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 energy efficiency and related 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 and fuel supply functions through competitive energy sales in well-developed energy markets 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 are: 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); PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; 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 2017 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 2017 AND FUTURE OUTLOOK

2017 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, and

•	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, 2017 and 2016 are presented below:

			Years Ended December 31,
			2017				2016
	Earnings (Losses)		Millions, except per share data
	PSE&G		$	973			$	889
	Power		479				18
	Other		122				(20		)
	PSEG Net Income		$	1,574			$	887
	PSEG Net Income Per Share (Diluted)		$	3.10			$	1.75

Our 2017 over 2016 increase in Net Income was due primarily to the favorable impacts of new tax legislation at Power and Energy Holdings in 2017, discussed below, partially offset by higher charges in 2017 related to the early retirement of our Hudson and Mercer units. Higher transmission revenues in 2017 at PSE&G, lower charges in 2017 related to investments in certain leveraged leases at Energy Holdings and lower plant outage costs at Power, partially offset by lower volumes of electricity sold at lower average prices, also contributed to the increase in Net Income. For a more detailed discussion of our financial results, see Results of Operations.

During 2017, 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 are 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. In July 2017, we filed a petition with the BPU for a GSMP II program, an extension of GSMP to continue to modernize our gas system, through which PSE&G has proposed investing $2.7 billion over five years beginning in 2019. This matter is pending. We believe the petition is consistent with the Infrastructure Investment Program (IIP) regulations that the BPU approved in December 2017. In August 2017, the BPU approved PSE&G’s petition for an Energy Efficiency 2017 Program (EE 2017) to extend three existing energy efficiency subprograms (multi-family, direct install and hospital efficiency) and establish two new residential energy efficiency offerings. The EE 2017 allows for $69 million of additional investment and $16 million of additional administrative and information technology costs. The EE 2017 was added as the eleventh component of the Green Program Recovery Charges (GPRC) rate effective September 1, 2017. 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 January 2018, PSE&G filed a distribution base rate case as required by the BPU as a condition of approval of its Energy Strong Program. The filing requests an approximate one percent increase in revenues and seeks to recover investments made to strengthen electric and gas distribution systems. In its filing, PSE&G requested that these rates take into account a reduction in the revenue requirement as a result of the federal corporate income tax rate reduction from 35% to 21% provided in new tax legislation enacted in December 2017 (Tax Act), including a one-time credit for estimated excess income taxes collected between January 1, 2018 and the time new rates go into effect, and the flow-back to customers of certain additional tax benefits. PSE&G anticipates the new base rates will take effect in the fourth quarter of 2018.

Separately, in January 2018, the BPU issued an order commencing a proceeding to ensure that the rate revenue resulting from expenses relating to taxes reflected in rates but no longer owed as the result of the Tax Act shall be passed onto the ratepayers. The BPU directed New Jersey utilities (including PSE&G) to make filings by March 2, 2018 setting forth interim rates to be effective April 1, 2018, reflecting the new federal corporate tax rate, and to subsequently file proposed final rates, effective July 1, 2018, incorporating all other effects of the Tax Act. This proceeding is currently pending.

As a result of the enactment of the Tax Act, various state regulatory authorities, including the BPU, have taken action to ensure that excess federal income taxes previously collected in rates are returned to ratepayers. We have made filings to adjust the revenue requirement in certain of our rate matters as a result of the change in federal income tax rate. We continue to assess whether any further action needs to be taken by the company at this time.

For additional information on our specific filings, see Item 8. Financial Statements and Supplementary Data—Note 6. Regulatory Assets and Liabilities.

Power manages its existing firm pipeline transportation contracts for the benefit of PSE&G’s customers through the basic gas supply service (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 may 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 2018 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 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 being at risk for early retirement. Most recently, in February 2018, Exelon, a co-owner of the Salem units, announced its intention to accelerate the closure of its Oyster Creek nuclear plant located in New Jersey, one year earlier than previously planned for economic reasons. These closures and retirements are generally due to the decline in market prices of energy, resulting from low natural gas prices driven by the growth of shale gas production since 2007, the continuing cost of regulatory compliance and enhanced security for nuclear facilities, both federal and state-level policies that provide financial incentives to construct renewable energy such as wind and solar and the failure to adequately compensate nuclear generating stations for the attributes they bring similar to renewable energy production. These trends have significantly reduced the revenues of nuclear generating stations while limiting their ability to reduce the unit cost of production. This may result in the electric generation industry experiencing a further shift from nuclear generation to natural gas-fired generation, creating less diversity of the generation fleet.

