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

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

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

•

PSE&G—which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). PSE&G also invests in solar generation projects and has implemented energy efficiency and demand response programs in New Jersey, which are regulated by the BPU, and

•

Power—which is a multi-regional energy supply company that integrates the operations of its merchant nuclear and fossil generating assets with its power marketing businesses through competitive energy sales in well-developed energy markets and fuel supply functions primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, Power owns and operates solar generation in various states. Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate.

PSEG’s other direct wholly owned subsidiaries include PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) transmission and distribution (T&D) system under an Operations Services Agreement (OSA); and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.

Our business discussion in Item 1. Business provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets, focusing on operational excellence, financial strength and making disciplined investments. Our risk factor discussion in Item 1A. Risk Factors provides information about factors that could have a material adverse impact on our businesses. The following discussion provides an overview of the significant events and business developments that have occurred during 2016 and key factors that we expect may drive our future performance. This discussion refers to the Consolidated Financial Statements (Statements) and the related Notes to the Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements and Notes.

EXECUTIVE OVERVIEW OF 2016 AND FUTURE OUTLOOK

2016 Overview

Our business plan is designed to achieve growth while managing the risks associated with fluctuating commodity prices and changes in customer demand. We continue our focus on operational excellence, financial strength and disciplined investment. These guiding principles have provided the base from which we have been able to execute our strategic initiatives, including:

•	improving utility operations through growth in investment in T&D and other infrastructure projects designed to enhance system reliability and resiliency and to meet customer expectations and public policy objectives,

•	maintaining and expanding a reliable generation fleet with the flexibility to utilize a diverse mix of fuels which allows us to respond to market volatility and capitalize on opportunities as they arise.

Financial Results

The results for PSEG, PSE&G and Power for the years ended December 31, 2016 and 2015 are presented below:

			Years Ended December 31,
			2016				2015
	Earnings (Losses)		Millions, except per share data
	PSE&G		$	889			$	787
	Power		18				856
	Other		(20		)		36
	PSEG Net Income		$	887			$	1,679
	PSEG Net Income Per Share (Diluted)		$	1.75			$	3.30

Our 2016 over 2015 decrease in Net Income was due primarily to charges related to the early retirement of our Hudson and Mercer units, mark-to-market (MTM) losses in 2016 as compared to gains in 2015, lower volumes of electricity and gas sold at lower average realized sales prices, lower capacity and operating reserve revenues, storm insurance recoveries received primarily by Power in 2015 related to Superstorm Sandy, and charges in 2016 related to investments in certain leveraged leases at Energy Holdings. These decreases were partially offset by higher transmission revenues, lower generation costs and higher costs incurred at Power for planned outages in 2015, and higher management fee revenues at PSEG LI pursuant to the OSA. For a more detailed discussion of our financial results, see Results of Operations.

During 2016, we maintained a strong balance sheet. We continued to effectively deploy capital without the need for additional equity, while our solid credit ratings aided our ability to access capital and credit markets. The greater emphasis on capital spending for projects on which we receive contemporaneous returns at PSE&G, our regulated utility, in recent years has yielded strong results, which when combined with the cash flow generated by Power, our merchant generator and power marketer, has allowed us to increase our dividend. These actions to transition our business to meet market conditions and investor expectations reflect our multi-year, long-term approach to managing our company. Our focus has been to invest capital in T&D and other infrastructure projects aimed at maintaining service reliability to our customers and bolstering our system resiliency. At Power, we strive to improve performance and reduce costs in order to enhance the value of our generation fleet in light of low gas prices, environmental considerations and competitive market forces that reward efficiency and reliability.

At PSE&G, we continue to invest in transmission projects that focus on reliability improvements and replacement of aging infrastructure. We also continue to make investments to improve the resiliency of our gas and electric distribution system as part of our Energy Strong program that was approved by the BPU in 2014 and to seek recovery on such investments. We also commenced modernizing PSE&G’s gas distribution systems as part of our Gas System Modernization Program (GSMP) that was approved by the BPU in late 2015. Over the past few years, these types of investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G. In 2017, as a result of our Energy Strong Order from the BPU, we will be required to file a distribution base rate case proceeding. We cannot predict the impact such proceeding will have on our distribution business.

Despite the unseasonable warm winter weather patterns in 2016, Power’s results benefited from access to natural gas supplies through existing firm pipeline transportation contracts. Power manages these contracts for the benefit of PSE&G’s customers through the BGSS arrangement. The contracts are sized to provide for delivery of a reliable gas supply to PSE&G customers on peak winter days. When pipeline capacity beyond the customers’ needs is available, Power can use it to make third-party sales and supply gas to its generating units in New Jersey. Alternatively, gas supply and pipeline capacity constraints could adversely impact our ability to meet the needs of our utility customers and generating units. Power’s hedging practices and ability to capitalize on market opportunities help it to balance some of the volatility of the merchant power business. More than half of Power’s expected gross margin in the upcoming year relates to our hedging strategy, our expected revenues from the capacity market mechanisms and certain ancillary service payments such as reactive power.

Our investments in the latter half of 2015 and early 2016 in Keys Energy Center (Keys), Sewaren 7 and Bridgeport Harbor Station 5 (BH5) reflect our recognition of the value of opportunistic growth in the Power business. See Item 1. Business—Power for additional information on major growth projects. These additions to our fleet both expand our geographic diversity and adjust our fuel mix and are expected to contribute to the overall efficiency of operations.

Since 2013, several nuclear generating stations in the United States have closed or announced early retirement due to economic reasons, or have announced as being at risk for early retirement. This situation is generally due to low natural gas prices resulting from the growth of shale gas production since 2007, the continuing cost of regulatory compliance for nuclear facilities and both federal and state-level policies that provide credits to renewable energy such as wind and solar, but do not apply to

nuclear generating stations. These trends have significantly reduced the revenues to nuclear generating stations while simultaneously raising the unit cost of production. This may result in the electric generation industry experiencing a shift from nuclear generation to natural gas-fired generation, creating greater reliance on natural gas pipelines for delivery and less diversity of the generation fleet.

If trends noted above continue or worsen, our nuclear generating units could cease being economically competitive which may cause us to retire such units prior to the end of their useful lives. The costs associated with any such retirement, which may include, among other things, accelerated depreciation and amortization or impairment charges, accelerated asset retirement costs, severance costs and environmental remediation costs, could be material. We continue to advocate for sound policies that recognize nuclear power as a source of clean energy and an important part of a diverse and reliable energy portfolio.

Regulatory, Legislative and Other Developments

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

Transmission Planning

In April 2013, PJM initiated its first “open window” solicitation process to allow both incumbents and non-incumbents the opportunity to submit transmission project proposals to address identified high voltage issues in New Jersey. In February 2016, FERC issued an order granting PSE&G’s request that it be permitted to seek recovery of 100% of its portion of the project’s costs to address identified high voltage issues at Artificial Island in New Jersey if the project is canceled for reasons beyond PSE&G’s control. In April 2016, PSE&G accepted construction responsibility for the three components of the project that PJM assigned to it, based on having reached agreement with PJM regarding an estimate for the project base cost of $273 million, plus risk and contingency for a total project cost of up to $340 million. In August 2016, PJM announced that it had suspended the Artificial Island transmission project and would be performing a comprehensive analysis to support a future course of action. PJM will submit its final recommendation to the PJM Board at the April 2017 Board meeting.

In April 2016, PJM filed at FERC to incorporate a voltage threshold into PJM’s Regional Transmission Expansion Plan (RTEP) process to exempt, except under certain circumstances, reliability violations on facilities below 200 kV from PJM’s proposal window process. We generally support this reform as a measure to improve the efficiency of the open window procedure that will permit transmission developers to focus on the projects most likely to benefit from a competitive process.

There are several matters pending before FERC that concern the allocation of costs associated with transmission projects being constructed by PSE&G. Regardless of how these proceedings are resolved, PSE&G’s ability to recover the costs of these projects will not be affected. However, the result of these proceedings could ultimately impact the amount of costs borne by ratepayers in New Jersey and may cause increased scrutiny regarding PSE&G’s future capital investments. In addition, as a basic generation service (BGS) supplier, Power provides services that include specified transmission costs. If the allocation of the costs associated with the transmission projects were to increase these BGS-related transmission costs, BGS suppliers may be entitled to an adjustment, subject to BPU approval. We do not believe that these matters will have a material effect on Power’s business or results of operations.

