comments received prior to issuing a Record of Decision (ROD) of a selected remedy for the lower eight miles. The EPA has broad authority to implement its selected remedy through the ROD and PSEG cannot at this time predict how the implementation of the ROD might impact PSE&G's and Power's ultimate liability.

Based on the facts and circumstance known at this time, and calculated in reference to the EPA estimate set forth in the FFS for its preferred remedy, PSE&G and Power believe that their respective shares of the costs to clean up the Passaic River will be immaterial. However, until (i) the RI/FS is completed, (ii) a final remedy is determined by the EPA or through litigation, (iii) PSE&G's and Power’s respective share of the costs, both in the aggregate as well as individually, are determined, and (iv)

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PSE&G’s continued ability to recover the costs in its rates is determined, it is not possible to predict this matter’s ultimate impact on our financial statements.

Natural Resource Damage Claims

In 2003, the New Jersey Department of Environmental Protection (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 New Jersey Spill Compensation and Control 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 (the Passaic River federal trustees) 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. 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 PSEG has not consented to fund the third phase. PSE&G and Power 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 $434 million and $505 million through 2021. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $434 million as of December 31, 2014. Of this amount, $79 million was recorded in Other Current Liabilities and $355 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $434 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.

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 the 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 (D.C. Court), the EPA published a Maximum Achievable Control Technology (MACT) regulation in February 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 D.C. Court in support of the EPA's implementation of MATS. In April 2014, the D.C. Court denied all petitions for review of the existing source NESHAP.

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Several parties, including 21 states, have filed petitions for review with the U.S. Supreme Court. On November 25, 2014, the U.S. Supreme Court issued an order granting review solely of the issue as to whether the EPA was unreasonable in its refusal to consider the materiality of costs in determining whether it is appropriate to regulate the emission of hazardous air pollutants by electric utilities.

Power believes that it will not be necessary to install any material new controls at its New Jersey facilities. Dry sorbent injection to control acid gases was installed at Power’s Bridgeport Harbor coal-fired unit in the fourth quarter of 2014 at an immaterial cost. This system is currently undergoing operational verification testing. In December 2011, to comply with the MACT regulations, the co-owners group, including Power, agreed 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 was completed in November 2014. Power's share of this investment is approximately $110 million.

Clean Water Act Permit Renewals

Pursuant to the Federal Water Pollution Control Act (FWPCA), National Pollutant Discharge Elimination System 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 NJDEP 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 more 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.

In October 2013, the Delaware Riverkeeper Network and several other environmental groups filed a lawsuit in the Superior Court of New Jersey seeking to force the NJDEP to take action on Power's pending application for permit renewal at Salem either by denying the application or issuing a draft for public comment. An application for renewal of the permit was submitted in January 2006 and the NJDEP had delayed action pending the EPA’s finalization of the Clean Water Act 316 (b) regulations. In November 2014, the environmental groups announced settlement of the lawsuit filed with the NJDEP and that the NJDEP had committed to issue a draft permit by June 30, 2015.

On May 19, 2014, the EPA issued a final rule that establishes new requirements for the regulation of cooling water intake structures at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. On August 15, 2014, the EPA established October 14, 2014 as the effective date for each state to implement the provisions of the rule going forward when considering the renewal of permits for existing facilities on a case by case basis. On September 5, 2014, several environmental non-governmental groups and certain energy industry groups filed motions to litigate the provisions of the rule. This case is pending at the U.S. Second Circuit Court of Appeals. In two related actions on October 17, 2014 and November 20, 2014, several environmental non-governmental groups initiated challenges to the endangered species act provisions of the 316 (b) rule. Power is unable to determine the ultimate impact of these actions on the implementation of the rule.

State permitting decisions 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. The filing has not been updated. Action on the issuance of a draft permit for Salem is anticipated by June 30, 2015. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures.

Power is unable to predict the outcome of these permitting decisions and the effect, if any, that they may have on Power's future capital requirements, financial condition or results of operations.

Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS)

PSE&G obtains its electric supply requirements through the annual New Jersey BGS auctions for two categories of customers who choose not to purchase electric supply from third party suppliers. The first category, which represents about 80% of PSE&G's load requirement, are residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category are larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial Pricing (CIEP)). Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master

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Agreement with the winners of these BGS auctions following the BPU’s approval of the auction results. PSE&G has entered into contracts with winning BGS suppliers, including Power, 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.

The BGS-CIEP auction is for a one-year supply period from June 1 to May 31 with the BGS-CIEP auction price measured in dollars per MW-day for capacity. The final price for the BGS-CIEP auction year commencing June 1, 2015 is $272.78 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2015 of $282.04 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period.

PSE&G contracts for its anticipated BGS-RSCP load on a three-year rolling basis, whereby each year one-third of the load is procured for a three-year period. The contract prices in dollars per MWh for the BGS-RSCP supply, as well as the approximate load, are as follows:




	Auction Year
	2012	2013	2014	2015
36-Month Terms Ending	May 2015	May 2016	May 2017	May 2018	(A)
Load (MW)	2,900	2,800	2,800	2,900
$ per MWh	$83.88	$92.18	$97.39	$99.54


(A)	Prices set in the 2015 BGS auction will become effective on June 1, 2015 when the 2012 BGS auction agreements expire.

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 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’s nuclear fuel 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 2017 and a significant portion through 2019 at Salem, Hope Creek and Peach Bottom.

Power has various long-term fuel purchase commitments for coal through 2017 to support its fossil generation stations and for firm transportation and storage capacity for natural gas.

Power’s various multi-year contracts for natural gas and 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.

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As of December 31, 2014, the total minimum purchase requirements included in these commitments were as follows:




Fuel Type	Power's Share of Commitments through 2019
	Millions
Nuclear Fuel
Uranium	$	439
Enrichment	$	431
Fabrication	$	208
Natural Gas	$	1,186
Coal	$	306

Regulatory Proceedings

FERC Compliance

In the first quarter of 2014, Power discovered that it incorrectly calculated certain components of its cost-based bids for its New Jersey fossil generating units in the PJM energy market. PSEG notified the FERC, PJM and the PJM Independent Market Monitor (IMM) of this issue. During the three months ended March 31, 2014, Power recorded a charge to income in the amount of $25 million related to these findings for these past errors based upon its best estimate available at the time. PSEG cannot provide any assurances that the total liability associated with this matter will not increase or decrease over the amount recorded.

Upon discovery of the errors, PSEG retained outside counsel to assist in the conduct of an investigation into the matter. As the investigation proceeded, additional pricing errors in the bids were identified and it was further determined that the quantity of energy that Power offered into the energy market for its fossil peaking units differed from the amount for which Power was compensated in the capacity market for those units. PSEG informed the FERC, PJM and the IMM of these additional issues, and has corrected these errors. Power has an ongoing process of implementing improved procedures to help mitigate the risk of similar issues occurring in the future.

On September 2, 2014, the FERC Staff initiated a preliminary, non-public staff investigation into the matter, which is ongoing. This investigation could result in the FERC seeking disgorgement of any over-collected amounts, civil penalties and non-financial remedies. It is not possible at this time to reasonably estimate the ultimate impact or predict any resulting penalties, other costs associated with this matter, or the applicability of mitigating factors. It is possible that Power will incur additional losses, and that such losses may be material, but PSEG cannot at the current time estimate the amount or range of any additional losses.

New Jersey Clean Energy Program

In June 2014, the BPU established the funding level for fiscal 2015 applicable to its Renewable Energy and Energy Efficiency programs. The fiscal year 2015 aggregate funding for all EDCs is $345 million with PSE&G’s share of the funding at $200 million. PSE&G has a remaining current liability of $142 million as of December 31, 2014 for its outstanding share of the fiscal 2015 and remaining fiscal 2014 funding. 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.

Superstorm Sandy

In late October 2012, Superstorm Sandy caused severe damage to PSE&G's T&D system throughout its service territory as well as to some of Power's generation infrastructure in the northern part of New Jersey. Strong winds and the resulting storm surge caused damage to switching stations, substations and generating infrastructure.

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 O&M 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. There were no significant changes to these amounts since 2012. PSE&G made a filing with the BPU to review the prudency of unreimbursed incremental storm restoration costs, including O&M and capital expenditures associated with Superstorm Sandy and certain other extreme weather events, for

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recovery in our next base rate case or sooner through a BPU-approved cost recovery mechanism. In September 2014, the BPU approved our filing. See Note 5. Regulatory Assets and Liabilities for additional information.

Power had incurred $79 million and $85 million of storm-related expense in 2013 and 2012, respectively, primarily for repairs at certain generating stations in Power's fossil fleet. These costs were recognized in O&M Expense, offset by $25 million and $19 million of insurance recoveries in 2013 and 2012, respectively. Power incurred an additional $27 million of O&M costs in 2014 primarily for repairs at certain generating stations in Power's fossil fleet.

PSEG maintains insurance coverage against loss or damage to plants and certain properties, subject to certain exceptions and limitations, to the extent such property is usually insured and insurance is available at a reasonable cost. As previously reported, PSEG continues to seek recovery from its insurers for the property damage resulting from Superstorm Sandy, above its self-insured retentions; however, no assurances can be given relative to the timing or amount of such recovery. In June 2013, PSEG, PSE&G and Power filed suit in New Jersey state court against its insurance carriers seeking an interpretation that the insurance policies cover their losses resulting from damage caused by Superstorm Sandy's storm surge. In August 2013, the insurance carriers filed an answer in which they denied most of the allegations made in the Complaint. In December 2014, PSEG notified the insurance carriers of an estimate of $564 million for total costs related to damaged facilities, of which $88 million and $476 million related to PSE&G and Power, respectively. Discovery in the case has been completed. On October 7, 2014, both parties filed cross-motions for summary judgment and those motions are scheduled to be argued on March 20, 2015. We cannot predict the outcome of this proceeding.

Nuclear Insurance Coverages and Assessments

Power is a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides the property, decontamination and decommissioning liability insurance at the Salem/Hope Creek and Peach Bottom sites. NEIL also provides 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 all include coverage for claims arising out of acts of terrorism, however, NEIL policies are subject to an industry aggregate limit of $3.2 billion plus such additional amounts as NEIL recovers for such losses from reinsurance, indemnity and any other source applicable to such losses.

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 $13.6 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 licensee can be assessed $127 million per reactor per incident, payable at not more than $19 million per reactor per incident per year. If the damages exceed the “limit of liability,” the Congress could impose further revenue-raising measures on the nuclear industry to pay claims. Power’s maximum aggregate assessment per incident is $401 million (based on Power’s ownership interests in Hope Creek, Peach Bottom and Salem) and its maximum aggregate annual assessment per incident is $60 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.

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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	13,241		(B)	401
Nuclear Liability Total	$	13,616	(C)	$	401
Property Damage (Primary Layer):
NEIL Primary (Salem/Hope Creek and Peach Bottom)	$	1,500		$	38
Property Damage (Excess Layers)
NEIL Excess (Salem/Hope Creek and Peach Bottom)	600		(D)	5
Property Damage Total (Per Site)	$	2,100		$	43
Accidental Outage:
NEIL I (Peach Bottom)	$	245	(E)	$	7
NEIL I (Salem)	281		(E)	7
NEIL I (Hope Creek)	490		(E)	6
Replacement Power Total	$	1,016		$	20


(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 third party workers claiming exposure to the nuclear energy hazard. 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 September 10, 2013. The next adjustment is due on or before September 10, 2018. 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 nuclear event property limits in excess of $1.5 billion, Power participates in a $600 million nuclear event Blanket Limit Policy. The blanket limit policy is shared with Exelon Generation and covers the following facilities: Braidwood, Byron, Clinton, Dresden, La Salle, Limerick, Oyster Creek, Quad Cities, TMI-1 Peach Bottom, Salem and Hope Creek. This limit is not subject to reinstatement in the event of a loss. Participation in this program reduces Power’s premium and the associated potential assessment. In addition, for non-nuclear event limits in excess of $1.5 billion, Power maintains a $600 million limit shared by the Salem and Hope Creek facilities. Exelon maintains a $600 million non-nuclear event limit shared by Peach Bottom, Braidwood, Byron, Clinton, Dresden, LaSalle, Limerick, Oyster Creek, Quad Cities, and the TMI-1 facilities.

(E)

Peach Bottom 2 and 3 have 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 1 and 2 have an aggregate indemnity limit based on a weekly indemnity of $2.5 million for 52 weeks followed by 80% of the weekly indemnity for 76 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.