If any or all of the Salem and Hope Creek units were shut down, it would significantly alter New Jersey’s energy supply predominately by increasing New Jersey’s reliance on natural gas generation. Such a decrease in fuel diversity could also increase the market’s vulnerability to price fluctuations and power disruptions in times of high demand. The New Jersey Legislature is assessing legislation that would provide a safety net in order to prevent the loss of environmental attributes from nuclear generating stations. We cannot predict whether the legislation will be enacted or, if enacted, whether our nuclear generating stations in New Jersey will be selected or whether the legislation will provide a sufficient safety net for the continued operation of nuclear generating stations in New Jersey.

In the ordinary course, management, and in the case of the Salem units the co-owner, each makes a number of decisions that impact the operation of our nuclear units beyond the current year, including whether and to what extent these units participate in RPM capacity auctions, commitments relating to refueling outages and significant capital expenditures, and decisions regarding our hedging arrangements. When considering whether to make these future commitments, management’s decisions will primarily be influenced by the financial outlook of the units, including the progress, timing and continued outlook for enactment of proposed legislation in the state of New Jersey.

If market prices continue to be depressed and legislation is not enacted that adequately compensates nuclear generating stations for their attributes, Power anticipates it will no longer be covering its costs nor be adequately compensated for its market and operational risks at the Salem and Hope Creek nuclear units and would anticipate retiring these units early. 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, environmental remediation costs and additional funding of the Nuclear Decommissioning Trust Fund (NDT) would be material to both PSEG and Power.

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

There are several matters pending before FERC and the U. S. Court of Appeals for the District of Columbia Circuit 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. 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 recovery, 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. 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. During 2015, PJM implemented a new “Capacity Performance” (CP) mechanism that created a more robust capacity product with enhanced incentives for performance during emergency conditions and significant penalties for non-performance. The CP product was implemented fully in the May 2017 RPM auction for the 2020-2021 Delivery Year. Subsequent to its implementation, FERC approved changes to the CP construct that will enhance the participation of intermittent and demand response resources (seasonal resources). However, two complaints remain pending that ask FERC to investigate the rules governing the participation of seasonal resources and extend the participation of the base resources for future auctions.

In May 2017, PJM announced the results of the RPM capacity auction for the 2020-2021 Delivery Year. Power cleared approximately 7,800 MW of its generating capacity at an average price of $174 per MW-day for the 2020-2021 delivery period. In the two prior capacity auctions covering the 2019-2020 and 2018-2019 delivery years, Power cleared approximately 8,900 MW at an average price of $116 per MW-day and approximately 8,700 MW at an average price of $215 per MW-day, respectively. Prices in the most recent auction reflect PJM’s downwardly-revised demand forecast, changes in the 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 commissions, 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.

In June 2017, PJM issued an energy price formation proposal to address a flaw in the energy market in which energy prices during off-peak periods often do not reflect the production costs of generators during these periods even though they are serving load. PJM’s proposal would allow large, inflexible units to set price. If placed into effect, this proposal will improve price formation by ensuring that the marginal costs of units serving load will be better reflected in clearing prices. We cannot predict the outcome of this matter.

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

Distribution

The BPU has enacted IIP regulations that allow utilities to construct, install, or remediate utility plant and facilities related to reliability, resiliency, and/or safety to support the provision of safe and adequate service. Under these regulations, utilities can seek authority to make specified infrastructure investments in programs extending for up to five years with accelerated cost recovery mechanisms. The BPU characterized the IIP regulations as a regulatory initiative intended to create a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing infrastructure that enhances reliability, resiliency, and/or safety.

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 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.

In March 2017, the President of the United States issued an Executive Order that instructed the EPA to review the New Source Performance Standards that establish emissions standards for CO2 for certain new fossil power plants, and the Clean Power Plan (CPP), a greenhouse gas emissions regulation under the Clean Air Act for existing power plants that establishes state-specific emission rate targets based on implementation of the best system of emission reduction. In October 2017, the EPA Administrator signed a proposed repeal of the CPP. The EPA Administrator concluded that the CPP exceeds the EPA’s statutory authority by considering measures that are beyond the control of the owners of the affected sources (fossil fuel-fired electric generating units). The EPA is considering rulemaking to replace the CPP. PSEG cannot assess the impact of any such rulemaking on its business and future results of operations at this time.