Several complaints have been filed and several remain pending at FERC against transmission owners around the country, challenging those transmission owners’ base return on equity (ROE). Certain of those complaints have resulted in decisions and others have been settled, resulting in reductions of those transmission owners’ base ROEs. While we are not the subject of a challenge to the ROE employed in PSE&G’s transmission formula rate, the results of these other proceedings could set precedents for other transmission owners with formula rates in place, including PSE&G.

Wholesale Power Market Design

Capacity market design, including the Reliability Pricing Model (RPM) in PJM, remains an important focus for us. In June 2015, FERC conditionally accepted a proposal from PJM for a capacity performance product to include generators, Demand Response and energy efficiency providers, which will be required to perform during emergency conditions, as a supplement to the base capacity product. The proposal included enhanced performance-based incentives and penalties. We believe that the auction pricing adequately reflects the increased costs that could result from operating under more stringent rules for generation availability. Based on the auction results, the capacity performance mechanism appears to have provided the opportunity for enhanced capacity market revenue streams for Power, but future impacts cannot be assured. Further, there may be requirements for additional investment and there are additional performance and financial risks. Appeals of FERC’s capacity performance orders are pending.

In May 2016, PJM announced the results of the RPM capacity auction for the 2019-2020 delivery year. Power cleared 8,895 MW of its generating capacity at an average price of $116 per MW-day for the 2019-2020 delivery period. Of the cleared

capacity, Power believes that nearly all is compliant with PJM’s capacity performance requirements. In the two prior capacity auctions covering the 2017-2018 and 2018-2019 delivery years, Power cleared approximately 8,700 MW at average prices of $177 per MW-day and $215 per MW-day, respectively. Prices in the most recent auction reflect PJM’s downwardly-revised demand forecast, changes in the capacity emergency transfer limits due to transmission expansion and the effects of both the new generation and uncleared generation from the prior year’s auction.

As a result of the efforts of certain entities in PJM to obtain financial support arrangements from their state commission, a group of suppliers requested that FERC direct PJM to expand the currently effective “minimum offer price rule” to apply to certain existing units seeking subsidies. The suppliers’ request was intended to avoid a scenario where the subsidized generators would submit bids into the PJM capacity market that did not reflect their actual costs of operation and could artificially suppress capacity market prices. We are currently awaiting FERC action on the suppliers’ request and cannot predict the outcome of the proceeding.

See Item 1. Business—Federal Regulation for additional information.

Environmental Regulation

We continue to advocate for the development and implementation of fair and reasonable rules by the EPA and state environmental regulators. In particular, section 316(b) of the Federal Water Pollution Control Act (FWPCA) requires that cooling water intake structures, which are a significant part of the generation of electricity at steam-electric generating stations, reflect the best technology available for minimizing adverse environmental impacts. Implementation of Section 316(b) and related state regulations could adversely impact future nuclear and fossil operations and costs.

The U.S. Supreme Court’s February 2016 decision to stay the implementation of the Clean Power Plan (CPP), a greenhouse gas emissions regulation under the Clean Air Act (CAA) for existing power plants, will delay deadlines for submission of state requests for extensions and final plans. If the CPP is upheld, new deadlines will need to be established and the effective date of the compliance period may be impacted.

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. In particular, the historic operations of PSEG companies and the operations of numerous other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of various statutes. We are also 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, and the costs of any such remediation efforts could be material.

For further information regarding the matters described above as well as other matters that may impact our financial condition and results of operations, see Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities.

FERC Compliance

Since September 2014, FERC Staff has been conducting a preliminary non-public investigation regarding errors in the calculation of certain components of Power’s cost-based bids for its New Jersey fossil generating units in the PJM energy market and the quantity of energy that Power offered into the energy market for its fossil peaking units compared to the amounts for which Power was compensated in the capacity market for those units. This investigation is ongoing. The amounts of potential disgorgement and other potential penalties that we may incur span a wide range depending on the success of our legal arguments. If our legal arguments do not prevail, in whole or in part with FERC or in a judicial challenge that we may choose to pursue, it is likely that Power would record losses that would be material to PSEG’s and Power’s results of operations in the quarterly and annual periods in which they are recorded. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities.

Early Retirement of Hudson and Mercer Units

In October 2016, Power determined it will cease generation operations of the existing coal/gas units at the Hudson and Mercer generating stations on June 1, 2017. The exact timing of the early retirement of these units may be impacted by operational and other conditions that could subsequently arise. The decision to retire the Hudson and Mercer units will have a material effect on PSEG’s and Power’s results of operations. In 2016, PSEG and Power recognized pre-tax charges in Energy Costs and Operation and Maintenance (O&M) of $62 million and $53 million, respectively, related to coal inventory adjustments, capacity penalties, materials and supplies inventory reserve adjustments for parts that cannot be used at other generating units, employee-related severance benefits costs and construction work in progress impairments, among other shut down items. In addition to these charges, Power recognized incremental Depreciation and Amortization during 2016 of $555 million ($571 million in total) and expects to recognize an additional $931 million ($958 million in total) in 2017 due to the significant shortening of the expected economic useful lives of Hudson and Mercer. Additional employee-related salary continuance and severance costs and various miscellaneous costs may also be incurred during the period prior to retirement. Finally, Power currently anticipates using the

sites for alternative industrial activity. However, if Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would trigger obligations under certain environmental regulations, including possible remediation. The amounts for any such remediation are neither currently probable nor estimable but may be material. For additional information, including our estimated costs through 2017, see Item 8. Financial Statements and Supplementary Data—Note 3. Early Plant Retirements.

The primary factors considered during our annual five-year strategic planning process that contributed to the decision to retire these units early include significant declines in revenues and margin caused by a sustained period of depressed wholesale power prices and reduced capacity factors caused by lower natural gas prices making coal generation less economically competitive than natural gas-fired generation. Despite experiencing recent warmer than normal weather in PJM this summer, Power did not experience the usual increase in electricity prices in PJM as it had in past hot summers. This trend has a further adverse economic impact to these units because they generally dispatch and earn energy margin on peak hot and cold days. In addition, the upcoming PJM capacity auction in May 2017 will be the first to require all generating units to meet the increased operating performance standards of PJM’s new capacity performance construct. Power determined that the costs to upgrade the existing units at the Hudson and Mercer stations to be able to comply with these higher reliability standards are too significant and not economic given current market conditions.

In addition, PSEG and Power continue to monitor their other coal assets, including the Keystone and Conemaugh generating stations, to ensure their economic viability through the end of their designated useful lives and their continued classification as held for use. The precise timing of a change in useful lives may be dependent upon events out of PSEG’s and Power’s control and may impact our ability to operate or maintain these assets in the future. These generating stations may be impacted by factors such as environmental legislation, co-owner capital requirements and continued depressed wholesale power prices or capacity factors, among other things. Any early retirement or change in the classification as held for use of our remaining coal units may have a material adverse impact on PSEG’s and Power’s future financial results.

Leveraged Lease Impairments

During the third quarter of 2016, Energy Holdings completed its annual review of estimated residual values embedded in the NRG REMA, LLC (REMA) leveraged leases. The outcome indicated that the revised residual value estimates were lower than the recorded residual values and the decline was deemed to be other than temporary due to the adverse economic conditions experienced by coal generation in PJM, as discussed in Item 8. Financial Statements and Supplementary Data—Note 3. Early Plant Retirements, negatively impacting the economic outlook of the leased assets. As a result, a pre-tax write-down of $137 million was reflected in Operating Revenues in the quarter ended September 30, 2016, calculated by comparing the gross investment in the leases before and after the revised residual estimates. During the fourth quarter of 2016, Energy Holdings recorded a $10 million pre-tax charge in Operating Revenues reflecting its best estimate of loss as a result of the current liquidity issues facing REMA. There can be no assurance that a continuation or worsening of the adverse economic conditions would not lead to additional write-downs at any of our other generation units in our leveraged lease portfolio, and such write-downs could be material.

