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

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

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

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

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

Our business discussion in Part I, Item 1. Business of our 2011 Annual Report on 10-K (Form 10-K) provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets, focusing on operational excellence, financial strength and making disciplined investments. Our risk factor discussion in Part II Item 1A of Form 10-K provides information about factors that could have a material adverse impact on our businesses. The following supplements that discussion and the discussion included in the Overview of 2011 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 2012 and any changes to the key factors that we expect may drive our future performance. The following discussion refers to the Condensed Consolidated Financial Statements (Statements) and the Related Notes to Condensed Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements, Notes, the 2011 Form 10-K and the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012.

OVERVIEW OF 2012 AND FUTURE OUTLOOK

During the first half of 2012, our results continued to be adversely impacted by lower prices for electricity and natural gas in the markets we serve. Our pricing also continues to be affected by customer migration away from our BGS supply contracts as these volumes are replaced with lower priced spot market sales. While the average BGS rates have been declining based on recent market prices, customers may still see an incentive to switch to third party suppliers. The result of such a switch may affect the price we receive on our sales, shifting from BGS rates that were established in auctions that had taken place over the past three years, to prices offered by third party suppliers which may be more representative of recent market pricing.

Partially offsetting this lower commodity pricing are higher transmission revenues as a result of our 2012 Annual Formula Rate Update with the Federal Energy Regulatory Commission (FERC), which provides for approximately $94 million in increased annual transmission revenues effective January 1, 2012.

Under the most recent auction in May 2012, for the 2015-2016 period, Power cleared approximately 9,000 MW of its generating capacity at an average price of $167 per MW-day.

Our volumes of gas sales were lower in the first half of 2012, but the decline in gas revenues was significantly mitigated by the favorable impact of a $51 million increase due to recovery of deficiency revenues through the Weather Normalization Charge (WNC). PSE&G's WNC is a 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.

For 2012 and beyond, the key issues we expect our business to confront include:

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

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

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

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

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

• successfully recontract our open supply positions, and

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

There have also been certain significant regulatory and legislative developments during the year which may affect our operations in the future as new rules and regulations are adopted. For additional information on these issues, see Item 5. Other Information.

• On April 12, 2012, the Maryland Public Utility Commission (PUC) issued an order requiring three of the four Maryland utility companies to enter into contracts with CPV Shore, LLC (CPV) to construct a new 661 MW natural gas-fired, combined cycle station in Maryland with an in-service date of June 2015. CPV cleared the May 2012 Reliability Pricing Model (RPM) auction. These developments in Maryland may stimulate construction of subsidized generation and impact energy and capacity prices in PJM. Power has joined other generators in challenging the constitutionality of this order in federal court. In addition, the Maryland electric distribution companies have appealed the PUC's order in state court. Both proceedings are pending.

New Jersey's Long-Term Capacity Agreement Pilot Program Act (LCAPP Act), Maryland's Request for Proposal or similar activity in other states may artificially depress prices in the competitive wholesale market and have the potential to harm competitive markets and adversely impact our generation business, on both a short-term and long-term basis.

• FERC Final Rule 1000 (Order 1000), issued in July 2011, among other things directs regional planners such as PJM to (i) be more flexible in how they plan for future transmission build (ii) eliminate any Right of First Refusal, which permits incumbent transmission owners, like us, the first opportunity to construct transmission within their respective service territories, subject to certain exceptions, and (iii) allocate costs for transmission projects in a way that roughly matches costs with benefits, while leaving flexibility to the regions to determine precise cost allocation methodologies. In June 2012, PSEG appealed this Order in federal court. Other companies and state commissions have filed appeals as well. PJM is currently conducting a stakeholder process to develop implementing details regarding Order 1000. An expected outcome of this process is the construction of more transmission and the opening up of transmission construction and ownership to third-party developers and to incumbents seeking to build outside of their service territories. We cannot predict the final outcome or impact on us; however, specific implementation of Order 1000 in the various regions, including within our service territory, may expose us to competition for construction of transmission, additional regulatory considerations and potential delay with respect to future transmission projects.