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. While considerable uncertainty remains as to the final resolution of these matters, based upon developments in the investigation in the first quarter of 2017, Power believes the disgorgement and interest costs related to the cost-based bidding matter may range between approximately $35 million and $135 million, depending on the legal interpretation of the principles under the PJM Tariff, plus penalties. Since no point within this range is more likely than any other, Power has accrued the low end of this range of $35 million by recording an additional pre-tax charge to income of $10 million during the three months ended March 31, 2017. PSEG is unable to reasonably estimate the range of possible loss, if any, for the quantity of energy offered matter or the penalties that FERC would impose relating to either the cost-based bidding or quantity of energy matter. However, any of these amounts could be individually material to PSEG and Power. We cannot predict the final outcome of these matters. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities.

Early Retirement of Hudson and Mercer Units

On June 1, 2017, Power completed its previously announced retirement of the generation operations of the existing coal/gas units at the Hudson and Mercer generating stations. The decision to retire the Hudson and Mercer units had a material effect on PSEG’s and Power’s results of operations in 2016 and continued to adversely impact their results of operations in 2017. As of June 1, 2017, Power completed recognition of the incremental Depreciation and Amortization (D&A) of $938 million ($964 million in total) due to the significant shortening of the expected economic useful lives of Hudson and Mercer. During 2017, Energy Costs of $15 million and Operation and Maintenance (O&M) of $23 million were also incurred. See Item 8. Financial Statements and Supplementary Data—Note 3. Early Plant Retirements for additional information.

Power is exploring various opportunities with these sites, including using the sites for alternative industrial activity or the disposition of one or both of the sites. 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.

In addition, PSEG and Power continue to monitor their other coal assets, including the Keystone and Conemaugh generating stations, to assess 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 their ability to operate or maintain certain 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

GenOn Energy, Inc. (GenOn) and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code on June 14, 2017. NRG REMA, LLC (REMA) was not included in the GenOn bankruptcy filing. GenOn is currently engaged in a balance sheet restructuring, which will take an undetermined time to complete. PSEG cannot predict the outcome of GenOn’s efforts to restructure its balance sheet and improve its liquidity.

During the first quarter of 2017, due to continuing liquidity issues facing REMA, economic challenges facing coal generation in PJM, and based upon an ongoing review of available alternatives as well as discussions with REMA management, Energy Holdings recorded an additional $55 million pre-tax charge for its current best estimate of loss relating to its REMA leveraged lease receivables, which was reflected in Operating Revenues. During the second quarter of 2017, Energy Holdings recorded an additional $22 million pre-tax charge for its current best estimate of loss related to lease receivables due to collectability of payments ($15 million) and economics impacting the residual value ($7 million) of certain leased assets. 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 lease receivables, and continue to discuss the situation with various parties relevant to this matter. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 7. Long-Term Investments and Note 8. Financing Receivables. 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 Powerton generating facilities. Similar to Shawville, Joliet was recently converted to use natural gas. Converted natural gas units such as Shawville and Joliet may have higher operating costs and fuel consumption as well as longer start-up times compared to newer combined cycle gas units. Powerton is a coal-fired generating facility in Illinois. Each of these three 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 other less efficient natural gas and coal generation facilities, which could require Energy Holdings to write down the residual value of the leveraged lease receivables associated with these facilities.

Tax Legislation

In December 2017, the U.S. government enacted comprehensive tax legislation (Tax Act), which, among other things, decreased the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018, and made certain changes to bonus depreciation rules.

As a result of the enacted reduction in the statutory U.S. corporate income tax rate, as well as other aspects of the Tax Act, we have recorded a one-time, non-cash earnings benefit of $745 million, including $588 million related to Power and $147 million related to Energy Holdings. This benefit is primarily due to the remeasurement of deferred tax balances. In addition, PSE&G had excess deferred taxes of approximately $2.1 billion as of December 31, 2017 and recorded an approximate $2.9 billion revenue impact of these excess deferred taxes as Regulatory Liabilities where it is probable that refunds will be made to customers in future rates. The amount and timing of any such refund cannot be determined at this time.

Beginning in 2018, PSEG, on a consolidated basis, will incur lower income tax expense resulting in a decrease in its projected effective income tax rate. This is also expected to increase PSEG’s and Power’s net income. To the extent allowed under the Tax Act, Power’s operating cash flows will reflect the full expensing of capital investments for income tax purposes. PSEG and Power expect that the interest on their debt will continue to be fully tax deductible albeit at a lower tax rate. For PSE&G, the Tax Act is expected to lead to lower customer rates due to lower income tax expense recoveries and the refund of deferred income tax regulatory liabilities, partially offset by the impacts of higher rate base. The impact of the lower federal income tax rate on PSE&G was reflected in PSE&G’s recently filed distribution base rate case and its transmission formula rate filings. The Tax Act is generally expected to result in lower operating cash flows for PSE&G resulting from the elimination of bonus depreciation, partially offset by higher revenues due to the higher rate base. The full impact of these and other provisions of the Tax Act cannot be determined at this time.

