Annual Reports

  • 10-K (Feb 26, 2018)
  • 10-K (Feb 27, 2017)
  • 10-K (Feb 26, 2016)
  • 10-K (Feb 26, 2015)
  • 10-K (Feb 26, 2014)
  • 10-K (Feb 26, 2013)

Quarterly Reports



Public Service Enterprise Group 10-K 2013
PSEG 2012 10K

100 F ST., N.E.
(Mark One)
File Number
Registrants, State of Incorporation,
Address, and Telephone Number
I.R.S. Employer
Identification No.
(A New Jersey Corporation)
80 Park Plaza, P.O. Box 1171
Newark, New Jersey 07101-1171
973 430-7000

(A Delaware Limited Liability Company)
80 Park Plaza—T25
Newark, New Jersey 07102-4194
973 430-7000

(A New Jersey Corporation)
80 Park Plaza, P.O. Box 570
Newark, New Jersey 07101-0570
973 430-7000

Securities registered pursuant to Section 12(b) of the Act:
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
8  5/8% Senior Notes, due 2031
New York Stock Exchange
First and Refunding Mortgage Bonds
Public Service Electric
and Gas Company
9  1/4% Series CC, due 2021
New York Stock Exchange
6  3/4% Series VV, due 2016
8%, due 2037
5%, due 2037

(Cover continued on next page)

(Cover continued from previous page)
Securities registered pursuant to Section 12(g) of the Act:
Title of Each Class
Limited Liability Company Membership Interest
Public Service Electric
and Gas Company
Medium-Term Notes
Indicate by check mark whether each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Public Service Enterprise Group Incorporated
Yes x
No ¨
Yes ¨
No x
Public Service Electric and Gas Company
Yes x
No ¨
Indicate by check mark if each of the registrants is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes ¨ No x
Indicate by check mark whether each of the registrants (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Public Service Enterprise Group Incorporated
Large accelerated filer x
Accelerated filer ¨
Non-accelerated filer ¨
Large accelerated filer ¨
Accelerated filer ¨
Non-accelerated filer x
Public Service Electric and Gas Company
Large accelerated filer ¨
Accelerated filer ¨
Non-accelerated filer x
Indicate by check mark whether any of the registrants is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
The aggregate market value of the Common Stock of Public Service Enterprise Group Incorporated held by non-affiliates as of June 30, 2012 was $16,420,936,616 based upon the New York Stock Exchange Composite Transaction closing price.
The number of shares outstanding of Public Service Enterprise Group Incorporated’s sole class of Common Stock as of January 31, 2013 was 505,959,216.
As of January 31, 2013, Public Service Electric and Gas Company had issued and outstanding 132,450,344 shares of Common Stock, without nominal or par value, all of which were privately held, beneficially and of record by Public Service Enterprise Group Incorporated.
PSEG Power LLC and Public Service Electric and Gas Company are wholly owned subsidiaries of Public Service Enterprise Group Incorporated and each meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K. Each is filing its Annual Report on Form 10-K with the reduced disclosure format authorized by General Instruction I.
Part of Form 10-K of
Public Service
Enterprise Group Incorporated
Documents Incorporated by Reference
Portions of the definitive Proxy Statement for the 2013 Annual Meeting of Stockholders of Public Service Enterprise Group Incorporated, which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 8, 2013, as specified herein.

Item 1.
Regulatory Issues
Environmental Matters
Segment Information
Item 1A.
Risk Factors
Item 1B.
Unresolved Staff Comments
Item 2.
Item 3.
Legal Proceedings
Item 4.
Mine Safety Disclosures
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6.
Selected Financial Data
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview of 2012 and Future Outlook
Results of Operations
Liquidity and Capital Resources
Capital Requirements
Off-Balance Sheet Arrangements
Critical Accounting Estimates
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements
Notes to Consolidated Financial Statements
Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies
Note 2. Recent Accounting Standards
Note 3. Variable Interest Entities
Note 4. Discontinued Operations and Dispositions
Note 5. Property, Plant and Equipment and Jointly-Owned Facilities
Note 6. Regulatory Assets and Liabilities
Note 7. Long-Term Investments
Note 8. Financing Receivables
Note 9. Available-for-Sale Securities
Note 10. Goodwill and Other Intangibles
Note 11. Asset Retirement Obligations (AROs)
Note 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plans
Note 13. Commitments and Contingent Liabilities
Note 14. Schedule of Consolidated Debt
Note 15. Schedule of Consolidated Capital Stock
Note 16. Financial Risk Management Activities
Note 17. Fair Value Measurements
Note 18. Stock Based Compensation
Note 19. Other Income and Deductions
Note 20. Income Taxes
Note 21. Earnings Per Share (EPS) and Dividends
Note 22. Financial Information by Business Segment
Note 23. Related-Party Transactions
Note 24. Selected Quarterly Data (Unaudited)
Note 25. Guarantees of Debt
Item 9.
Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
Item 9A.
Controls and Procedures
Item 9B.
Other Information
Item 10.
Directors, Executive Officers and Corporate Governance
Item 11.
Executive Compensation
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13.
Certain Relationships and Related Transactions, and Director Independence
Item 14.
Principal Accounting Fees and Services
Item 15.
Exhibits and Financial Statement Schedules
Schedule II - Valuation and Qualifying Accounts
Glossary of Terms
Exhibit Index



Certain of the matters discussed in this report constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management’s beliefs as well as assumptions made by and information currently available to management. When used herein, the words “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “should,” “hypothetical,” “potential,” “forecast,” “project,” variations of such words and similar expressions are intended to identify forward-looking statements. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Other factors that could cause actual results to differ materially from those contemplated in any forward-looking statements made by us herein are discussed in Item 1A. Risk Factors, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A), Item 8. Financial Statements and Supplementary Data —Note 13. Commitments and Contingent Liabilities, and other factors discussed in filings we make with the United States Securities and Exchange Commission (SEC). These factors include, but are not limited to:
adverse changes in the demand for or the price of the capacity and energy that we sell into wholesale electricity markets,
adverse changes in energy industry law, policies and regulation, including market structures and a potential shift away from competitive markets toward subsidized market mechanisms, transmission planning and cost allocation rules, including rules regarding how transmission is planned and who is permitted to build transmission in the future, and reliability standards,
any inability of our transmission and distribution businesses to obtain adequate and timely rate relief and regulatory approvals from federal and state regulators,
changes in federal and state environmental regulations that could increase our costs or limit our operations,
changes in nuclear regulation and/or general developments in the nuclear power industry, including various impacts from any accidents or incidents experienced at our facilities or by others in the industry, that could limit operations of our nuclear generating units,
actions or activities at one of our nuclear units located on a multi-unit site that might adversely affect our ability to continue to operate that unit or other units located at the same site,
any inability to balance our energy obligations, available supply and risks,
any deterioration in our credit quality or the credit quality of our counterparties, including in our leveraged leases,
availability of capital and credit at commercially reasonable terms and conditions and our ability to meet cash needs,
changes in the cost of, or interruption in the supply of, fuel and other commodities necessary to the operation of our generating units,
delays in receipt of necessary permits and approvals for our construction and development activities,
delays or unforeseen cost escalations in our construction and development activities,
any inability to achieve, or continue to sustain, our expected levels of operating performance,
any equipment failures, accidents, severe weather events or other incidents that impact our ability to provide safe and reliable service to our customers,
increase in competition in energy supply markets as well as competition for certain rate-based transmission projects,
any inability to realize anticipated tax benefits or retain tax credits,
challenges associated with recruitment and/or retention of a qualified workforce,
adverse performance of our decommissioning and defined benefit plan trust fund investments and changes in funding requirements, and
changes in technology and customer usage patterns.

All of the forward-looking statements made in this report are qualified by these cautionary statements and we cannot assure you that the results or developments anticipated by management will be realized or, even if realized, will have the expected consequences to, or effects on, us or our business prospects, financial condition or results of operations. Readers are cautioned not to place undue reliance on these forward-looking statements in making any investment decision. Forward-looking statements made in this report apply only as of the date of this report. While we may elect to update forward-looking statements from time to time, we specifically disclaim any obligation to do so, even if internal estimates change, unless otherwise required by applicable securities laws.
The forward-looking statements contained in this report are intended to qualify for the safe harbor provisions of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.


This combined Annual Report on Form 10-K is separately filed by Public Service Enterprise Group Incorporated (PSEG), PSEG Power LLC (Power) and Public Service Electric and Gas Company (PSE&G). Information relating to any individual company is filed by such company on its own behalf. Power and PSE&G are each only responsible for information about itself and its subsidiaries.
Discussions throughout the document refer to PSEG and its direct operating subsidiaries, Power, PSE&G and PSEG Energy Holdings L.L.C. (Energy Holdings). Depending on the context of each section, references to “we,” “us,” and “our” relate to the specific company or companies being discussed. In addition, certain key acronyms and definitions are summarized in a glossary beginning on page 191.
We file annual, quarterly and special reports, proxy statements and other information with the SEC. You may read and copy any document that we file at the Public Reference Room of the SEC at 100 F Street, N.E., Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. You may also obtain our filed documents from commercial document retrieval services, the SEC’s internet website at or our website at 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.

We were incorporated under the laws of the State of New Jersey in 1985 and our principal executive offices are located at 80 Park Plaza, Newark, New Jersey 07102. We conduct our business through three direct wholly owned subsidiaries, Power, PSE&G and Energy Holdings, each of which also has its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. PSEG Services Corporation (Services), our other wholly owned subsidiary, provides us and these operating subsidiaries with certain management, administrative and general services at cost.
We are an energy company with a diversified business mix. Our operations are located primarily in the Northeastern and Mid- Atlantic United States. Our business approach focuses on operational excellence, financial strength and disciplined investment. As a holding company, our profitability depends on our subsidiaries’ operating results. Below are descriptions of our direct operating subsidiaries.
Energy Holdings
A Delaware limited liability company formed in 1999 that integrates its generating asset operations with its wholesale energy sales, fuel supply and energy trading functions.
Earns revenues from selling under contract or on the spot market a range of diverse products such as electricity, natural gas, capacity, emissions credits and a series of energy-related products used to optimize the operation of the energy grid.
A New Jersey corporation, incorporated in 1924, which is a franchised public utility in New Jersey. It is also the provider of last resort for gas and electric commodity service for end users in its service territory.
Earns revenues from its regulated rate tariffs under which it provides electric transmission and electric and gas distribution to residential, commercial and industrial customers in its service territory. It also offers appliance services and repairs to customers throughout its service territory.
Has also implemented demand response and energy efficiency programs and invested in solar generation within New Jersey.
A New Jersey limited liability
company (successor to a
corporation which was formed
in 1989) that invests and
operates through its two primary
Earns revenues primarily from its portfolio of lease investments and its solar generation projects.


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
Through Power, we seek to produce low-cost energy by efficiently operating our nuclear, coal, gas and oil-fired generation facilities, while balancing generation production, fuel requirements and supply obligations through energy portfolio management. We use commodity contracts and financial instruments, combined with our owned generation, to cover our commitments for Basic Generation Service (BGS) in New Jersey and other bilateral supply contract agreements.
Products and Services
As a merchant generator, our profit is derived from selling a range of products and services under contract to power marketers and to others, such as investor-owned and municipal utilities, and to aggregators who resell energy to retail consumers, or in the spot market. These products and services include:
Energy—the electrical output produced by generation plants that is ultimately delivered to customers for use in lighting, heating, air conditioning and operation of other electrical equipment. Energy is our principal product and is priced on a usage basis, typically in cents per kilowatt hour (kWh) or dollars per megawatt hour (MWh).
Capacity—a product distinct from energy, is a market commitment that a given generation unit will be available to an Independent System Operator (ISO) for dispatch if it is needed to meet system demand. Capacity is typically priced in dollars per megawatt (MW) for a given sale period.
Ancillary Services—related activities supplied by generation unit owners to the wholesale market, required by the ISO to ensure the safe and reliable operation of the bulk power system. Owners of generation units may bid units into the ancillary services market in return for compensatory payments. Costs to pay generators for ancillary services are recovered through charges imposed on market participants.
Emissions Allowances and Congestion Credits—Emissions allowances (or credits) represent the right to emit a specific amount of certain pollutants. Allowance trading is used to control air pollution by providing economic incentives for achieving reductions in the emissions of pollutants. Congestion credits (or Financial Transmission Rights) are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly congestion price differences across a transmission path.
Power also sells wholesale natural gas, primarily through a full requirements Basic Gas Supply Service (BGSS) contract with PSE&G to meet the gas supply requirements of PSE&G's customers. This long-term contract was for an initial period which extended through March 31, 2012 and continues on a year-to-year basis thereafter, unless terminated by either party with a one year notice.
Approximately 46% of PSE&G’s peak daily gas requirements is provided from Power’s firm transportation capacity, which is available every day of the year. Power satisfies the remainder of PSE&G’s requirements from storage contracts, liquefied natural gas, seasonal purchases, contract peaking supply, propane and refinery gas. Based upon availability, Power also sells gas to others.
How Power Operates
We own approximately 13,226 MW of generation capacity located in the Northeast and Mid-Atlantic regions of the United States in some of the country’s largest and most developed electricity markets.


The map below shows the locations of our Northeast and Mid-Atlantic generation facilities
Generation Capacity
Power has approved the expenditure of approximately $192 million for a steam path retrofit and related upgrades at its co-owned Peach Bottom Units 2 and 3. Unit 3 upgrades were completed in October 2011. Unit 2 upgrades were completed in October 2012. The balance of work to ensure efficient operation is expected to be completed by 2014. Total expenditures through December 31, 2012 were $154 million.
Power has also approved the expenditure of $419 million for an extended power uprate of the Peach Bottom nuclear units. The uprate is expected to result in an increase in Power’s share of nominal capacity by approximately 130 MW. The uprate is expected to be in service in 2015 for Unit 2 and 2016 for Unit 3. Total expenditures through December 31, 2012 were $73 million.
In 2011, we sold 2,000 MW of generation facilities we owned and operated in Texas. See Item 8. Financial Statements and Supplementary Data—Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies and Note 4. Discontinued Operations and Dispositions, for additional information.
For additional information on each of our generation facilities, see Item 2. Properties.
Our installed capacity utilizes a diverse mix of fuels: 45% gas, 28% nuclear, 18% coal, 8% oil and 1% pumped storage. This fuel diversity helps to mitigate risks associated with fuel price volatility and market demand cycles. Our total generating output in 2012 was approximately 53,000 gigawatt hours (GWh). The generation mix by fuel type has changed slightly in recent years due to the relatively favorable price of natural gas as compared to coal, making it more economical to run certain of our gas units than our coal units. The following table indicates the proportionate share of generating output by fuel type.