Additional facilities in our leveraged lease portfolio include the Joliet and Shawville generating facilities, which were converted to use natural gas. However, these units may have higher operating costs and fuel consumption as well as longer start-up times compared to newer combined cycle gas units. As a result, these facilities may not be as economically competitive as newer combined cycle gas units and could continue to be adversely impacted by the same economic conditions experienced by coal generation facilities, which could require Energy Holdings to write down the residual value of the leveraged leases associated with these facilities.

Further, REMA’s parent company, GenOn Energy, Inc. (GenOn), reported in August 2016 that it did not expect to have sufficient liquidity to repay their senior unsecured notes due in June 2017. Although all lease payments are current, PSEG cannot predict the outcome of GenOn’s efforts to restructure its portfolio and improve its liquidity and the possible related impact on REMA. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments, which could include further write-downs of the values of Energy Holdings’ leveraged leases. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 8. Financing Receivables.

Salem Operations

The previously announced bolt replacement at Salem Unit 1 was completed and the unit returned to service on July 30, 2016. We expect to continue to inspect and replace degraded bolts at both Salem units over the next several refueling outage cycles. We are participating with the Electric Power Research Institute, the Nuclear Energy Institute and other operators of similarly-designed pressurized water reactors in developing a strategy to maintain the long-term health of the reactor vessel internals.

Extension of the Salem Unit 1 outage into July and an unplanned outage at Salem Unit 2 due to a transformer failure currently under investigation reduced output from the Salem units in the third quarter. This was partially offset by increased production at our Hope Creek and Peach Bottom units. As a result, our nuclear capacity factor for the year ended December 31, 2016 was 86.9%.

Pension Plan Merger

As of December 31, 2016, PSEG merged its three qualified defined benefit pension plans (excluding Servco plans) into one plan, thereby also merging all of the pension plans’ assets. As a result, we estimate that in 2017, the total net periodic benefit costs are expected to decrease by approximately $72 million or $48 million, net of amounts capitalized, as compared to the 2017 amounts that would have been recognized had the plans not been merged. This is due to the amortization period for gains and losses for the merged plan resulting in lower amortization than that of the individual plans. No changes were made to the benefit formulas, vesting provisions, or to the employees covered by the plans.

Pension and Other Postretirement Benefits—Change in Accounting Estimate

At the end of 2015, we changed the approach used to measure future service and interest costs for pension and other post-retirement benefits. For 2015 and prior, we calculated service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the plan obligations. For 2016 and beyond, we have elected to calculate service and interest costs by applying the specific spot rates along that yield curve to the plans’ liability cash flows. We believe the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plans’ liability cash flows to the corresponding spot rates on the yield curve. This change did not affect the measurement of the plan obligations. As a change in accounting estimate, this change was reflected prospectively. We reduced 2016 pension and OPEB expense by approximately $34 million and $13 million, respectively, net of amounts capitalized.

Operational Excellence

We emphasize operational performance while developing opportunities in both our competitive and regulated businesses. Flexibility in our generating fleet has allowed us to take advantage of opportunities in a rapidly evolving market as we remain diligent in managing costs. In 2016, our

•	diverse fuel mix and dispatch flexibility allowed us to generate approximately 52 terra-watt hours while addressing fuel availability and price volatility and compensating for the extended outages at our Salem units,

•	combined cycle fleet produced 16 terawatt hours at an average capacity factor of 57%, and

•	utility was recognized for the fifteenth consecutive year as the most reliable utility in the Mid-Atlantic region.

Financial Strength

Our financial strength is predicated on a solid balance sheet, positive operating cash flow and reasonable risk-adjusted returns on increased investment. Our financial position remained strong during 2016 as we:

•	maintained sufficient liquidity,

•	maintained solid investment grade credit ratings, and

•	increased our indicative annual dividend for 2016 to $1.64 per share.

We expect to be able to fund our planned capital requirements, as described in Liquidity and Capital Resources, without the issuance of new equity.

Disciplined Investment

We utilize rigorous investment criteria when deploying capital and seek to invest in areas that complement our existing business and provide reasonable risk-adjusted returns. These areas include upgrading our energy infrastructure, responding to trends in environmental protection and providing new energy supplies in domestic markets with growing demand. In 2016, we

•	made additional investments in transmission infrastructure projects,

•	began executing our GSMP and continued executing Energy Strong and other existing BPU-approved utility programs,

•	commenced construction of our Keys and Sewaren 7 generation projects for targeted commercial operation in 2018 and announced our plan to construct BH5 and commence operations in mid-2019, and

•	acquired solar energy projects totaling 248 MW-direct current (dc), of which 177 MW dc are already in-service, primarily in North Carolina, Colorado and Utah. The remaining MW dc are scheduled to be in-service by the fourth quarter of 2017.

Future Outlook

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

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

•	successfully manage our energy obligations and re-contract our open supply positions in response to changes in demand,

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

•	effectively manage construction of our Keys, Sewaren 7, BH5 and other generation projects,

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

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

•	successfully operate the LIPA T&D system and manage LIPA’s fuel supply and generation dispatch obligations.

For 2017 and beyond, the key issues and challenges we expect our business to confront include:

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

•	fair and timely rate relief from the BPU and FERC for recovery of costs and return on investments, including with respect to our distribution base rate case which must be filed with the BPU no later than November 1, 2017,

•	the potential for comprehensive tax reform, particularly in light of public statements by the current U.S. administration and key members of Congress,

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

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

•	the impact of lower natural gas prices and increasing environmental compliance costs on the competitiveness of our nuclear and remaining coal-fired generation plants, and the potential for retirement of such plants earlier than their current useful lives,

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

•	maintaining a diverse mix of fuels to mitigate risks associated with fuel price volatility and market demand cycles, and

•	FERC Staff’s continuing investigation of certain of Power’s New Jersey fossil generating unit bids in the PJM energy market.

Our primary investment opportunities are in two areas: our regulated utility business and our merchant power business. We continually assess a broad range of strategic options to maximize long-term stockholder value. In assessing our options, we consider a wide variety of factors, including the performance and prospects of our businesses; the views of investors, regulators and rating agencies; our existing indebtedness and restrictions it imposes; and tax considerations, among other things. Strategic options available to us include:

•	the acquisition, construction or disposition of transmission and distribution facilities and/or generation units,

•	the disposition or reorganization of our merchant generation business or other existing businesses or the acquisition or development of new businesses,

•	the expansion of our geographic footprint,

•	continued or expanded participation in solar, demand response and energy efficiency programs, and

•	investments in capital improvements and additions, including the installation of environmental upgrades and retrofits, improvements to system resiliency, modernizing existing infrastructure and participation in transmission projects through FERC’s “open window” solicitation process.

In 2016, Power announced its intention to develop a retail platform to sell physical electricity and natural gas, which we believe would complement our existing wholesale marketing business. Power was granted licenses in 2016 to sell both electricity and gas in the states of New Jersey and Pennsylvania.

There can be no assurance, however, that we will successfully develop and execute any of the strategic options noted above, or any additional options we may consider in the future. The execution of any such strategic plan may not have the expected benefits or may have unexpected adverse consequences.

RESULTS OF OPERATIONS

			Years Ended December 31,
			2016				2015				2014
	Earnings (Losses)		Millions
	PSE&G		$	889			$	787			$	725
	Power (A)		18				856				760
	Other (B)		(20		)		36				33
	PSEG Net Income		$	887			$	1,679			$	1,518
	PSEG Net Income Per Share (Diluted)		$	1.75			$	3.30			$	2.99

(A)	Power’s results in 2016 includes after-tax expenses of $396 million related to the early retirement of its Hudson and Mercer coal/gas generation plants. See Item 8. Financial Statements and Supplementary Data—Note 3. Early Plant Retirements for additional information. Power’s results in 2015 include an after-tax insurance recovery for Superstorm Sandy of $102 million.

(B)

Other includes after-tax activities at the parent company, PSEG LI and Energy Holdings as well as intercompany eliminations. Energy Holdings recorded after-tax charges totaling $92 million related to its investments in NRG REMA, LLC’s leveraged leases in 2016. See Item 8. Financial Statements and Supplementary Data—Note 7. Long-Term Investments and Note 8. Financing Receivables for further information.