The impact of the Tax Act may differ from these estimates, possibly materially, due to, among other things, changes in interpretations and assumptions PSEG has made, guidance that may be issued and actions PSEG may take as a result of the Tax Act. For additional information, see Note 20. Income Taxes.

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 2017, our

•	diverse fuel mix and dispatch flexibility allowed us to generate approximately 51 terra-watt hours while addressing

fuel availability and price volatility,

•	total nuclear fleet achieved an average capacity factor of 94%, and

•	utility was recognized for the sixteenth 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 2017 as we:

•	maintained sufficient liquidity,

•	maintained solid investment grade credit ratings, and

•	increased our indicative annual dividend for 2017 to $1.72 per share.

We expect to be able to fund our planned capital requirements, as described in Liquidity and Capital Resources, and manage the impacts of the Tax Act 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 2017, we

•	made additional investments in transmission infrastructure projects,

•	continued to execute our GSMP, Energy Strong, Energy Efficiency, solar and other existing BPU-approved utility programs,

•	continued construction of our Keys and Sewaren 7 generation projects for targeted commercial operation in 2018 and commenced construction of our BH5 generation project for targeted commercial operation in mid-2019, and

•	acquired six solar energy projects in various states totaling 88 MW-direct current (dc), for a total of 414 MW (dc) of installed capacity in 14 states throughout the U.S.

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, and obtain approval for extension of these programs,

•	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 2018 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 was filed with the BPU in January 2018,

•	continuing discussions regarding the restructuring of GenOn and REMA and its potential impact on the value of our Keystone, Conemaugh and Shawville leveraged leases,

•	the continuing impact of the Tax Act,

•	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 T&D 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.

Power is developing a retail energy business to sell energy, which we believe complements our existing wholesale marketing business. Power began these marketing activities in 2017 and has been granted retail energy supplier licenses in New Jersey, Pennsylvania and Maryland.

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,
			2017				2016				2015
	Earnings (Losses)		Millions
	PSE&G		$	973			$	889			$	787
	Power (A)(B)		479				18				856
	Other (B)(C)		122				(20		)		36
	PSEG Net Income		$	1,574			$	887			$	1,679
	PSEG Net Income Per Share (Diluted)		$	3.10			$	1.75			$	3.30

(A)

Power’s results in 2017 and 2016 include after-tax expenses of $577 million and $396 million, respectively, 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)	Results in 2017 include the non-cash net income benefit of $745 million, including $588 million related to Power and $147 million related to Energy Holdings, resulting from the remeasurement of deferred tax liabilities required due to the enactment of the Tax Act in December 2017.

(C)

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 $45 million and $92 million related to its investments in REMA’s leveraged leases in 2017 and 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 Nuclear Decommissioning Trust (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 Asset Retirement Obligation (ARO) is recorded in O&M Expense and the depreciation related to the ARO asset is recorded in D&A Expense.

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

The combined after-tax impact on Net Income for the years ended December 31, 2017, 2016 and 2015 include the changes related to NDT Fund and MTM activity shown in the chart below:

	Years Ended December 31,		2017				2016				2015
			Millions, after tax
	NDT Fund and Related Activity (A)		$	62			$	—			$	8
	Non-Trading MTM Gains (Losses) (B)		$	(99	)		$	(100	)		$	93

(A)	Net of tax (expense) benefit of $(72) million, $(5) million and $(16) million for the years ended December 31, 2017, 2016 and 2015, respectively.

(B)	Net of tax (expense) benefit of $68 million, $68 million and $(65) million for the years ended December 31, 2017, 2016 and 2015, respectively.

The 2017 year-over-year increase in our Net Income was driven primarily by:

•	non-cash net income benefits related to new tax legislation (See Item 8. Financial Statements and Supplementary Data—Note 20. Income Taxes) at Power and Energy Holdings,

•	higher transmission revenues,

•	higher net NDT gains in 2017, and

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

These increases were partially offset by:

•	higher 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), and

•	lower volumes of energy sold at lower average realized sales prices under the BGS contracts and in the PJM and New England regions.

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 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.