• On March 30, 2012, the FERC issued an order finding that allocation of costs associated with high voltage (500 kV and higher) transmission projects in PJM to all customers in PJM is just and reasonable. This order, which has been challenged on rehearing, therefore preserves the current cost allocation for the Susquehanna-Roseland project. However, the FERC also stated in its order that other cost allocation methodologies could be just and reasonable and this may lead to the adoption of a different cost allocation methodology for transmission in PJM in the future.

Operational Excellence

Our nuclear and fossil facilities continued their strong operating performance through the first six months of 2012. Our nuclear units have achieved a capacity factor of 92.7% and our combined cycle units have continued to improve their forced outage rates. Overall, generation volumes for the first half of 2012 were
25.8 TWh, approximately 5% lower than in 2011 due primarily to reduced demands due to milder weather in 2012.

In the second quarter of 2012, we received the final approvals for the 10-year contract that we won in December 2011 to manage Long Island Power Authority's electric transmission and distribution system in Long Island, New York. The contract, which commences January 1, 2014, represents an opportunity to improve returns and is recognition of our history of strong reliability and customer satisfaction.

Financial Strength

Our cash from operations has remained strong. During the first six months of 2012, we made approximately $1.3 billion in capital expenditures, paid dividends of $359 million and made our entire planned pension and other postretirement employee benefit contributions for the year 2012 of $135 million.

In March 2012, Power's $1.525 billion and PSEG's $477 million credit facilities that were set to expire in December 2012 were replaced with $1.6 billion and $500 million credit facilities, respectively, expiring in March 2017. As of June 30, 2012, our total credit capacity was $4.3 billion and we had over $750 million of cash on hand.

On January 31, 2012, we entered into a specific matter closing agreement settling our dispute with the IRS over certain lease transactions. This agreement settles the international leveraged lease dispute with finality for all tax periods in which we realized tax deductions from these transactions. Also on January 31, 2012, we signed a settlement agreement covering all audit issues for tax years 1997 through 2003. On March 26, 2012, we executed a formal settlement agreement covering all audit issues for tax years 2004 through 2006. These two agreements conclude 10 years of audits for us and the leasing issue for all tax years.

Disciplined Investment

We seek to invest in areas that complement our existing businesses and provide attractive risk-adjusted returns. These areas include upgrading critical energy infrastructure, responding to trends in environmental protection and providing new energy supplies in domestic markets with growing demand. We also have several projects where we are investing to continue to improve our operational performance. Over the past few years, we have shifted our focus to investing at the utility. Our capital expenditure forecast includes over $6.7 billion in spending over the next three years, over 75% of which is at PSE&G.

• We are continuing to pursue obtaining the necessary regulatory approvals for the Susquehanna-Roseland transmission project including approval from the National Park Service (NPS), which has resulted in a delay to the project implementation date. In March 2012, the NPS identified a "preferred alternative" for the final form of its Draft Environmental Impact Statement (EIS), under which the project would follow the route of the existing transmission line. This route was the one approved by state regulators including the BPU. The final EIS is expected to be issued in October 2012. Currently, the expected in-service date for the Eastern segment of the project is June 2014 and for the Western segment is June 2015, although further delays are possible. The cost of construction is up to an estimated $790 million for this project. As of June 30, 2012, total capital expenditures were $217 million.

• We have made additional investments in solar power in New Jersey. Under our solar loan program we have provided a total of $177 million in loans for 721 projects as of June 30, 2012, representing 55 MW to date. Under our Solar 4 All program, we have made total program expenditures of approximately $401 million as of June 30, 2012. Approximately 30 MW of solar panels have been installed on distribution poles and another 36 MW representing 20 projects have been placed into service. Additional projects are in various stages of development. Our total anticipated expenditures to develop all approved 80 MW are approximately $456 million. The BPU has concluded a generic stakeholder proceeding to examine whether utility rate-based solar programs should be modified, expanded or terminated in the future, and has determined that utility rate-based solar programs should be continued under defined scope and size parameters.