Generation by Fuel Type
Actual 2012
New Jersey facilities
Pennsylvania facilities
Pennsylvania facilities
Connecticut facilities
Coal and Natural Gas:
New Jersey facilities
Oil and Natural Gas:
New Jersey facilities
New York facilities
Connecticut facilities
(A) Less than one percent.

Generation Dispatch
Our generation units are typically characterized as serving one or more of three general energy market segments: base load; load following; and peaking, based on their operating capability and performance. On a capacity basis, our portfolio of generation assets consists of 33% base load, 43% load following and 24% peaking. This diversity helps to reduce the risk associated with market demand cycles and allows us to participate in the market at each segment of the dispatch curve.
Base Load Units run the most and typically operate whenever they are available. These units generally derive revenues from energy and capacity sales. Variable operating costs are low due to the combination of highly efficient operations and the use of relatively lower-cost fuels. Performance is generally measured by the unit’s “capacity factor,” or the ratio of the actual output to the theoretical maximum output. In 2012, our base load capacity factors were as follows:
Salem Unit 1
Salem Unit 2
Hope Creek
Peach Bottom Unit 2
Peach Bottom Unit 3
No assurances can be given that these capacity factors will be achieved in the future.
Load Following Units typically operate between 20% and 80% of the time. The operating costs are higher per unit of output due to lower efficiency and/or the use of higher-cost fuels such as oil, natural gas and, in some cases, coal. They operate less frequently than base load units and derive revenues from energy, capacity and ancillary services.
Peaking Units run the least amount of time and utilize higher-priced fuels. These units typically operate less than 20% of the time. Costs per unit of output tend to be much higher than for base load units. The majority of


revenues are from capacity and ancillary service sales. The characteristics of these units enable them to capture energy revenues during periods of high energy prices.
In the energy markets in which we operate, owners of power plants specify to the ISO prices at which they are prepared to generate and sell energy based on the marginal cost of generating energy from each individual unit. The ISOs will dispatch in merit order, calling on the lowest variable cost units first and dispatching progressively higher-cost units until the point that the entire system demand for power (known as the system “load”) is satisfied. Base load units are dispatched first, with load following units next, followed by peaking units.
During periods when one or more parts of the transmission grid are operating at full capability, thereby resulting in a constraint on the transmission system, it may not be possible to dispatch units in merit order without violating transmission reliability standards. Under such circumstances, the ISO will dispatch higher-cost generation out of merit order within the congested area and power suppliers will be paid an increased Locational Marginal Price (LMP) in congested areas, reflecting the bid prices of those higher-cost generation units.
The following chart depicts the merit order of dispatch of our units in PJM Interconnection L.L.C. (PJM), where most of our generation units are located, based on illustrative historical dispatch cost. It should be noted that market price fluctuations have resulted in changes from historical norms, with lower gas prices allowing some gas generation to displace some coal generation.
The size of each facility's fuel circle in the above chart illustrates the relative MW capacity of the generating capacity of that facility. For additional information on each of our generation facilities, see Item 2. Properties.
The bid price of the last unit dispatched by an ISO establishes the energy market-clearing price. After considering the market-clearing price and the effect of transmission congestion and other factors, the ISO calculates the LMP for every location in the system. The ISO pays all units that are dispatched their respective LMP for each MWh of energy produced, regardless of their specific bid prices. Since bids generally approximate the marginal cost of production, units with lower marginal costs typically generate higher operating profits than units with comparatively higher marginal costs.
This method of determining supply and pricing creates an environment in the markets such that natural gas prices often have a major impact on the price that generators will receive for their output, especially in periods of relatively strong demand. Therefore, significant changes in the price of natural gas will often translate into significant changes in the wholesale price of electricity. This can be seen in the following graphs which present historical annual spot prices and forward calendar prices as averaged over each year.


Historical data and forward prices would imply that the price of natural gas will continue to have a strong influence on the price of electricity in the primary markets in which we operate.
The prices reflected in the tables above do not necessarily illustrate our contract prices, but they are representative of market prices at relatively liquid hubs, with nearer-term forward pricing generally resulting from more liquid markets than pricing for later years. In addition, the prices do not reflect locational differences resulting from congestion or other factors, which can be considerable. While these prices provide some perspective on past and future prices, the forward prices are highly volatile and there can be no assurance that such prices will remain in effect or that we will be able to contract output at these forward prices.
Fuel Supply
Nuclear Fuel Supply—To run our nuclear units we have long-term contracts for nuclear fuel. These contracts provide for:
purchase of uranium (concentrates and uranium hexafluoride),
conversion of uranium concentrates to uranium hexafluoride,
enrichment of uranium hexafluoride, and
fabrication of nuclear fuel assemblies.


Coal Supply—Coal is the primary fuel for our Keystone, Conemaugh and Bridgeport stations. Coal is also used by Hudson and Mercer which operate on both coal and natural gas. We have coal contracts with numerous suppliers. Coal is delivered to our units through a combination of rail, truck, barge or ocean shipments.
In order to minimize emissions levels, our Bridgeport 3 unit uses a specific type of coal obtained from Indonesia. If the supply from Indonesia or equivalent coal from other sources was not available for this facility, its long-term operations would be adversely impacted since additional material capital expenditures would be required to modify our Bridgeport 3 station to enable it to operate using a broader mix of coal sources.
Gas Supply—Natural gas is the primary fuel for the bulk of our load following and peaking fleet. We purchase gas directly from natural gas producers and marketers. These supplies are transported to New Jersey by four interstate pipelines with whom we have contracted. In addition, we have firm gas transportation contracts to serve our Bethlehem Energy Center (BEC) in New York.
We have 1.3 billion cubic feet-per-day of firm transportation capacity under contract to meet our obligations under the BGSS contract. On an as available basis, this firm transportation capacity may also be used to serve the gas supply needs of our generation fleet. We supplement that supply with a total storage capacity of 76 billion cubic feet.
Oil—Oil is used as the primary fuel for one load following steam unit and nine combustion turbine peaking units and can be used as an alternate fuel by several load following and peaking units that have dual-fuel capability. Oil for operations is drawn from on-site storage and is generally purchased on the spot market and delivered by truck, barge or pipeline.
We expect to be able to meet the fuel supply demands of our customers and our own operations. However, the ability to maintain an adequate fuel supply could be affected by several factors not within our control, including changes in prices and demand, curtailments by suppliers, severe weather and other factors. For additional information, see Item 7. Management's Discussion and Analysis (MD&A)—Overview of 2012 and Future Outlook and Item 8. Financial Statements and Supplementary Data -Note 13. Commitments and Contingent Liabilities.
Markets and Market Pricing
Power’s generation assets are located in three centralized, competitive electricity markets operated by ISO organizations all of which are subject to the regulatory oversight of the Federal Energy Regulatory Commission (FERC):
PJM Regional Transmission Organization—PJM conducts the largest centrally dispatched energy market in North America. It serves over 60 million people, nearly 20% of the total United States population, and has a peak demand of over 163,848 MW. The PJM Interconnection coordinates the movement of electricity through all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. The majority of our generating stations operate in PJM.
New York—The NYISO is the market coordinator for New York State and is responsible for managing the New York Power Pool and for administering its energy marketplace. This service area has a population of about 19 million and a peak demand of over 33,939 MW. Our BEC station operates in New York.
New England—ISO-NE coordinates the movement of electricity in a region covering Maine, New Hampshire, Vermont, Massachusetts, Connecticut and Rhode Island. This service area has a population of about 14 million and a peak demand of over 28,130 MW. Our Bridgeport and New Haven stations operate in Connecticut.
The price of electricity varies by location in each of these markets. Depending upon our production and our obligations, these price differentials can serve to increase or decrease our profitability.
Commodity prices, such as electricity, gas, coal, oil and emissions, as well as the availability of our diverse fleet of generation units to produce these products, also have a considerable effect on our profitability. These commodity prices have been, and continue to be, subject to significant market volatility. Over the long-term, the higher the forward prices are, the more attractive an environment exists for us to contract for the sale of our anticipated output. However, higher prices also increase the cost of replacement power; thereby placing us at greater risk should our generating units fail to function effectively or otherwise become unavailable.
Over the past few years, a decline in wholesale natural gas prices has resulted in lower electricity prices. One of the reasons for the decline in natural gas prices is greater supply from shale production. This trend has reduced margin on forward sales as we re-contract our expected generation output.
In addition to energy sales, we also earn revenue from capacity payments for our generating assets. These payments are compensation for committing a portion of our capacity to the ISO for dispatch at its discretion. Capacity payments reflect the


value to the ISO of assurance that there is sufficient generating capacity available at all times to meet system reliability and energy requirements. Currently, there is sufficient capacity in the markets in which we operate. However, in certain areas of these markets there are transmission system constraints, raising concerns about reliability and creating a more acute need for capacity.
In PJM and ISO-NE, where we operate most of our generation, the market design for capacity payments provides for a structured, forward-looking, transparent capacity pricing mechanism. This is through the Reliability Pricing Model (RPM) in PJM and the Forward Capacity Market (FCM) in ISO-NE. These mechanisms provide greater transparency regarding the value of capacity, resulting in an improved pricing signal to prospective investors in new generating facilities so as to encourage expansion of capacity to meet future market demands.
The prices to be received by generating units in PJM for capacity have been set through RPM base residual auctions and depend upon the zone in which the generating unit is located. The majority of our PJM generating units are located in zones where the following prices have been set:
Delivery Year
June 2012 to May 2013


June 2013 to May 2014


June 2014 to May 2015


June 2015 to May 2016


For each delivery year, the prices differ in the various areas of PJM, depending on the constraints in each area of the transmission system. Keystone and Conemaugh receive lower prices than the majority of our PJM generating units since there are fewer constraints in that region and our generating units in northern New Jersey usually receive higher pricing.
The price that must be paid by an entity serving load in the various zones is also set through these auctions. These prices can be higher or lower than the prices noted in the table above due to import and export capability to and from lower-priced areas.
Like PJM and ISO-NE, the NYISO provides capacity payments to its generating units, but unlike the other two markets, the New York market does not provide a forward price signal beyond a six month auction period.
On a prospective basis, many factors may affect the capacity pricing, including but not limited to:
changes in load and demand,
changes in the available amounts of demand response resources,
changes in available generating capacity (including retirements, additions, derates, forced outages, etc.),
increases in transmission capability between zones,
changes to the pricing mechanism, including potentially increasing the number of zones to create more pricing sensitivity to changes in supply and demand, as well as other potential changes that PJM and the other ISOs may propose over time, and
changes driven by legislative and/or regulatory action, that permit states to subsidize local electric power generation.
For additional information on the RPM and FCM markets, as well as on state subsidization through various mechanisms, see Regulatory Issues—Federal Regulation.
Hedging Strategy
In an attempt to mitigate volatility in our results, we seek to contract in advance for a significant portion of our anticipated electric output, capacity and fuel needs. We seek to sell a portion of our anticipated lower-cost generation over a multi-year forward horizon, normally over a period of two to three years. We believe this hedging strategy increases stability of earnings.
Among the ways in which we hedge our output are: (1) sales at PJM West and (2) BGS contracts. Sales at PJM West reflect block energy sales at the liquid PJM Western Hub and other transactions that seek to secure price certainty for our generation related products. In addition, the BGS-Fixed Price contract, a full requirements contract that includes energy and capacity, ancillary and other services, is awarded for three-year periods through an auction process managed by the New Jersey Board of Public Utilities (BPU). The volume of BGS contracts and the electric utilities that our generation operations serve will vary from year to year. Pricing for the BGS contracts, including a capacity component, for recent and future periods by purchasing utility is as follows:


Load Zone ($/MWh)
Jersey Central Power & Light
Atlantic City Electric
Rockland Electric Company
We have obtained price certainty for all of our PJM and New England capacity through May 2016 through the RPM and FCM pricing mechanisms.
Although we enter into these hedges in an effort to provide price certainty for a large portion of our anticipated generation, there is variability in both our actual output as well as in our hedges. Our actual output will vary based upon total market demand, the relative cost position of our units compared to all units in the market and the operational flexibility of our units. Our hedge volume can also vary, depending on the type of hedge into which we have entered. The BGS auction, for example, results in a contract that provides for the supplier to serve a percentage of the default load of a New Jersey electric distribution company (EDC), that is, the load that remains after some customers have chosen to be served directly by third party suppliers. The amount of power supplied through the BGS auction varies based on the level of the EDC's default load, which is affected by the number of customers who choose a third party supplier, as well as by other factors such as weather and the economy.
Historically, the number of customers that have switched to third party suppliers was relatively constant, but in recent years, as market prices declined from past years' historic highs, there was additional incentive for more of the smaller commercial and industrial electric customers to switch. In a falling price environment, this has a negative impact on our margins, as the anticipated BGS pricing is replaced by lower spot market pricing. While this impact has been reduced as average BGS rates have declined to a level more closely resembling current market prices, customers may still see an incentive to switch to third party suppliers. We are unable to determine the degree to which this switching, or “migration,” will continue, but the impact on our results could be material.
As of February 6, 2013, we had contracted for the following percentages of our anticipated base load generation output for the next three years with modest amounts beyond 2015.
Base Load Generation
Generation Sales
Our strategy is to maintain certain levels of uranium in inventory and to make periodic purchases to support such levels. Our nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements for the three years. We also have various long-term fuel purchase commitments for coal to support our fossil generation stations. These purchase obligations are consistent with our strategy to enter into contracts for its fuel supply in comparable volumes to its sales contracts.
We take a more opportunistic approach in hedging our anticipated natural gas-fired generation. The generation from these units is less predictable, as a significant portion of these units will only dispatch when aggregate market demand has exceeded the supply provided by lower-cost units.
In a changing market environment, this hedging strategy may cause our realized prices to differ materially from current market prices. In a rising price environment, this strategy normally results in lower margins than would have been the case if little or no hedging activity had been conducted. Alternatively, in a falling price environment, this hedging strategy will tend to create margins higher than those implied by the then current market.