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Minimum Lease Payments

The total future minimum payments under various operating leases as of December 31, 2014 are:




	PSE&G		Power		Services		Other
	Millions
2015	$	12	$	2	$	5	$	2
2016	9		2		12		1
2017	7		1		13		1
2018	6		2		13		—
2019	6		2		13		—
Thereafter	55		23		159		—
Total Minimum Lease Payments	$	95	$	32	$	215	$	4

Note 13. Schedule of Consolidated Debt

Long-Term Debt




	As of December 31,
	2014			2013
	Millions
PSEG (Parent)
Fair Value of Swaps (A)	$	22		$	38
Amounts Due Within One Year	(8		)	—
Unamortized Discount Related to Debt Exchange (B)	(8		)	(14		)
Total Long-Term Debt of PSEG (Parent)	$	6		$	24

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		As of December 31,
	Maturity	2014			2013
		Millions
PSE&G
First and Refunding Mortgage Bonds (C):
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 (C):
Floating rate (D)	2033	50			50
Floating rate (D)	2046	50			50
Total Pollution Control Bonds		100			100
Medium-Term Notes (MTNs) (C):
0.85%	2014	—			250
5.00%	2014	—			250
2.70%	2015	300			300
5.30%	2018	400			400
2.30%	2018	350			350
1.80%	2019	250			—
2.00%	2019	250			—
7.04%	2020	9			9
3.50%	2020	250			250
2.38%	2023	500			500
3.75%	2024	250			250
3.15%	2024	250			—
3.05%	2024	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			450
3.65%	2042	350			350
3.80%	2043	400			400
4.00%	2044	250			—
Total MTNs		5,909			5,159
Principal Amount Outstanding		6,329			5,579
Amounts Due Within One Year		(300		)	(500		)
Net Unamortized Discount		(17		)	(13		)
Total Long-Term Debt of PSE&G (excluding Transition Funding and Transition Funding II)		$	6,012		$	5,066

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		As of December 31,
	Maturity	2014			2013
		Millions
Transition Funding (PSE&G)
Securitization Bonds:
6.75%	2014	$	—		$	106
6.89%	2014-2015	251			370
Principal Amount Outstanding		251			476
Amounts Due Within One Year		(251		)	(225		)
Total Securitization Debt of Transition Funding		—			251
Transition Funding II (PSE&G)
Securitization Bonds:
4.57%	2014-2015	8			20
Principal Amount Outstanding		8			20
Amounts Due Within One Year		(8		)	(12		)
Total Securitization Debt of Transition Funding II		—			8
Total Long-Term Debt of PSE&G		$	6,012		$	5,325




		As of December 31,
	Maturity	2014			2013
		Millions
Power
Senior Notes:
5.50%	2015	$	300		$	300
5.32%	2016	303			303
2.75%	2016	250			250
2.45%	2018	250			250
5.13%	2020	406			406
4.15%	2021	250			250
4.30%	2023	250			250
8.63%	2031	500			500
Total Senior Notes		2,509			2,509
Pollution Control Notes:
Floating Rate (D)	2019	44			44
Total Pollution Control Notes		44			44
Principal Amount Outstanding		2,553			2,553
Amounts Due Within One Year		(300		)	(44		)
Net Unamortized Discount		(10		)	(12		)
Total Long-Term Debt of Power		$	2,243		$	2,497

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		As of December 31,
	Maturity	2014			2013
		Millions
Energy Holdings
Non-Recourse Project Debt (E):
Resources - 5.00% to 5.275%	2014-2015	$	16		$	16
Principal Amount Outstanding		16			16
Amounts Due Within One Year		(16		)	—
Total Non-Recourse Project Debt		—			16
Total Long-Term Debt of Energy Holdings		$	—		$	16


(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 Sheets. For additional information, see Note 15. 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 Sheets.


(C)	Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage.

(D)

The Pollution Control Financing Authority of Salem County bonds and the Pennsylvania Economic Development Authority (PEDFA) bond that are serviced and secured by PSE&G Pollution Control Bonds and Power Pollution Control Notes, respectively, are variable rate bonds that are in weekly reset mode. In October 2014, Power executed an extension of the letter of credit backing PEDFA bond. The existing letter of credit, which was scheduled to expire on November 30, 2014, has been extended through November 30, 2019.


(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.

Long-Term Debt Maturities

The aggregate principal amounts of maturities for each of the five years following December 31, 2014 are as follows:




	PSE&G								Energy Holdings
Year	PSE&G		Transition Funding		Transition Funding II		Power		Non-Recourse Debt		Total
	Millions
2015	$	300	$	251	$	8	$	300	$	16	$	875
2016	171		—		—		553		—		724
2017	—		—		—		—		—		—
2018	750		—		—		250		—		1,000
2019	500		—		—		44		—		544
Thereafter	4,608		—		—		1,406		—		6,014
Total	$	6,329	$	251	$	8	$	2,553	$	16	$	9,157

Long-Term Debt Financing Transactions

During 2014, PSEG and its subsidiaries had the following Long-Term Debt issuances, maturities and redemptions:

PSE&G


•	issued $250 million of 1.80% Secured Medium-Term Notes, Series I due June 2019,

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•	issued $250 million of 4.00% Secured Medium-Term Notes, Series I due June 2044,


•	issued $250 million of 2.00% Secured Medium-Term Notes, Series J due August 2019,


•	issued $250 million of 3.15% Secured Medium-Term Notes, Series J due August 2024,


•	issued $250 million of 3.05% Secured Medium-Term Notes, Series J due November 2024,


•	paid $250 million of 0.85% Secured Medium-Term Notes at maturity,


•	paid $250 million of 5.00% Secured Medium-Term Notes at maturity,


•	paid $225 million of Transition Funding's securitization debt,


•	paid $12 million of Transition Funding II's securitization debt, and


•	received $175 million capital contribution from PSEG.

Power


•	paid cash dividends of $895 million to PSEG.

Short-Term Liquidity

PSEG meets its short-term liquidity requirements, as well as those of Power, primarily with cash and through the issuance of commercial paper. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facilities.

The commitments under our $4.3 billion credit facilities are provided by a diverse bank group. As of December 31, 2014, our total available credit capacity was $4.1 billion.

As of December 31, 2014, no single institution represented more than 8% of the total commitments in our credit facilities.

As of December 31, 2014, 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 in the following table; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. In April 2014, PSEG and Power amended their 2012 credit agreements ending in 2017, extending the expiration date from March 2017 to April 2019. PSEG's $500 million and Power's $1.6 billion facility amendments, resulting in total commitments of $2.1 billion, will mature in 2019.

Our total credit facilities and available liquidity as of December 31, 2014 were as follows:




	As of December 31, 2014
Company/Facility	Total Facility		Usage		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facility	$	500	$	8	$	492	Apr 2019	Commercial Paper (CP) Support/Funding/Letters of Credit
5-year Credit Facility (A)	500		—		500		Mar 2018	CP Support/Funding/Letters of Credit
Total PSEG	$	1,000	$	8	$	992
PSE&G
5-year Credit Facility (B)	$	600	$	14	$	586	Mar 2018	CP Support/Funding/Letters of Credit
Total PSE&G	$	600	$	14	$	586
Power
5-year Credit Facility	$	1,600	$	97	$	1,503	Apr 2019	Funding/Letters of Credit
5-year Credit Facility (C)	1,000		—		1,000		Mar 2018	Funding/Letters of Credit
Bilateral Credit Facility	100		100		—		Sept 2015	Letters of Credit
Total Power	$	2,700	$	197	$	2,503
Total	$	4,300	$	219	$	4,081


(A)	In April 2016, this facility will be reduced by $23 million.

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(B)	In April 2016, this facility will be reduced by $29 million.


(C)	In April 2016, this facility will be reduced by $48 million.

Fair Value of Debt

The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions as of December 31, 2014 and 2013. See Note 16. Fair Value Measurements for more information on fair value guidance and the hierarchy that prioritizes the inputs to fair value measurements into three levels.




	December 31, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A)	$	14	$	22	$	24	$	38
PSE&G (B)	6,312		6,912		5,566		5,629
Transition Funding (PSE&G) (B)	251		261		476		511
Transition Funding II (PSE&G) (B)	8		8		20		21
Power - Recourse Debt (B)	2,543		2,930		2,541		2,846
Energy Holdings:
Project Level, Non-Recourse Debt (C)	16		16		16		16
	$	9,144	$	10,149	$	8,643	$	9,061


(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)	Non-recourse project debt is valued as equivalent to the amortized cost and is classified as a Level 3 measurement.

Note 14. Schedule of Consolidated Capital Stock




	As of December 31,
	Outstanding Shares		Book Value
	2014	2013	2014		2013
			Millions
PSEG Common Stock (no par value) (A)
Authorized 1,000,000,000 shares	505,836,592	505,857,262	$	4,241	$	4,246


(A)	PSEG did not issue any new shares under the Dividend Reinvestment and Stock Purchase Plan (DRASPP) or the Employee Stock Purchase Plan (ESPP) in 2014 or 2013. Total authorized and unissued shares of common stock available for issuance through PSEG’s DRASPP, ESPP and various employee benefit plans amounted to approximately 7 million shares as of December 31, 2014.

As of December 31, 2014, PSE&G had 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 15. 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.

Derivative accounting guidance requires that a derivative instrument be recognized as either an asset or a liability at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation provided that the derivative instrument meets specific, restrictive criteria, both at the time of designation and on an ongoing basis. These alternative permissible treatments include normal purchase normal sale (NPNS), cash flow hedge and fair value hedge accounting. PSEG, Power and PSE&G have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements and fuel agreements. Transactions receiving NPNS treatment are accounted for upon settlement. For a derivative instrument that qualifies and is designated as a cash flow hedge, the changes in the fair value of such a derivative that are highly effective are recorded in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. For a derivative instrument that qualifies and is designated as a fair value hedge, the gains or losses on the derivative as well as the offsetting losses or gains on the hedged item attributable to the hedged risk are recognized in earnings each period. Power and PSE&G enter into additional contracts that are derivatives, but do not qualify for or are not designated as either cash flow hedges or fair value hedges. These transactions are economic hedges and changes in the fair value of these contracts are recorded in earnings each period.

Commodity Prices

Within PSEG and its affiliate companies, Power has the most exposure to commodity price risk. Power is exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. Power uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including physical and financial transactions in the wholesale energy markets to mitigate the effects of adverse movements in fuel and electricity prices. 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

PSEG and Power use forward sale and purchase contracts, swaps and futures contracts to hedge certain forecasted natural gas sales and purchases made to support the BGSS contract with PSE&G.

These derivative transactions qualify and are designated as cash flow hedges. During the second quarter of 2012, Power de-designated commodity derivative transactions related to the hedging of forecasted energy sales from its generation stations 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, 2014 and 2013, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with accounting hedge activity was as follows:




	As of December 31,
	2014		2013
	Millions
Fair Value of Cash Flow Hedges	$	18	$	(4	)
Impact on Accumulated Other Comprehensive Income (Loss) (after tax)	$	10	$	(1	)

The expiration date of the longest-dated cash flow hedge at Power is in December 2015. Power’s after-tax unrealized gains on these derivatives that are expected to be reclassified to earnings during the next 12 months are $10 million. There was no ineffectiveness associated with qualifying hedges as of December 31, 2014.

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Economic Hedges

PSEG and Power enter into derivative contracts that do not qualify or are not designated as either cash flow or fair value hedges. Power enters into financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity. These transactions are economic hedges, intended to mitigate exposure to fluctuations in commodity prices and optimize the value of Power's expected generation. PSE&G is a party to certain long-term natural gas sales contracts to optimize its pipeline capacity utilization. Changes in the fair market value of these contracts are recorded in earnings.

Interest Rates

PSEG, Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, they have used a mix of fixed and floating rate debt and interest rate swaps.

Fair Value Hedges

PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. As of December 31, 2014, PSEG had 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, 2014 and 2013, the fair value of all the underlying hedges was $22 million and $38 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 immaterial as of December 31, 2014 and 2013.

Fair Values of Derivative Instruments

The following are the fair values of derivative instruments on the Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with our accounting policy, these positions have been offset on the Consolidated Balance Sheets of Power, PSE&G and PSEG. The following tabular disclosure does not include the offsetting of trade receivables and payables.

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	As of December 31, 2014
	Power (A)											PSE&G (A)		PSEG (A)		Consolidated
	Cash Flow Hedges		Not Designated									Not Designated		Fair Value Hedges
Balance Sheet Location	Energy- Related Contracts		Energy- Related Contracts			Netting (B)			Total Power			Energy- Related Contracts		Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	18	$	597		$	(408	)	$	207		$	18	$	15	$	240
Noncurrent Assets	—		171			(109		)	62			8		7		77
Total Mark-to-Market Derivative Assets	$	18	$	768		$	(517	)	$	269		$	26	$	22	$	317
Derivative Contracts
Current Liabilities	$	—	$	(568	)	$	436		$	(132	)	$	—	$	—	$	(132	)
Noncurrent Liabilities	—		(138		)	105			(33		)	—		—		(33		)
Total Mark-to-Market Derivative (Liabilities)	$	—	$	(706	)	$	541		$	(165	)	$	—	$	—	$	(165	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	18	$	62		$	24		$	104		$	26	$	22	$	152




	As of December 31, 2013
	Power (A)												PSE&G (A)		PSEG (A)		Consolidated
	Cash Flow Hedges			Not Designated									Not Designated		Fair Value Hedges
Balance Sheet Location	Energy- Related Contracts			Energy- Related Contracts			Netting (B)			Total Power			Energy- Related Contracts		Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	—		$	323		$	(266	)	$	57		$	25	$	16	$	98
Noncurrent Assets	—			155			(83		)	72			69		22		163
Total Mark-to-Market Derivative Assets	$	—		$	478		$	(349	)	$	129		$	94	$	38	$	261
Derivative Contracts
Current Liabilities	$	(4	)	$	(343	)	$	271		$	(76	)	$	—	$	—	$	(76	)
Noncurrent Liabilities	—			(111		)	80			(31		)	—		—		(31		)
Total Mark-to-Market Derivative (Liabilities)	$	(4	)	$	(454	)	$	351		$	(107	)	$	—	$	—	$	(107	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	(4	)	$	24		$	2		$	22		$	94	$	38	$	154


(A)	Substantially all of Power's and PSEG's derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of December 31, 2014 and 2013. PSE&G does not have any derivative contracts subject to master netting or similar agreements.