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,
			2017				2016				2015				2017 vs. 2016						2016 vs. 2015
			Millions												Millions				%			Millions				%
	Operating Revenues		$	9,084			$	9,061			$	10,415			$	23			—			$	(1,354	)		(13	)
	Energy Costs		2,800				3,001				3,261				(201		)		(7	)		(260		)		(8	)
	Operation and Maintenance		2,869				3,008				2,978				(139		)		(5	)		30				1
	Depreciation and Amortization		1,986				1,476				1,214				510				35			262				22
	Income from Equity Method Investments		14				11				12				3				27			(1		)		(8	)
	Other Income (Deductions)		228				124				152				104				84			(28		)		(18	)
	Other-Than-Temporary Impairments		12				28				53				(16		)		(57	)		(25		)		(47	)
	Interest Expense		391				385				393				6				2			(8		)		(2	)
	Income Tax (Benefit) Expense		(306		)		411				1,001				(717		)		(174	)		(590		)		(59	)

The 2017, 2016 and 2015 amounts in the preceding table for Operating Revenues and O&M costs each include $438 million, $410 million and $375 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 Entity for further explanation. The Income Tax Benefit in 2017 includes the non-cash benefit resulting from the remeasurement of deferred tax liabilities required due to the enactment of the Tax Act in December 2017. 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)
			2017				2016				2015				2017 vs. 2016						2016 vs. 2015
			Millions												Millions				%			Millions				%
	Operating Revenues		$	6,234			$	6,221			$	6,636			$	13			—			$	(415	)		(6	)
	Energy Costs		2,363				2,567				2,722				(204		)		(8	)		(155		)		(6	)
	Operation and Maintenance		1,434				1,475				1,560				(41		)		(3	)		(85		)		(5	)
	Depreciation and Amortization		685				565				892				120				21			(327		)		(37	)
	Other Income (Deductions)		87				79				75				8				10			4				5
	Interest Expense		303				289				280				14				5			9				3
	Income Tax Expense		563				515				470				48				9			45				10

Year Ended December 31, 2017 as compared to 2016

Operating Revenues increased $13 million due to changes in delivery, clause, commodity and other operating revenues.

Delivery Revenues increased $166 million due primarily to an increase in transmission revenues.

•	Transmission revenues were $152 million higher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.

•	Gas distribution revenues increased $30 million due to a $16 million increase due to Energy Strong, $10 million from inclusion of the GSMP in base rates, $4 million in higher collections of GPRC and an increase of $2 million due to higher sales volumes. These increases were partially offset by lower Weather Normalization Clause (WNC) revenues of $2 million.

•	Electric distribution revenues decreased $16 million due primarily to a $28 million decrease in sales volume and $14 million in lower collections of GPRC, partially offset by a $26 million increase in Energy Strong revenues.

Clause Revenues increased $47 million due to the absence of the return in 2016 to customers of overcollections of Securitization Transition Charge (STC) revenues of $59 million and higher Margin Adjustment Clause (MAC) revenues of $4 million. These increases were partially offset by lower Societal Benefit Charges (SBC) of $17 million. The changes in STC, MAC and SBC amounts were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, D&A and Interest Expense. PSE&G does not earn margin on STC, SBC, Solar Pilot Recovery Charges (SPRC) or MAC collections.

Commodity Revenues decreased $204 million due to lower Electric revenues partially offset by higher Gas revenues. This decrease 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 $274 million due to $199 million in lower BGS revenues reflecting $109 million from lower sales volumes and $90 million from lower prices, $61 million in lower collections of Non-Utility Generation Charges (NGC) due primarily to lower prices and $14 million in lower revenues from the decreased sales volume of Non-Utility Generation (NUG) energy.

•	Gas revenues increased $70 million due to higher BGSS prices of $68 million and $2 million from higher sales volumes.

Operating Expenses

Energy Costs decreased $204 million. This is entirely offset by Commodity Revenues.

Operation and Maintenance decreased $41 million due to

•	a $28 million net reduction related to various clause mechanisms and GPRC expenditures,

•	a $15 million decrease in appliance service costs, and

•	a $7 million net decrease in pension and OPEB expenses, net of amounts capitalized,

•	partially offset by a $9 million net increase in other operating expenses.

Depreciation and Amortization increased $120 million due primarily to a $61 million net increase in amortization of Regulatory Assets, including the absence of the STC liability that ended in 2016, and an increase in depreciation of $59 million due to additional plant placed into service in 2017.

Other Income (Deductions) increased $8 million due primarily to a $7 million increase in Allowance for Funds Used During Construction (AFUDC).

Interest Expense increased $14 million primarily due to

•	$11 million due to net long-term debt issuances in 2016 and $9 million due to net long-term debt issuances in 2017, partially offset by

•	a decrease of $6 million due to clause-related interest for BGSS in 2016.