On July 23, 2012, the Governor of New Jersey signed legislation that, among other things, requires energy providers, including BGS providers and third party suppliers, to increase the amount of power in their portfolios derived from solar electricity, increasing the demand for Solar Renewable Energy Credits and increasing the potential for additional utility solar generation investment.

On July 31, 2012, PSE&G filed for an extension of its Solar 4 All program. In this filing, PSE&G is seeking BPU approval for up to $690 million to develop 136 MW of utility-owned solar photovoltaic systems over a five year period starting in 2013. Consistent with the existing Solar 4 All program, PSE&G proposes to sell the energy and capacity from the solar systems in the PJM wholesale energy and capacity markets.

Also, consistent with the BPU's generic proceeding on solar, PSE&G filed for an additional extension of our Solar Loan program (Solar Loan III) on July 31, 2012. In the filing, PSE&G is seeking BPU approval to provide financing support for the installation of 97 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, projects are built and loans are closed.

The estimated project costs included in the July 31, 2012 filings for extensions of our Solar 4 All and Solar Loan III programs are not included in our $6.7 billion three-year capital forecast.

• Our Capital Infrastructure Program (CIP II) provides for approximately $273 million in accelerated capital investments in our electric and gas infrastructure through 2012. As of June 30, 2012, total capital expenditures since inception of this program were $177 million.

• We made additional expenditures under our Energy Efficiency and Demand Response programs. As of June 30, 2012, total capital expenditures since inception of these projects were $147 million for Energy Efficiency Economic Stimulus (EEE), $2 million for EEE Extension and $43 million for Carbon Abatement and $23 million for Demand Response.

• We continued various construction activities at Power, including a steam path retrofit and extended power uprate at Peach Bottom and we completed construction of new gas-fired peaking units at Kearny and in Connecticut (see Note 8. Commitments and Contingent Liabilities and Part II. Item 5. Other Information for additional information). This additional capacity at Kearny was bid into and has cleared the RPM capacity auction, and the additional capacity in Connecticut is subject to a contract with a Connecticut utility.

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

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

RESULTS OF OPERATIONS

The results for PSEG, PSE&G, Power and Energy Holdings for the three months and
six months ended June 30, 2012 and 2011 are presented below:



                                                 Three Months Ended              Six Months Ended
                                                      June 30,                       June 30,
Earnings (Losses)                              2012             2011            2012           2011
                                                                      Millions
Power                                        $     104        $     205       $    357        $  502
PSE&G                                              101              105            298           268
Energy Holdings                                      2                5             42             2
Other (A)                                            4                5              7            10

PSEG Income from Continuing Operations             211              320            704           782
Income (Loss) from Discontinued
Operations (B)                                       0                3              0            67

PSEG Net Income                              $     211        $     323       $    704        $  849

                                             Three Months Ended                     Six Months Ended
                                                  June 30,                              June 30,
Earnings Per Share (Diluted)              2012                2011               2012               2011
PSEG Income from Continuing
Operations                             $      0.42         $      0.63        $     1.39         $     1.54
Income (Loss) from Discontinued
Operations (B)                                0.00                0.00              0.00               0.13

PSEG Net Income                        $      0.42         $      0.63        $     1.39         $     1.67

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

(B) See Note 4. Discontinued Operations and Dispositions.

Our results include the realized gains, losses and earnings on Power's Nuclear Decommissioning Trust (NDT) Fund and other related NDT activity. This includes the net realized gains, interest and dividend income and other costs related to the NDT Fund which are recorded in Other Income and Deductions. This also includes credit-related impairments on certain NDT securities which are included in Other-Than-Temporary Impairments and the interest accretion expense on Power's nuclear Asset Retirement Obligation (ARO), which is recorded in Operation and Maintenance Expense and the depreciation related to the ARO asset.