(B)

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contract positions. Of the $24 million as of December 31, 2014, $(4) million and $(8) million were netted against current assets and noncurrent assets, respectively, and $32 million and $4 million were netted against current liabilities and noncurrent liabilities, respectively. Of the $2 million as of December 31, 2013, cash collateral of $(3) million and $5 million were netted against noncurrent assets and current 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 to a below investment grade 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 $127 million and $91 million as of December 31, 2014 and 2013, respectively. As of December 31, 2014 and 2013, Power had the contractual right of offset of $18 million and $39 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 to a below investment grade rating, it would have had additional collateral obligations of $109 million and $52 million as of December 31, 2014 and 2013, 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 $945 million and $691 million as of December 31, 2014 and 2013, respectively, discussed in Note 12. 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, 2014, 2013 and 2012:




	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,
	2014		2013			2012				2014			2013			2012			2014		2013			2012
	Millions									Millions
PSEG
Energy-Related Contracts	$	12	$	(4	)	$	32		Operating Revenues	$	(9	)	$	13		$	79		$	—	$	(1	)	$	1
Energy-Related Contracts	—		—			(4		)	Energy Costs	—			—			(9		)	—		—			—
Interest Rate Swaps (A)	—		—			—			Interest Expense	—			(1		)	—			—		—			—
Total PSEG	$	12	$	(4	)	$	28			$	(9	)	$	12		$	70		$	—	$	(1	)	$	1
Power
Energy-Related Contracts	$	12	$	(4	)	$	32		Operating Revenues	$	(9	)	$	13		$	79		$	—	$	(1	)	$	1
Energy-Related Contracts	—		—			(4		)	Energy Costs	—			—			(9		)	—		—			—
Total Power	$	12	$	(4	)	$	28			$	(9	)	$	13		$	70		$	—	$	(1	)	$	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:




Accumulated Other Comprehensive Income	Pre-Tax			After-Tax
	Millions
Balance as of December 31, 2012	$	12		$	7
Loss Recognized in AOCI	(4		)	(2		)
Less: Gain Reclassified into Income	(12		)	(7		)
Balance as of December 31, 2013	$	(4	)	$	(2	)
Gain Recognized in AOCI	12			7
Plus: Loss Reclassified into Income	9			5
Balance as of December 31, 2014	$	17		$	10

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, 2014, 2013 and 2012:




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,
		2014			2013			2012
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	(348	)	$	(128	)	$	232
Energy-Related Contracts	Energy Costs	32			106			(19		)
Total PSEG and Power		$	(316	)	$	(22	)	$	213

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. 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 $20 million, $19 million and $22 million for the years ended December 31, 2014, 2013 and 2012, respectively.

The following reflects the gross volume, on an absolute value basis, of derivatives as of December 31, 2014 and 2013:




Type	Notional	Total	PSEG	Power	PSE&G
	Millions
As of December 31, 2014
Natural Gas	Dth	274	—	216	58
Electricity	MWh	310	—	310	—
Financial Transmission Rights (FTRs)	MWh	15	—	15	—
Interest Rate Swaps	U.S. Dollars	850	850	—	—
As of December 31, 2013
Natural Gas	Dth	614	—	466	148
Electricity	MWh	243	—	243	—
FTRs	MWh	16	—	16	—
Interest Rate Swaps	U.S. Dollars	850	850	—	—

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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, 2014, 99.7% 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, 2014. 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	$	436	$	51	$	425	2	$	259	(A)
Non-Investment Grade—External Rating	2		—		1		—	—
Investment Grade—No External Rating	6		—		6		—	—
Non-Investment Grade—No External Rating	—		—		—		—	—
Total	$	444	$	51	$	432	2	$	259


(A)	Includes net exposure of $206 million with PSE&G. The remaining net exposure of $53 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. 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, 2014, Power had 148 active counterparties.

PSE&G’s supplier master agreements are approved by the BPU and govern the terms of its electric supply procurement contracts. These agreements define a supplier’s performance assurance requirements and allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s credit ratings from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day the procurement transaction is executed, compared to the forward price curve for energy on the valuation day. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post a parental guaranty or other security instrument such as a letter of credit or cash, as collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of December 31, 2014, primarily all of the posted collateral was in the form of parental guarantees. The unsecured credit used by the suppliers represents PSE&G’s net credit exposure. PSE&G's suppliers’ credit exposure is calculated each business day. As of December 31, 2014, PSE&G had no net credit exposure with suppliers, including Power.

PSE&G is permitted to recover its costs of procuring energy through the BPU-approved BGS tariffs. PSE&G’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates.

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Note 16. 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, 2014, these consisted primarily of electric load contracts whose basis is deemed significant to the fair value measurement and long-term gas supply contracts.

The following tables present information about PSEG’s, PSE&G’s and Power's respective assets and (liabilities) measured at fair value on a recurring basis as of December 31, 2014 and December 31, 2013, 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, 2014
Description	Total			Netting (E)			Quoted Market Prices for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	365		$	—		$	365	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	295		$	(517	)	$	—	$	774		$	38
Interest Rate Swaps (C)	$	22		$	—		$	—	$	22		$	—
NDT Fund (D)
Equity Securities	$	897		$	—		$	896	$	1		$	—
Debt Securities—Govt Obligations	$	438		$	—		$	—	$	438		$	—
Debt Securities—Other	$	339		$	—		$	—	$	339		$	—
Other Securities	$	106		$	—		$	106	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	23		$	—		$	23	$	—		$	—
Debt Securities—Govt Obligations	$	91		$	—		$	—	$	91		$	—
Debt Securities—Other	$	75		$	—		$	—	$	75		$	—
Other Securities	$	2		$	—		$	—	$	2		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(165	)	$	541		$	—	$	(705	)	$	(1	)
PSE&G
Assets:
Cash Equivalents (A)	$	294		$	—		$	294	$	—		$	—
Derivative Contracts:
Energy Related Contracts (B)	$	26		$	—		$	—	$	—		$	26
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	20		$	—		$	—	$	20		$	—
Debt Securities—Other	$	16		$	—		$	—	$	16		$	—
Other Securities	$	—		$	—		$	—	$	—		$	—
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	269		$	(517	)	$	—	$	774		$	12
NDT Fund (D)
Equity Securities	$	897		$	—		$	896	$	1		$	—
Debt Securities—Govt Obligations	$	438		$	—		$	—	$	438		$	—
Debt Securities—Other	$	339		$	—		$	—	$	339		$	—
Other Securities	$	106		$	—		$	106	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	21		$	—		$	—	$	21		$	—
Debt Securities—Other	$	18		$	—		$	—	$	18		$	—
Other Securities	$	1		$	—		$	—	$	1		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(165	)	$	541		$	—	$	(705	)	$	(1	)

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	Recurring Fair Value Measurements as of December 31, 2013
Description	Total			Netting (E)			Quoted Market Prices for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	439		$	—		$	439	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	223		$	(349	)	$	—	$	474		$	98
Interest Rate Swaps (C)	$	38		$	—		$	—	$	38		$	—
NDT Fund (D)
Equity Securities	$	897		$	—		$	892	$	5		$	—
Debt Securities—Govt Obligations	$	429		$	—		$	—	$	429		$	—
Debt Securities—Other	$	291		$	—		$	—	$	291		$	—
Other Securities	$	84		$	—		$	57	$	27		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	23		$	—		$	23	$	—		$	—
Debt Securities—Govt Obligations	$	107		$	—		$	—	$	107		$	—
Debt Securities—Other	$	46		$	—		$	—	$	46		$	—
Other Securities	$	3		$	—		$	—	$	3		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(107	)	$	351		$	—	$	(448	)	$	(10	)
PSE&G
Assets:
Derivative Contracts:
Energy Related Contracts (B)	$	94		$	—		$	—	$	—		$	94
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	25		$	—		$	—	$	25		$	—
Debt Securities—Other	$	11		$	—		$	—	$	11		$	—
Other Securities	$	1		$	—		$	—	$	1		$	—
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	129		$	(349	)	$	—	$	474		$	4
NDT Fund (D)
Equity Securities	$	897		$	—		$	892	$	5		$	—
Debt Securities—Govt Obligations	$	429		$	—		$	—	$	429		$	—
Debt Securities—Other	$	291		$	—		$	—	$	291		$	—
Other Securities	$	84		$	—		$	57	$	27		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	23		$	—		$	—	$	23		$	—
Debt Securities—Other	$	10		$	—		$	—	$	10		$	—
Other Securities	$	1		$	—		$	—	$	1		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(107	)	$	351		$	—	$	(448	)	$	(10	)


(A)	Represents money market mutual funds


(B)	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

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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 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.


(C)	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.

(D)

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. Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active markets. The Rabbi Trust equity index fund is valued based on quoted prices in an active market.

Level 2—NDT and Rabbi Trust fixed income securities are limited to investment grade corporate bonds and United States Treasury obligations or Federal Agency asset-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. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield.

(E)

Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Consolidated Balance Sheet. As of December 31, 2014, net cash collateral (received) paid of $24 million was netted against the corresponding net derivative contract positions. Of the $24 million of cash collateral as of December 31, 2014, $(12) million was netted against assets, and $36 million was netted against liabilities. As of December 31, 2013, net cash collateral (received) paid of $2 million was netted against the corresponding net derivative contract positions. Of the $2 million of cash collateral as of December 31, 2013, $(3) million was netted against assets and $5 million was netted against liabilities.

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.

For PSE&G and Power, natural gas supply contracts are measured at fair value using modeling techniques taking into account the current price of natural gas adjusted for appropriate risk factors, as applicable, and internal assumptions about transportation costs, and accordingly, the fair value measurements are classified in Level 3. For Power, in general, electric swaps are measured at fair value based on at least two pricing inputs, the underlying price of electricity at a liquid reference point and the basis difference between electricity prices at the liquid reference point and electricity prices at the respective delivery locations. To

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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 fair value of Power's electric load contracts in which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. For Power, long-term electric capacity contracts are measured using capacity auction prices. If the fair value for the unobservable tenor is significant, then the entire capacity contract is categorized as Level 3. For additional information see Note 12. Commitments and Contingent Liabilities. The following tables provide detail surrounding significant Level 3 valuations as of December 31, 2014 and 2013.




	Quantitative Information About Level 3 Fair Value Measurements
Commodity	Level 3 Position	Fair Value as of December 31, 2014					Valuation Technique(s)	Significant Unobservable Input	Range
Commodity	Level 3 Position	Fair Value as of December 31, 2014					Valuation Technique(s)	Significant Unobservable Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Forward Contracts	$	26	$	—		Discounted Cash Flow	Transportation Costs	$0.70 to $1/dekatherm
Total PSE&G		$	26	$	—
Power
Electricity	Electric Load Contracts	$	12	$	(1	)	Discounted Cash flow	Historic Load Variability	0% to +10%
Other	Various (A)	—		—
Total Power		$	12	$	(1	)
Total PSEG		$	38	$	(1	)




	Quantitative Information About Level 3 Fair Value Measurements
Commodity	Level 3 Position	Fair Value as of December 31, 2013					Valuation Technique(s)	Significant Unobservable Input	Range
Commodity	Level 3 Position	Fair Value as of December 31, 2013					Valuation Technique(s)	Significant Unobservable Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Forward Contracts	$	94	$	—		Discounted Cash Flow	Transportation Costs	$0.70 to $1/dekatherm
Total PSE&G		$	94	$	—
Power
Electricity	Electric Swaps	$	3	$	(1	)	Discounted Cash Flow	Power Basis	$0 to $10/MWh
Electricity	Electric Load Contracts	—		(8		)	Discounted Cash Flow	Historic Load Variability	-5% to +10%
Other	Various (B)	1		(1		)
Total Power		$	4	$	(10	)
Total PSEG		$	98	$	(10	)


(A)	Includes gas supply positions and long-term electric capacity positions which were immaterial as of December 31, 2014.


(B)	Includes gas supply positions which were immaterial as of December 31, 2013.