Income Tax Expense increased $48 million due primarily to higher pre-tax income.

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 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 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 STC revenues of $419 million, lower SBC of $33 million and lower SPRC of $8 million. These decreases were partially offset by higher MAC revenues of $15 million. The changes in STC, SBC, SPRC and MAC amounts were entirely offset by changes in the amortization of related costs (Regulatory Assets) in O&M, D&A 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 NGC due primarily to lower prices, $42 million in lower revenues from the sale of NUG energy and $21 million in lower prices 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 T&D 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 to additional plant in 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 decrease 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.

Power

			Years Ended December 31,												Increase / (Decrease)							Increase / (Decrease)
			2017				2016				2015				2017 vs. 2016						2016 vs. 2015
			Millions												Millions				%			Millions				%
	Operating Revenues		$	3,930			$	4,023			$	4,928			$	(93	)		(2	)		$	(905	)		(18	)
	Energy Costs		1,983				1,986				2,150				(3		)		N/A			(164		)		(8	)
	Operation and Maintenance		1,038				1,143				1,057				(105		)		(9	)		86				8
	Depreciation and Amortization		1,268				881				291				387				44			590				N/A
	Income from Equity Method Investments		14				11				14				3				27			(3		)		(21	)
	Other Income (Deductions)		157				45				97				112				N/A			(52		)		(54	)
	Other-Than-Temporary Impairments		12				28				53				(16		)		(57	)		(25		)		(47	)
	Interest Expense		50				84				121				(34		)		(40	)		(37		)		(31	)
	Income Tax Expense (Benefit)		(729		)		(61		)		511				(668		)		N/A			(572		)		N/A

Year Ended December 31, 2017 as compared to 2016

Operating Revenues decreased $93 million due to changes in generation, gas supply and other operating revenues.

Generation Revenues decreased $204 million due primarily to

•	a decrease of $126 million in energy sales in the PJM and New England (NE) regions due primarily to lower average realized prices,

•	a decrease of $100 million in electricity sold under our BGS contracts due primarily to lower volumes coupled with lower prices,

•	a decrease of $24 million in revenue expected to be returned to ratepayers associated with excess federal income tax previously collected by Power’s subsidiary, PSEG New Haven LLC, due to the change in federal tax rates effective January 1, 2018,

•	a decrease of $18 million in operating reserves in the PJM region,

•	a charge of $10 million due to an increase in the FERC accrual related to the PJM bidding matter,

•	a decrease of $7 million due to higher MTM losses in 2017 as compared to 2016. Of this amount, $120 million was due to increased forward prices, partially offset by a decrease of $113 million due to lower gains on positions reclassified to realized upon settlement in 2017 as compared to 2016,

•	partially offset by a net increase of $53 million due primarily to higher volumes of electricity sold under wholesale load contracts in the PJM and NE regions,

•	a net increase of $18 million in capacity revenues in the PJM and NE regions due to increases in cleared capacity and capacity auction prices, and

•	an increase of $11 million due to higher sales related to new solar projects.

Gas Supply Revenues increased $110 million due primarily to

•	an increase of $67 million in sales under the BGSS contract, of which $40 million was due to higher average sales prices coupled with a $27 million increase in sales volumes due to periods of colder weather in the heating season,

•	a net increase of $24 million due to higher MTM gains in 2017 as compared to 2016, and

•	an increase of $19 million related to sales to third parties, of which $48 million was due to higher average sales prices, partially offset by $29 million of 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 $3 million due to

Generation costs decreased $69 million due primarily to

•	a net decrease of $83 million primarily due to lower congestion costs in PJM due to lower rates coupled with less volumes, partially offset by higher transmission charges due to higher rates,

•	a net decrease of $50 million due to charges associated with the announced early retirement of the Mercer and Hudson units in 2016, primarily related to lower coal inventory write-downs in 2017, partially offset by additional retirement costs incurred in 2017,

•	partially offset by higher fuel costs of $31 million reflecting higher average realized prices for natural gas coupled with the utilization of higher volumes of coal, partially offset by the utilization of lower volumes of gas,

•	an increase of $17 million due to MTM losses in 2017 as compared to MTM gains in 2016, and

•	a net increase of $16 million primarily due to an increase in the volume of energy purchases in the NE region to serve load obligations.

Gas costs increased $66 million due to

•	an increase of $50 million related to sales under the BGSS contract, of which $31 million was due to higher average gas costs, coupled with a $19 million increase in volumes sold due to periods of colder weather in the heating season, and

•	an increase of $16 million related to sales to third parties, of which $44 million was due to higher average gas costs, partially offset by a $28 million decrease in volumes sold.