Our results include the realized gains, losses and earnings on Power’s NDT Fund and other related NDT activity. Realized gains and losses, interest and dividend income and other costs related to the NDT Fund are recorded in Other Income (Deductions), and impairments on certain NDT securities are recorded as Other-Than-Temporary Impairments. Interest accretion expense on Power’s nuclear ARO is recorded in O&M Expense and the depreciation related to the ARO asset is recorded in Depreciation and Amortization Expense. In 2014, we restructured portions of our NDT Fund and realized a pre-tax gain of $65 million.

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

The combined after-tax impact on Net Income for the years ended December 31, 2016, 2015 and 2014 include the changes related to NDT Fund and MTM activity shown in the chart below:

	Years Ended December 31,		2016				2015				2014
			Millions, after tax
	NDT Fund and Related Activity (A)		$	—			$	8			$	68
	Non-Trading MTM Gains (Losses) (B)		$	(100	)		$	93			$	66

(A)	Net of tax (expense) benefit of $(5) million, $(16) million and $(70) million for the years ended December 31, 2016, 2015 and 2014, respectively.

(B)	Net of tax (expense) benefit of $68 million, $(65) million and $(45) million for the years ended December 31, 2016, 2015 and 2014, respectively.

The 2016 year-over-year decrease in our Net Income was driven primarily by:

•	charges related to the early retirement of two coal/gas generation units at Power (See Item 8. Financial Statements and Supplementary Data—Note 3. Early Plant Retirements),

•	MTM losses in 2016 as compared to MTM gains in 2015,

•	lower volumes of energy sold at lower average realized sales prices,

•	lower capacity and operating reserve revenues in PJM,

•	higher 2016 congestion costs in PJM due primarily to realized gains on financial transmission rights (FTR) in PJM in the prior year due to extremely cold weather,

•	lower volumes of gas sold at lower average prices under the Basic Gas Supply Service (BGSS) contract,

•	insurance recoveries received primarily by Power in 2015 related to Superstorm Sandy, and

•	an impairment related to investments in certain leveraged leases at Energy Holdings (See Item 8. Financial Statements and Supplementary Data—Note 8. Financing Receivables).

These decreases were partially offset by:

•	lower generation costs driven by lower fuel costs, particularly for natural gas, and reduced generation output at Power,

• higher costs incurred at Power for planned outages in 2015,

•	higher transmission revenues, and

•	higher management fee revenues at PSEG LI pursuant to the OSA.

The 2015 year-over-year increase in our Net Income was driven by:

•	higher transmission revenues,

•	lower generation costs due to lower fuel costs, primarily reflecting lower natural gas and coal prices,

•	higher MTM gains in 2015, and

•	insurance recoveries of Superstorm Sandy costs, primarily at Power.

These increases were partially offset by:

•	lower capacity revenues resulting from lower average auction prices coupled with lower ancillary and operating reserve revenues in the PJM region,

•	lower realized gains and higher other-than-temporary impairments related to the NDT Fund, and

•	higher pension and OPEB costs, net of amounts capitalized.

PSEG

Our results of operations are primarily comprised of the results of operations of our principal operating subsidiaries, PSE&G and Power, excluding charges related to intercompany transactions, which are eliminated in consolidation. For additional information on intercompany transactions, see Item 8. Financial Statements and Supplementary Data—Note 24. Related-Party Transactions.

															Increase / (Decrease)							Increase / (Decrease)
			Years Ended December 31,
			2016				2015				2014				2016 vs. 2015						2015 vs. 2014
			Millions												Millions				%			Millions				%
	Operating Revenues		$	9,061			$	10,415			$	10,886			$	(1,354	)		(13	)		$	(471	)		(4	)
	Energy Costs		3,001				3,261				3,886				(260		)		(8	)		(625		)		(16	)
	Operation and Maintenance		3,008				2,978				3,150				30				1			(172		)		(5	)
	Depreciation and Amortization		1,476				1,214				1,227				262				22			(13		)		(1	)
	Income from Equity Method Investments		11				12				13				(1		)		(8	)		(1		)		(8	)
	Other Income (Deductions)		124				152				229				(28		)		(18	)		(77		)		(34	)
	Other-Than-Temporary Impairments		28				53				20				(25		)		(47	)		33				N/A
	Interest Expense		385				393				389				(8		)		(2	)		4				1
	Income Tax Expense		411				1,001				938				(590		)		(59	)		63				7

The 2016, 2015 and 2014 amounts in the preceding table for Operating Revenues and O&M costs each include $410 million, $375 million and $389 million, respectively, for Servco. These amounts represent the O&M pass-through costs for the Long Island operations, the full reimbursement of which is reflected in Operating Revenues. See Item 8. Financial Statements and Supplementary Data—Note 4. Variable Interest Entities for further explanation. The following discussions for PSE&G and Power provide a detailed explanation of their respective variances.

PSE&G

			Years Ended December 31,												Increase / (Decrease)							Increase / (Decrease)
			2016				2015				2014				2016 vs. 2015						2015 vs. 2014
			Millions												Millions				%			Millions				%
	Operating Revenues		$	6,221			$	6,636			$	6,766			$	(415	)		(6	)		$	(130	)		(2	)
	Energy Costs		2,567				2,722				2,909				(155		)		(6	)		(187		)		(6	)
	Operation and Maintenance		1,475				1,560				1,558				(85		)		(5	)		2				—
	Depreciation and Amortization		565				892				906				(327		)		(37	)		(14		)		(2	)
	Other Income (Deductions)		79				75				58				4				5			17				29
	Interest Expense		289				280				277				9				3			3				1
	Income Tax Expense		515				470				449				45				10			21				5

Year Ended December 31, 2016 as compared to 2015

Operating Revenues decreased $415 million due to changes in delivery, clause, commodity and other operating revenues.

Delivery Revenues increased $191 million due primarily to an increase in transmission revenues.

•	Transmission revenues were $223 million higher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.

•	Electric distribution revenues decreased $27 million due primarily to $47 million in lower collections of Green Program Recovery Charges (GPRC), partially offset by an $18 million increase in Energy Strong revenues.

•	Gas distribution revenues decreased $5 million due to a decrease of $43 million due to lower sales volumes and $7 million in lower collections of GPRC. These decreases were partially offset by higher Weather Normalization Clause (WNC) revenues of $25 million due to warmer weather in 2016 compared to 2015 and $20 million due to the inclusion of Energy Strong in base rates.

Clause Revenues decreased $445 million due to lower Securitization Transition Charge (STC) revenues of $419 million, lower Societal Benefit Charges (SBC) of $33 million, and lower Solar Pilot Recovery Charges (SPRC) of $8 million. These decreases were partially offset by higher Margin Adjustment Clause (MAC) revenues of $15 million. The changes in STC, SBC, SPRC and MAC amounts were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on STC, SBC, SPRC or MAC collections.

Commodity Revenues decreased $155 million due to lower Electric and Gas revenues. This is entirely offset with decreased Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.

•	Electric revenues decreased $136 million due to $73 million in lower collections of Non-Utility Generation Charges (NGC) due primarily to lower prices, $42 million in lower revenues from the sale of Non-Utility Generation (NUG) energy and $21 million in lower BGS revenues primarily due to lower sales volumes.

•	Gas revenues decreased $19 million due to $80 million from lower sales volumes, partially offset by higher BGSS prices of $61 million.

Operating Expenses

Energy Costs decreased $155 million. This is entirely offset by Commodity Revenues.

Operation and Maintenance decreased $85 million due to

•	a $98 million net reduction related to various clause mechanisms and GPRC, and

•	a $13 million decrease in pension and OPEB expenses, net of amounts capitalized,

•	partially offset by $10 million of insurance recovery proceeds in 2015,

•	a $10 million increase in vegetation management costs, and

•	a $6 million net increase due primarily to transmission and distribution corrective maintenance and appliance service costs.

Depreciation and Amortization decreased $327 million due primarily to a $396 million net decrease in amortization of Regulatory Assets, partially offset by an increase in depreciation of $65 million due additional plant placed into service in 2016.

Interest Expense increased $9 million due to increases of

•	$14 million due to net debt issuances in 2015, and

•	$13 million due to net debt issuances in 2016,

•	partially offset by a decreases of $11 million due to the redemption of securitization debt in 2015 and

•	$7 million of higher interest related to BGSS in 2015.