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 gas supply contracts where PSE&G is a seller, an increase in gas transportation cost would increase the fair value. For energy-related contracts in cases where Power is a seller, an increase in either the power basis or the load variability or the longer-term gas basis amounts would decrease 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, 2014 and 2013, respectively, follows:

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

for the Year Ended December 31, 2014




				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2014			Included in Income (A)			Included in Regulatory Assets/ Liabilities (B)			Purchases, (Sales)		Issuances (Settlements) (C)		Transfers In (Out) (D)			Balance as of December 31, 2014
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	88		$	(31	)	$	(68	)	$	—	$	51	$	(3	)	$	37
PSE&G
Net Derivative Assets (Liabilities)	$	94		$	—		$	(68	)	$	—	$	—	$	—		$	26
Power
Net Derivative Assets (Liabilities)	$	(6	)	$	(31	)	$	—		$	—	$	51	$	(3	)	$	11

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

for the Year Ended December 31, 2013




				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2013			Included in Income (A)			Included in Regulatory Assets/ Liabilities (B)		Purchases, (Sales)		Issuances (Settlements) (C)		Transfers In (Out) (D)		Balance as of December 31, 2013
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	(31	)	$	(27	)	$	134	$	—	$	8	$	4	$	88
PSE&G
Net Derivative Assets (Liabilities)	$	(40	)	$	—		$	134	$	—	$	—	$	—	$	94
Power
Net Derivative Assets (Liabilities)	$	9		$	(27	)	$	—	$	—	$	8	$	4	$	(6	)


(A)	PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $(31) million and $(27) million in Operating Income in 2014 and 2013, respectively. Of the $(31) million in Operating Income in 2014, $22 million is unrealized. Of the $(27) million in Operating Income in 2013, $(19) million is unrealized.


(B)	Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Accumulated Other Comprehensive Income (Loss), as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers.

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(C)	Represents $51 million and $8 million in settlements for derivative contracts in 2014 and 2013, respectively.


(D)	During the years ended December 31, 2014 and 2013, $(3) million and $4 million, respectively, of net derivatives assets/liabilities were transferred from Level 3 to Level 2 due to more observable pricing for the underlying securities. The transfers were recognized as of the beginning of the quarters (i.e. the quarter in which the transfers occurred), as per PSEG’s policy.

As of December 31, 2014, PSEG carried $2.5 billion of net assets that are measured at fair value on a recurring basis, of which $37 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

As of December 31, 2013, PSEG carried $2.5 billion of net assets that are measured at fair value on a recurring basis, of which $88 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

Non-recurring Fair Value Measurements

During the fourth quarter of 2014, an assessment of recoverability was triggered for two commercial real estate properties located in Ohio and Michigan. As a result of the evaluation, Energy Holdings recorded a pre-tax impairment of $14 million which is included in Operating Revenues in PSEG’s Consolidated Statement of Operations for the year ended December 31, 2014. The remaining investment in these properties of $9 million is carried as a nonrecurring fair value measurement determined using an income approach valuation technique (cash flow analyses) along with bids received as part of a marketing initiative. This technique relied on significant unobservable inputs and is considered a Level 3 measurement within the fair value hierarchy.

Note 17. Stock Based Compensation

PSEG's Amended and Restated 2004 Long-Term Incentive Plan (LTIP) is a broad-based equity compensation program that provides for grants of various long-term incentive compensation awards, such as stock options, stock appreciation rights, performance share 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 LTIP are non-qualified options to purchase shares of PSEG's common stock, restricted stock awards, restricted stock unit awards and performance share 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 LTIP currently provides for the issuance of equity awards with respect to approximately 16 million shares of common stock. As of December 31, 2014, there were approximately 16 million shares available for future awards under the LTIP.

Stock Options

Under the 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 ten years from the date of grant) and are subject to such other terms and conditions as the OCC determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the OCC, by delivering previously acquired shares of PSEG common stock.

Restricted Stock

Under the 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 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 2014 and 2013 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.

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Performance Share Units

Under the LTIP, PSEG has granted performance share units to officers and other key employees. These 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 share 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 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 the total shareholder return target for its performance share unit awards based on the grant date fair values of the award, which are determined using the Monte Carlo model. The accrual of compensation cost is based on the probable achievement of the performance conditions, which result in a payout from 0% to 200% of the initial grant. PSEG recognizes compensation expense for the return on invested capital target for its performance share units based on the grant date fair value of the awards, which is equal to the market price of PSEG’s common stock on the date of the grant. The accrual during the year of grant is estimated at 100% of the original grant. Such accrual may be adjusted to reflect the actual outcome.




	2014		2013		2012
	Millions
Compensation Cost included in Operation and Maintenance Expense	$	32	$	32	$	25
Income Tax Benefit Recognized in Consolidated Statement of Operations	$	13	$	13	$	10

There was no excess tax benefit for 2014 and 2013. There was less than $1 million of excess tax benefits for 2012.

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.

Stock Options

Changes in stock options for 2014 are summarized as follows:




	Options	Weighted Average Exercise Price		Weighted Average Remaining Years Contractual Term	Aggregate Intrinsic Value
Outstanding as of January 1, 2014	2,615,166	$	34.43
Exercised	519,250	$	30.51
Canceled/Forfeited	20,066	$	39.88
Outstanding as of December 31, 2014	2,075,850	$	35.35	3.8	$	15,016,886
Exercisable at December 31, 2014	2,075,850	$	35.35	3.8	$	15,016,886

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 2014, 2013 and 2012.

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Activity for options exercised for the years ended December 31, 2014, 2013 and 2012 is shown below:




	2014		2013		2012
	Millions
Total Intrinsic Value of Options Exercised	$	4	$	1	$	4
Cash Received from Options Exercised	$	16	$	7	$	7
Tax Benefit Realized from Options Exercised	$	—	$	—	$	1

No options were vested during the year ended December 31, 2014. Less than one million options vested during each of the years ended December 31, 2013 and 2012. The total fair value of the stock options vested during the years ended December 31, 2013 and 2012 was $1 million and $3 million, respectively.

Restricted Stock

Changes in restricted stock for the year ended December 31, 2014 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, 2014	8,800	$	30.18
Vested	8,800	$	30.18
Non-vested as of December 31, 2014	—	$	—	0	$	—

There were no restricted stock awards granted in 2014, 2013 and 2012.

The total intrinsic value of restricted stock vested during the years ended December 31, 2014, 2013 and 2012 was $2 million, $2 million and $1 million, respectively.

Restricted Stock Units

Changes in restricted stock units for the year ended December 31, 2014 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, 2014	1,047,569	$	31.30
Granted	356,240	$	35.16
Vested	325,504	$	31.57
Canceled/Forfeited	9,276	$	33.95
Non-vested as of December 31, 2014	1,069,029	$	32.49	1.1	$	44,268,491

The weighted average grant date fair value per share for restricted stock during the years ended December 31, 2014, 2013 and 2012 was $35.16, $31.41 and $30.95 per share, respectively.

The total intrinsic value of restricted stock units vested during the years ended December 31, 2014, 2013 and 2012 was $12 million, $4 million and $5 million, respectively.

As of December 31, 2014, there was approximately $5 million of unrecognized compensation cost related to the restricted stock units, which is expected to be recognized over a weighted average period of one year. Dividend equivalents units of 42,648 accrued on the restricted stock units during the year.

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Performance Share Units

Changes in performance share units for the year ended December 31, 2014 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, 2014	802,118	$	33.25
Granted	358,265	$	38.94
Vested	382,504	$	31.25
Canceled/Forfeited	12,246	$	36.45
Non-vested as of December 31, 2014	765,633	$	36.86	1.5	$	31,704,863

The weighted average grant date fair value per share for performance share units during the years ended December 31, 2014, 2013 and 2012 was $38.94, $35.07 and $31.25 per share, respectively.

The total intrinsic value of performance share units vested during the year ended December 31, 2014, 2013 and 2012 was $6 million, $5 million and $4 million, respectively.

As of December 31, 2014, there was approximately $14 million of unrecognized compensation cost related to the performance share units, which is expected to be recognized over a weighted average period of one year. Dividend equivalents units of 45,779 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 as specified by him/her in accordance with the provisions of the plan.

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, 2014, 2013 and 2012 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 for represented employees and 90% for non-represented employees through payroll deductions. Dividends will be reinvested for all employees at 95% of the fair market price unless the participant elects to receive a cash dividend. All employees are required to hold the shares purchased under the ESPP for at least three months from the purchase date. In any year, employees may purchase shares having a value not exceeding 10% of their base pay.

During the years ended December 31, 2014, 2013 and 2012, employees purchased 207,248 shares, 257,513 shares and 191,572 shares at an average price of $36.07, $30.57 and $31.32 per share, respectively. As of December 31, 2014, 3.6 million shares were available for future issuance under this plan.

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Note 18. Other Income and Deductions




Other Income	PSE&G		Power		Other (A)		Consolidated Total

Year Ended December 31, 2014
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	219	$	—	$	219
Allowance for Funds Used During Construction	31		—		—		31
Solar Loan Interest	24		—		—		24
Other	6		3		7		16
Total Other Income	$	61	$	222	$	7	$	290
Year Ended December 31, 2013
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	152	$	—	$	152
Allowance for Funds Used During Construction	24		—		—		24
Solar Loan Interest	23		—		—		23
Other	7		2		5		14
Total Other Income	$	54	$	154	$	5	$	213
Year Ended December 31, 2012
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	194	$	—	$	194
Allowance for Funds Used During Construction	23		—		—		23
Solar Loan Interest	18		—		—		18
Other	11		7		7		25
Total Other Income	$	52	$	201	$	7	$	260




Other Deductions	PSE&G		Power		Other (A)		Consolidated Total

Year Ended December 31, 2014
NDT Fund Realized Losses and Expense	$	—	$	31	$	—	$	31
Other	3		21		6		30
Total Other Deductions	$	3	$	52	$	6	$	61
Year Ended December 31, 2013
NDT Fund Realized Losses and Expense	$	—	$	34	$	—	$	34
Other	3		15		2		20
Total Other Deductions	$	3	$	49	$	2	$	54
Year Ended December 31, 2012
NDT Fund Realized Losses and Expense	$	—	$	58	$	—	$	58
Loss on Early Extinguishment of Debt	—		15		—		15
Other	5		17		3		25
Total Other Deductions	$	5	$	90	$	3	$	98


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

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Note 19. 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,
PSEG	2014			2013			2012
	Millions
Net Income	$	1,518		$	1,243		$	1,275
Income Taxes:
Operating Income:
Current Expense:
Federal	$	335		$	487		$	(204	)
State	58			42			(2		)
Total Current	393			529			(206		)
Deferred Expense:
Federal	262			147			758
State	260			118			125
Total Deferred	522			265			883
Investment Tax Credit (ITC)	23			18			59
Total Income Taxes	$	938		$	812		$	736
Pre-Tax Income	$	2,456		$	2,055		$	2,011
Tax Computed at Statutory Rate @ 35%	$	860		$	719		$	704
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)	145			108			115
Uncertain Tax Positions	(9		)	10			4
Manufacturing Deduction	(16		)	(9		)	—
NDT Fund	14			12			10
Plant-Related Items	(13		)	(14		)	(5		)
Tax Credits	(14		)	(9		)	(10		)
Audit Settlement	(12		)	—			(71		)
Other	(17		)	(5		)	(11		)
Sub-Total	78			93			32
Total Income Tax Provision	$	938		$	812		$	736
Effective Income Tax Rate	38.2		%	39.5		%	36.6		%

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




	As of December 31,
PSEG	2014		2013
	Millions
Deferred Income Taxes
Assets:
Current (net)	$	11	$	24
Noncurrent
OPEB	$	269	$	280
Related to Uncertain Tax Position	160		201
Securitization-Overcollection	55		—
Accumulated Other Comprehensive Income (Loss)	—		3
Other	—		124
Total Noncurrent Assets	$	484	$	608
Total Assets	$	495	$	632
Liabilities:
Current (net)
Securitization	$	163	$	—
Other	$	10	$	—
Total Current Liabilities (net)	$	173	$	—
Noncurrent:
Plant-Related Items	$	5,422	$	4,865
New Jersey Corporate Business Tax	535		534
Securitization	—		279
Leasing Activities	623		639
Pension Costs	219		288
AROs and NDT Fund	419		523
Taxes Recoverable Through Future Rate (net)	196		181
Other	240		293
Total Noncurrent Liabilities	$	7,654	$	7,602
Total Liabilities	$	7,827	$	7,602
Summary of Accumulated Deferred Income Taxes:
Net Current Deferred Income Tax Assets	$	11	$	24
Net Current Deferred Income Tax Liabilities	$	173	$	—
Net Noncurrent Deferred Income Tax Liabilities	$	7,170	$	6,994
ITC	133		113
Net Total Noncurrent Deferred Income Taxes and ITC	$	7,303	$	7,107

The deferred tax effect of certain assets and liabilities are presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals. Also, the deferred tax effect of AROs are presented net of the deferred tax effect of the associated funding of those obligations.