Our public utility, PSE&G, distributes electric energy and gas to customers within a designated service territory running diagonally across New Jersey where approximately 6.2 million people, or about 70% of New Jersey's population resides.
Products and Services
Our utility operations primarily earn margins through the transmission and distribution of electricity and the distribution of gas.
Transmission—the movement of electricity at high voltage from generating plants to substations and transformers, where it is then reduced to a lower voltage for distribution to homes, businesses and industrial customers. Our revenues for these services are based upon tariffs approved by the FERC.
Distribution—the delivery of electricity and gas to the retail customer’s home, business or industrial facility. Our revenues for these services are based upon tariffs approved by the BPU.
We also earn margins through competitive services, such as appliance repair. The commodity portion of our utility business’ electric and gas sales is managed by BGS and BGSS suppliers. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for our utility operations.
In addition to our current utility products and services, we have implemented several programs to increase the level of solar generation including:
a program to help finance the installation of solar power systems throughout our electric service area, and
a program to develop, own and operate solar power systems.
We have also implemented a set of energy efficiency and demand response programs to encourage conservation and energy efficiency by providing energy and cost saving measures directly to businesses and families. For additional information concerning these programs and the components of our tariffs, see Regulatory Issues.


How PSE&G Operates
We provide network transmission and point-to-point transmission services, which are coordinated with PJM, and provide distribution service to 2.2 million electric customers and 1.8 million gas customers in a service area that covers approximately 2,600 square miles running diagonally across New Jersey. We serve the most heavily populated, commercialized and industrialized territory in New Jersey, including its six largest cities and approximately three hundred suburban and rural communities.
We use formula rates for our transmission investments. Formula-type rates provide a method of rate recovery where the transmission owner annually determines its revenue requirements through a fixed formula which considers Operations and Maintenance expenditures, Rate Base and capital investments and applies an approved return on equity (ROE) in developing the weighted average cost of capital. Our approved rates provide for a base ROE of 11.68% on existing and new transmission investment, while certain investments are entitled to earn an additional incentive rate. For more information on current transmission construction activities, see Regulatory Issues, Federal Regulation—Transmission Regulation.
Transmission Statistics
December 31, 2012
Network Circuit Miles
Billing Peak (MW)
Historical Annual Load Growth 2008-2012
The primary business of our utility is the distribution of gas and electricity to end users in our service territory. Our load requirements were split among residential, commercial and industrial customers, as described below for 2012. We believe that we have all the franchise rights (including consents) necessary for our electric and gas distribution operations in the territory we serve.
% of 2012 Sales
Customer Type
While our customer base has remained steady, gas and electric load have declined as illustrated:
Electric and Gas Distribution Statistics
December 31, 2012
Number of
Electric Sales and Gas
Sold and Transported
Historical Annual Load Decline 2008-2012


Million Therms

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


Solar Generation
We have undertaken major initiatives in order to spur investment in solar power in New Jersey. For additional details, please refer to our discussion under Energy Policy.
Although commodity revenues make up almost 48% of our revenues, we make no margin on the supply of energy since the actual costs are passed through to our customers.
All electric and gas customers in New Jersey have the ability to choose their own electric energy and/or gas supplier. Pursuant to the BPU requirements, we serve as the supplier of last resort for electric and gas customers within our service territory that are not served by another supplier. As a practical matter, this means we are obligated to provide supply to a vast majority of residential customers and a smaller portion of commercial and industrial customers.
We procure the supply to meet our BGS obligations through auctions authorized by the BPU for New Jersey’s total BGS requirement. These auctions take place annually in February. Results of these auctions determine which energy suppliers are authorized to supply BGS to New Jersey’s EDCs. Once validated by the BPU, electricity prices for BGS service are set.
PSE&G procures the supply requirements of our default service BGSS gas customers through a full requirements contract with Power. The BPU has approved a mechanism designed to recover all gas commodity costs related to BGSS for residential customers. BGSS filings are made annually by June 1 of each year, with an effective date of October 1. Any difference between rates charged under the BGSS contract and rates charged to our residential customers is deferred and collected or refunded through adjustments in future rates. Commercial and industrial customers that do not have third party suppliers are also supplied under the BGSS arrangement. These customers are charged a market-based price largely determined by prices for commodity futures contracts.
Markets and Market Pricing
Historically, there has been significant volatility in commodity prices. Such volatility can have a considerable impact on us since a rising commodity price environment results in higher delivered electric and gas rates for customers. This could result in decreased demand for electricity and gas, increased regulatory pressures and greater working capital requirements as the collection of higher commodity costs from our customers may be deferred under our regulated rate structure. A declining commodity price on the other hand, would be expected to have the opposite effect. For additional information, including the impact of natural gas commodity prices on electricity prices such as BGS, see Item 7. MD&A—Overview of 2012 and Future Outlook.
Energy Holdings
Energy Holdings primarily owns and manages a portfolio of lease investments and solar generation projects and is exploring opportunities for additional investment in renewable generation.
Over the past several years, we have terminated all of our international leveraged leases in order to reduce the cash tax exposure related to these leases. We have also reduced our risk by opportunistically monetizing all of our previous international investments. In February, 2012, the California Public Utilities Commission approved the shutdown of GWF Power and we anticipate recovering the remaining book value of our investment. For additional information on these generation facilities, see Item 2. Properties.
Products and Services
The majority of our remaining $840 million of domestic lease investments are primarily energy-related leveraged leases. As of December 31, 2012, 67% of our total leveraged lease investments were rated as below investment grade by Standard & Poor's.
Our leveraged leasing portfolio is designed to provide a fixed rate of return. Leveraged lease investments involve three parties: an owner/lessor, a creditor and a lessee. In a typical leveraged lease financing, the lessor purchases an asset to be leased. The purchase price is typically financed 80% with debt provided by the creditor and the balance comes from equity funds provided by the lessor. The creditor provides long-term financing to the transaction secured by the property subject to the lease. Such long-term financing is non-recourse to the lessor and, with respect to our lease investments, is not presented on our Consolidated Balance Sheets.
The lessor acquires economic and tax ownership of the asset and then leases it to the lessee for a period of time no greater than 80% of its remaining useful life. As the owner, the lessor is entitled to depreciate the asset under applicable federal and state tax guidelines. The lessor receives income from lease payments made by the lessee during the term of the lease and from tax benefits associated with interest and depreciation deductions with respect to the leased property. Our ability to realize these tax


benefits is dependent on operating gains generated by our other operating subsidiaries and allocated pursuant to the consolidated tax sharing agreement between us and our operating subsidiaries.
Lease rental payments are unconditional obligations of the lessee and are set at levels at least sufficient to service the non-recourse lease debt. The lessor is also entitled to any residual value associated with the leased asset at the end of the lease term. An evaluation of the after-tax cash flows to the lessor determines the return on the investment. Under accounting principles generally accepted in the United States (GAAP), the leveraged lease investment is recorded net of non-recourse debt and income is recognized as a constant return on the net unrecovered investment.
For additional information on leases, including the credit, tax and accounting risks, see Item 1A. Risk Factors, Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Credit Risk, Item 8. Financial Statements and Supplementary Data—Note 8. Financing Receivables and Note 13. Commitments and Contingent Liabilities.
Through Energy Holdings, we own and operate solar projects in New Jersey, Delaware, Florida, Ohio and Arizona totaling 69 MW. See Item 2. Properties for additional information.
In January 2012, we acquired a 25 MW solar project in Arizona. This project is currently in service. All of the energy, capacity and environmental attributes generated by the project in the first 20 years are expected to be sold under a long-term power purchase agreement. The total investment for the project was approximately $75 million.
In September 2012, we acquired a 15 MW solar project in Delaware. This project is currently in service. The project has a 20-year power purchase agreement for energy and the majority of renewable energy credits with a wholesale electric utility servicing municipal EDCs in Delaware. Energy Holdings has issued guarantees of up to $37 million for payment of obligations related to the construction of the project, of which $4 million was outstanding as of December 31, 2012. The total investment for the project was approximately $47 million.
In December 2012, we acquired an additional 19 MW solar project currently under construction in Arizona. The project is expected to begin commercial operation in the latter half of 2013. Energy Holdings has issued guarantees of up to $48 million for payment of obligations related to the construction of the project, all of which were outstanding as of December 31, 2012. The total investment for the project is expected to be approximately $51 million.
Also, in December 2011, the Long Island Power Authority (LIPA) selected PSEG Long Island LLC (PSEG LI), a newly formed wholly owned subsidiary of Energy Holdings, to manage its electric transmission and distribution system in Long Island, New York. LIPA issued a press release that it had selected us for a variety of reasons, including our proven track record of first quartile customer service and reliability, commitment to cost control, corporate culture of transparency and local decision making, technical expertise and proven environmental track record. The ten-year contract, Operations Services Agreement (OSA), is scheduled to commence on January 1, 2014, following completion of the Transition Services Agreement (TSA). As part of the OSA, PSEG LI will be expected to develop and manage the implementation of a number of operational improvements to provide safe and reliable service for LIPA’s customers, increase customer satisfaction and manage the operational and maintenance costs of LIPA. In November, 2012, the Governor of New York initiated an inquiry into the current structure of LIPA as a political subdivision of the State Of New York. The privatization of LIPA's transmission and distribution system is among the restructuring options under consideration. LIPA has the right under the OSA and the TSA to terminate each agreement, in the event that LIPA elects to either transfer its transmission and distribution system to a third party (privatization) or operate and maintain its transmission and distribution system with its own employees (municipalization). If LIPA elects to implement either of these options, LIPA is required to pay PSEG LI its service fees, milestone payments and wind-down expenses, in each case up to the effective date of such termination.
Various market participants compete with us and one another in buying and selling in the wholesale energy markets, entering into bilateral contracts and selling to aggregated retail customers. Our competitors include:
merchant generators,
domestic and multi-national utility generators,
energy marketers,
banks, funds and other financial entities,
fuel supply companies, and
affiliates of other industrial companies.


New additions of lower-cost or more efficient generation capacity could make our plants less economical in the future. Although it is not clear if this capacity will be built or, if so, what the economic impact will be, such additions could impact market prices and our competitiveness.
Our business is also under competitive pressure due to demand side management (DSM) and other efficiency efforts aimed at changing the quantity and patterns of usage by consumers which could result in a reduction in load requirements. A reduction in load requirements can also be caused by economic cycles, weather, customer migration and other factors. It is also possible that advances in technology, such as distributed generation, will reduce the cost of alternative methods of producing electricity to a level that is competitive with that of most central station electric production. To the extent that additions to the transmission system relieve or reduce congestion in eastern PJM where most of our plants are located, our revenues could be adversely affected. Changes in the rules governing what types of transmission will be built, who is permitted to build transmission and who will pay the costs of future transmission could also impact our revenues.
We are also at risk if the states in which we operate take actions that interfere with competitive wholesale markets. For example, on January 28, 2011, New Jersey enacted a law establishing a long-term capacity agreement pilot program (LCAPP) which provides for up to 2,000 MW of subsidized base load or mid-merit electric power generation. This action may have the effect of artificially depressing prices in the competitive wholesale market and thus has the potential to harm competitive markets, on both a short-term and a long-term basis.
Environmental issues, such as restrictions on emissions of carbon dioxide (CO2) and other pollutants, may also have a competitive impact on us to the extent that it becomes more expensive for some of our plants to remain compliant, thus affecting our ability to be a lower-cost provider compared to competitors without such restrictions. In addition, most of our plants, which are located in the Northeast where rules are more stringent, can be at an economic disadvantage compared to our competitors in certain Midwest states. If any new legislation were to require our competitors to meet the environmental standards currently imposed upon us, we would likely have an economic advantage since we have already installed significant pollution-control technology at most of our fossil stations.
In addition, pressures from renewable resources could increase over time. For example, many parts of the country, including the mid-western region within the footprint of the Midwest Independent System Operator, the California ISO and the PJM region, have either implemented or proposed implementing changes to their respective regional transmission planning processes that may enable the construction of large amounts of “public policy” transmission to move renewable generation to load centers. For additional information, see the discussion in Regulatory Issues—Federal Regulation, below.
Our transmission and distribution business is minimally impacted when customers choose alternate electric or gas suppliers since we earn our return by providing transmission and distribution service, not by supplying the commodity. The demand for electric energy and gas by customers is affected by customer conservation, economic conditions, weather and other factors not within our control.
Changes in the current policies for building new transmission lines, such as those ordered by the FERC and being implemented by PJM and other ISOs to eliminate contractual provisions that provide us a “right of first refusal” to construct projects in our service territory, could result in additional competition to build transmission lines in our area in the future and would allow us to seek opportunities to build in other service territories.
Construction of new local generation, such as the proposed subsidized generation in New Jersey and Maryland, also has the potential to reduce the need for the construction of new transmission to transport remote generation and alleviate system constraints.
As of December 31, 2012, we had 9,798 employees within our subsidiaries, including 6,248 covered under collective bargaining agreements. During the fourth quarter of 2012, we reached agreements with four labor unions to extend their collective bargaining agreements for four years. Three of these agreements expire in April 2017 and one expires in October 2017. Collectively, these four unions represent approximately 80% of union employees of PSE&G, Power and Services. Our collective bargaining agreements with our other two unions are set to expire in April and May 2014, respectively. We believe we maintain satisfactory relationships with our employees.


Employees as of December 31, 2012








Total Employees




Number of Union Groups





Federal Regulation
The FERC is an independent federal agency that regulates the transmission of electric energy and gas in interstate commerce and the sale of electric energy and gas at wholesale pursuant to the Federal Power Act (FPA) and the Natural Gas Act. PSE&G and the generation and energy trading subsidiaries of Power are public utilities as defined by the FPA. The FERC has extensive oversight over such “public utilities.” FERC approval is usually required when a public utility seeks to: sell or acquire an asset that is regulated by the FERC (such as a transmission line or a generating station); collect costs from customers associated with a new transmission facility; charge a rate for wholesale sales under a contract or tariff; or engage in certain mergers and internal corporate reorganizations.
The FERC also regulates generating facilities known as qualifying facilities (QFs). QFs are cogeneration facilities that produce electricity and another form of useful thermal energy, or small power production facilities where the primary energy source is renewable, biomass, waste or geothermal resources. QFs must meet certain criteria established by the FERC. We own various QFs through Energy Holdings. QFs are subject to some, but not all, of the same FERC requirements as public utilities.
The FERC also regulates Regional Transmission Operators/ISOs, such as PJM, and their energy and capacity markets.
For us, the major effects of the FERC regulation fall into five general categories:
Regulation of Wholesale Sales—Generation/Market Issues
Energy Clearing Prices
Capacity Market Issues
Transmission Regulation
Regulation of Wholesale Sales—Generation/Market Issues
Market Power
Under FERC regulations, public utilities must receive FERC authorization to sell power in interstate commerce. They can sell power at cost-based rates or apply to the FERC for authority to make market based rate (MBR) sales. For a requesting company to receive MBR authority, the FERC must first make a determination that the requesting company lacks market power in the relevant markets and/or that market power in the relevant markets is sufficiently mitigated. The FERC requires that holders of MBR tariffs file an update every three years demonstrating that they continue to lack market power and/or that market power has been sufficiently mitigated and report in the interim to FERC any material change in facts from those the FERC relied on in granting MBR authority. 
PSE&G, PSEG Energy Resources & Trade LLC, PSEG Power Connecticut, PSEG Fossil LLC and PSEG Nuclear LLC were each granted continued MBR authority from the FERC in June 2011. PSEG New Haven LLC was also granted initial MBR authority in May 2012. Retention of MBR authority is important to the maintenance of our current generation business’ revenues.