Income Tax Expense increased $45 million due primarily to higher pre-tax income partially offset by changes in the reserve for uncertain tax positions and flow through items.

Year Ended December 31, 2015 as compared to 2014

Operating Revenues decreased $130 million due to changes in delivery, clause, commodity and other operating revenues.

Delivery Revenues increased $212 million due primarily to an increase in transmission revenues.

•	Transmission revenues were $164 million higher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.

•	Electric distribution revenues increased $31 million due primarily to higher sales volumes due to weather.

•	Gas distribution revenues increased $17 million due to higher WNC revenues of $35 million due to warmer weather in 2015 compared to 2014, partially offset by $18 million due to lower sales volumes.

Clause Revenues decreased $154 million due to lower STC revenues of $86 million, lower SBC of $31 million, lower MAC of $29 million, and lower SPRC of $8 million. The changes in STC, SBC, MAC and SPRC amounts were entirely offset by decreases in the amortization of Regulatory Assets and related costs in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on STC, SBC, MAC or SPRC collections.

Commodity Revenues decreased $187 million due to lower Gas revenues, partially offset by higher Electric revenues. This is entirely offset with decreased Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.

•	Gas revenues decreased $266 million due to lower BGSS prices of $295 million, partially offset by $29 million from higher sales volumes. The average price of natural gas was 29% lower to the customer in 2015 than in 2014.

•

Electric revenues increased $79 million due to $120 million in higher net BGS revenues, comprised of $166 million from higher sales volumes, partially offset by lower prices of $46 million. BGS sales volume increased due primarily to weather. The BGS net revenue increase was partially offset by $41 million in lower revenues from the sale of NUG energy and the collections of NGC due primarily to lower prices.

Operating Expenses

Energy Costs decreased $187 million. This is entirely offset by Commodity Revenues.

Operation and Maintenance increased $2 million, of which the most significant components were increases of

•	$33 million in pension and OPEB expenses, net of amounts capitalized,

•	$13 million in transmission operating expenses,

•	$7 million in gas bad debt expense, and

•	a $49 million net increase due to various increases, including information technology expenditures, wages, appliance service costs and preventative maintenance,

•	almost entirely offset by a $90 million net reduction related to various clause mechanisms, GPRC and the Capital Infrastructure Program, and

•	$10 million of insurance recovery proceeds.

Depreciation and Amortization decreased $14 million due to a $69 million decrease in amortization of Regulatory Assets, partially offset by an increase in depreciation of $55 million due to additional plant in service.

Other Income (Deductions) net increase of $17 million in AFUDC.

Interest Expense increased $3 million due primarily to increases of

•	$12 million due to net debt issuances in the latter half of 2014, and

•	$9 million due to net debt issuances in 2015,

•	partially offset by a decrease of $17 million due to the redemption of securitization debt in 2015.

Income Tax Expense increased $21 million due primarily to higher pre-tax income.

Power

			Years Ended December 31,												Increase / (Decrease)							Increase / (Decrease)
			2016				2015				2014				2016 vs. 2015						2015 vs. 2014
			Millions												Millions				%			Millions				%
	Operating Revenues		$	4,023			$	4,928			$	5,434			$	(905	)		(18	)		$	(506	)		(9	)
	Energy Costs		1,986				2,150				2,747				(164		)		(8	)		(597		)		(22	)
	Operation and Maintenance		1,143				1,057				1,186				86				8			(129		)		(11	)
	Depreciation and Amortization		881				291				292				590				N/A			(1		)		—
	Income from Equity Method Investments		11				14				14				(3		)		(21	)		—				—
	Other Income (Deductions)		45				97				170				(52		)		(54	)		(73		)		(43	)
	Other-Than-Temporary Impairments		28				53				20				(25		)		(47	)		33				N/A
	Interest Expense		84				121				122				(37		)		(31	)		(1		)		(1	)
	Income Tax Expense (Benefit)		(61		)		511				491				(572		)		N/A			20				4

Year Ended December 31, 2016 as compared to 2015

Operating Revenues decreased $905 million due to changes in generation, gas supply and other operating revenues.

Generation Revenues decreased $714 million due primarily to

•	a decrease of $317 million due to MTM losses in 2016 as compared to MTM gains in 2015. Of this amount, $199 million was due to changes in forward power prices resulting in lower MTM gains this year compared to last year. Also contributing to the decrease was $118 million of higher gains on positions reclassified to realized upon settlement this year compared to last year,

•	a decrease of $298 million in energy sales volumes in the PJM, NE and NY regions due primarily to milder weather in 2016 and lower average realized prices,

•	a decrease of $80 million in capacity revenue primarily in the PJM region due to the retirement of older peaking units in June 2015, and

•	a decrease of $49 million due to lower operating reserve revenues in the PJM region due to less congestion and lower prices,

•	partially offset by a net increase of $19 million due primarily to higher volumes of electricity sold under wholesale load contracts in the PJM and NE regions, partially offset by lower average prices, and

•	a net increase of $8 million due to new solar projects beginning commercial operations.

Gas Supply Revenues decreased $191 million due primarily to

•	a decrease of $183 million in sales under the BGSS contract due primarily to lower average sales prices and a decrease in sales volumes due to warmer average temperatures in the 2016 heating season, and

•	a decrease of $9 million due to MTM losses in 2016 due to changes in forward prices.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $164 million due to

Generation costs decreased $95 million due primarily to

•	lower fuel costs of $288 million reflecting lower average realized prices for natural gas and the utilization of lower volumes of fuel,

•	partially offset by a net increase of $143 million primarily due to realized gains on FTRs in PJM in the prior year due to extremely cold weather, and

•	a $62 million charge associated with the announced early retirement of the Mercer and Hudson units, primarily related to a coal inventory write-down.

Gas costs decreased $69 million due to

•	a decrease of $101 million related to sales under the BGSS contract due primarily to lower average gas costs and a decrease in volumes sold due to warmer average temperatures during the 2016 winter heating season,

•	partially offset by an increase of $32 million related to sales to third parties due primarily to higher average gas costs and an increase in volumes sold.

Operation and Maintenance increased $86 million due to

•	$145 million of insurance recoveries received in 2015 related to Superstorm Sandy, and

•	$53 million of charges related to the early retirement of the Hudson and Mercer units,

•	partially offset by a net decrease of $73 million related to our fossil plants, largely due to higher costs incurred in 2015 for our planned major outages at the Bethlehem Energy Center and Bergen generating plants,

•	a net decrease of $31 million related to our nuclear plants due primarily to lower planned outage costs at our 100%-owned Hope Creek plant and our 57%-owned Salem Unit 1 plant, and

•	an $8 million decrease due to lower pension and OPEB costs.

Depreciation and Amortization increased $590 million due primarily to

•	$555 million of accelerated depreciation due to the early retirement of the Hudson and Mercer units,

•	a $24 million increase due primarily to a higher nuclear asset base, and

•	$5 million of higher depreciation due to new solar projects.

Other Income (Deductions) decreased $52 million due primarily to $28 million of insurance recoveries received in 2015 related to Superstorm Sandy and $38 million of lower net realized gains from the NDT Fund in 2016, partially offset by $10 million of lower purchased tax credits in 2016.

Other-Than-Temporary Impairments decreased $25 million due to lower impairments of equity securities in the NDT Fund in 2016.

Interest Expense decreased $37 million due to

•	$27 million of interest capitalized for the construction of three new fossil stations: Bridgeport Harbor 5, Sewaren 7 and Keys Energy Center, and

•	a $15 million decrease due to the maturity of 5.50% of Senior Notes in December 2015,

•	partially offset by an increase of $5 million due to net debt issuances in 2016.

Income Tax Expense decreased $572 million in 2016 due primarily to a pre-tax loss in 2016 as compared to pre-tax income in 2015.

Year Ended December 31, 2015 as compared to 2014

Operating Revenues decreased $506 million due to changes in generation, gas supply and other operating revenues.

Generation Revenues decreased $172 million due to

•	a decrease of $192 million due primarily to lower capacity revenues resulting from lower average auction prices and the retirement of older peaking units in June 2015, coupled with lower ancillary and operating reserve revenues in the PJM region, and

•	lower net revenues of $73 million due primarily to lower energy volumes sold in the NE region and lower average realized prices in the NE and NY regions, partially offset by higher energy volumes sold in the NY and PJM regions. Also included in the net decrease is $22 million due to lower MTM gains in 2015.