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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,
PSE&G	2014			2013			2012
	Millions
Net Income	$	725		$	612		$	528
Income Taxes:
Operating Income:
Current Expense:
Federal	$	124		$	183		$	(217	)
State	16			—			9
Total Current	140			183			(208		)
Deferred Expense:
Federal	214			101			409
State	84			92			83
Total Deferred	298			193			492
ITC	11			5			23
Total Income Taxes	$	449		$	381		$	307
Pre-Tax Income	$	1,174		$	993		$	835
Tax Computed at Statutory Rate @ 35%	$	411		$	348		$	292
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)	65			59			52
Uncertain Tax Positions	—			—			7
Plant-Related Items	(13		)	(14		)	(4		)
Tax Credits	(7		)	(6		)	(3		)
Audit Settlement	1			—			(31		)
Other	(8		)	(6		)	(6		)
Sub-Total	38			33			15
Total Income Tax Provision	$	449		$	381		$	307
Effective Income Tax Rate	38.2		%	38.4		%	36.8		%

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




	As of December 31,
PSE&G	2014		2013
	Millions
Deferred Income Taxes
Assets:
Current (net)	$	24	$	16
Noncurrent:
OPEB	$	173	$	182
Securitization-Overcollection	55		—
Total Noncurrent Assets	$	228	$	182
Total Assets	$	252	$	198
Liabilities:
Current (net)
Securitization	$	163	$	—
Other	2		30
Total Current Liabilities (net)	$	165	$	30
Noncurrent:
Plant-Related Items	$	3,869	$	3,439
New Jersey Corporate Business Tax	268		340
Securitization	—		279
Conservation Costs	48		52
Pension Costs	269		171
Taxes Recoverable Through Future Rate (net)	196		181
Other	84		68
Total Noncurrent Liabilities	$	4,734	$	4,530
Total Liabilities	$	4,899	$	4,560
Summary of Accumulated Deferred Income Taxes:
Net Current Deferred Income Tax Assets	$	24	$	16
Net Current Deferred Income Tax Liabilities	$	165	$	30
Net Noncurrent Deferred Income Tax Liabilities	$	4,506	$	4,348
ITC	69		58
Net Total Noncurrent Deferred Income Taxes and ITC	$	4,575	$	4,406

The deferred tax effect of certain assets and liabilities are presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals.

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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,
Power	2014			2013			2012
	Millions
Net Income	$	760		$	644		$	666
Income Taxes:
Operating Income:
Current Expense:
Federal	$	231		$	262		$	30
State	39			40			51
Total Current	270			302			81
Deferred Expense:
Federal	163			69			279
State	48			35			37
Total Deferred	211			104			316
ITC	10			13			36
Total Income Taxes	$	491		$	419		$	433
Pre-Tax Income	$	1,251		$	1,063		$	1,099
Tax Computed at Statutory Rate @ 35%	$	438		$	372		$	385
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)	58			51			55
Manufacturing Deduction	(16		)	(10		)	—
NDT Fund	15			12			10
Tax Credits	(6		)	(2		)	(7		)
Uncertain Tax Positions	(8		)	3			(6		)
Audit Settlement	(4		)	—			(1		)
Other	14			(7		)	(3		)
Sub-Total	53			47			48
Total Income Tax Provision	$	491		$	419		$	433
Effective Income Tax Rate	39.2		%	39.4		%	39.4		%

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




	As of December 31,
Power	2014		2013
	Millions
Deferred Income Taxes
Assets:
Current	$	—	$	30
Noncurrent:
Pension Costs	$	52	$	—
Contractual Liabilities & Environmental Costs	18		35
Related to Uncertain Tax Positions	23		32
Other	70		91
Total Noncurrent Assets	$	163	$	158
Total Assets	$	163	$	188
Liabilities:
Current (net)	$	43	$	—
Noncurrent:
Plant-Related Items	$	1,552	$	1,416
New Jersey Corporate Business Tax	192		81
Pension Costs	—		77
AROs and NDT Fund	420		523
Accumulated Other Comprehensive Income (Loss)	—		2
Other	—		36
Total Noncurrent Liabilities	$	2,164	$	2,135
Total Liabilities	$	2,207	$	2,135
Summary of Accumulated Deferred Income Taxes:
Net Current Deferred Income Tax Assets	$	—	$	30
Net Current Deferred Income Tax Liabilities	$	43	$	—
Net Noncurrent Deferred Income Tax Liabilities	$	2,001	$	1,977
ITC	64		54
Net Total Noncurrent Deferred Income Taxes and ITC	$	2,065	$	2,031

In the above table, the deferred tax effect of asset retirement obligations are presented net of the deferred tax effect of the associated funding of those obligations.

As of December 31, 2014, PSEG had a federal net operating loss (NOL) carryforward of $243 million. The loss was generated in 2012 and will expire in 2033. PSEG believes that it is more-likely-than-not that the federal benefit from the NOL will be realized.

PSEG, PSE&G and Power each 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 5. Regulatory Assets and Liabilities.

On August 11, 2014, PSEG received notice from the IRS that the audit settlement covering tax years 2007 through 2010 had been approved by the Joint Committee on Taxation. This effectively settles all issues with the IRS through 2010. On September 9, 2014, PSEG received refunds from the IRS totaling $121 million, representing the net settlement of all disputed amounts, including interest, through the tax year 2010. As a result of the settlement of this audit, PSEG recorded a $12 million reduction of tax expense in the quarter ended September 30, 2014.

In September 2013, the U.S. Department of the Treasury and the IRS released final regulations effective in 2014 that provide guidance on applying Section 263(a) of the Internal Revenue Code to amounts paid to acquire, produce or improve tangible

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property, as well as rules for materials and supplies. Implementation of these regulations did not have any material impact on PSEG’s and its subsidiaries’ results of operations, financial condition or cash flows.

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 was eligible for 50% bonus depreciation for tax purposes. The American Taxpayer Relief Act of 2012 extended the 50% bonus depreciation rules for qualified property placed into service before January 1, 2014. In addition, long production property placed into service in 2014 is eligible for 50% bonus depreciation for tax purposes. On December 19, 2014, the Tax Increase Prevention Act of 2014 was enacted. This act further extended the 50% bonus depreciation rules for qualified property that was placed into service before January 1, 2015 and for long production property that is to be placed into service in 2015. These provisions have generated cash for PSEG, PSE&G and Power through tax benefits related to the accelerated depreciation. These tax benefits would have otherwise been received over an estimated average 20 year period.

PSEG recorded the following amounts related to its unrecognized tax benefits, which were primarily comprised of amounts recorded for PSE&G, Power and Energy Holdings:




2014	PSEG			PSE&G			Power			Energy Holdings
	Millions
Total Amount of Unrecognized Tax Benefits as of January 1, 2014	$	478		$	208		$	156		$	110
Increases as a Result of Positions Taken in a Prior Period	82			65			17			—
Decreases as a Result of Positions Taken in a Prior Period	(190		)	(92		)	(80		)	(18		)
Increases as a Result of Positions Taken during the Current Period	30			16			9			5
Decreases as a Result of Positions Taken during the Current Period	(8		)	—			(8		)	—
Decreases as a Result of Settlements with Taxing Authorities	(60		)	(32		)	(24		)	(2		)
Decreases due to Lapses of Applicable Statute of Limitations	—			—			—			—
Total Amount of Unrecognized Tax Benefits as of December 31, 2014	$	332		$	165		$	70		$	95
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits	(225		)	(138		)	(52		)	(35		)
Regulatory Asset—Unrecognized Tax Benefits	(27		)	(27		)	—			—
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties)	$	80		$	—		$	18		$	60




2013	PSEG			PSE&G			Power			Energy Holdings
	Millions
Total Amount of Unrecognized Tax Benefits as of January 1, 2013	$	402		$	163		$	134		$	101
Increases as a Result of Positions Taken in a Prior Period	83			39			33			11
Decreases as a Result of Positions Taken in a Prior Period	(30		)	(9		)	(19		)	(2		)
Increases as a Result of Positions Taken during the Current Period	23			15			8			—
Decreases as a Result of Positions Taken during the Current Period	—			—			—			—
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, 2013	$	478		$	208		$	156		$	110
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits	(320		)	(177		)	(105		)	(37		)
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)	$	128		$	1		$	51		$	73

159

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2012	PSEG			PSE&G			Power			Energy Holdings
	Millions
Total Amount of Unrecognized Tax Benefits as of January 1, 2012	$	825		$	113		$	121		$	555
Increases as a Result of Positions Taken in a Prior Period	92			55			27			9
Decreases as a Result of Positions Taken in a Prior Period	(173		)	(47		)	(7		)	(119		)
Increases as a Result of Positions Taken during the Current Period	47			42			3			—
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		$	163		$	134		$	101
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits	(264		)	(133		)	(93		)	(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

PSEG and its subsidiaries include accrued interest and penalties related to uncertain tax positions required to be recorded, as Income Tax Expense in the Consolidated Statements of Operations. Accumulated interest and penalties that are recorded on the Consolidated Balance Sheets on uncertain tax positions were as follows:




	Interest and Penalties on Uncertain Tax Positions Years Ended December 31,
	2014		2013			2012
	Millions
PSE&G	$	15	$	6		$	1
Power	9		(2		)	(2		)
Energy Holdings	45		44			39
Total	$	69	$	48		$	38

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	$	59
PSE&G	$	2
Power	$	23

160

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A description of income tax years that remain subject to examination by material jurisdictions, where an examination has not already concluded are:




	PSEG	PSE&G	Power
United States
Federal	2011-2013	N/A	N/A
New Jersey	2006-2013	2006-2013	N/A
Pennsylvania	2001-2013	2000-2013	N/A
Connecticut	2002-2013	N/A	N/A
Texas	2007-2013	N/A	N/A
California	2003-2013	N/A	N/A
New York	2009-2013	N/A	2009-2013

Note 20. Accumulated Other Comprehensive Income (Loss), Net of Tax




PSEG	Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for -Sale Securities			Total
	Millions
Balance as of December 31, 2012	$	7		$	(485	)	$	90		$	(388	)
Other Comprehensive Income before Reclassifications	(2		)	210			91			299
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(7		)	37			(36		)	(6		)
Net Current Period Other Comprehensive Income (Loss)	(9		)	247			55			293
Balance as of December 31, 2013	$	(2	)	$	(238	)	$	145		$	(95	)
Other Comprehensive Income before Reclassifications	7			(184		)	42			(135		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	5			11			(69		)	(53		)
Net Current Period Other Comprehensive Income (Loss)	12			(173		)	(27		)	(188		)
Balance as of December 31, 2014	$	10		$	(411	)	$	118		$	(283	)

Power	Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for -Sale Securities			Total
	Millions
Balance as of December 31, 2012	$	9		$	(422	)	$	85		$	(328	)
Other Comprehensive Income before Reclassifications	(2		)	185			93			276
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(8		)	33			(36		)	(11		)
Net Current Period Other Comprehensive Income (Loss)	(10		)	218			57			265
Balance as of December 31, 2013	$	(1	)	$	(204	)	$	142		$	(63	)
Other Comprehensive Income before Reclassifications	7			(156		)	39			(110		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	5			9			(69		)	(55		)
Net Current Period Other Comprehensive Income (Loss)	12			(147		)	(30		)	(165		)
Balance as of December 31, 2014	$	11		$	(351	)	$	112		$	(228	)

161

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PSEG			Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
			Year Ended December 31, 2013
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
			Millions
Cash Flow Hedges
Energy-Related Contracts	Operating Revenues		$	13		$	(5	)	$	8
Interest Rate Swaps	Interest Expense		(1		)	—			(1		)
Total Cash Flow Hedges			12			(5		)	7
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense		11			(4		)	7
Amortization of Actuarial Loss	O&M Expense		(75		)	31			(44		)
Total Pension and OPEB Plans			(64		)	27			(37		)
Available-for-Sale Securities
Realized Gains	Other Income		116			(59		)	57
Realized Losses	Other Deductions		(29		)	14			(15		)
Other-Than-Temporary Impairments (OTTI)	OTTI		(12		)	6			(6		)
Total Available-for-Sale Securities			75			(39		)	36
Total			$	23		$	(17	)	$	6

PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
			Year Ended December 31, 2014
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
			Millions
Cash Flow Hedges
Energy-Related Contracts	Operating Revenues		$	(9	)	$	4		$	(5	)
Total Cash Flow Hedges			(9		)	4			(5		)
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense		10			(4		)	6
Amortization of Actuarial Loss	O&M Expense		(28		)	11			(17		)
Total Pension and OPEB Plans			(18		)	7			(11		)
Available-for-Sale Securities
Realized Gains	Other Income		181			(89		)	92
Realized Losses	Other Deductions		(26		)	13			(13		)
OTTI	OTTI		(20		)	10			(10		)
Total Available-for-Sale Securities			135			(66		)	69
Total			$	108		$	(55	)	$	53

162

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Power			Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
			Year Ended December 31, 2013
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
			Millions
Cash Flow Hedges
Energy-Related Contracts	Operating Revenues		$	13		$	(5	)	$	8
Total Cash Flow Hedges			13			(5		)	8
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense		9			(4		)	5
Amortization of Actuarial Loss	O&M Expense		(64		)	26			(38		)
Total Pension and OPEB Plans			(55		)	22			(33		)
Available-for-Sale Securities
Realized Gains	Other Income		112			(57		)	55
Realized Losses	Other Deductions		(26		)	13			(13		)
OTTI	OTTI		(12		)	6			(6		)
Total Available-for-Sale Securities			74			(38		)	36
Total			$	32		$	(21	)	$	11

Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
			Year Ended December 31, 2014
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
			Millions
Cash Flow Hedges
Energy-Related Contracts	Operating Revenues		$	(9	)	$	4		$	(5	)
Total Cash Flow Hedges			(9		)	4			(5		)
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense		9			(4		)	5
Amortization of Actuarial Loss	O&M Expense		(25		)	11			(14		)
Total Pension and OPEB Plans			(16		)	7			(9		)
Available-for-Sale Securities
Realized Gains	Other Income		178			(87		)	91
Realized Losses	Other Deductions		(24		)	12			(12		)
OTTI	OTTI		(20		)	10			(10		)
Total Available-for-Sale Securities			134			(65		)	69
Total			$	109		$	(54	)	$	55

163

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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 PSEG's 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,
	2014				2013				2012
	Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator:
(Millions)
Net Income	$	1,518	$	1,518	$	1,243	$	1,243	$	1,275	$	1,275
EPS Denominator:
(Millions)
Weighted Average Common Shares Outstanding	506		506		506		506		506		506
Effect of Stock Based Compensation Awards	—		2		—		2		—		1
Total Shares	506		508		506		508		506		507
EPS:
Net Income	$	3.00	$	2.99	$	2.46	$	2.45	$	2.52	$	2.51

There were approximately 0.4 million, 1.6 million and 1.8 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, 2014, 2013 and 2012, respectively. No other stock options had an antidilutive effect for the years ended December 31, 2014, 2013 or 2012.