Operation and Maintenance decreased $105 million due to

•	a $72 million decrease at our fossil plants, due primarily to the retirement of the Hudson and Mercer units and higher planned outage costs in 2016,

•	a $35 million net decrease related to our nuclear plants due primarily to lower labor-related expenses and outage costs,

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

•	partially offset by $5 million of costs related to new solar plants placed into service in 2017.

Depreciation and Amortization increased $387 million due primarily to

•	$346 million of higher depreciation for Hudson and Mercer, primarily due to the accelerated expense related to the early retirement of those units,

•	a $15 million increase due to the accelerated retirement date for the Bridgeport Harbor unit 3,

•	an $11 million increase due primarily to a higher nuclear asset base, and

•	$11 million of higher depreciation due to new solar projects.

Other Income (Deductions) increased $112 million due primarily to higher net realized gains from the NDT Fund in 2017.

Other-Than-Temporary Impairments decreased $16 million due to lower impairments of equity securities in the NDT Fund in 2017.

Interest Expense decreased $34 million due primarily to

•	a $24 million decrease due to higher interest capitalized for the construction of three new fossil stations: BH5, Sewaren 7 and Keys, and

•	a net $7 million decrease due to debt maturities in September 2016, partially offset by a debt issuance in June 2016.

Income Tax Expense decreased $668 million due primarily to the one-time benefit recorded as a result of the remeasurement of deferred tax balances required due to the enactment of the Tax Act in December 2017.

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 in 2016 compared to 2015. Also contributing to the decrease was $118 million of higher gains on positions reclassified to realized upon settlement in 2016 compared to 2015,

•	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 contract 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 2015 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.

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 revolving 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. PSEG LI’s subsidiary, Long Island Electric Utility Servco, LLC (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 revolving credit facilities totaling $1.5 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 $700 million term loan credit agreement that is scheduled to expire in June 2019. From time to time, PSEG may make equity contributions or provide credit support to its subsidiaries.

Power’s sources of external liquidity include $2.1 billion of multi-year revolving 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, 2017, our operating cash flow decreased by $50 million. For the year ended December 31, 2016, our operating cash flow decreased by $608 million. The net changes were primarily due to net tax payments at PSEG and its other subsidiaries in 2017 offset by net changes from our subsidiaries as discussed below.

PSE&G

PSE&G’s operating cash flow decreased $55 million from $1,894 million to $1,839 million for the year ended December 31, 2017, as compared to 2016, due primarily to lower tax refunds and a decrease of $50 million related to a change in regulatory deferrals. These amounts were partially offset by higher earnings and $30 million in decreased vendor payments.

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.

Power

Power’s operating cash flow increased $71 million from $1,255 million to $1,326 million for the year ended December 31, 2017, as compared to 2016, primarily resulting from a decrease of $61 million in payments to counterparties, a $26 million increase from higher net collections of counterparty receivables, and higher earnings. These amounts were partially offset by higher tax payments and an increase in margin deposit requirements of $14 million.

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.

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, 2017 were as follows:

	Company/Facility		As of December 31, 2017
	Total Facility				Usage				Available Liquidity
			Millions
	PSEG		$	1,500			$	556			$	944
	PSE&G		600				15				585
	Power		2,100				151				1,949
	Total		$	4,200			$	722			$	3,478

As of December 31, 2017, 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 $848 million and $783 million as of December 31, 2017 and 2016, respectively. The early retirement of Power’s Hudson and Mercer coal/gas generation units did not 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

PSE&G has $400 million of 5.30% Medium Term Notes maturing in May 2018 and $350 million of 2.30% Medium Term Notes maturing in September 2018.

Power has $250 million of 2.45% Senior Notes maturing in November 2018.

For a discussion of our long-term debt transactions during 2017 and into 2018, 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, 2017, PSE&G’s Mortgage coverage ratio was 5.2 to 1 and the Mortgage would permit up to approximately $6.9 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		2017				2016				2015
	Per Share		$	1.72			$	1.64			$	1.56
	in Millions		$	870			$	830			$	789

On February 20, 2018, our Board of Directors approved a $0.45 per share of common stock dividend for the first quarter of 2018. This reflects an indicative annual dividend rate of $1.80 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—Note16. 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 April 2017, S&P published updated research and affirmed the ratings and outlooks on PSEG and PSE&G. In June 2017, S&P published updated research on Power and the rating and outlook remained unchanged. In July 2017, Moody’s upgraded PSEG’s senior unsecured rating to Baa1 from Baa2 and revised its outlook to Stable from Positive. Also in July, Moody’s affirmed the ratings at PSE&G and Power.