Energy Clearing Prices
Energy clearing prices in the markets in which we operate are generally based on bids submitted by generating units. Under FERC-approved market rules, bids are subject to price caps and mitigation rules applicable to certain generation units. The FERC rules also govern the overall design of these markets. At present, all units receive a single clearing price based on the bid of the marginal unit (i.e. the last unit that must be dispatched to serve the needs of load). These FERC rules have a direct impact on the energy prices received by our units.
Capacity Market Issues
PJM, NYISO, and ISO-NE each have capacity markets that have been approved by FERC.
PJM—RPM is a locational installed capacity market design for the PJM region, including a forward auction for installed capacity. Under RPM, generators located in constrained areas within PJM are paid more for their capacity as an incentive to ensure adequate supply where generation capacity is most needed. The mechanics of RPM in PJM continue to evolve and be refined in stakeholder proceedings in which we are active, and there is currently significant discussion about the future role of demand response in the RPM market, including examining how demand response resources should be paid and how these resources and programs should be measured and verified to ensure their availability.
ISO-NE—ISO-NE’s market for installed capacity with all generators in New England provides fixed capacity payments. The market design consists of a forward-looking auction for installed capacity that is intended to recognize the locational value of generators on the system and contains incentive mechanisms to encourage generator availability during generation shortages. As in PJM, capacity market rules in ISO-NE continue to develop. We challenged in court the results of ISO-NE’s first forward capacity auction, arguing that our units received inadequate compensation notwithstanding the location of our resources in a constrained area. The D.C. Circuit Court of Appeals ruled in our favor and remanded the proceeding to the FERC where it remains pending. We and other generators also filed a complaint at the FERC regarding ISO-NE’s capacity market design, alleging that it insufficiently reflects locational capacity values. The FERC acted on the complaint, largely accepting the ISO-NE’s capacity market design; however, an appeal of this rule is pending.
NYISO—NYISO operates a short-term capacity market that provides a forward price signal only for six months into the future. The NYISO capacity model recognizes only two separate zones that potentially may separate in price: New York City and Long Island. NYISO is creating a third locality encompassing the lower Hudson Valley to take effect May 1, 2014. The exact configuration of this new zone has not yet been determined. The triennial process for updating demand curves used for establishing capacity prices is also underway. The NYISO is required to file with the FERC by the end of 2013 revised demand curves covering the May 1, 2014 through April 30, 2017 period. Discussions concerning other potential changes to NYISO capacity markets, including rules to govern payments and bidding requirements for generators proposing to exit the market but required to remain in service for reliability reasons, are also ongoing.  
Long-Term Capacity Agreement Pilot Program Act (LCAPP)—In 2011, the State of New Jersey concluded that new natural gas-fired generation was needed and enacted the LCAPP Act to subsidize approximately 2,000 MW of new generation. The LCAPP Act provided that subsidies would be offered through long-term standard offer capacity agreements (SOCAs) between selected generators and the New Jersey Electric Distribution Companies (EDCs). The SOCA required each New Jersey EDC to provide the generators with guaranteed capacity payments funded by ratepayers. Each of the New Jersey EDCs, including PSE&G, entered into the SOCAs as directed by the State, but did so under protest reserving their rights. In May 2012, two of the three generators, CPV Shore, LLC (CPV), a subsidiary of Competitive Power Ventures, Inc. and Hess Newark, LLC (Hess), a subsidiary of Hess Corporation, that received SOCA contracts cleared the RPM auction for the 2015/2016 delivery year in the aggregate notional amount of approximately 1,300 MW of installed capacity.
Legal challenges to the BPU's implementation of the LCAPP Act were filed in New Jersey appellate court and the appeal remains pending. In addition, the LCAPP Act has been challenged on constitutional grounds in federal court. The hearing for this matter is scheduled to begin in March 2013.
Maryland is also taking action to subsidize above-market new generation. In April 2012, the Maryland Public Service Commission (PSC) issued an order requiring the Maryland utility companies to enter into a contract with CPV Shore, LLC (CPV) to build a new 661 MW natural gas-fired, combined cycle station in Maryland with an in-service date of June 2015. This contract has not yet been finalized, as the Maryland PSC continues to evaluate its terms. In the May 2012 RPM auction, the CPV generator cleared the auction. We have joined other generators in challenging this order on constitutional grounds in federal court and that case is set for hearing in March 2013. The Maryland EDCs have also appealed the April 2012 order in state court.
These efforts to artificially depress prices in the wholesale capacity auction were intended to be mitigated by the Minimum Offer Price Rule (MOPR) approved by the FERC. The MOPR was intended to restrict new generation from bidding in RPM at less than an established minimum level established by Tariff, or a cost-based bid to the extent that the generator can demonstrate that its costs are lower than the MOPR. The MOPR was in place for the May 2012 auction, but we believe it did


not operate to protect the market against these suppression efforts given that two of the three SOCA generators cleared the auction. As a result, discussions among a diverse group of PJM stakeholders to improve the MOPR ensued and a settlement was reached among those stakeholders. That proposal was then subject to a PJM stakeholder review and vote. The proposal was modified and received almost a 90% supporting vote. In December 2012, PJM filed Tariff changes with the FERC to implement the revised MOPR. In February 2013, the FERC issued a deficiency letter to PJM seeking additional information regarding the proposed MOPR changes. PJM must respond to those changes within 30 days and then the FERC has 60 days to act on the proposal. If FERC approves the proposal, we believe these modifications should significantly improve the MOPR rules and appropriately reduce the ability for subsidized generation assets to artificially suppress wholesale market prices. We cannot predict the outcome of this matter.
Transmission Regulation
The FERC has exclusive jurisdiction to establish the rates and terms and conditions of service for interstate transmission. We currently have FERC-approved formula rates in effect to recover the costs of our transmission facilities. Under this formula, rates are put into effect in January of each year based upon our internal forecast of annual expenses and capital expenditures. Rates are then trued up the following year to reflect actual annual expenses/capital expenditures. Our allowed ROE is 11.68% for both existing and new transmission investments and we have received incentive rates, affording a higher ROE, for certain large scale transmission investments. Our 2012 Annual Formula Rate Update with the FERC provided for approximately $94 million in increased annual transmission revenues effective January 1, 2012. We filed our 2013 Annual Formula Rate Update with the FERC in October 2012, which provides for approximately $174 million in increased annual transmission revenues effective January 1, 2013.
Transmission Policy Developments—In 2010, the FERC initiated a proceeding to evaluate whether reforms to current transmission planning and cost allocation rules were necessary to stimulate additional transmission development. The rulemaking also addressed the issue of whether construction of transmission should be opened up to competition by eliminating the “right of first refusal” (ROFR) under which incumbent transmission companies such as PSE&G have a ROFR to build transmission located within their respective service territories. The FERC ultimately concluded in Order No. 1000 that the ROFR should be eliminated, subject to certain exceptions, and left it to Regional Transmission Organizations/Independent System Operators such as PJM to establish the implementation details. We, along with many other companies, have challenged the FERC's orders in federal court. In addition, we have joined other PJM transmission owners in filing for the FERC approval of new rules that will determine who pays for future transmission projects in PJM.
We cannot predict the final outcome or impact on us; however, specific implementation of Order 1000 in the various regions, including within our service territory, may expose us to competition for certain types of transmission projects, while at the same time providing opportunities to build transmission outside of our service territory.
Transmission Expansion—In June 2007, PJM identified the need for the construction of the Susquehanna-Roseland line, a new 500 kiloVolt (kV) transmission line intended to maintain the reliability of the electrical grid serving New Jersey customers. PJM assigned construction responsibility for the new line to us and PPL Corporation (PPL) for the New Jersey and Pennsylvania portions of the project, respectively. The estimated cost of our portion of this construction project is up to $790 million, and PJM had originally directed that the line be placed into service by June 2012. As of December 31, 2012, total capital expenditures were $324 million. Construction of the Susquehanna-Roseland line is contingent upon obtaining all necessary federal, state, municipal and landowner permits and approvals. We have obtained environmental permits for the project from the New Jersey Department of Environmental Protection (NJDEP). On October 1, 2012, the National Park Service (NPS) issued a final Environmental Impact Statement (EIS) for the Susquehanna-Roseland line, selecting our and PPL's choice of route in certain federal park lands subject to the NPS' jurisdiction that follows the existing right of way. On October 15, 2012, several environmental groups filed a complaint in federal court, which, as amended, challenges the NPS' issuance of the final EIS, seeking to set aside the EIS and asking the court for an injunction that would generally prohibit construction of the project within the federal park lands at issue. If this request for injunctive relief is granted, the construction schedule for the project could be impacted. We have begun construction in those areas where necessary permits have been obtained. Currently, the expected in-service date for the Eastern segment of the project is June 2014 and for the Western segment is June 2015, although further delays are possible. Delays in the construction schedule could impact the cost of construction and the timing of expected transmission revenues.
Also, in 2010, certain environmental groups had appealed the BPU's approval of the Susquehanna-Roseland line, although no stay was sought. On February 11, 2013, the Appellate Division of the New Jersey Superior Court issued an order rejecting the appeal and affirming the BPU's approval of the project.


We had previously been directed by PJM to build a 500 kV reliability project from Branchburg to Roseland to Hudson. The scope of this project has since changed; it is now a 230 kV project referred to as the Northeast Grid project, for which we are currently seeking to obtain municipal siting approvals. The Northeast Grid project has an expected in-service date of June 2015 and an estimated cost of construction of $895 million. As of December 31, 2012, total capital expenditures were $88 million.
In 2012, both the BPU and the NJDEP approved siting of the North Central Reliability project. This project, which involves upgrading certain circuits and switching stations from 138 kV to 230 kV in the northern and central portions of New Jersey, is estimated to cost up to $390 million and has an in-service date of June 2014. The project is currently under construction and, as of December 31, 2012, total capital expenditures for this project were $163 million.
In 2012, we received both municipal siting and the NJDEP approval for the Burlington-Camden project. The project, which also involves upgrading certain circuits and switching stations from 138 kV to 230 kV in the southern portion of New Jersey, is estimated to cost up to $399 million and has an in-service date of June 2014. The project is currently under construction. As of December 31, 2012, total capital expenditures for the project were $169 million.
We are still in the process of obtaining necessary municipal and environmental approvals for the Mickleton-Gloucester-Camden project. This is another project that involves converting both circuits and switching stations from 138 kV to 230 kV in southern New Jersey and is estimated to cost up to $435 million. The project has an in-service date of June 2015. This project is still in the engineering/design phase and, as of December 31, 2012, total capital expenditures were $24 million.
Transmission Rate Proceedings—In September 2011, the Massachusetts Attorney General, along with several state utility commissions, consumer advocates and consumer groups from six New England states, filed a complaint at the FERC against a group of New England transmission owners seeking to reduce the base return on equity used in calculating these transmission owners' formula transmission rates. The matter has been set for hearing, and the proceeding is pending. In addition, there have been FERC complaints filed by municipal utilities in New York against a New York transmission-owning utility seeking to lower that utility's transmission ROE. While we are not the subject of any of these complaints. The results of these proceedings could set a precedent for the FERC-regulated transmission owners with formula rates in place, such as ours.
    FERC Audit—Each of the PSEG companies that have MBR authority from the FERC is being audited by the FERC for compliance with its rules for (i) receiving and retaining MBR authority (ii) the filing of electric quarterly reports and (iii) our units' receipt of payments from the RTO/ISO when they are required to run for reliability reasons when it is not economic for them to do so. The FERC will issue a report at the conclusion of the audit.
    Reliability Standards—Congress has required the FERC to put in place, through the North American Electric Reliability Council (NERC), national and regional reliability standards to ensure the reliability of the United States electric transmission and generation system and to prevent major system blackouts. Many reliability standards have been developed and approved. These standards apply both to reliability of physical assets interconnected to the bulk power system and to the protection of critical cyber assets. Our generation assets were audited in 2011 and our utility assets were audited in 2012. NERC compliance represents a significant and challenging area of compliance responsibility for us. As new standards are developed and approved, existing standards are revised and registration requirements are modified which could increase our compliance responsibilities.
Commodity Futures Trading Commission (CFTC)
In accordance with the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), the SEC and the CFTC are in the process of implementing a new regulatory framework for swaps and security-based swaps. The legislation was enacted to reduce systemic risk, increase transparency and promote market integrity within the financial system by providing for the registration and comprehensive regulation of swap dealers and by imposing recordkeeping, data reporting, margin and clearing requirements with respect to swaps. To implement the Dodd-Frank Act, the CFTC has engaged in a comprehensive rulemaking process and has issued a number of proposed and final rules addressing many of the key issues. For example, the CFTC has issued rules defining the term “swap dealer” and “commercial end user” (We fall in the latter category). The CFTC also issued rules establishing position limits for trading in certain commodities, such as natural gas but a federal court vacated these rules. The CFTC has appealed this decision to vacate the position limits rules. We are currently preparing to comply with the new record keeping and data reporting requirements of the Dodd-Frank Act applicable to commercial end users, for compliance in April 2013. We are continuing to analyze the potential impact of these rules and preparing to comply with the requirements that apply to entities that are considered commercial end-users under the Dodd-Frank Act.