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

The quarter-over-quarter and six month-over-six month variances in our Income from Continuing Operations include the changes related to NDT and MTM shown in the chart below:

                                         Three Months Ended          Six Months Ended
                                              June 30,                   June 30,
                                         2012            2011       2012          2011
                                                       Millions, after tax
      NDT Fund Income (Expense)        $       4         $  15     $     9       $    42
      Non-Trading MTM Gains (Losses)   $     (10 )       $   4     $    42       $     8

In addition to the changes in NDT and MTM, our $109 million and $78 million decreases in Income from Continuing Operations for the three months and six months ended June 30, 2012, respectively, were driven primarily by:

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

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

• lower gas volumes and demand due to milder winter weather, partially offset by the WNC.

The decrease for the six months ended June 30, 2012 was partially offset by increased earnings from transmission and renewable investments at PSE&G and lower tax expense due to the settlement of 10 years of IRS audits.

PSEG

Our results of operations are primarily comprised of the results of operations of our operating subsidiaries, Power, PSE&G and Energy Holdings, excluding charges related to intercompany transactions, which are eliminated in consolidation. We also include certain financing costs, charitable contributions and general and administrative costs at the parent company. For additional information on intercompany transactions, see Note 17. Related-Party Transactions. For an explanation of the variances, see the discussions for Power, PSE&G and Energy Holdings that follow the table below:

                                         Three Months Ended                 Increase/                  Six Months Ended                 Increase/
                                              June 30,                      (Decrease)                     June 30,                     (Decrease)
                                        2012             2011              2012 vs 2011              2012            2011              2012 vs 2011
                                                Millions                Millions          %                  Millions               Millions          %
Operating Revenues                   $    2,098       $    2,469      $     (371 )       (15 )     $   4,973      $    5,823      $     (850 )       (15 )
Energy Costs                                761            1,010            (249 )       (25 )         1,940           2,573            (633 )       (25 )
Operation and Maintenance                   629              575              54           9           1,257           1,226              31           3
Depreciation and Amortization               255              235              20           9             511             476              35           7
Taxes Other than Income Taxes                20               28              (8 )       (29 )            49              71             (22 )       (31 )
Income from Equity Method
Investments                                   2                4              (2 )       (50 )             2               7              (5 )       (71 )
Other Income and (Deductions)                32               40              (8 )       (20 )            60             103             (43 )       (42 )
Other-Than-Temporary Impairments              7                1               6         N/A              12               5               7         N/A
Interest Expense                            103              117             (14 )       (12 )           204             244             (40 )       (16 )
Income Tax Expense                          146              227             (81 )       (36 )           358             556            (198 )       (36 )
Income (Loss) from Discontinued
Operations                                    0                3              (3 )       N/A               0              67             (67 )       N/A

Power



                                   Three Months Ended             Increase/              Six Months Ended             Increase/
                                        June 30,                  (Decrease)                 June 30,                 (Decrease)
                                 2012             2011           2012 vs 2011           2012           2011          2012 vs 2011
                                                                              Millions
Income from Continuing
Operations                     $     104        $     205       $         (101 )      $    357        $   502       $         (145 )
Income (Loss) from
Discontinued Operations,
net of tax                             0                3                   (3 )             0             67                  (67 )
Net Income                     $     104        $     208       $         (104 )      $    357        $   569       $         (212 )

For the three months and six months ended June 30, 2012, the primary reasons for the $101 million and $145 million decreases in Income from Continuing Operations were

• lower average prices realized on generation sold into the PJM and New York power pools,

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

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

• lower average pricing and volumes of gas sold under our BGSS contracts, net of lower cost to serve, as a result of warmer winter weather in 2012,

• higher operation and maintenance costs in 2012 at our nuclear plants, and

• lower net realized gains on the NDT Fund.

These decreases were partially offset by

. . .