		Moody’s (A)		S&P (B)
	PSEG
	Outlook	Stable		Stable
	Senior Notes	Baa1		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, 2017, we had Other Comprehensive Income of $34 million on a consolidated basis. Other Comprehensive Income was due primarily to a $44 million increase in net unrealized gains related to Available-for-Sale Securities, partially offset by a decrease of $8 million in our consolidated liability for pension and postretirement benefits and $2 million of unrealized losses on derivative contracts accounted for as hedges. 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.

			2018				2019				2020
							Millions
	PSE&G:
	Transmission		$	1,235			$	1,290			$	1,280
	Distribution		1,015				715				705
	Energy Strong		35				—				—
	Gas System Modernization Program		300				40				—
	Solar/Energy Efficiency		85				75				55
	Total PSE&G		$	2,670			$	2,120			$	2,040
	Power:
	Baseline		$	170			$	165			$	165
	Fossil Growth Opportunities		445				65				10
	Other		30				30				20
	Total Power		$	645			$	260			$	195
	Other		$	40			$	30			$	20
	Total PSEG		$	3,355			$	2,410			$	2,255

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 November 2017, the BPU issued an order approving PSE&G’s net investment of $100 million to rebuild New Jersey Transit’s Mason electric distribution substation and related facilities in Kearny, New Jersey. This project is expected to be completed in December 2021.

In July 2017, PSE&G filed a petition with the BPU requesting approval of the $2.7 billion next phase of the Gas System Modernization Program (GSMP II) and associated cost recovery mechanism. The GSMP II program will enable PSE&G to continue to accelerate the replacement of its aging cast-iron and unprotected steel gas pipes. This matter is currently pending before the BPU and is not included in the PSE&G’s projected capital expenditures above.

In 2017, PSE&G made $2,919 million of capital expenditures, primarily for transmission and distribution system reliability. This does not include expenditures for cost of removal, net of salvage, of $107 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.

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

•	Other—includes investments made in response to environmental, regulatory and legal mandates and other capital projects.

In 2017, Power made $1,040 million of capital expenditures, excluding $191 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		$	2,100			$	—			$	1,100			$	1,000			$	—
	PSE&G		8,658				750				759				434				6,715
	Power		2,400				250				450				950				750
	Interest on Recourse Debt
	PSEG		157				49				65				43				—
	PSE&G		5,186				313				578				525				3,770
	Power		821				113				202				129				377
	Capital Lease Obligations
	Power		2				1				1				—				—
	Operating Leases
	PSE&G		113				16				17				15				65
	Power		58				5				9				6				38
	Services		194				14				30				30				120
	Other		6				1				2				2				1
	Energy-Related Purchase Commitments
	Power		2,670				730				938				468				534
	Total Contractual Cash Obligations		$	22,365			$	2,242			$	4,151			$	3,602			$	12,370
	Liability Payments for Uncertain Tax Positions
	PSEG		$	69			$	69			$	—			$	—			$	—
	PSE&G		35				35				—				—				—
	Power		30				30				—				—				—

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		2017			2016			2015
	Discount Rate		3.73	%		4.29	%		4.54	%
	Expected Rate of Return on Plan Assets		7.80	%		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.

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 a net periodic pension credit in 2018 of approximately $(36) million, or $(87) 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.

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 3.73% discount rate for 2018. 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, 2017				Increase to Pension Expense in 2018				Increase to Pension Expense, net of Amounts Capitalized in 2018
	Assumption				Millions
	Discount Rate		(1)%		$	866			$	46			$	36
	Expected Rate of Return on Plan Assets		(1)%		N/A				$	57			$	57

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 per the original lease terms, net of any subsequent impairments. 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.

A review of the residual valuations is 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 $78 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 with the corresponding expense recorded in Operation and Maintenance.

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 93% of Power’s total AROs as of December 31, 2017. 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:

•	financial feasibility and impacts on potential early shutdown,

•	license renewals,

•	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 $120 million increase in the Nuclear ARO as of December 31, 2017. An increase of 1% in the inflation rate would result in a $324 million increase in the Nuclear ARO as of December 31, 2017. 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 $550 million at December 31, 2017. If Power were to increase its early shutdown probability to 100% and retire Salem and Hope Creek in 2021 (when the current capacity obligations for Salem and Hope Creek expire), which is significantly earlier than the end of their current license periods, the Nuclear ARO would increase by $428 million.

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.