Nuclear Regulatory Commission (NRC)
Our operation of nuclear generating facilities is subject to comprehensive regulation by the NRC, a federal agency established to regulate nuclear activities to ensure protection of public health and safety, as well as the security and protection of the environment. Such regulation involves testing, evaluation and modification of all aspects of plant operation in light of NRC safety and environmental requirements. Continuous demonstration to the NRC that plant operations meet requirements is also necessary. The NRC has the ultimate authority to determine whether any nuclear generating unit may operate. The current operating licenses of our nuclear facilities expire in the years shown below:
Salem Unit 1
Salem Unit 2
Hope Creek
Peach Bottom Unit 2
Peach Bottom Unit 3
In 2010, we also filed an application for an Early Site Permit (ESP) for a new nuclear generating station to be located at the current site of the Salem and Hope Creek generating stations. The NRC acceptance review is complete and agency evaluation is underway. There were no petitions filed for permission to intervene. The current NRC schedule would likely result in a decision with respect to the issuance of the ESP in 2015. While the ESP qualifies the site as an approved location for a new reactor for a period of 20 years, it imposes no obligation to do so.
As a result of events at the Fukushima Daiichi nuclear facility in Japan following the earthquake and tsunami in March 2011, the NRC began performing additional operational and safety reviews of nuclear facilities in the United States. These reviews and the lessons learned from the events in Japan have resulted in additional regulation for the nuclear industry and could impact future operations and capital requirements for our facilities. We believe that our nuclear plants currently meet the stringent applicable design and safety specifications of the NRC.
In 2011, the NRC task force submitted a report containing various recommendations to ensure plant protection, enhance accident mitigation, strengthen emergency preparedness and improve NRC program efficiency. The NRC staff also issued a document which provided for a prioritization of the task force recommendations. The NRC approved the staff's prioritization and implementation recommendations subject to a number of conditions. Among other things, the NRC advised the staff to give the highest priority to those activities that can achieve the greatest safety benefit and/or have the broadest applicability (Tier 1), to review filtration of boiling water reactor (BWR) primary containment vents and encouraged the staff to create requirements based on a performance-based system which allows for flexible approaches and the ability to address a diverse range of site-specific circumstances and conditions and strive to implement the requirements by 2016. The NRC issued letters and orders to licensees implementing the Tier 1 recommendations in March 2012. Additional regulations are expected.
Separately, a petition was filed with the NRC in April 2011 seeking suspension of the operating licenses of all General Electric BWRs utilizing the Mark I containment design in the United States, including our Hope Creek and Peach Bottom units, pending completion of the NRC review. Fukushima Daiichi Units 1-4 are BWRs equipped with Mark I containments. The petition names 23 of the total 104 active commercial nuclear reactors in the United States. While we do not believe the petition will be successful, we are unable to predict the outcome of any action that the NRC may take in connection with the petition
State Regulation
Since our operations are primarily located within New Jersey, our principal state regulator is the BPU, which oversees electric and natural gas distribution companies in New Jersey. Our utility operations are subject to comprehensive regulation by the BPU including, among other matters, regulation of retail electric and gas distribution rates and service, the issuance and sale of certain types of securities and compliance matters. PSE&G's participation in solar, demand response and energy efficiency programs is also regulated by the BPU, as the terms and conditions of these programs are approved by the BPU. BPU regulation can also have a direct or indirect impact on our power generation business as it relates to energy supply agreements and energy policy in New Jersey.
We are also subject to various other states’ regulations due to our operations in those states.
Electric and Gas Base Rates—We must file electric and gas rate cases with the BPU in order to change our utility base distribution rates. Our last base rate adjustment was in 2010.


Rate Adjustment Clauses and Other Regulatory Filings—In addition to base rates, we recover certain costs or earn on certain investments, from customers pursuant to mechanisms known as adjustment clauses. These clauses permit, at set intervals, the flow-through of costs to, or the recovery of investments from, customers related to specific programs, outside the context of base rate case proceedings. Recovery of these costs or investments is subject to BPU approval for which we make periodic filings. Delays in the pass-through of costs or recovery of investments under these mechanisms could result in significant changes in cash flow. For additional information on our specific filings, see Item 8. Financial Statements and Supplementary Data—Note 6. Regulatory Assets and Liabilities.
Some of our more significant recovery mechanisms and filings are as follows:
Storm Damage Deferral—In December 2012, the BPU granted our request to defer on our books actually incurred, uninsured, incremental storm restoration costs to our gas and electric distribution systems associated with extraordinary storms, including Hurricane Irene and Superstorm Sandy. In February 2013, the BPU announced that it would initiate a generic proceeding to evaluate the prudency of extraordinary, storm-related costs incurred by all of the regulated utilities as a result of the natural disasters experienced in New Jersey in 2011 and 2012 and in this proceeding will consider the manner in which such prudent costs shall be recovered.
Capital Infrastructure Programs (CIP I and CIP II)—We have received approval from the BPU for programs that provide for accelerated investment in utility infrastructure. The goal of these accelerated capital investments is to improve the reliability of our utility's infrastructure and New Jersey's economy through job creation. The programs allow us to receive a full return of and on our investments. In December 2012, the BPU approved stipulations regarding our CIP I and CIP II filings effective January 1, 2013. These Orders resulted in a combined increase of $40 million and $23 million for electric and gas customers, respectively.
Weather Normalization Clause (WNC)—Our WNC is an annual rate mechanism that allows us to increase our rates to compensate for lower revenues we receive from customers as a result of warmer-than-normal winters and to decrease our rates to make up for higher revenues we receive as a result of colder-than-normal winters. The payments and refunds are subject to certain limitations and rate caps. Unrecovered balances associated with application of the rate cap are deferred until the next recovery period. This rate mechanism requires us to calculate, at the end of each October-to-May period, the level by which margin revenues differed from what would have resulted if normal weather had occurred. In June 2012, we filed a petition and testimony with the BPU including eight months of actual and four months of forecasted data, which sought BPU approval to recover $41 million in deficiency revenues from our customers during the 2012-2013 Winter Period (October 1 to May 31) and a carryover deficiency of $16 million to the 2013-2014 Winter Period. In September 2012, an Order approving the stipulation for provisional rates was signed. In December 2012, we made a supplemental filing incorporating twelve months of actual financial data, which would, if approved by the BPU, result in no change to customer rates during the 2012-2013 Winter Period. The supplemental filing would, however, result in an increase of the carryover deficiency to the 2013-2014 Winter Period from $16 million to $24 million. We are awaiting a final Order.
Solar and Energy Efficiency Recovery Charges (RRC)—are comprised of: Carbon Abatement, Energy Efficiency Economic Stimulus Program (EEE), EEE Extension, Demand Response, Solar 4 All, and Solar Loan II. These programs are aimed at reducing the New Jersey's Greenhouse Gas (GHG) Emissions. We file for annual recovery for our investments under these programs which includes a return on our investment and recovery of expenses. In July 2012, we filed a petition with the BPU requesting an increase in RRC seeking to recover approximately $62 million in electric revenue and $8 million in gas revenue, on an annual basis consistent with the terms of the approved program. The discovery phase of this proceeding is underway.

Other material rate filings pending before the BPU include:

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


Solar 4 All Extension—In July 2012, we filed for an extension of our Solar 4 All program. In this filing, we are seeking BPU approval to invest up to $690 million to develop 136 MW of utility-owned solar photovoltaic systems over a five year period starting in 2013. Consistent with the existing Solar 4 All program, we propose to sell the energy and capacity from the solar systems in the PJM wholesale energy and capacity markets which will offset the cost of the program.
We also filed for an additional extension of our Solar Loan program (Solar Loan III) in July 2012. In the filing, we are seeking BPU approval to provide financing support for the installation of 97.5 MW of solar systems by providing loans to qualified customers. The total investment of the proposed Solar Loan III program is anticipated to be up to $193 million once the program is fully subscribed, the projects are built and the loans are closed.
Energy Supply
BGS—New Jersey’s EDCs provide two types of BGS, the default electric supply service for customers who do not have a third party supplier. The first type, which represents about 80% of PSE&G’s load requirements, provides default supply service for smaller industrial and commercial customers and residential customers at seasonally-adjusted fixed prices for a three-year term (BGS-Fixed Price). These rates change annually on June 1 and are based on the average price obtained at auctions in the current year and two prior years. The second type provides default supply for larger customers, with energy priced at hourly PJM real-time market prices for a contract term of 12 months (BGS-CIEP).
All of New Jersey’s EDCs jointly procure the supply to meet their BGS obligations through two concurrent auctions authorized each year by the BPU for New Jersey’s total BGS requirement. These auctions take place annually in February. Results of these auctions determine which energy suppliers provide BGS to New Jersey’s EDCs.
Approximately one-third of PSE&G’s total BGS-Fixed Price eligible load is auctioned each year for a three-year term. Current pricing is as follows:
36 Month Terms Ending
May 2013

May 2014

May 2015

May 2016

Eligible Load (MW)




$ per kWh




(A)Prices set in the February 2013 BGS Auction will be effective on June 1, 2013 when the 2010 BGS agreements expire.
The BPU approved the auction process for 2013 with no significant changes to the process.
For additional information, see Item 8. Financial Statements and Supplementary Data— Note 13. Commitments and Contingent Liabilities.
BGSS—BGSS is the mechanism approved by the BPU designed to recover all gas costs related to the supply for residential customers. BGSS filings are made annually by June 1 of each year, with an effective date of October 1. PSE&G’s revenues are matched with its costs using deferral accounting, with the goal of achieving a zero cumulative balance by September 30 of each year. In addition, we have the ability to put in place two self-implementing BGSS increases on December 1 and February 1 of up to 5% and also may reduce the BGSS rate at any time.
PSE&G had a full requirements contract with Power for an initial period which extended through March 2012 to meet the supply requirements of default service gas customers. This long-term contract continues on a year-to-year basis thereafter, unless terminated by either party with a one year notice. Power charges PSE&G for gas commodity costs which PSE&G recovers from customers. Any difference between rates charged by Power under the BGSS contract and rates charged to PSE&G’s residential customers are deferred and collected or refunded through adjustments in future rates. PSE&G earns no margin on the provision of BGSS.
In June 2012, we made our annual BGSS filing with the BPU. The filing requested a decrease in annual BGSS revenue of $71 million, excluding sales and use tax, to be effective October 1, 2012. This represented a reduction of approximately 5.2% for a typical residential gas heating customer. This BGSS reduction was the ninth consecutive reduction since January 2009. We entered into a Stipulation with the parties which put the requested lower BGSS rate into effect as filed on October 1, 2012 on a provisional basis. A final decision is expected in early 2013.


Energy Policy
New Jersey Energy Master Plan (EMP)—New Jersey law requires that an EMP be developed every three years, the purpose of which is to ensure safe, secure and reasonably-priced energy supply, foster economic growth and development and protect the environment. The most recent EMP was finalized in December 2011.
The 2011 EMP places an emphasis on expanding in-state electricity resources and reducing energy costs. The plan also recognizes the impact of climate change and accepts the previously set goal of a 22.5% target for the renewable portfolio standard (RPS) in 2021. It also references a goal that 70% of New Jersey’s energy supplies should be from clean energy sources by 2050. To meet this goal, the plan redefined clean energy to include nuclear, natural gas and hydro power along with defined renewable sources and proposes a number of changes aimed at reducing the cost of achieving the 22.5% goal.
Specific program initiatives in the EMP include:
construction of new combined cycle natural gas plants through the implementation of LCAPP, with the continued State challenge to FERC and PJM policies on market pricing rules in the capacity market,
support for construction of new nuclear generation,
changes to the solar program to reduce cost, expand opportunities, expand transparency and ensure economic and environmental benefits,
expanded natural gas use to meet energy needs,
development of decentralized combined heat and power,
redesign of the delivery of state energy efficiency programs, and
continued support for implementation of off-shore wind, without setting a specific capacity goal.
Solar Initiatives—In order to spur investment in solar power in New Jersey and meet renewable energy goals, we have undertaken two major initiatives at PSE&G.
Solar Loans: The first solar initiative helps finance the installation of 81 MW of solar systems throughout our electric service area by providing loans to customers. The borrowers can repay the loans over a period of either 10 years (for residential customer loans) or 15 years (for non-residential customers), by providing us with solar renewable energy certificates (SRECs) or cash. The value of the SRECs towards the repayment of the loan is guaranteed to be not less than a floor price. SRECs received by us in repayment of the loan are sold through a periodic auction. Proceeds are used to offset program costs.
The total investment of both phases of the Solar Loan Program is expected to be between $210 million and $250 million once the program is fully subscribed, projects are built and loans are closed. As of December 31, 2012, we have provided a total of $209 million in loans for 878 projects representing 67 MW.
Solar 4 All: The second solar initiative is the Solar 4 All Program under which we are investing approximately $456 million to develop 80 MW of utility-owned solar photovoltaic (PV) systems over four years. The program consists of centralized solar systems 500 kW or greater installed on PSE&G-owned property and third-party sites in our electric service territory (40 MW) and solar panels installed on distribution system poles (40 MW). We sell the energy and capacity from the systems in the PJM wholesale electricity market. In addition, we sell any SRECs received from the projects through the same auction used in the loan program. Proceeds from these sales are used to offset program costs.
As of December 31, 2012, we have installed and placed in service 35 MW on approximately 160,000 distribution poles with an investment of approximately $245 million, and 39 MW of centralized solar systems representing 23 projects with an investment of approximately $192 million
BPU Storm Report In 2011, the BPU commenced an investigation of all four New Jersey electric utilities, including PSE&G, to examine their preparations, performance and restoration efforts during Hurricane Irene and the October 2011 snow storm. Following the completion of a report by its consultant, the BPU issued an order in January 2013, ordering the utilities to take specific action to improve their preparedness and responses to major storms. There are 103 separate measures contained in the Order, with most of the measures requiring utility implementation by September 2013.  We are evaluating the implications of this report.


BPU Audits
Management/Affiliate Audit—In 2009, the BPU, in accordance with New Jersey statutes, initiated audits of PSE&G with respect to the effectiveness of its management and its compliance with rules governing PSE&G's interactions with its affiliated companies. In 2012, the BPU issued a report making a number of findings and recommendations, including the finding that no violations of either the state or federal affiliate rules were found. The BPU is expected to issue an order addressing the audit report's findings and recommendations, although timing is uncertain.
BPU Investigations
RRC/CIP—In January 2012, New Jersey's Rate Counsel requested that the BPU investigate certain allegations of wrong doing in PSE&G’s solar, EEE, and CIP programs raised by three former employees in a lawsuit. The BPU initiated an inquiry into these allegations and requested documentation from PSE&G. PSE&G has cooperated with the BPU and provided all requested information and documentation.

Changing environmental laws and regulations significantly impact the manner in which our operations are currently conducted and impose costs on us to reduce the health and environmental impacts of our operations. To the extent that environmental requirements are more stringent and compliance more costly in certain states where we operate compared to other states that are part of the same market, such rules may impact our ability to compete within that market. Due to evolving environmental regulations, it is difficult to project future costs of compliance and their impact on competition. Capital costs of complying with known pollution control requirements are included in our estimate of construction expenditures in Item 7. MD&A—Capital Requirements. The costs of compliance associated with any new requirements that may be imposed by future regulations are not known, but may be material.
Areas of environmental regulation may include, but are not limited to:
air pollution control,
climate change,
water pollution control,
hazardous substance liability, and
fuel and waste disposal.