•	partially offset by an increase of $56 million due primarily to higher volumes of electricity sold under wholesale load contracts in the PJM and NE regions coupled with higher average prices in the NE region, and

•	an increase of $37 million due primarily to higher volumes of electricity sold under the BGS contract at higher average prices.

Gas Supply Revenues decreased $336 million due to

•	a net decrease of $214 million in sales under the BGSS contract, substantially comprised of lower average sales prices, and

•	a decrease of $122 million on sales to third-party customers, of which $93 million was due to lower average sales prices and $29 million to lower volumes sold.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $597 million due to

•	Generation costs decreased $254 million due primarily to lower fuel costs of $330 million reflecting lower average realized natural gas and coal prices and the utilization of lower volumes of oil and coal. MTM gains in 2015 as compared to MTM losses in 2014 resulted in a $66 million decrease. These decreased costs were partially offset by higher congestion costs in the PJM region of $140 million.

•	Gas costs decreased $343 million mainly related to a decrease in average gas costs on both obligations under the BGSS contract and sales to third parties.

Operation and Maintenance decreased $129 million due primarily to

•	a decrease of $145 million due to insurance recoveries received in 2015 related to Superstorm Sandy, and

•	a net decrease of $61 million related to our fossil plants, largely due to higher costs incurred in 2014 for planned outage costs, including maintenance and installation of upgraded technology at our Linden combined cycle gas generating plant, partially offset by planned outage costs in 2015 at our BEC generating plant and installation of upgraded technology at our combined cycle Bergen plant,

•	partially offset by an increase of $51 million at our nuclear facilities, primarily due to higher planned outage costs at our 100%-owned Hope Creek and 50%-owned Peach Bottom 3 nuclear plants in 2015 as compared to our 57%-owned Salem nuclear unit 2 in 2014, and

•	a $30 million increase due to higher pension and OPEB costs, net of amounts capitalized.

Other Income (Deductions) decreased $73 million due primarily to lower net realized gains from the NDT Fund, partially offset by a $28 million insurance recovery related to Superstorm Sandy.

Other-Than-Temporary Impairments increased $33 million due primarily to an increase in impairments of equity securities in the NDT Fund.

Income Tax Expense increased $20 million in 2015 due primarily to higher pre-tax income.

LIQUIDITY AND CAPITAL RESOURCES

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

Financing Methodology

We expect our capital requirements to be met through internally generated cash flows and external financings, consisting of short-term debt for working capital needs and long-term debt for capital investments.

PSE&G’s sources of external liquidity include a $600 million multi-year syndicated credit facility. PSE&G uses internally generated cash flow and its commercial paper program to meet seasonal, intra-month and temporary working capital needs.

PSE&G does not engage in any intercompany borrowing or lending arrangements. PSE&G maintains back-up facilities in an amount sufficient to cover the commercial paper and letters of credit outstanding. PSE&G’s dividend payments to/capital contributions from PSEG are consistent with its capital structure objectives which have been established to maintain investment grade credit ratings. PSE&G’s long-term financing plan is designed to replace maturities, fund a portion of its capital program and manage short-term debt balances. Generally, PSE&G uses either secured medium-term notes or first mortgage bonds to raise long-term capital.

PSEG, Power, Energy Holdings, PSEG LI and Services participate in a corporate money pool, an aggregation of daily cash balances designed to efficiently manage their respective short-term liquidity needs. Servco does not participate in the corporate money pool. Servco’s short-term liquidity needs are met through an account funded and owned by LIPA.

PSEG’s sources of external liquidity may include the issuance of long-term debt securities and the incurrence of additional indebtedness under credit facilities. Our current sources of external liquidity include multi-year syndicated credit facilities totaling $1 billion. These facilities are available to back-stop PSEG’s commercial paper program, issue letters of credit and for general corporate purposes. These facilities may also be used to provide support to PSEG’s subsidiaries. PSEG’s credit facilities and the commercial paper program are available to support PSEG working capital needs or to temporarily fund growth opportunities in advance of obtaining permanent financing. PSEG also has a $500 million term loan credit agreement that is scheduled to expire in November 2017. From time to time, PSEG may make equity contributions or provide credit support to its subsidiaries.

Power’s sources of external liquidity include $2.6 billion of syndicated multi-year credit facilities. Additionally, from time to time, Power maintains bilateral credit agreements designed to enhance its liquidity position. Credit capacity is primarily used to provide collateral in support of Power’s forward energy sale and forward fuel purchase contracts as the market prices for energy and fuel fluctuate, and to meet potential collateral postings in the event that Power is downgraded to below investment grade by S&P or Moody’s. Power’s dividend payments to PSEG are also designed to be consistent with its capital structure objectives which have been established to maintain investment grade credit ratings and provide sufficient financial flexibility. Generally, Power issues senior unsecured debt to raise long-term capital.

Operating Cash Flows

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

For the year ended December 31, 2016, our operating cash flow decreased by $608 million. For the year ended December 31, 2015, our operating cash flow increased by $759 million. The net changes were primarily due to net changes from our subsidiaries as discussed below.

PSE&G

PSE&G’s operating cash flow decreased $231 million from $2,125 million to $1,894 million for the year ended December 31, 2016, as compared to 2015, due primarily to a decrease from lower collections for securitization debt principal repayments which were $259 million in 2015, a decrease of $249 million in cash receipts from customers due to lower sales driven by warmer winter weather in 2016 compared to 2015, a decrease of $90 million related to a change in regulatory deferrals, primarily driven by net returns to customers in 2016 related to 2015 overcollections, partially offset by higher bill credits and $74 million in increased vendor payments. These amounts were partially offset by higher earnings and higher tax refunds in 2016.

PSE&G’s operating cash flow increased $292 million from $1,833 million to $2,125 million for the year ended December 31, 2015, as compared to 2014, due primarily to higher earnings, a $311 million reduction in tax payments, and an increase of $102 million due to higher customer billings in the fourth quarter of 2014 primarily as a result of increased usage due to weather. These increases were partially offset by a decrease of $250 million related to a change in regulatory deferrals, primarily driven by the return of prior year overcollections to customers for BGSS gas costs, Gas WNC charges and BGS costs.

Power

Power’s operating cash flow decreased $451 million from $1,706 million to $1,255 million for the year ended December 31, 2016, as compared to 2015, primarily resulting from lower earnings, an increase in margin deposit requirements of $198 million, and a $134 million decrease from net collection of counterparty receivables, partially offset by a reduction in tax payments.

Power’s operating cash flow increased $281 million from $1,425 million to $1,706 million for the year ended December 31, 2015, as compared to 2014, primarily resulting from higher earnings, a decrease in margin deposit requirements of $144 million, and a $78 million increase from net collection of counterparty receivables. These amounts were partially offset by an increase of $325 million in tax payments.

Short-Term Liquidity

We continually monitor our liquidity and seek to add capacity as needed to meet our liquidity requirements. Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. Our total credit facilities and available liquidity as of December 31, 2016 were as follows:

	Company/Facility		As of December 31, 2016
	Total Facility				Usage				Available Liquidity
			Millions
	PSEG		$	1,000			$	398			$	602
	PSE&G		600				14				586
	Power		2,553				198				2,355
	Total		$	4,153			$	610			$	3,543

As of December 31, 2016, our credit facility capacity was in excess of our projected maximum liquidity requirements over our 12 month planning horizon. Our maximum liquidity requirements are based on stress scenarios that incorporate changes in commodity prices and the potential impact of Power losing its investment grade credit rating from S&P or Moody’s, which would represent a three level downgrade from its current S&P or Moody’s ratings. In the event of a deterioration of Power’s credit rating certain of Power’s agreements allow the counterparty to demand further performance assurance. The potential additional collateral that we would be required to post under these agreements if Power were to lose its investment grade credit rating was approximately $783 million and $864 million as of December 31, 2016 and 2015, respectively. The early retirement of Power’s Hudson and Mercer coal/gas generation units is not expected to have a material impact on Power’s debt covenant ratios or its ability to obtain credit facilities. See Item 8. Financial Statements and Supplementary Data—Note 3. Early Plant Retirements.