Dividends




	Years Ended December 31,
Dividend Payments on Common Stock	2014		2013		2012
Per Share	$	1.48	$	1.44	$	1.42
in Millions	$	748	$	728	$	718

On February 17, 2015, PSEG’s Board of Directors approved a $0.39 per share common stock dividend for the first quarter of 2015.

Note 22. Financial Information by Business Segment

Basis of Organization

PSEG’s operating segments are PSE&G and Power. The operating segments were determined by management in accordance with GAAP. 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.

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 solar investments, sundry sales, the appliance service business, wholesale transmission services and other miscellaneous services.

164

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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.

Other

This category includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services.




	PSE&G		Power		Other			Eliminations (A)			Consolidated Total

Year Ended December 31, 2014
Operating Revenues	$	6,766	$	5,434	$	455		$	(1,769	)	$	10,886
Depreciation and Amortization	906		292		29			—			1,227
Operating Income (Loss)	1,393		1,209		21			—			2,623
Income from Equity Method Investments	—		14		(1		)	—			13
Interest Income	26		1		25			(22		)	30
Interest Expense	277		122		12			(22		)	389
Income (Loss) before Income Taxes	1,174		1,251		31			—			2,456
Income Tax Expense (Benefit)	449		491		(2		)	—			938
Net Income (Loss)	725		760		33			—			1,518
Gross Additions to Long-Lived Assets	$	2,164	$	626	$	30		$	—		$	2,820
As of December 31, 2014
Total Assets	$	22,223	$	12,046	$	2,799		$	(1,735	)	$	35,333
Investments in Equity Method Subsidiaries	$	—	$	121	$	2		$	—		$	123




	PSE&G		Power		Other			Eliminations (A)			Consolidated Total

Year Ended December 31, 2013
Operating Revenues	$	6,655	$	5,063	$	52		$	(1,802	)	$	9,968
Depreciation and Amortization	872		273		33			—			1,178
Operating Income (Loss)	1,235		1,070		(6		)	—			2,299
Income from Equity Method Investments	—		16		(5		)	—			11
Interest Income	25		1		25			(22		)	29
Interest Expense	293		116		15			(22		)	402
Income (Loss) before Income Taxes	993		1,063		(1		)	—			2,055
Income Tax Expense (Benefit)	381		419		12			—			812
Net Income (Loss)	612		644		(13		)	—			1,243
Gross Additions to Long-Lived Assets	$	2,175	$	609	$	27		$	—		$	2,811
As of December 31, 2013
Total Assets	$	19,720	$	12,002	$	4,025		$	(3,225	)	$	32,522
Investments in Equity Method Subsidiaries	$	—	$	123	$	3		$	—		$	126

165

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




	PSE&G		Power		Other			Eliminations (A)			Consolidated Total

Year Ended December 31, 2012
Operating Revenues	$	6,626	$	4,873	$	103		$	(1,821	)	$	9,781
Depreciation and Amortization	778		242		34			—			1,054
Operating Income (Loss)	1,083		1,123		72			—			2,278
Income from Equity Method Investments	—		15		(3		)	—			12
Interest Income	20		3		25			(21		)	27
Interest Expense	295		132		17			(21		)	423
Income (Loss) before Income Taxes	835		1,099		77			—			2,011
Income Tax Expense (Benefit)	307		433		(4		)	—			736
Net Income (Loss)	528		666		81			—			1,275
Gross Additions to Long-Lived Assets	$	1,770	$	770	$	34		$	—		$	2,574
As of December 31, 2012
Total Assets	$	19,223	$	11,323	$	4,161		$	(2,982	)	$	31,725
Investments in Equity Method Subsidiaries	$	—	$	125	$	9		$	—		$	134

(A)

Intercompany eliminations, primarily relate to intercompany transactions between PSE&G and Power. 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 PSE&G and Power, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 23. Related-Party Transactions.

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.

PSE&G

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




	Years Ended December 31,
Related Party Transactions	2014		2013		2012
	Millions
Expense Billings from Affiliates:
Billings from Power primarily through BGSS and BGS (A)	$	1,771	$	1,797	$	1,802
Administrative Billings from Services (B)	248		255		230
Total Expense Billings from Affiliates	$	2,019	$	2,052	$	2,032

166

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




	Years Ended December 31,
Related Party Transactions	2014			2013
	Millions
Payable to Power (A)	$	(313	)	$	(267	)
Receivable from (Payable to) Services (B)	(66		)	(73		)
Receivable from (Payable to) PSEG (C)	274			150
Accounts Receivable (Payable)—Affiliated Companies, net	$	(105	)	$	(190	)
Working Capital Advances to Services (D)	$	33		$	33
Long-Term Accrued Taxes Receivable (Payable)	$	(116	)	$	(72	)

Power

The financial statements for Power include transactions with related parties presented as follows:




	Years Ended December 31,
Related Party Transactions	2014		2013		2012
	Millions
Revenue from Affiliates:
Billings to PSE&G primarily through BGSS and BGS (A)	$	1,771	$	1,797	$	1,802
Expense Billings from Affiliates:
Administrative Billings from Services (B)	$	165	$	178	$	154




	Years Ended December 31,
Related Party Transactions	2014			2013
	Millions
Receivables from PSE&G (A)	$	313		$	267
Receivable from (Payable to) Services (B)	(23		)	(31		)
Receivable from (Payable to) PSEG (C)	(95		)	97
Accounts Receivable (Payable)—Affiliated Companies, net	$	195		$	333
Short-Term Loan (to) from Affiliate (Demand Note (to) from PSEG) (E)	$	584		$	790
Working Capital Advances to Services (D)	$	17		$	17
Long-Term Accrued Taxes Receivable (Payable)	$	(41	)	$	(53	)


(A)	PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. 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 PSE&G and Power at cost. In addition, PSE&G and Power 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)	PSE&G and Power have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on PSE&G’s and Power’s Consolidated Balance Sheets.


(E)	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.

167

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PSEG RESTRICTED DRAFT 1-21-2015

Note 24. Selected Quarterly Data (Unaudited)

The information shown in the following tables, in the opinion of PSEG, PSE&G and Power includes all adjustments, consisting only of normal recurring accruals, necessary to fairly present such amounts.




	Quarter Ended
	March 31,				June 30,				September 30,				December 31,
	2014		2013		2014		2013		2014		2013		2014		2013
PSEG Consolidated:	Millions, except per share data
Operating Revenues	$	3,223	$	2,786	$	2,249	$	2,310	$	2,641	$	2,554	$	2,773	$	2,318
Operating Income	$	705	$	610	$	365	$	612	$	746	$	712	$	807	$	365
Net Income (Loss)	$	386	$	320	$	212	$	333	$	444	$	390	$	476	$	200
Earnings Per Share:
Basic:
Net Income (Loss)	$	0.76	$	0.63	$	0.42	$	0.66	$	0.88	$	0.77	$	0.94	$	0.40
Diluted:
Net Income (Loss)	$	0.76	$	0.63	$	0.42	$	0.66	$	0.87	$	0.77	$	0.94	$	0.39
Weighted Average Common Shares Outstanding:
Basic	506		507		506		506		506		506		506		506
Diluted	508		507		508		508		507		508		508		508




	Quarter Ended
	March 31,				June 30,				September 30,				December 31,
	2014		2013		2014		2013		2014		2013		2014		2013
PSE&G:	Millions
Operating Revenues	$	2,145	$	1,995	$	1,435	$	1,423	$	1,655	$	1,666	$	1,531	$	1,571
Operating Income	$	411	$	365	$	291	$	253	$	383	$	346	$	308	$	271
Net Income (Loss)	$	214	$	179	$	151	$	121	$	200	$	168	$	160	$	144




	Quarter Ended
	March 31,				June 30,				September 30,				December 31,
	2014		2013		2014		2013		2014		2013		2014		2013
Power:	Millions
Operating Revenues	$	1,700	$	1,451	$	986	$	1,193	$	1,138	$	1,174	$	1,610	$	1,245
Operating Income	$	282	$	242	$	67	$	351	$	353	$	370	$	507	$	107
Net Income (Loss)	$	164	$	141	$	54	$	210	$	222	$	226	$	320	$	67

168

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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, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012.




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Year Ended December 31, 2014
Operating Revenues	$	—		$	5,390		$	153		$	(109	)	$	5,434
Operating Expenses	16			4,175			143			(109		)	4,225
Operating Income (Loss)	(16		)	1,215			10			—			1,209
Equity Earnings (Losses) of Subsidiaries	799			(5		)	14			(794		)	14
Other Income	34			222			—			(34		)	222
Other Deductions	(20		)	(32		)	—			—			(52		)
Other-Than-Temporary Impairments	—			(20		)	—			—			(20		)
Interest Expense	(102		)	(35		)	(19		)	34			(122		)
Income Tax Benefit (Expense)	65			(558		)	2			—			(491		)
Net Income (Loss)	$	760		$	787		$	7		$	(794	)	$	760
Comprehensive Income (Loss)	$	595		$	768		$	7		$	(775	)	$	595
As of December 31, 2014
Current Assets	$	4,263		$	2,037		$	150		$	(4,091	)	$	2,359
Property, Plant and Equipment, net	81			6,265			1,169			—			7,515
Investment in Subsidiaries	4,516			120			—			(4,636		)	—
Noncurrent Assets	278			1,952			137			(195		)	2,172
Total Assets	$	9,138		$	10,374		$	1,456		$	(8,922	)	$	12,046
Current Liabilities	$	883		$	3,606		$	786		$	(4,091	)	$	1,184
Noncurrent Liabilities	454			2,442			360			(195		)	3,061
Long-Term Debt	2,243			—			—			—			2,243
Member’s Equity	5,558			4,326			310			(4,636		)	5,558
Total Liabilities and Member’s Equity	$	9,138		$	10,374		$	1,456		$	(8,922	)	$	12,046
Year Ended December 31, 2014
Net Cash Provided By (Used In) Operating Activities	$	577		$	1,674		$	76		$	(902	)	$	1,425
Net Cash Provided By (Used In) Investing Activities	$	148		$	(856	)	$	(42	)	$	226		$	(524	)
Net Cash Provided By (Used In) Financing Activities	$	(724	)	$	(818	)	$	(32	)	$	676		$	(898	)

169

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Year Ended December 31, 2013
Operating Revenues	$	—		$	5,022		$	190		$	(149	)	$	5,063
Operating Expenses	23			3,945			174			(149		)	3,993
Operating Income (Loss)	(23		)	1,077			16			—			1,070
Equity Earnings (Losses) of Subsidiaries	684			(5		)	16			(679		)	16
Other Income	35			157			—			(38		)	154
Other Deductions	(14		)	(35		)	—			—			(49		)
Other-Than-Temporary Impairments	—			(12		)	—			—			(12		)
Interest Expense	(93		)	(42		)	(19		)	38			(116		)
Income Tax Benefit (Expense)	55			(474		)	—			—			(419		)
Net Income (Loss)	$	644		$	666		$	13		$	(679	)	$	644
Comprehensive Income (Loss)	$	909		$	713		$	11		$	(724	)	$	909
As of December 31, 2013
Current Assets	$	4,413		$	2,076		$	102		$	(4,115	)	$	2,476
Property, Plant and Equipment, net	81			6,108			1,178			—			7,367
Investment in Subsidiaries	4,645			124			—			(4,769		)	—
Noncurrent Assets	222			1,847			138			(48		)	2,159
Total Assets	$	9,361		$	10,155		$	1,418		$	(8,932	)	$	12,002
Current Liabilities	$	697		$	3,474		$	745		$	(4,116	)	$	800
Noncurrent Liabilities	309			2,247			338			(47		)	2,847
Long-Term Debt	2,497			—			—			—			2,497
Member’s Equity	5,858			4,434			335			(4,769		)	5,858
Total Liabilities and Member’s Equity	$	9,361		$	10,155		$	1,418		$	(8,932	)	$	12,002
Year Ended December 31, 2013
Net Cash Provided By (Used In) Operating Activities	$	288		$	1,503		$	82		$	(526	)	$	1,347
Net Cash Provided By (Used In) Investing Activities	$	(395	)	$	(1,092	)	$	(71	)	$	697		$	(861	)
Net Cash Provided By (Used In) Financing Activities	$	107		$	(412	)	$	(11	)	$	(171	)	$	(487	)

170

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Year Ended December 31, 2012
Operating Revenues	$	—		$	4,850		$	135		$	(112	)	$	4,873
Operating Expenses	7			3,730			125			(112		)	3,750
Operating Income (Loss)	(7		)	1,120			10			—			1,123
Equity Earnings (Losses) of Subsidiaries	707			(10		)	15			(697		)	15
Other Income	45			206			2			(52		)	201
Other Deductions	(31		)	(59		)	—			—			(90		)
Other-Than-Temporary Impairments	—			(18		)	—			—			(18		)
Interest Expense	(118		)	(51		)	(16		)	53			(132		)
Income Tax Benefit (Expense)	70			(501		)	(2		)	—			(433		)
Net Income (Loss)	$	666		$	687		$	9		$	(696	)	$	666
Comprehensive Income (Loss)	$	614		$	681		$	9		$	(690	)	$	614
Year Ended December 31, 2012
Net Cash Provided By (Used In) Operating Activities	$	298		$	1,562		$	67		$	(474	)	$	1,453
Net Cash Provided By (Used In) Investing Activities	$	(14	)	$	(1,206	)	$	(151	)	$	899		$	(472	)
Net Cash Provided By (Used In) Financing Activities	$	(284	)	$	(361	)	$	83		$	(424	)	$	(986	)

Immaterial Correction of Prior Financial Information

The financial information included in the tables above has been corrected from the disclosure provided in Power's Form 10-K filed on February 26, 2014 (2013 10-K) to conform to the requirements of Section 210.3-10 of SEC Regulation S-X.

In the prior disclosure, Operating Revenues and Operating Expenses among the Guarantor Subsidiaries were eliminated in the Consolidating Adjustments column. The revised presentation eliminates this activity in the Guarantor Subsidiaries column and removes such activity from the Consolidating Adjustments column. This revised presentation decreased both Operating Revenues and Operating Expenses in both the Guarantor Subsidiaries and Consolidating Adjustments columns. This correction had no impact on Power’s consolidated Operating Revenues and Operating Expenses.

In the prior disclosure, loans payable by Power parent company to one of its guarantor subsidiaries were netted against loans receivable in net cash flows used in investing activities. The revised presentation reclassifies the increase in loans payable by the parent company to the guarantor subsidiary from net cash flows used in investing activities to net cash flows provided by financing activities. This revised presentation decreased net cash flows used in investing activities and increased net cash flows provided by financing activities in the Power column with corresponding offsets to the amounts in the Consolidating Adjustments Column.

In addition, the revised information was corrected to present the intercompany balances on a net basis when the right of offset exists in either Current Assets or Current Liabilities. This revised presentation resulted in increases/(decreases) to certain categories of the Consolidated Balance Sheet.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the adjustments for all prior periods that have been revised in this Note.




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Consolidated
	Increase (Decrease)
	Millions
Year Ended December 31, 2013
Operating Revenues	$	—		$	(1,468	)	$	—		$	1,468		$	—
Operating Expenses	$	—		$	(1,468	)	$	—		$	1,468		$	—
Net Cash Provided By (Used In) Investing Activities	$	(588	)	$	—		$	—		$	588		$	—
Net Cash Provided By (Used In) Financing Activities	$	588		$	—		$	—		$	(588	)	$	—
As of December 31, 2013
Current Assets	$	253		$	(6,840	)	$	(842	)	$	7,429		$	—
Investment in Subsidiaries	—			(605		)	—			605			—
Total Assets	$	253		$	(7,445	)	$	(842	)	$	8,034		$	—
Current Liabilities	$	253		$	(7,445	)	$	(237	)	$	7,429		$	—
Member's Equity	—			—			(605		)	605			—
Total Liabilities and Member's Equity	$	253		$	(7,445	)	$	(842	)	$	8,034		$	—
Year Ended December 31, 2012
Operating Revenues	$	—		$	(1,388	)	$	—		$	1,388		$	—
Operating Expenses	$	—		$	(1,388	)	$	—		$	1,388		$	—
Net Cash Provided By (Used In) Investing Activities	$	(729	)	$	—		$	—		$	729		$	—
Net Cash Provided By (Used In) Financing Activities	$	679		$	—		$	—		$	(679	)	$	—

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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, PSE&G and Power

We have established and maintain disclosure controls and procedures as defined under Rule 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) that are designed to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported and is accumulated and communicated to the Chief Executive Officer (CEO) and Chief Financial Officer (CFO) 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 CFO and CEO of each of Public Service Enterprise Group Incorporated, PSEG Public Service Electric and Gas Company, and PSEG Power LLC. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The CFO and CEO of each of Public Service Enterprise Group Incorporated, Public Service Electric and Gas Company, and PSEG Power LLC 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, PSE&G and Power

We have conducted assessments of our internal control over financial reporting as of December 31, 2014, 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, PSE&G’s and Power’s internal control over financial reporting are included on pages 174, 175 and 176, 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 177. Management has concluded that internal control over financial reporting is effective as of December 31, 2014.

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 2014 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 Incorporated (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 based on criteria established in the Internal Control - Integrated Framework (2013) issued 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, 2014 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, 2014.

PSEG’s external auditors, Deloitte & Touche LLP, have audited PSEG’s financial statements for the year ended December 31, 2014 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, 2015

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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 based on criteria established in the Internal Control - Integrated Framework (2013) issued 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, 2014 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, 2014.




/s/ RALPH IZZO
Chief Executive Officer

/s/ CAROLINE DORSA
Chief Financial Officer
February 25, 2015

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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 based on criteria established in the Internal Control - Integrated Framework (2013) issued 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, 2014 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, 2014.




/s/ RALPH IZZO
Chief Executive Officer

/s/ CAROLINE DORSA
Chief Financial Officer
February 25, 2015

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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, 2014 based on criteria established in Internal Control - Integrated Framework (2013) 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, 2014, based on the criteria established in Internal Control - Integrated Framework (2013) 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 15 (B)(a) as of and for the year ended December 31, 2014 of the Company and our report dated February 25, 2015 expressed an unqualified opinion on those consolidated financial statements and consolidated financial statement schedule.

/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey

February 25, 2015

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE

GOVERNANCE

Executive Officers

PSEG




Name	Age as of December 31, 2014	Office	Effective Date First Elected to Present Position
Ralph Izzo	57	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 and Chief Executive Officer (Services)	January 2010 to present
Caroline Dorsa	55	Executive Vice President and Chief Financial Officer (PSEG)	April 2009 to present
		Executive Vice President and Chief Financial Officer (PSE&G)	April 2009 to present
		Executive Vice President and Chief Financial Officer (Power)	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
William Levis	58	President and Chief Operating Officer (Power)	June 2007 to present
Ralph LaRossa	51	President and Chief Operating Officer (PSE&G)	October 2006 to present
		Chairman of the Board of PSEG Long Island LLC	October 2013 to present
Derek M. DiRisio	50	President (Services)	August 2014 to present
		Vice President and Controller (PSEG)	January 2007 to August 2014
		Vice President and Controller (PSE&G)	January 2007 to August 2014
		Vice President and Controller (Power)	January 2007 to August 2014
		Vice President and Controller (Energy Holdings)	January 2007 to August 2014
		Vice President and Controller (Services)	January 2007 to August 2014
Stuart J. Black	52	Vice President and Controller (PSEG)	August 2014 to present
		Vice President and Controller (PSE&G)	August 2014 to present
		Vice President and Controller (Power)	August 2014 to present
		Vice President (Services) and Assistant Controller (Power)	March 2010 to August 2014
		Vice President of Internal Auditing Services (Services)	January 2005 to March 2010
Tamara L. Linde	50	Executive Vice President and General Counsel (PSEG)	July 2014 to present
		Executive Vice President and General Counsel (PSE&G)	July 2014 to present
		Executive Vice President and General Counsel (Power)	July 2014 to present
		Vice President - Regulatory (Services)	December 2006 to July 2014

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PSE&G and Power

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 2015 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 9, 2015 and which information set forth under said heading is incorporated herein by this reference thereto.

PSE&G and Power

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 PSE&G's, Power’s, Energy Holdings’ and Services’ respective principal executive officer, principal financial officer, principal accounting officer or Controller and persons performing similar functions). Each such person is responsible for understanding and complying with the Standards. The Standards are posted on our website, www.pseg.com/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 2014, 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 2015 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 9, 2015 and such information set forth under such heading is incorporated herein by this reference thereto.

Section 16 Beneficial Ownership Reporting Compliance

During 2014, 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.

Power and PSE&G

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

179

Table of Contents

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 2015 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 9, 2015 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 Part II, Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Power and PSE&G

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

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND

DIRECTOR INDEPENDENCE

PSEG

The information required by Item 13 of Form 10-K is set forth under the heading “Transactions with Related Persons” in PSEG’s definitive Proxy Statement for the 2015 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 9, 2015 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 by Deloitte & Touche LLP for 2014 and 2013” in PSEG’s definitive Proxy Statement for the 2015 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 9, 2015. Such information set forth under such heading is incorporated herein by this reference hereto.

PART IV

ITEM 15. EXHIBITS, 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, 2014 and 2013 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Stockholders’ Equity for the three years ended December 31, 2014 on pages 71 through 76.


b.	Public Service Electric and Gas Company’s Consolidated Balance Sheets as of December 31, 2014 and 2013 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Common Stockholders’ Equity for the three years ended December 31, 2014 on pages 77 through 82.

180

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c.	PSEG Power LLC’s Consolidated Balance Sheets as of December 31, 2014 and 2013 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Capitalization and Member’s Equity for the three years ended December 31, 2014 on pages 83 through 88.

(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, 2014 (page 188).


b.	PSE&G's Financial Statement Schedules:

Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2014 (page 188).


c.	Power's Financial Statement Schedules:

Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2014 (page 189).

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)		Deferred Compensation Plan for Directors, amended July 19, 2011⁽¹⁰⁾
10a(6)		Deferred Compensation Plan for Certain Employees, amended November 1, 2011⁽⁵⁷⁾
10a(7)		1989 Long-Term Incentive Plan, as amended⁽¹²⁾
10a(8)		2001 Long-Term Incentive Plan⁽¹³⁾
10a(9)		Senior Management Incentive Compensation Plan⁽¹⁴⁾
10a(10)		Amended and Restated Key Executive Severance Plan, amended effective December 17, 2012⁽⁶¹⁾
10a(11)		Severance Agreement with Ralph Izzo dated December 16, 2008⁽¹⁵⁾
10a(12)		Employment Agreement with Caroline Dorsa dated March 11, 2009, as amended April 24, 2009⁽¹⁶⁾
10a(13)		Stock Plan for Outside Directors, as amended⁽¹⁷⁾
10a(14)		Compensation Plan for Outside Directors⁽¹⁸⁾
10a(15)		2004 Long-Term Incentive Plan, amended and restated as of April 16, 2013⁽¹⁹⁾

181

Table of Contents

LIST OF EXHIBITS:

10a(16)		Form of Advancement of Expenses Agreement with Outside Directors⁽²⁰⁾
10a(17)		Equity Deferral Plan, effective November 1, 2011, amended December 9, 2011⁽⁵⁸⁾
10a(18)		Employment Agreement with J.A. Bouknight dated August 26, 2009⁽⁵⁹⁾
10a(19)		Amendment to Employment Agreement with Caroline Dorsa, dated July 12, 2011⁽⁵⁶⁾
10a(20)		Amendment to Employment Agreement with William Levis, dated September 19, 2011⁽¹¹⁾
10a(21)		Amendment to Employment Agreement with J.A. Bouknight dated November 20, 2012⁽⁶⁰⁾
10a(22)		Amendment to Employment Agreement with J.A. Bouknight dated February 18, 2014⁽⁶²⁾
10a(23)		Agreement with Tamara L. Linde dated June 18, 2014
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⁽²¹⁾
3b		PSEG Power LLC Limited Liability Company Agreement⁽²²⁾
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⁽²³⁾
4b		First Supplemental Indenture, supplemental to Exhibit 4a, dated as of March 13, 2002⁽²⁴⁾
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)		Deferred Compensation Plan for Certain Employees, amended November 1, 2011⁽⁵⁷⁾
10a(5)		1989 Long-Term Incentive Plan, as amended⁽¹²⁾
10a(6)		2001 Long-Term Incentive Plan⁽¹³⁾
10a(7)		Senior Management Incentive Compensation Plan⁽¹⁴⁾
10a(8)		Amended and Restated Key Executive Severance Plan, amended effective December 17, 2012⁽⁶¹⁾
10a(9)		Severance Agreement with Ralph Izzo dated December 16, 2008⁽¹⁵⁾
10a(10)		Employment Agreement with Caroline Dorsa dated March 11, 2009, as amended April 24, 2009⁽¹⁶⁾
10a(11)		2004 Long-Term Incentive Plan, amended and restated as of April 16, 2013⁽¹⁹⁾

182

Table of Contents

LIST OF EXHIBITS:

10a(12)		Equity Deferral Plan, effective November 1, 2011, amended December 9, 2011⁽⁵⁸⁾
10a(13)		Employment Agreement with J.A. Bouknight dated August 26, 2009⁽⁵⁹⁾
10a(14)		Amendment to Employment Agreement with Caroline Dorsa, dated July 12, 2011⁽⁵⁶⁾
10a(15)		Amendment to Employment Agreement with William Levis, dated September 19, 2011⁽¹¹⁾
10a(16)		Amendment to Employment Agreement with J.A. Bouknight dated November 20, 2012⁽⁶⁰⁾
10a(17)		Amendment to Employment Agreement with J.A. Bouknight dated February 18, 2014⁽⁶²⁾
10a(18)		Agreement with Tamara L. Linde dated June 18, 2014
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⁽²⁵⁾
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⁽²⁶⁾
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⁽²⁷⁾
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⁽²⁸⁾
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⁽²⁹⁾
3b(1)		By-Laws of PSE&G as in effect April 17, 2007⁽³⁰⁾
4a(1)		Indenture between PSE&G and Fidelity Union Trust Company (now, Wachovia Bank, National Association), as Trustee, dated August 1, 1924⁽³¹⁾, 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)		June 1, 1937⁽³²⁾
4a(3)		July 1, 1937⁽³³⁾
4a(4)		March 1, 1942⁽³⁴⁾
4a(5)		June 1, 1991 (No. 1)⁽³⁵⁾

183

Table of Contents

LIST OF EXHIBITS:

4a(6)		July 1, 1993⁽³⁶⁾
4a(7)		January 1, 1996 (No. 1)⁽³⁷⁾
4a(8)		December 1, 2003 (No. 1)⁽³⁸⁾
4a(9)		December 1, 2003 (No. 2)⁽³⁹⁾
4a(10)		December 1, 2003 (No. 3)⁽⁴⁰⁾
4a(11)		December 1, 2003 (No. 4)⁽⁴¹⁾
4a(12)		August 1, 2004 (No. 1)⁽⁴²⁾
4a(13)		August 1, 2004 (No. 2)⁽⁴³⁾
4a(14)		August 1, 2004 (No. 3)⁽⁴⁴⁾
4a(15)		August 1, 2004 (No. 4)⁽⁴⁵⁾
4a(16)		April 1, 2007⁽⁴⁶⁾
4a(17)		November 1, 2008⁽⁴⁷⁾
4a(18)		October 1, 2010⁽⁴⁸⁾
4a(19)		May 1, 2012⁽⁵¹⁾
4a(20)		June 1, 2012⁽⁵²⁾
4a(21)		May 1, 2013⁽⁵³⁾
4a(22)		August 1, 2014⁽⁵⁴⁾
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⁽⁴⁹⁾
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⁽⁵⁰⁾
10a(1)		Supplemental Executive Retirement Income Plan, effective as of May 31, 2011⁽⁶⁾
10a(2)		Retirement Income Reinstatement Plan for Non-Represented Employees as amended May 31, 2011⁽⁷⁾
10a(3)		Amended and Restated 2007 Equity Compensation Plan for Outside Directors, effective July 19, 2011⁽⁹⁾
10a(4)		Deferred Compensation Plan for Directors, amended July 19, 2011⁽¹⁰⁾
10a(5)		Deferred Compensation Plan for Certain Employees, amended November 1, 2011⁽⁵⁷⁾
10a(6)		1989 Long-Term Incentive Plan, as amended⁽¹²⁾
10a(7)		2001 Long-Term Incentive Plan⁽¹³⁾
10a(8)		Senior Management Incentive Compensation Plan⁽¹⁴⁾
10a(9)		Amended and Restated Key Executive Severance Plan, amended effective December 17, 2012⁽⁶¹⁾
10a(10)		Severance Agreement with Ralph Izzo dated December 16, 2008⁽¹⁵⁾
10a(11)		Employment Agreement with Caroline Dorsa dated March 11, 2009, as amended April 24, 2009⁽¹⁶⁾
10a(12)		Stock Plan for Outside Directors, as amended⁽¹⁷⁾
10a(13)		Compensation Plan for Outside Directors⁽¹⁸⁾
10a(14)		2004 Long-Term Incentive Plan, amended and restated as of April 16, 2013⁽¹⁹⁾
10a(15)		Form of Advancement of Expenses Agreement with Outside Directors⁽⁵⁵⁾
10a(16)		Equity Deferral Plan, effective November 1, 2011, amended December 9, 2011⁽⁵⁸⁾
10a(17)		Employment Agreement with J.A. Bouknight dated August 26, 2009⁽⁵⁹⁾
10a(18)		Amendment to Employment Agreement with Caroline Dorsa, dated July 12, 2011⁽⁵⁶⁾
10a(19)		Amendment to Employment Agreement with J.A. Bouknight dated November 20, 2012⁽⁶⁰⁾
10a(20)		Amendment to Employment Agreement with J.A. Bouknight dated February 18, 2014⁽⁶²⁾
10a(21)		Agreement with Tamara L. Linde dated June 18, 2014
11		Inapplicable
12b		Computation of Ratios of Earnings to Fixed Charges

184

Table of Contents

LIST OF EXHIBITS:

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.


(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 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.


(11)	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.


(12)	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.


(13)	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.


(14)	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.


(15)	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.


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

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(17)	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.


(18)	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.


(19)	Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, File No. 001-09120 on April 30, 2013 and incorporated herein by reference.


(20)	Filed as Exhibit 10.1 with Current Report on Form 8-K, File No. 001-09120 on February 19, 2009 and incorporated herein by this reference.


(21)	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.


(22)	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.


(23)	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.


(24)	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.


(25)	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.


(26)	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.


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


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


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


(30)	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.


(31)	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.


(32)	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.


(33)	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.


(34)	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.


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


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


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


(38)	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.


(39)	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.


(40)	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.


(41)	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.


(42)	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.


(43)	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.


(44)	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.


(45)	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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Table of Contents


(46)	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.


(47)	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.


(48)	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.


(49)	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.


(50)	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.


(51)	Filed as Exhibit 4a(32) with Annual Report on Form 10-K for the year ended December 31, 2012, File No. 001-00973 on February 25, 2013.


(52)	Filed as Exhibit 4a(33) with Annual Report on Form 10-K for the year ended December 31, 2012, File No. 001-00973 on February 25, 2013.


(53)	Filed as Exhibit 4 with Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, File No. 001-00973 on July 30, 2013.


(54)	Filed as Exhibit 4a(22) with Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 001-09120 on October 30, 2014 and incorporated herein by reference.


(55)	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.


(56)	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.


(57)	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.


(58)	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.


(59)	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.


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


(61)	Filed as Exhibit 10a(11) with Annual Report on Form 10-K for the year ended December 31, 2012, File No. 001-09120 on February 25, 2013.


(62)	Filed as Exhibit 10 with Current Report on Form 8-K, File No. 001-09120 on February 21, 2014 and incorporated herein by reference.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

Schedule II—Valuation and Qualifying Accounts Years Ended December 31, 2014—December 31, 2012




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
2014
Allowance for Doubtful Accounts	$	56	$	86	$	—	$	90	(A)	$	52
Materials and Supplies Valuation Reserve	8		9		—		2			15
2013
Allowance for Doubtful Accounts	$	56	$	90	$	—	$	90	(A)	$	56
Materials and Supplies Valuation Reserve	22		2		—		16		(B)	8
2012
Allowance for Doubtful Accounts	$	56	$	96	$	—	$	96	(A)	$	56
Materials and Supplies Valuation Reserve	3		21		—		2		(B)	22


(A)	Accounts Receivable written off.


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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

Schedule II—Valuation and Qualifying Accounts Years Ended December 31, 2014—December 31, 2012




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
2014					Millions
Allowance for Doubtful Accounts	$	56	$	86	$	—	$	90	(A)	$	52
Materials and Supplies Valuation Reserve	—		2		—		—			2
2013
Allowance for Doubtful Accounts	$	56	$	90	$	—	$	90	(A)	$	56
2012
Allowance for Doubtful Accounts	$	56	$	96	$	—	$	96	(A)	$	56


(A)	Accounts Receivable written off.

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PSEG POWER LLC

Schedule II—Valuation and Qualifying Accounts Years Ended December 31, 2014—December 31, 2012




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
2014
Materials and Supplies Valuation Reserve	$	8	$	7	$	—	$	2		$	13
2013
Materials and Supplies Valuation Reserve	$	22	$	2	$	—	$	16	(A)	$	8
2012
Materials and Supplies Valuation Reserve	$	3	$	21	$	—	$	2	(A)	$	22


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

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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

ASC		Accounting Standards Codification
		FASB’s official source of authoritative, nongovernmental U.S. GAAP
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-RSCP		Basic Generation Service-Residential Small Commercial Product
		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
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

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
Lifeline Program		A New Jersey social program for utility assistance that offers up to $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
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

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Term Phrase/Description

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 Accounting Standard Codification Topic 980: Regulated operations (ASC 980)
Regulatory Liability		Costs recognized by a regulated utility company in accordance with ASC 980
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
RPM		Reliability Pricing Model (PJM market)
		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, 2015

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, 2015
Ralph Izzo	Director (Principal Executive Officer)

/s/ CAROLINE DORSA	Executive Vice President and Chief Financial Officer	February 25, 2015
Caroline Dorsa	(Principal Financial Officer)

/s/ STUART J. BLACK	Vice President and Controller	February 25, 2015
Stuart J. Black	(Principal Accounting Officer)

/s/ ALBERT R. GAMPER, JR.	Director	February 25, 2015
Albert R. Gamper, Jr.

/s/ WILLIAM V. HICKEY	Director	February 25, 2015
William V. Hickey

/s/ SHIRLEY ANN JACKSON	Director	February 25, 2015
Shirley Ann Jackson

/s/ DAVID LILLEY	Director	February 25, 2015
David Lilley

/s/ THOMAS A. RENYI	Director	February 25, 2015
Thomas A. Renyi

/s/ HAK CHEOL SHIN	Director	February 25, 2015
Hak Cheol Shin

/s/ RICHARD J. SWIFT	Director	February 25, 2015
Richard J. Swift

/s/ SUSAN TOMASKY	Director	February 25, 2015
Susan Tomasky

/s/ ALFRED W. ZOLLAR	Director	February 25, 2015
Alfred W. Zollar

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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, 2015




Signature	Title	Date

/s/ RALPH IZZO	Chairman of the Board and Chief Executive Officer and	February 25, 2015
Ralph Izzo	Director (Principal Executive Officer)

/s/ CAROLINE DORSA	Executive Vice President and Chief Financial Officer	February 25, 2015
Caroline Dorsa	(Principal Financial Officer)

/s/ STUART J. BLACK	Vice President and Controller	February 25, 2015
Stuart J. Black	(Principal Accounting Officer)

/s/ ALBERT R. GAMPER, JR.	Director	February 25, 2015
Albert R. Gamper Jr.

/s/ SHIRLEY ANN JACKSON	Director	February 25, 2015
Shirley Ann Jackson

/s/ RICHARD J. SWIFT	Director	February 25, 2015
Richard J. Swift

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SIGNATURES




			PSEG POWER LLC

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

Date: February 25, 2015




Signature	Title	Date

/s/ RALPH IZZO	Chairman of the Board and Chief Executive Officer and	February 25, 2015
Ralph Izzo	Director (Principal Executive Officer)

/s/ CAROLINE DORSA	Executive Vice President and Chief Financial Officer and	February 25, 2015
Caroline Dorsa	Director (Principal Financial Officer)

/s/ STUART J. BLACK	Vice President and Controller	February 25, 2015
Stuart J. Black	(Principal Accounting Officer)

/s/ DEREK M. DIRISIO	Director	February 25, 2015
Derek M. DiRisio

/s/ WILLIAM LEVIS	Director	February 25, 2015
William Levis

/s/ TAMARA L. LINDE	Director	February 25, 2015
Tamara L. Linde

/s/ MARGARET M. PEGO	Director	February 25, 2015
Margaret M. Pego

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EXHIBIT INDEX

The following documents are filed as a part of this report:



a. PSEG:
Exhibit 10a(23)		Agreement with Tamara L. Linde dated June 18, 2014
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(18)		Agreement with Tamara L. Linde dated June 18, 2014
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 10a(21)		Agreement with Tamara L. Linde dated June 18, 2014

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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

197