For additional information related to environmental matters, including proceedings not discussed below, as well as anticipated expenditures for installation of pollution control equipment, hazardous substance liabilities and fuel and waste disposal costs, see Item 1A. Risk Factors, Item 3. Legal Proceedings and Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities.
Air Pollution Control
Our facilities are subject to federal regulation under the Clean Air Act (CAA) which requires controls of emissions from sources of air pollution and imposes record keeping, reporting and permit requirements. Our facilities are also subject to requirements established under state and local air pollution laws.
The CAA requires all major sources, such as our generation facilities, to obtain and keep current an operating permit. The costs of compliance associated with any new requirements that may be imposed and included in these permits in the future could be material and are not included in our estimates of capital expenditures.
New Jersey Nitrogen Oxide (NOx) Regulation: High Electric Demand Day—In April 2009, the New Jersey Department of Environmental Protection (NJDEP) finalized revisions to NOx emission control regulations that impose new NOx emission reduction requirements and limits for New Jersey fossil fuel-fired electric generation units. The rule has an impact on our generation fleet, as it imposes NOx emissions limits that require capital investment for controls or the retirement of up to 86 combustion turbines (approximately 1,750 MW) and four older New Jersey steam electric generation units (approximately 400 MW) by May 2015. Retirement notifications for the combustion turbines, except for Salem Unit 3, have been filed with PJM.  The Salem Unit 3 combustion turbine (38 MW) will be transitioning to an emergency generator. Evaluations are ongoing for the steam electric generation units.
Connecticut NOx Regulation—Under current Connecticut regulations, our Bridgeport and New Haven facilities have been utilizing Discrete Emission Reduction Credits (DERCs) to comply with certain NOx emission limitations that


were incorporated into the facilities’ operating permits. In 2010, we negotiated new agreements with the State of Connecticut extending the continued use of DERCs for certain emission units and equipment until May 31, 2014.
Hazardous Air Pollutants Regulation—In accordance with a ruling of the United States Court of Appeals of the District of Columbia (Court of Appeals), the EPA published a Maximum Achievable Control Technology (MACT) regulation on February 16, 2012. These Mercury Air Toxics Standards (MATS) are scheduled to go into effect on April 16, 2015 and establish allowable emission levels for mercury as well as other hazardous air pollutants pursuant to the CAA. In February 2012, members of the electric generating industry filed a petition challenging the existing source National Emission Standard for Hazardous Air Pollutants (NESHAP), new source NESHAP and the New Source Performance Standard (NSPS). In March 2012, PSEG filed a motion to intervene with the Court of Appeals in support of the EPA's implementation of MATS. The Court of Appeals has split the litigation related to these matters into three cases, addressing separately the existing source NESHAP, new source NESHAP and the NSPS.  These cases remain pending. The EPA has stayed implementation of the new source NESHAP rule pending its reconsideration. The EPA published the proposed reconsideration for the new source NESHAP and the NSPS in the Federal Register on November 30, 2012. The EPA expects to finalize the reconsideration of the new source NESHAP and the NSPS in March 2013.
The impact to our fossil generation fleet in New Jersey and Connecticut and our jointly-owned coal fired generating facilities in Pennsylvania is currently being determined. We believe the back-end technology environmental controls installed at our Hudson and Mercer coal facilities should meet the MACT's requirements. Some additional controls could be necessary at our Connecticut facility, pending engineering evaluation. In December 2011, a decision was reached to upgrade the previously planned two flue gas desulfurization scrubbers and install Selective Catalytic Reduction (SCR) systems at our jointly-owned coal fired generating facility at Conemaugh in Pennsylvania. This installation is expected to be completed in the fourth quarter of 2014. Our share of this investment is approximately $147 million.
Cross-State Air Pollution Rule (CSAPR)—On July 6, 2011, the EPA issued the final CSAPR. CSAPR limits power plant emissions of Sulfur Dioxide (SO2) and annual and ozone season NOx in 28 states that contribute to the ability of downwind states to attain and/or maintain current particulate matter and ozone National Ambient Air Quality Standards (NAAQS).
On August 21, 2012, the Court of Appeals vacated CSAPR and ordered that the existing Clean Air Interstate Rule (CAIR) requirements remain in effect until an appropriate substitute rule has been promulgated. On October 5, 2012, the EPA filed a request for rehearing which the Court denied on January 24, 2013. What future actions the EPA will take regarding the Court's decision or the timing of those actions are unknown at this time. The purpose of CAIR is to improve ozone and fine particulate air quality within states that have not demonstrated achievement of the NAAQS. CAIR was implemented through a cap-and-trade program and, to date, the impact has not been material to us as the allowances allocated to our stations were sufficient. If 2013 operations are similar to those in the past three years, it is expected that the impact to operations in New Jersey, New York and Connecticut from the temporary implementation of CAIR in 2013 will not be significant.
We currently anticipate that this rule will not have a material adverse impact to our capital investment program or our units’ operations.
Climate Change
CO2 Regulation Under the CAA—In April 2010, the EPA and the National Highway Transportation Safety Board (NHTSB) jointly issued a final rule to regulate GHGs emissions from certain motor vehicles (Motor Vehicle Rule). Under the CAA, the adoption of the Motor Vehicle Rule would have automatically subjected many emission sources, including ours, to CAA permitting for new facilities and major facility modifications that increase the emission of GHGs, including CO2. However, guidance issued by the EPA in March 2010 interpreted the CAA to require permitting for GHGs at other facilities, such as ours, only when the Motor Vehicle Rule was scheduled to take effect in January 2011. In May 2010, the EPA finalized a “Tailoring Rule” that would have phased in beginning in 2011, the application of this permitting requirement to facilities such as ours. The significance of the permitting requirement is that, in cases where a new source is constructed or an existing source undergoes a major modification, the owner of the facility would need to evaluate and perhaps install best available control technology (BACT) for GHG emissions.
In November 2010, the EPA published guidance to state and local permitting authorities to undertake BACT determinations for new and modified emission sources. The guidance does not define the specific technology or technologies that should be considered BACT. The guidance does emphasize the use of energy efficiency, and specifically states that the technology of storing CO2 under the earth, also known as carbon capture and storage, is not yet mature enough to be considered a viable alternative at this stage. On April 13, 2012, the EPA published the


proposed New Source Performance Standards (NSPS) for GHG for new power plants and refineries. New or modified sources must employ BACT which is defined on a case-by-case basis and can be no less stringent than the applicable NSPS. Thus, for new power plants where the proposed NSPS identifies the applicable standard, if adopted as proposed, all permit decisions regarding BACT and application completeness should be made to reflect at least the level of stringency contained in those standards. The EPA is expected to move to regulation of existing electric generating units under the CAA. However, implementation of such regulations for existing sources is anticipated to be several years away.
Climate-Related Legislation—The federal government may consider legislative proposals to define a national energy policy and address climate change. Proposals under consideration include, but are not limited to, provisions to establish a national clean energy portfolio standard and to establish an energy efficiency resource standard. Provisions of any new proposal may present material risks and opportunities to our businesses. The final design of any legislation will determine the impact on us, which we are not now able to reasonably estimate.
Regional Greenhouse Gas Initiative (RGGI)—In response to concerns over global climate change, some states have developed initiatives to stimulate national climate legislation through CO2 emission reductions in the electric power industry. Ten northeastern states, including New Jersey, New York and Connecticut, originally established RGGI to cap and reduce CO2 emissions in the region. In general, these states adopted state-specific rules to enable the RGGI regulatory mandate in each state.
Applicable rules make allowances available through a regional auction whereby generators may acquire allowances that are each equal to one ton of CO2 emissions. Generators are required to submit an allowance for each ton emitted over a three year period (e.g. 2009, 2010, and 2011). Allowances are available through the auction or through secondary markets and were required to be submitted to states by March 2012 for the first compliance period.
The Governor of New Jersey withdrew New Jersey from RGGI beginning in 2012. Therefore, our New Jersey facilities are no longer obligated to acquire CO2 emission allowances, but our generation facilities in New York and Connecticut remain subject to RGGI. The Governor's action to withdraw has been challenged by environmental groups in the New Jersey state court.
New Jersey also adopted the Global Warming Response Act in 2007, which calls for stabilizing its GHGs emissions to 1990 levels by 2020, followed by a further reduction of greenhouse emissions to 80% below 2006 levels by 2050. To reach this goal, the NJDEP, the BPU, other state agencies and stakeholders are required to evaluate methods to meet and exceed the emission reduction targets, taking into account their economic benefits and costs.
Water Pollution Control
The Federal Water Pollution Control Act (FWPCA) prohibits the discharge of pollutants to U.S. waters from point sources, except pursuant to a National Pollutant Discharge Elimination System (NPDES) permit issued by the EPA or by a state under a federally authorized state program. The FWPCA authorizes the imposition of technology-based and water quality-based effluent limits to regulate the discharge of pollutants into surface waters and ground waters. The EPA has delegated authority to a number of state agencies, including those in New Jersey, New York and Connecticut, to administer the NPDES program through state acts. We also have ownership interests in facilities in other jurisdictions that have their own laws and implement regulations to control discharges to their surface waters and ground waters that directly govern our facilities in those jurisdictions.
In addition to regulating the discharge of pollutants, the FWPCA regulates the intake of surface waters for cooling. The use of cooling water is a significant part of the generation of electricity at steam-electric generating stations. Section 316(b) of the FWPCA requires that cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impact. The impact of regulations under Section 316(b) can be significant, particularly at steam-electric generating stations which do not have closed cycle cooling through the use of cooling towers to recycle water for cooling purposes. The installation of cooling towers at an existing generating station can impose significant engineering challenges and significant costs, which can affect the economic viability of a particular plant. In late 2010, the EPA entered into a settlement agreement with environmental groups that established a schedule to develop a new 316(b) rule by July 27, 2012.
In April 2011, the EPA published a new proposed rule which did not establish any particular technology as the BTA (e.g. closed-cycle cooling). Instead, the proposed rule established marine life mortality standards for existing cooling water intake structures with a design flow of more than two million gallons per day. We reviewed the proposed rule, assessed the potential impact on our generating facilities and used this information to develop our comments to the EPA which were filed in August 2011. On June 11, 2012, the EPA posted a Notice of Data Availability (NODA) requesting comment on a series of technical issues related to the impingement mortality proposed standards. On June 12, 2012, the EPA posted a second NODA outlining its plans to finalize a “Willingness to Pay” survey it initiated to develop non-use benefits data in support of the April 2011 rule proposal. PSEG and industry trade associations submitted comments on both NODAs in July 2012. In July 2012, the EPA and


environmental groups agreed to delay the deadline for finalization of the Rule to June 27, 2013 to allow for more time to address public comments and analyze data submitted in response to the NODAs.
If the rule were to be adopted as proposed, the impact on us would be material since the majority of our electric generating stations would be affected. We are unable to predict the outcome of this proposed rulemaking, the final form that the proposed regulations may take and the effect, if any, that they may have on our future capital requirements, financial condition or results of operations, although such impacts could be material. See Note 13. Commitments and Contingent Liabilities for additional information.  
Hazardous Substance Liability
The production and delivery of electricity, the distribution of gas and, formerly, the manufacture of gas, results in various by-products and substances classified by federal and state regulations as hazardous. These regulations may impose liability for damages to the environment from hazardous substances, including obligations to conduct environmental remediation of discharged hazardous substances as well as monetary payments, regardless of the absence of fault and the absence of any prohibitions against the activity when it occurred, as compensation for injuries to natural resources. Our historic operations and the operations of hundreds of other companies along the Passaic and Hackensack Rivers are alleged by federal and state agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities.
Site Remediation—The Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and the New Jersey Spill Compensation and Control Act (Spill Act) require the remediation of discharged hazardous substances and authorize the EPA, the NJDEP and private parties to commence lawsuits to compel clean-ups or reimbursement for such remediation. The clean-ups can be more complicated and costly when the hazardous substances are in a body of water.
Natural Resource Damages—CERCLA and the Spill Act authorize the assessment of damages against persons who have discharged a hazardous substance, causing an injury to natural resources. Pursuant to the Spill Act, the NJDEP requires persons conducting remediation to characterize injuries to natural resources and to address those injuries through restoration or damages. The NJDEP adopted regulations concerning site investigation and remediation that require an ecological evaluation of potential damages to natural resources in connection with an environmental investigation of contaminated sites. The NJDEP also issued guidance to assist parties in calculating their natural resource damage liability for settlement purposes, but has stated that those calculations are applicable only for those parties that volunteer to settle a claim for natural resource damages before a claim is asserted by the NJDEP. We are currently unable to assess the magnitude of the potential financial impact of this regulatory change, although such impacts could be material.
Fuel and Waste Disposal
Nuclear Fuel Disposal—The federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate disposal of spent nuclear fuel. To pay for this service, nuclear plant owners are required to contribute to a Nuclear Waste Fund. Under the contracts, the U.S. Department of Energy (DOE) was required to begin taking possession of the spent nuclear fuel by no later than 1998 but has not yet done so. The Nuclear Waste Policy Act of 1982 requires the DOE to perform an annual review of the Nuclear Waste Fee to determine whether that fee is set appropriately to fund the national nuclear waste disposal program. In October 2009, the DOE stated that the current fee of 1/10 cent per kWh was adequate to recover program costs. In March 2011, we joined the Nuclear Energy Institute (NEI) and fifteen other nuclear plant operators in a lawsuit seeking suspension of the Nuclear Waste Fee. On June 1, 2012, The U.S. Court of Appeals for the District of Columbia ruled that the DOE failed to justify continued payments by electricity consumers into the Nuclear Waste Fund. The court ordered the DOE to conduct a complete reassessment of this fee within six months. The DOE's assessment was completed in January 2013, and concluded that fee collection should be maintained. On January 31, 2013, motions were filed with the Court seeking to reopen the case and set a schedule for expedited review of the DOE fee adequacy report.
Spent nuclear fuel generated in any reactor can be stored in reactor facility storage pools or in Independent Spent Fuel Storage Installations located at reactors or away from reactor sites. We have on-site storage facilities that are expected to satisfy the storage needs of Salem 1, Salem 2, Hope Creek, Peach Bottom 2 and Peach Bottom 3 through the end of their operating licenses.
Low Level Radioactive Waste—As a by-product of their operations, nuclear generation units produce low level radioactive waste. Such waste includes paper, plastics, protective clothing, water purification materials and other materials. These waste materials are accumulated on site and disposed of at licensed permanent disposal facilities. New Jersey, Connecticut and South Carolina have formed the Atlantic Compact, which gives New Jersey nuclear


generators continued access to the Barnwell waste disposal facility which is owned by South Carolina. We believe that the Atlantic Compact will provide for adequate low level radioactive waste disposal for Salem and Hope Creek through the end of their current licenses including full decommissioning, although no assurances can be given. Low Level Radioactive Waste is periodically being shipped to the Barnwell site from Salem and Hope Creek. Additionally, there are on-site storage facilities for Salem, Hope Creek and Peach Bottom, which we believe have the capacity for at least five years of temporary storage for each facility.
Coal Combustion Residuals (CCRs)—In June 2010, the EPA formally published a proposed rule offering three main options for the management of CCRs under the Resource Conservation and Recovery Act. One of these options regulates CCRs as a hazardous waste and the other two options are variations of a non-hazardous designation. All options communicate the EPA’s intent of ceasing wet ash transfer and instituting engineering controls on ash ponds and landfills to limit impact on human health and the environment. The outcome of the EPA rulemaking cannot be predicted. The EPA has not established a date for release of a final rule.
On April 5, 2012, several environmental organizations and CCR marketers brought a citizens' suit against the EPA in federal court arguing that the EPA has a non-discretionary duty to issue the CCR rules by a certain date. On May 15, 2012, the Utility Solid Waste Activities Group Policy Committee filed a Motion to Intervene in order to be in alignment with the EPA in defending against the environmental organizations' action. After May 2012, all parties agreed to a schedule for submitting briefs in this case. Motions for summary judgment remain pending.
Financial information with respect to our business segments is set forth in Item 8. Financial Statements and Supplementary Data—Note 22. Financial Information by Business Segment.