For additional information, see Item 8.Financial Statements and Supplementary Data—Note 14. Debt and Credit Facilities.

Long-Term Debt Financing

PSEG has a floating rate $500 million term loan maturing in November 2017.

For a discussion of our long-term debt transactions during 2016 and into 2017, see Item 8. Financial Statements and Supplementary Data—Note 14. Debt and Credit Facilities.

Debt Covenants

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

In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements, provided that its ratio of earnings to fixed charges calculated in accordance with its Mortgage is at least 2 to 1, and/or against retired Mortgage Bonds. As of December 31, 2016, PSE&G’s Mortgage coverage ratio was 4.2 to 1 and the Mortgage would permit up to approximately $5.7 billion aggregate principal amount of new Mortgage Bonds to be issued against additions and improvements to its property.

Default Provisions

Our bank credit agreements and indentures contain various, customary default provisions that could result in the potential acceleration of indebtedness under the defaulting company’s agreement.

In particular, PSEG’s bank credit agreements contain provisions under which certain events, including an acceleration of material indebtedness under PSE&G’s and Power’s respective financing agreements, a failure by PSE&G or Power to satisfy certain final judgments and certain bankruptcy events by PSE&G or Power, that would constitute an event of default under the PSEG bank credit agreements. Under the PSEG bank credit agreements, it would also be an event of default if either PSE&G or Power ceases to be wholly owned by PSEG. The PSE&G and Power bank credit agreements include similar default provisions; however such provisions only relate to the respective borrower under such agreement and its subsidiaries and do not contain cross default provisions to each other. The PSE&G and Power bank credit agreements do not include cross default provisions relating to PSEG.

There are no cross acceleration provisions in PSEG’s or PSE&G’s indentures. However, PSEG’s existing notes include a cross acceleration provision that may be triggered upon the acceleration of more than $75 million of indebtedness incurred by PSEG. Such provision does not extend to an acceleration of indebtedness by any of PSEG’s subsidiaries. Power’s indenture includes a cross acceleration provision similar to that described above for PSEG’s existing notes except that such provision may be triggered upon the acceleration of more than $50 million of indebtedness incurred by Power or any of its subsidiaries. Such provision does not cross accelerate to PSEG, any of PSEG’s subsidiaries (other than Power and its subsidiaries), PSE&G or any of PSE&G’s subsidiaries.

Ratings Triggers

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

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

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

Common Stock Dividends

			Years Ended December 31,
	Dividend Payments on Common Stock		2016				2015				2014
	Per Share		$	1.64			$	1.56			$	1.48
	in Millions		$	830			$	789			$	748

On February 21, 2017, our Board of Directors approved a $0.43 per share common stock dividend for the first quarter of 2017. This reflects an indicative annual dividend rate of $1.72 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant. For additional information related to cash dividends on our common stock, see Item 8. Financial Statements and Supplementary Data—Note 22. Earnings Per Share (EPS) and Dividends.

Credit Ratings

If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Credit Ratings shown are for securities that we typically issue. Outlooks are shown for Corporate Credit Ratings (S&P) and Issuer Credit Ratings (Moody’s) and can be Stable, Negative, or Positive. There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security.

In January 2016, S&P published updated research reports on PSEG and PSE&G and the existing ratings and outlooks were unchanged. In June 2016, Moody’s published credit opinions on Power and PSE&G and the existing ratings and outlooks were unchanged. In June 2016, S&P published an updated research report on Power and the existing rating and outlook were unchanged. In September 2016, Moody’s published an updated research report on PSEG and the existing rating and outlook were unchanged.

		Moody’s (A)		S&P (B)
	PSEG
	Outlook	Positive		Stable
	Senior Notes	Baa2		BBB
	Commercial Paper	P2		A2
	PSE&G
	Outlook	Stable		Stable
	Mortgage Bonds	Aa3		A
	Commercial Paper	P1		A2
	Power
	Outlook	Stable		Stable
	Senior Notes	Baa1		BBB+

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

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

Other Comprehensive Income

For the year ended December 31, 2016, we had Other Comprehensive Income of $32 million on a consolidated basis. Other Comprehensive Income was due primarily to a $42 million increase in net unrealized gains related to Available-for-Sale Securities and $2 million of unrealized gains on derivative contracts accounted for as hedges, partially offset by a decrease of $12 million in our consolidated liability for pension and postretirement benefits. See Item 8. Financial Statements and Supplementary Data—Note 21. Accumulated Other Comprehensive Income (Loss), Net of Tax for additional information.

CAPITAL REQUIREMENTS

We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. Projected capital construction and investment expenditures, excluding nuclear fuel purchases, for the next three years are presented in the table below. These projections include Allowance for Funds Used During Construction and Interest Capitalized During Construction for PSE&G and Power, respectively. These amounts are subject to change, based on various factors. Amounts shown below for Energy Strong, GSMP and Solar/Energy Efficiency programs are for currently approved programs. We intend to continue to invest in infrastructure modernization and will seek to extend these and related programs as appropriate. We will also continue to approach potential growth investments for Power opportunistically, seeking projects that will provide attractive risk-adjusted returns for our shareholders.

			2017				2018				2019
							Millions
	PSE&G:
	Transmission		$	1,630			$	1,375			$	1,110
	Distribution		1,180				775				615
	Energy Strong		205				75				15
	Gas System Modernization Program		305				315				50
	Solar/Energy Efficiency		90				75				60
	Total PSE&G		$	3,410			$	2,615			$	1,850
	Power:
	Baseline		$	190			$	210			$	170
	Environmental/Regulatory		35				35				35
	Fossil Growth Opportunities		825				405				90
	Nuclear Expansion		20				20				10
	Solar Growth Opportunities		130				—				—
	Total Power		$	1,200			$	670			$	305
	Other		$	50			$	35			$	35
	Total PSEG		$	4,660			$	3,320			$	2,190

PSE&G

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

•	Transmission—investments focused on reliability improvements and replacement of aging infrastructure.

•	Distribution—investments for new business, reliability improvements, and replacement of equipment that has reached the end of its useful life.

•	Energy Strong—Electric and Gas Distribution reliability investment program focused on system hardening and resiliency.

•	Gas System Modernization Program—Gas Distribution investment program to replace aging infrastructure.

•	Solar/Energy Efficiency—investments associated with grid-connected solar, solar loan programs, and customer energy efficiency programs.

In August 2016, PSE&G filed a petition with the BPU requesting approval of the $268 million investment and an associated cost recovery mechanism to develop a project where PSE&G would rebuild New Jersey Transit’s Mason substation and related facilities in Kearny, NJ. This is not included in PSE&G’s projected capital expenditures.

In 2016, PSE&G made $2,816 million of capital expenditures, primarily for transmission and distribution system reliability. This does not include expenditures for cost of removal, net of salvage, of $131 million, which are included in operating cash flows.

Power

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

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

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

•	Fossil Growth Opportunities—investments associated with new construction, including Keys Energy Center, Sewaren 7 and BH5, and with upgrades to increase efficiency and output at combined cycle plants.

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

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

In 2016, Power made $1,136 million of capital expenditures, excluding $207 million for nuclear fuel, primarily related to various projects at Fossil, Solar and Nuclear.

Disclosures about Contractual Obligations

The following table reflects our contractual cash obligations in the respective periods in which they are due. In addition, the table summarizes anticipated debt maturities for the years shown. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 14. Debt and Credit Facilities.

The table below does not reflect any anticipated cash payments for pension obligations due to uncertain timing of payments or liabilities for uncertain tax positions since we are unable to reasonably estimate the timing of liability payments in individual years beyond 12 months due to uncertainties in the timing of the effective settlement of tax positions. See Item 8. Financial Statements and Supplementary Data—Note 20. Income Taxes for additional information.

			Total Amount Committed				Less Than 1 Year				2 - 3 Years				4- 5 Years				Over 5 Years
			Millions
	Contractual Cash Obligations
	Long-Term Recourse Debt Maturities
	PSEG		$	1,200			$	500			$	400			$	300			$	—
	PSE&G		7,883				—				1,250				693				5,940
	Power		2,400				—				294				1,356				750
	Interest on Recourse Debt
	PSEG		57				20				25				12				—
	PSE&G		4,986				299				555				502				3,630
	Power		935				113				221				170				431
	Capital Lease Obligations
	Power		3				1				1				1				—
	Operating Leases
	PSE&G		100				12				15				12				61
	Power		52				3				6				4				39
	Services		198				13				26				27				132
	Other		5				1				2				2				—
	Energy-Related Purchase Commitments
	Power		2,625				745				898				450				532
	Total Contractual Cash Obligations		$	20,444			$	1,707			$	3,693			$	3,529			$	11,515
	Liability Payments for Uncertain Tax Positions
	PSEG		$	14			$	14			$	—			$	—			$	—
	PSE&G		3				3				—				—				—
	Power		7				7				—				—				—

OFF-BALANCE SHEET ARRANGEMENTS

PSEG and Power issue guarantees, primarily in conjunction with certain of Power’s energy contracts. See Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities for further discussion.

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

In the event that collection of the minimum lease payments to be received by Energy Holdings is no longer reasonably assured, Energy Holdings may deem that a lessee has a high probability of defaulting on the lease obligation, and would consider the need to record an impairment of its investment. In the event the lease is ultimately rejected by the lessee in a Bankruptcy Court proceeding, the fair value of the underlying asset and the associated debt would be recorded on the Consolidated Balance Sheets instead of the net equity investment in the lease.

CRITICAL ACCOUNTING ESTIMATES

Under GAAP, many accounting standards require the use of estimates, variable inputs and assumptions (collectively referred to as estimates) that are subjective in nature. Because of this, differences between the actual measure realized versus the estimate

can have a material impact on results of operations, financial position and cash flows. We have determined that the following estimates are considered critical to the application of rules that relate to the respective businesses.

Accounting for Pensions

PSEG sponsors qualified and nonqualified pension plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. The market-related value of plan assets held for the qualified pension plan is equal to the fair value of these assets as of year-end. The plan assets are comprised of investments in both debt and equity securities which are valued using quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. We calculate pension costs using various economic and demographic assumptions.

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

	Assumption		2016			2015			2014
	Discount Rate		4.29	%		4.54	%		4.20	%
	Expected Rate of Return on Plan Assets		8.00	%		8.00	%		8.00	%

The discount rate used to calculate pension obligations is determined as of December 31 each year, our measurement date. The discount rate is determined by developing a spot rate curve based on the yield to maturity of a universe of high quality corporate bonds with similar maturities to the plan obligations. The spot rates are used to discount the estimated plan distributions. The discount rate is the single equivalent rate that produces the same result as the full spot rate curve.

At the end of 2015, we changed the approach used to measure future service and interest costs for pension benefits. See Item 8. Financial Statements and Supplementary Data—Note 12. Pension and Other Postretirement Benefits (OPEB) and Savings Plans for additional information.

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

Based on the above assumptions, we have estimated net periodic pension expense in 2017 of approximately $3 million or $6 million, net of amounts capitalized.

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

As of December 31, 2016, PSEG merged its three qualified defined benefit pension plans (excluding Servco plans) into one plan, thereby also merging all of the pension plans’ assets. As a result, we estimate that in 2017, the total net periodic benefit costs are expected to decrease by approximately $72 million or $48 million, net of amounts capitalized, as compared to the 2017 amounts that would have been recognized had the plans not been merged. This is due to the amortization period for gains and losses for the merged plan resulting in lower amortization than that of the individual plans. No changes were made to the benefit formulas, vesting provisions, or to the employees covered by the plans.

Effect if Different Assumptions Used: As part of the business planning process, we have modeled future costs assuming a 7.80% expected rate of return and a 4.29% discount rate for 2017. Actual future pension expense/income and funding levels will depend on future investment performance, changes in discount rates, market conditions, funding levels relative to our projected benefit obligation and accumulated benefit obligation and various other factors related to the populations participating in the pension plans.

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

			% Change		Impact on Pension Benefit Obligation as of December 31, 2016				Increase to Pension Expense in 2017				Increase to Pension Expense, net of Amounts Capitalized in 2017
	Assumption				Millions
	Discount Rate		(1)%		$	737			$	40			$	27
	Expected Rate of Return on Plan Assets		(1)%		N/A				$	50			$	33

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

Derivative Instruments

The operations of PSEG, Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through executing derivative transactions. Derivative instruments are used to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments.

Current accounting guidance requires us to recognize all derivatives on the balance sheet at their fair value, except for derivatives that qualify for and are designated as normal purchases and normal sales contracts.

Assumptions and Approach Used: In general, the fair value of our derivative instruments is determined primarily by end of day clearing market prices from an exchange, such as NYMEX, Intercontinental Exchange and Nodal Exchange, or auction prices. Fair values of other energy contracts may be based on broker quotes.

For a small number of contracts where limited observable inputs or pricing information are available, modeling techniques are employed in determination of their fair value using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable.

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

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

For additional information regarding Derivative Financial Instruments, see Item 8. Financial Statements and Supplementary Data – Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies, Note 16. Financial Risk Management Activities and Note 17. Fair Value Measurements.

Long-Lived Assets

Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate or market conditions, could potentially indicate an asset’s or asset group’s carrying amount may not be recoverable.

Assumptions and Approach Used: In the event certain triggers exist indicating an asset/asset group may not be recoverable, an undiscounted cash flow test is performed to determine if an impairment exists. When the carrying value of a long-lived asset/asset group exceeds the undiscounted estimate of future cash flows associated with the asset/asset group, an impairment may exist to the extent that the fair value of the asset/asset group is less than its carrying amount. These tests require significant estimates and judgment when developing expected future cash flows. Significant inputs include forward power prices, fuel costs, dispatch rates, other operating and capital expenditures and the cost of borrowing.

Effect if Different Assumptions Used: The above cash flow tests and fair value estimates may be impacted by a change in the assumptions noted above and could significantly impact the outcome, triggering additional impairment tests or write-offs.

Lease Investments

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

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

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

•	related prices of fuel for the plants,

•	dispatch rates for the plants,

•	future capital expenditures required to maintain the plants,

•	future operation and maintenance expenses,

•	discount rates, and

•	the current estimated economic viability of the plants after the end of the base lease term.

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

Effect if Different Assumptions Used: A significant change to the assumptions, such as a large decrease in near-term power prices that affects the market’s view of long-term power prices, could result in an impairment of one or more of the residual values, but not necessarily to all of the residual values. However, if, because of changes in assumptions, all the residual values related to the merchant energy plants were deemed to be zero, we would recognize an after-tax charge to income of approximately $91 million.

Asset Retirement Obligations (ARO)

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

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

•	estimation of dates for retirement, which can be dependent on environmental and other legislation,

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

•	discount rates,

•	cost escalation rates,

•	market risk premium,

•	inflation rates, and

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

We obtain updated cost studies triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2015. When we revise any assumptions used to calculate fair values of existing AROs, we adjust the ARO balance and corresponding long-lived asset which impacts the amount of accretion and depreciation expense recognized in future periods.

Nuclear Decommissioning AROs

AROs related to the future decommissioning of Power’s nuclear facilities comprised 89% of Power’s total AROs as of December 31, 2016. Power determines its AROs for its nuclear units by assigning probability weighting to various discounted cash flow outcomes for each of its nuclear units that incorporate the assumptions above as well as:

•	license renewals,

•	early shutdown,

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

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

Effect if Different Assumptions Used: Changes in the assumptions could result in a material change in the ARO balance sheet obligation and the period over which we accrete to the ultimate liability. For example, a decrease of 1% in the discount rate would result in a $39 million increase in the Nuclear ARO as of December 31, 2016. An increase of 1% in the inflation rate would result in a $203 million increase in the Nuclear ARO as of December 31, 2016. Also, if we did not assume that we would recover from the federal government the costs incurred for spent nuclear fuel, the Nuclear ARO would increase by $283 million at December 31, 2016.

Accounting for Regulated Businesses

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

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

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

•	past experience regarding similar items with the BPU,

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

•	passage of new legislation, and

•	recent discussions with the BPU.

All deferred costs are subject to prudence reviews by the BPU. When the recovery of a Regulatory Asset or payment of a Regulatory Liability is no longer probable, PSE&G charges or credits earnings, as appropriate.

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