The following factors should be considered when reviewing our business. These factors could have a material adverse impact on our financial position, results of operations or net cash flows and could cause results to differ materially from those expressed elsewhere in this document.
The factors discussed in Item 7. MD&A may also have a material adverse effect on our results of operations and cash flows and affect the market prices for our publicly-traded securities. While we believe that we have identified and discussed the key risk factors affecting our business, there may be additional risks and uncertainties that are not presently known or that are not currently believed to be significant.
We are subject to comprehensive and evolving regulation by federal, state and local regulatory agencies that affects, or may affect, our businesses.
We are subject to regulation by federal, state and local authorities. Changes in regulation can cause significant delays in or materially affect business planning and transactions and can materially increase our costs. Regulation affects almost every aspect of our businesses, such as our ability to:
Obtain fair and timely rate relief—Our utility’s retail rates are regulated by the BPU and its wholesale transmission rates are regulated by the FERC. The retail rates for electric and gas distribution services are established in a base rate case and remain in effect until a new base rate case is filed and concluded. In addition, our utility has received approval for several clause recovery mechanisms, some of which provide for recovery of and on the authorized investments. These clause mechanisms require periodic updates to be reviewed and approved by the BPU.  Our utility's transmission rates are recovered through a FERC approved formula rate. The revenue requirements are reset each year through this formula. Transmission ROEs have recently become the target of certain state utility commissions, municipal utilities, consumer advocates and consumer groups seeking to lower customer rates in New England and New York. These agencies and groups have filed complaints at the FERC asking the FERC to reduce the base ROE of various transmission owners. They point to changes in the capital markets as justification for lowering the ROE of these companies. While we are not the subject of any of these complaints, the matter could set a precedent for FERC-regulated transmission owners, such as PSE&G. Inability to obtain fair or timely recovery of all our costs, including a return of or on our investments in rates, could have a material impact on our business. 
Obtain required regulatory approvals—The majority of our businesses operate under MBR authority granted by the FERC, which has determined that our subsidiaries do not have unmitigated market power and that MBR rules have


been satisfied. Failure to maintain MBR eligibility, or the effects of any severe mitigation measures that may be required if market power was evaluated differently in the future, could have a material adverse effect on us.
We may also require various other regulatory approvals to, among other things, buy or sell assets, engage in transactions between our public utility and our other subsidiaries, and, in some cases, enter into financing arrangements, issue securities and allow our subsidiaries to pay dividends. Failure to obtain these approvals on a timely basis could materially adversely affect our results of operations and cash flows.
Comply with regulatory requirements—There are Federal standards, including mandatory NERC and cybersecurity standards, in place to ensure the reliability of the U. S. electric transmission and generation system and to prevent major system black-outs. We have been, and will continue to be, periodically audited by the NERC for compliance.
Further, the FERC requires compliance with all of its rules and orders, including rules concerning Standards of Conduct, market behavior and anti-manipulation rules, reporting, interlocking directorate rules and cross-subsidization. Our companies with MBR authority are currently being audited by the FERC for compliance with FERC's rules regarding MBR authority, the filing of Electric Quarterly Reports (EQRs) and the receipt of payments in organized markets by our generating units that are required to run for reliability reasons when it is not economical for them to do so.
We will soon be subject to the reporting and record-keeping requirements of the Dodd-Frank Act, as implemented by the CFTC, and may in the future be subject to CFTC requirements regarding position limits for trading of certain commodities. As part of the Dodd-Frank Act compliance, we will need to be vigilant in monitoring and reporting our swap transactions.
The BPU conducts periodic combined management/competitive service audits of New Jersey utilities related to affiliate standard requirements, competitive services, cross-subsidization, cost allocation and other issues. The BPU is near completion of a management audit and an affiliate transactions audit of PSE&G.
We are exposed to commodity price volatility as a result of our participation in the wholesale energy markets.
The material risks associated with the wholesale energy markets known or currently anticipated that could adversely affect our operations include:
Price fluctuations and collateral requirements—We expect to meet our supply obligations through a combination of generation and energy purchases. We also enter into derivative and other positions related to our generation assets and supply obligations. As a result, we are subject to the risk of price fluctuations that could affect our future results and impact our liquidity needs. These include:
variability in costs, such as changes in the expected price of energy and capacity that we sell into the market,
increases in the price of energy purchased to meet supply obligations or the amount of excess energy sold into the market,
the cost of fuel to generate electricity, and
the cost of emission credits and congestion credits that we use to transmit electricity.

In the markets where we operate, natural gas prices typically have a major impact on the price that generators will receive for their output, especially in periods of relatively strong demand. Therefore, significant changes in the price of natural gas will usually translate into significant changes in the wholesale price of electricity.
Over the past few years, wholesale prices for natural gas have declined from the peak levels experienced in 2008. One of the reasons for this decline is increased shale gas production as extraction technology has improved. Lower gas prices have resulted in lower electricity prices, which has reduced our margins as nuclear and coal generation costs have not declined similarly. Over that time, generation by our coal units was also adversely affected by the relatively lower price of natural gas as compared to coal, making it sometimes more economical to run certain of our gas units than our coal units.
Natural gas prices may remain at low levels for an extended period and continue to decline if further advances in technology result in greater volumes of shale gas production.
Many factors may affect capacity pricing in PJM, including but not limited to:
changes in load and demand,
changes in the available amounts of demand response resources,
changes in available generating capacity (including retirements, additions, derates, forced outage rates, etc.),


increases in transmission capability between zones, and
changes to the pricing mechanism, including increasing the potential number of zones to create more pricing sensitivity to changes in supply and demand, as well as other potential changes that PJM may propose over time, including issues currently pending at the FERC.

Potential changes to the rules governing energy markets in which the output of our plants is sold also poses risk to our business.
Also, as market prices for energy and fuel fluctuate, our forward energy sale and forward fuel purchase contracts could require us to post substantial additional collateral, thus requiring us to obtain additional sources of liquidity during periods when our ability to do so may be limited. If Power were to lose its investment grade credit rating, it would be required under certain agreements to provide a significant amount of additional collateral in the form of letters of credit or cash, which would have a material adverse effect on our liquidity and cash flows. If Power had lost its investment grade credit rating as of December 31, 2012, it may have had to provide approximately $654 million in additional collateral. We may also be subject to additional collateral requirements which could be required under new rules being developed by the CFTC which are expected to be implemented in 2013.
Our cost of coal and nuclear fuel may substantially increase—Our coal and nuclear units have a diversified portfolio of contracts and inventory that will provide a substantial portion of our fuel needs over the next several years. However, it will be necessary to enter into additional arrangements to acquire coal and nuclear fuel in the future. Market prices for coal and nuclear fuel have recently been volatile. Although our fuel contract portfolio provides a degree of hedging against these market risks, future increases in our fuel costs cannot be predicted with certainty and could materially and adversely affect liquidity, financial condition and results of operations.
While our generation runs on diverse fuels, allowing for flexibility, the mix of fuels ultimately used can impact earnings.
Third party credit risk—We sell generation output and buy fuel through the execution of bilateral contracts. These contracts are subject to credit risk, which relates to the ability of our counterparties to meet their contractual obligations to us. Any failure to perform by these counterparties could have a material adverse impact on our results of operations, cash flows and financial position. In the spot markets, we are exposed to the risks of whatever default mechanisms exist in those markets, some of which attempt to spread the risk across all participants, which may not be an effective way of lessening the severity of the risk and the amounts at stake. The impact of economic conditions may also increase such risk.
We are subject to numerous Federal and state environmental laws and regulations that may significantly limit or affect our businesses, adversely impact our business plans or expose us to significant environmental fines and liabilities.
We are subject to extensive environmental regulation by Federal, state and local authorities regarding air quality, water quality, site remediation, land use, waste disposal, aesthetics, impact on global climate, natural resources damages and other matters. These laws and regulations affect the manner in which we conduct our operations and make capital expenditures. Future changes may result in significant increases in compliance costs.
Delay in obtaining, or failure to obtain and maintain, any environmental permits or approvals, or delay in or failure to satisfy any applicable environmental regulatory requirements, could:
prevent construction of new facilities,
prevent continued operation of existing facilities,
prevent the sale of energy from these facilities, or
result in significant additional costs, each of which could materially affect our business, results of operations and cash flows.
In obtaining required approvals and maintaining compliance with laws and regulations, we focus on several key environmental issues, including:
Concerns over global climate change could result in laws and regulations to limit CO2 emissions or other GHG produced by our fossil generation facilities—Federal and state legislation and regulation designed to address global climate change through the reduction of GHG emissions could materially impact our fossil generation facilities. Legislation enacted in the states where our generation facilities are located establishes aggressive goals for the reduction of CO2 emissions over a 40-year period. There could be significant costs incurred to continue operation of our fossil generation facilities, including the potential need to purchase CO2 emission allowances. Such expenditures could materially affect the continued economic viability of one or more such facilities. Multiple states are developing


or have developed state-specific or regional initiatives to obtain CO2 emissions reductions in the electric power industry. The RGGI is such a program in the northeast.
CO2 Litigation—In addition to legislative and regulatory initiatives, the outcome of certain legal proceedings regarding alleged impacts of global climate change not involving us could be material to the future liability of energy companies.
In June 2012, the United States Court of Appeals for the D.C. Circuit upheld the EPA finding that GHGs could reasonably be expected to endanger public health and welfare. However, the Court dismissed the action brought by individuals, local governments and interest groups alleging that various industries, including various energy companies, emitted GHGs, causing global climate change resulting in a variety of damages. Plaintiffs are expected to appeal to the United States Supreme Court.
In November 2012, the Ninth Circuit Court of Appeals refused to reconsider its decision not to rehear an Alaskan village's public nuisance lawsuit alleging that GHGs emissions from ExxonMobil Corporation and many other energy companies had made the village uninhabitable. The appellate court denied the petition for rehearing which accused these companies of causing GHGs emissions that contributed to global warming and alleged injury to the village. If relevant federal or state common law were to develop that imposed liability upon those that emit GHGs for alleged impacts of GHGs emissions, such potential liability to us could be material.
Potential closed-cycle cooling requirements—Our Salem nuclear generating facility has a permit from the NJDEP allowing for its continued operation with its existing cooling water system. That permit expired in July 2006. Our application to renew the permit, filed in February 2006, estimated the costs associated with cooling towers for Salem to be approximately $1 billion, of which our share was approximately $575 million. These amounts have not been updated since our 2006 filing.
If the NJDEP and the Connecticut Department of Environmental Protection were to require installation of closed-cycle cooling or its equivalent at our Salem, Mercer, Hudson, Bridgeport, Sewaren or New Haven generating stations, the related increased costs and impacts would be material to our financial position, results of operations and net cash flows and would require further economic review to determine whether to continue operations or decommission the stations.
The EPA issued a proposed rule in 2011 regarding regulation of cooling water intake structures. If adopted as proposed, the impact of this rulemaking could significantly impact states’ permitting decisions on whether to require closed cycle cooling and could materially increase our cost of compliance. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities.
Remediation of environmental contamination at current or formerly owned facilities—We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we generated. Remediation activities associated with our former Manufactured Gas Plant (MGP) operations are one source of such costs. Also, we are currently involved in a number of proceedings relating to sites where other hazardous substances may have been discharged and may be subject to additional proceedings in the future, the related costs of which could have a material adverse effect on our financial condition, results of operations and cash flows. Recent amendments to New Jersey law now place affirmative obligations on us to investigate and, if necessary, remediate contaminated property upon which we were in any way responsible for a discharge of hazardous substances. While those amendments do not change our liability, they do impact the speed by which we will need to investigate contaminated properties, which could adversely impact cash flow.
The State of New Jersey has filed multiple lawsuits against parties, including us, who were alleged to be responsible for injuries to natural resources in New Jersey, including a site being remediated under our MGP program. We cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to these or other natural resource damages claims. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities.
More stringent air pollution control requirements in New Jersey—Most of our generating facilities are located in New Jersey where restrictions are generally considered to be more stringent in comparison to other states. Therefore, there may be instances where the facilities located in New Jersey are subject to more restrictive and, therefore, more costly pollution control requirements and liability for damage to natural resources, than competing facilities in other states. Most of New Jersey has been classified as “nonattainment” with NAAQS for one or more air pollutants. This requires New Jersey to develop programs to reduce air emissions. Such programs can impose additional costs on us by requiring that we offset any emissions increases from new electric generators we may want to build and by setting more stringent emission limits on our facilities that run during the hottest days of the year.


Coal Ash Management—Coal ash is a CCR produced as a byproduct of generation at our coal-fired facilities. We currently have a program to beneficially reuse coal ash as presently allowed by federal and state regulations. In June 2010, the EPA formally published a proposed rule offering three main options for the management of CCRs under the Resource Conservation and Recovery Act. One of these options regulates CCRs as a hazardous waste and the other two options are variations of a non-hazardous designation. All options communicate the EPA’s intent of ceasing wet ash transfer and instituting engineering controls on ash ponds and landfills to limit impact on human health and the environment. The outcome of the EPA rulemaking cannot be predicted. Proposed regulations which more stringently regulate coal ash, including regulating coal ash as hazardous waste, could materially increase costs at our coal-fired generation facilities. The EPA has not established a date for release of a final rule.
Our ownership and operation of nuclear power plants involve regulatory, financial, environmental, health and safety risks.
Approximately half of our total generation output each year is provided by our nuclear fleet, which comprises approximately one-fourth of our total owned generation capacity. For this reason, we are exposed to risks related to the continued successful operation of our nuclear facilities and issues that may adversely affect the nuclear generation industry. These include:
Storage and Disposal of Spent Nuclear Fuel—We currently use on-site storage for spent nuclear fuel. Disposal of nuclear materials, including the availability or unavailability of a permanent repository for spent nuclear fuel, could impact future operations of these stations. In addition, the availability of an off-site repository for spent nuclear fuel may affect our ability to fully decommission our nuclear units in the future.
Regulatory and Legal Risk—The NRC may modify, suspend or revoke licenses, or shut down a nuclear facility and impose substantial civil penalties for failure to comply with the Atomic Energy Act, related regulations or the terms and conditions of the licenses for nuclear generating facilities. As with all of our generation facilities, as discussed above, our nuclear facilities are also subject to comprehensive, evolving environmental regulation. Our nuclear generating facilities are currently operating under NRC licenses that expire in 2033 through 2046.
Operational Risk—Operations at any of our nuclear generating units could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. Since our nuclear fleet provides the majority of our generation output, any significant outage could result in reduced earnings as we would need to purchase or generate higher-priced energy to meet our contractual obligations.
Nuclear Incident or Accident Risk—Accidents and other unforeseen problems have occurred at nuclear stations, both in the United States and elsewhere. The consequences of an accident can be severe and may include loss of life, significant property damage and/or a change in the regulatory climate. We have nuclear units at two sites. It is possible that an accident or other incident at a nuclear generating unit could adversely affect our ability to continue to operate unaffected units located at the same site, which would further affect our financial condition, operating results and cash flows. An accident or incident at a nuclear unit not owned by us could also affect our ability to continue to operate our units. Any resulting financial impact from a nuclear accident may exceed our resources, including insurance coverages.
We may be adversely affected by changes in energy regulatory policies, including energy and capacity market design rules and developments affecting transmission.
The energy industry continues to be regulated and the rules to which our businesses are subject are always at risk of being changed. Our business has been impacted by established rules that create locational capacity markets in each of PJM, ISO-NE and NYISO. Under these rules, generators located in constrained areas are paid more for their capacity so there is an incentive to locate in those areas where generation capacity is most needed. Because much of our generation is located in constrained areas in PJM and ISO-NE, the existence of these rules has had a positive impact on our revenues. PJM’s locational capacity market design rules and New England forward capacity market rules have been challenged in court and continue to evolve. Any changes to these rules may have an adverse impact on our financial condition, results of operations and cash flows.
In addition, legislative developments in the State of New Jersey have the potential to adversely impact RPM prices. In January 2011, New Jersey enacted a law establishing a LCAPP which provides for the construction of subsidized base load or mid-merit electric power generation. The LCAPP may have the effect of artificially depressing prices in the competitive wholesale market on both a short-term and long-term basis. PJM’s Independent Market Monitor has released a report estimating that the impact of bidding 2,000 MW of capacity in New Jersey as a price taker could be a reduction in capacity market revenues to PJM suppliers of more than $2 billion in the first year.


We could also be impacted by a number of other events, including regulatory or legislative actions favoring non-competitive markets and energy efficiency and demand response initiatives. Further, some of the market-based mechanisms in which we participate, including BGS auctions, are at times the subject of review or discussion by some of the participants in the New Jersey and Federal regulatory and political arenas. We can provide no assurance that these mechanisms will continue to exist in their current form, nor otherwise be modified.
To the extent that additions to the transmission system relieve or reduce congestion in eastern PJM where most of our plants are located, Power's revenues could be adversely affected. Moreover, the FERC has issued a rule, currently being challenged in court, that requires changes to transmission planning processes which may result in more transmission being built to facilitate renewable generation. This rule has also opened up the construction of certain types of transmission to competition through elimination of the ROFR.
Changes in the current policies for building new transmission lines could result in additional competition to build transmission lines in our service territory in the future and would allow us to seek opportunities to build in other service territories.
We face significant competition in the merchant energy markets.
Our wholesale power and marketing businesses are subject to significant competition that may adversely affect our ability to make investments or sales on favorable terms and achieve our annual objectives. Increased competition could contribute to a reduction in prices offered for power and could result in lower earnings. Decreased competition could negatively impact results through a decline in market liquidity. Some of our competitors include:
merchant generators,
domestic and multi-national utility rate-based generators,
energy marketers,
banks, funds and other financial entities,
fuel supply companies, and
affiliates of other industrial companies.
Regulatory, environmental, industry and other operational developments will have a significant impact on our ability to compete in energy markets, potentially resulting in erosion of our market share and impairment in the value of our power plants. Our ability to compete will also be impacted by:
DSM and other efficiency efforts—DSM and other efficiency efforts aimed at changing the quantity and patterns of consumers’ usage could result in a reduction in load requirements.
Changes in technology and/or customer conservation—It is possible that advances in technology will reduce the cost of alternative methods of producing electricity, such as fuel cells, micro turbines, windmills and PV (solar) cells, to a level that is competitive with that of most central station electric production. It is also possible that electric customers may significantly decrease their electric consumption due to demand-side energy conservation programs. Changes in technology could also alter the channels through which retail electric customers buy electricity, which could adversely affect our financial results.
Our inability to balance energy obligations with available supply could negatively impact results.
The revenues generated by the operation of our generating stations are subject to market risks that are beyond our control. Generation output will either be used to satisfy wholesale contract requirements, other bilateral contracts or be sold into competitive power markets. Participants in the competitive power markets are not guaranteed any specified rate of return on their capital investments. Generation revenues and results of operations are dependent upon prevailing market prices for energy, capacity, ancillary services and fuel supply in the markets served.
Our generation business frequently involves the establishment of forward sale positions in the wholesale energy markets on long-term and short-term bases. To the extent that we have produced or purchased energy in excess of our contracted obligations, a reduction in market prices could reduce profitability. Conversely, to the extent that we have contracted obligations in excess of energy we have produced or purchased, an increase in market prices could reduce profitability. If the strategy we utilize to hedge our exposure to these various risks is not effective, we could incur significant losses. Our market positions can also be adversely affected by the level of volatility in the energy markets that, in turn, depends on various factors,


including weather in various geographical areas, short-term supply and demand imbalances, customer migration and pricing differentials at various geographic locations. These cannot be predicted with certainty.
Increases in market prices also affect our ability to hedge generation output and fuel requirements as the obligation to post margin increases with increasing prices and could require the maintenance of liquidity resources that would be prohibitively expensive.
Any inability to recover the carrying amount of our assets could result in future impairment charges which could have a material adverse impact on our financial condition, results of operations and cash flows.
In accordance with accounting guidance, management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate or market conditions, could potentially indicate an asset’s or group of assets’ carrying amount may not be recoverable. Significant reductions in our expected revenues or cash flows for an extended period of time resulting from such events could result in future asset impairment charges, which could have a material adverse impact on our financial condition and results of operations.
Inability to access sufficient capital at reasonable rates or commercially reasonable terms or maintain sufficient liquidity in the amounts and at the times needed could adversely impact our business.
Capital for projects and investments has been provided primarily by internally-generated cash flow and external financings. We have significant capital requirements and will need continued access to debt capital from outside sources in order to efficiently fund the construction and other cash flow needs of our businesses. The ability to arrange financing and the costs of capital depend on numerous factors including, among other things, general economic and market conditions, the availability of credit from banks and other financial institutions, investor confidence, the success of current projects and the quality of new projects.
The ability to have continued access to the credit and capital markets at a reasonable economic cost is dependent upon our current and future capital structure, financial performance, our credit ratings and the availability of capital under reasonable terms and conditions. As a result, no assurance can be given that we will be successful in obtaining re-financing for maturing debt, financing for projects and investments or funding the equity commitments required for such projects and investments in the future.
Financial market performance directly affects the asset values of our nuclear decommissioning trust funds and defined benefit plan trust funds. Sustained decreases in asset value of trust assets could result in the need for significant additional funding.
The performance of the financial markets will affect the value of the assets that are held in trust to satisfy our future obligations under our pension and postretirement benefit plans and to decommission our nuclear generating plants. A decline in the market value of our pension assets similar to the one experienced in 2008 could result in the need for us to make significant contributions in the future to maintain our funding at sufficient levels.
An extended economic recession would likely have a material adverse effect on our businesses.
Our results of operations may be negatively affected by sustained downturns or sluggishness in the economy, including low levels in the market prices of commodities. Adverse conditions in the economy affect the markets in which we operate and can negatively impact our results. Declines in demand for energy will reduce overall sales and lessen cash flows, especially as customers reduce their consumption of electricity and gas. Although our utility business is subject to regulated allowable rates of return, overall declines in electricity and gas sold and/or increases in non-payment of customer bills would materially adversely affect our liquidity, financial condition and results of operations.
We may be adversely affected by equipment failures, accidents, severe weather events or other incidents that impact our ability to provide safe and reliable service to our customers and remain competitive.
The success of our businesses is dependent on our ability to continue providing safe and reliable service to our customers while minimizing service disruptions. We are also exposed to the risk of accidents, severe weather events such as we experienced from Hurricane Irene and Superstorm Sandy, or other incidents which could result in damage to or destruction of our facilities or damage to persons or property. The physical risks of climate change, such as more frequent or more extreme weather events, changes in temperature and precipitation patterns and other related phenomena have exacerbated these risks. Such issues experienced at our facilities, or by others in our industry, could adversely impact our revenues, increase costs to repair and maintain our systems, subject us to potential litigation and/or damage claims and increase the level of oversight of our utility and generation operations and infrastructure through investigations or through the imposition of additional regulatory or legislative requirements. Such actions could affect our costs, competitiveness and future investments, which could be material to our financial position, results of operations and cash flow. 


Acts of war, terrorism or cybersecurity breaches could adversely affect our operations.
Our businesses and industry may be impacted by acts and threats of war or terrorism. These actions could result in increased political, economic and financial market instability and volatility in fuel prices which could materially adversely affect our operations. In addition, our infrastructure facilities, such as our generating stations, transmission and distribution facilities and information management systems for customer-related operations, could be direct or indirect targets or be affected by terrorist or other criminal activity.
Our businesses could also be impacted by cybersecurity breaches. Cybersecurity threats include:
operational interference, such as attacks on our generation facilities, transmission lines or the power grid,
information theft as to employees, shareholders, vendors and/or customers, such as personal financial and health records, and
business system interruption or compromise.
Such events could severely disrupt business operations and prevent us from servicing our customers or collecting revenues. These events could also result in significant expenses to repair security breaches or system damage as well as increased capital, insurance and operating costs, including increased security costs for our facilities. A breach of certain business systems could affect our ability to record, process and/or report financial information correctly. In addition, new or updated security regulations may require us to make changes to our current measures which could also result in additional expenses.
Inability to successfully develop or construct generation, transmission and distribution projects within budget could adversely impact our businesses.
Our business plan calls for extensive investment in capital improvements and additions, including the installation of required environmental upgrades and retrofits, construction and/or acquisition of additional generation units and transmission facilities and modernizing existing infrastructure. Currently, we have several significant projects underway or being contemplated.
Our success will depend, in part, on our ability to complete these projects within budgets, on commercially reasonable terms and conditions and, in our regulated businesses, our ability to recover the related costs through rates. Any delays, cost escalations or otherwise unsuccessful construction and development could materially affect our financial position, results of operations and cash flows.
We may be unable to achieve, or continue to sustain, our expected levels of operating performance.
One of the key elements to achieving the results in our business plan is the ability to sustain generating operating performance and capacity factors at expected levels since our forward sales of energy and capacity assume acceptable levels of operating performance. This is especially important at our lower-cost facilities. Operations at any of our plants could degrade to the point where the plant has to shut down or operate at less than full capacity. Some issues that could impact the operation of our facilities are:
breakdown or failure of equipment, processes or management effectiveness,
disruptions in the transmission of electricity,
labor disputes,
fuel supply interruptions,
transportation constraints,
limitations which may be imposed by environmental or other regulatory requirements,
permit limitations, and
operator error or catastrophic events such as fires, earthquakes, explosions, floods, severe storms, acts of terrorism or other similar occurrences.
Identifying and correcting any of these issues may require significant time and expense. Depending on the materiality of the issue, we may choose to close a plant rather than incur the expense of restarting it or returning it to full capacity. In either event, to the extent that our operational targets are not met, we could have to operate higher-cost generation facilities or meet our obligations through higher-cost open market purchases.


Challenges associated with retention of a qualified workforce could adversely impact our businesses.
Our operations depend on the retention of a skilled workforce. The loss or retirement of key executives or other employees, including those with the specialized knowledge required to support our generation, transmission and distribution operations, could result in various operational challenges. These challenges may include the lack of appropriate replacements, the loss of institutional and industry knowledge and the increased costs to hire and train new personnel. This has the potential to become more critical over the next several years as a growing number of employees become eligible to retire.
In addition, because a significant portion of our employees are covered under collective bargaining agreements, our success will depend on our ability to successfully renegotiate these agreements as they expire. Inability to do so may result in employee strikes or work stoppages which would disrupt our operations and could also result in increased costs.
Our receipt of payment of receivables related to our domestic leveraged leases is dependent upon the credit quality and the ability of lessees to meet their obligations.
Our receipt of payments of equity rent, debt service and other fees related to our leveraged lease portfolio in accordance with the lease contracts can be impacted by various factors. The factors which may impact future lease cash flow include, but are not limited to, new environmental legislation regarding air quality and other discharges in the process of generating electricity, market prices for fuel and electricity, including the impact of low gas prices on our coal generation investments, overall financial condition of lease counterparties and the quality and condition of assets under lease. If a lessee were to default, we could potentially be required to impair our current investment balances. For additional information relating to these leases, see Item 7. MD&A—Critical Accounting Estimates and Item 8. Financial Statements and Supplementary Data—Note 8. Financing Receivables.

PSEG, Power and PSE&G

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


Generation Facilities
As of December 31, 2012, Power’s share of summer installed generating capacity is shown in the following table:
% Owned


Load Following


Load Following


Load Following
Keystone (A)


Base Load
Conemaugh (A)


Base Load
Bridgeport Harbor


Load Following
New Haven Harbor


Load Following
Total Steam


Hope Creek


Base Load
Salem 1 & 2


Base Load
Peach Bottom 2 & 3 (B)


Base Load
Total Nuclear


Combined Cycle:


Load Following


Load Following


Load Following
Total Combined Cycle


Combustion Turbine: