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

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

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

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

•PSE&G—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 regulated 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; 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 2018 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 2018 AND FUTURE OUTLOOK

Our business plan is designed to achieve growth while managing the risks associated with fluctuating commodity prices and changes in customer demand.

PSE&G

At PSE&G, our focus is on enhancing system reliability and resiliency, meeting customer expectations and supporting public policy objectives by investing capital in T&D infrastructure and clean energy projects. Over the past few years, our investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G. Over the next five years, we expect to invest between $11 billion and $16 billion in our business which is expected to provide an annual rate base growth of 7%—9%. We completed our Energy Strong Program I (ES I) and essentially completed our Gas System Modernization Program I (GSMP I). See Item 1. Business—Business Operations and Strategy—PSE&G for a description of these programs.

In May 2018, we received approval for our Gas System Modernization Program II (GSMP II), an expanded, five-year program to invest $1.9 billion beginning in 2019 to replace approximately 875 miles of cast iron and unprotected steel mains in addition to other improvements to the gas system. Approximately $1.6 billion will be recovered through periodic rate roll-ins, with the remaining $300 million to be recovered through a future base rate proceeding. As part of the settlement, PSE&G agreed to file a base rate proceeding no later than five years from the commencement of the program, to maintain a base level of gas distribution capital expenditures of $155 million per year and to achieve certain leak reduction targets.

In June 2018, we filed for our Energy Strong Program II (ES II), a proposed five-year $2.5 billion program to harden, modernize and make our electric and gas distribution systems more resilient. The size and duration of ES II, as well as certain other elements of the program, are subject to BPU approval. The review process is expected to conclude in mid-2019.

In October 2018, we filed our proposed Clean Energy Future (CEF) program with the BPU, a six-year estimated $3.6 billion investment covering four programs; (i) an Energy Efficiency (EE) program totaling $2.5 billion of investment designed to

achieve energy efficiency targets required under New Jersey’s Clean Energy law; (ii) an Electric Vehicle (EV) infrastructure program; (iii) an Energy Storage (ES) program and (iv) an Energy Cloud (EC) program which will include installing approximately two million electric smart meters and associated infrastructure. The review process for the CEF-EE program is expected to conclude by the third quarter of 2019. The CEF-EV/ ES and CEF-EC programs will have separate procedural schedules.

In November 2018, the New Jersey Division of Rate Counsel (Rate Counsel) filed a motion to dismiss the CEF-EC filing on the basis that the BPU announced a moratorium on electric distribution companies’ AMI program. In December 2018, Rate Counsel filed a motion to stay the CEF-EV/ES filing, arguing that the BPU should conclude other regulatory proceedings addressing EVs and ES, including the new Energy Master Plan and initiatives required by the Clean Energy Act, before it rules on PSE&G’s program. We opposed Rate Counsel’s motions, asking for the BPU to permit these filings to proceed. There is no timetable for the BPU to decide on Rate Counsel’s motions.

Also, in October 2018, the BPU issued an Order approving the settlement of our distribution base rate proceeding with new rates effective November 1, 2018. The settlement resulted in a net reduction in overall annual revenues of approximately $13 million, comprised of a $212 million increase in base revenues, which includes the recovery of deferred storm costs, and the return of tax benefits largely due to tax reform of approximately $225 million. The Order provides for a distribution rate base of $9.5 billion, a 9.6% return on equity (ROE) for our distribution business and a 54% equity component of our capitalization structure.

Power

At Power, we strive to improve performance and reduce costs in order to optimize cash flow generation from our fleet in light of low wholesale power and gas prices, environmental considerations and competitive market forces that reward efficiency and reliability. Power continues to move its fleet toward improved efficiency and believes that its investment program enhances its competitive position with the addition of efficient, clean, reliable combined cycle gas turbine capacity. Our commitments for load, such as basic generation service (BGS) in New Jersey and other bilateral supply contracts, are backed by this generation or may be combined with the use of physical commodity purchases and financial instruments from the market to optimize the economic efficiency of serving our obligations. 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 Unit 5 (BH5) reflect our recognition of the value of opportunistic growth in the Power business. These additions to our fleet both expand our geographic diversity and adjust our fuel mix and enhance the environmental profile and overall efficiency of Power’s generation fleet.

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 2018, our

•utility achieved continued strong reliability and customer satisfaction results, as well as comprehensive storm preparation and restoration efforts, and ongoing cost control,
•diverse fuel mix and dispatch flexibility allowed us to generate approximately 56 terawatt hours while addressing fuel availability and price volatility, and
•total nuclear fleet achieved a capacity factor of 91.4%.

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 2018 as we

•maintained sufficient liquidity,
•maintained solid investment grade credit ratings, and
•increased our indicative annual dividend for 2018 to $1.80 per share.

We expect to be able to fund our planned capital requirements, as described in Liquidity and Capital Resources, and the impacts of the Tax Cuts and Jobs Act of 2017 (Tax Act) without the issuance of new equity. For additional information on the impacts of the Tax Act, see Item 8. Note 7. Regulatory Assets and Liabilities and Note 21. Income Taxes.

The financial results for PSEG, PSE&G and Power for the years ended December 31, 2018 and 2017 are presented below:

Years Ended December 31,
20182017
Millions, except per share data
PSE&G$1,067$973
Power365479
Other6122
PSEG Net Income$1,438$1,574
PSEG Net Income Per Share (Diluted)$2.83$3.10

Our 2018 over 2017 decrease in Net Income was due primarily to the one-time favorable impacts in 2017 of new tax legislation at Power and Holdings, discussed below, and the recognition in 2018 of net unrealized losses on NDT Fund equity securities at Power in accordance with new accounting guidance. The decrease was partially offset by charges in 2017 related to the early retirement of our Hudson and Mercer units, as well as a lower federal tax rate at Power and higher earnings from T&D investments and the favorable impact of new rates upon settlement of the distribution base rate proceeding, discussed above, at PSE&G. For a more detailed discussion of our financial results, see Results of Operations.

Disciplined Investment

We utilize rigorous 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 2018, we

•made additional investments in T&D infrastructure projects,
•continued to execute our GSMP I, Energy Efficiency and other existing BPU-approved utility programs,
•received approval for our GSMP II program and filed our proposed ES II and CEF programs, and
•commenced commercial operation of Sewaren 7 and Keys generation facilities and continued construction of our BH5 generation project, which is targeted for commercial operation in mid-2019.

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. For additional information about regulatory, legislative and other developments that may affect the company, see Item 1. Business—Regulatory Issues.

Transmission Planning

There are several matters pending before FERC that may impact the allocation of costs associated with transmission projects, including those 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 customers in New Jersey. In addition, as a 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 would 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 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.

In October 2018, FERC issued an order establishing a new framework for determining whether a company’s ROE is unjust and unreasonable. FERC proposes to rely on financial models to establish a composite zone of reasonableness that will be used to determine whether an ROE complaint should be dismissed. If FERC determines that an ROE for a company is not just and reasonable, it intends to reset the ROE based on averaging the results of various financial models. We are still analyzing the potential impact of these methodologies and cannot predict the outcome of ongoing ROE proceedings.

Wholesale Power Market Design

In June 2018, FERC issued an order finding that PJM’s current capacity market is not just and reasonable because it enabled state-supported resources to bid below their costs which resulted in suppressed clearing prices. In particular, FERC found that nuclear generating units that receive zero emission certificate (ZEC) payments were of concern. Depending on the outcome of this matter, our generating stations could also be impacted. For additional information see Item 1. Business—Regulatory Issues—Federal Regulation.

In February 2019, the PJM Board approved a filing to modify the curves used for pricing reserves with FERC. The reforms include a 30-minute reserve product in real-time, more dynamic reserve requirements to better capture operator actions taken to maintain reliability, and improvement to the curves used to price reserves during reserve shortage conditions. If placed into effect, this reform is expected to improve energy and reserve prices by ensuring that when operators commit resources to ensure reliability, the commitments are reflected in market clearing prices. However, this reform could result in lower capacity payments. There is no timeline for this type of filing and therefore we cannot predict when FERC will act on the filing or the outcome of this matter.

In October 2018, PJM filed with FERC to revise the shape of the Variable Resource Requirement (VRR) curve that will be implemented for the capacity auction to be held in August 2019. The VRR curve is the administratively determined demand curve that serves as one of the key elements for establishing the amount of generation capacity to be procured in the auction. PJM contends that its proposal will lower capacity prices as compared to the currently effective VRR curve. PSEG protested PJM’s proposal on the grounds that it would result in understated prices for capacity relative to the cost of constructing a new reference generating unit and will result in prices that are unjust and unreasonable. This matter is pending before FERC and we cannot predict the outcome.

Distribution

Effective in January 2018, the BPU adopted Infrastructure Investment Program (IIP) regulations that encourage 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 traditional utility infrastructure that enhances reliability, resiliency, and/or safety. Since these regulations were adopted, the BPU approved our GSMP II and we filed our ES II and CEF-EC programs with the BPU.

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 Clean Water 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 August 2018, the EPA released the proposed Affordable Clean Energy (ACE) rule as a replacement for the EPA’s Clean Power Plan. The proposed ACE rule gives states great flexibility to evaluate specific heat rate improvement technologies and practices to be applied at coal-fired electric generating units. States have three years from the date of finalization to submit a plan that establishes a standard of performance that reflects the degree of emission limitation through the application of heat rate improvement technologies and practices. We cannot estimate the impact of this action on our business or results of operations at this time.

We are also 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.

In December 2018, the New Jersey Department of Environmental Protection proposed two rules that begin the state’s re-entry into the Regional Greenhouse Gas Initiative (RGGI). The first proposal is the mechanism rulemaking that establishes the state’s initial cap on greenhouse gas emissions of 18 million tons in 2020. The proposal follows the RGGI model rule with a cap that will decline three percent annually through 2030 to a final cap of 11.5 million tons. New Jersey is committed to a start date of January 1, 2020. The second proposal establishes the framework for how the state will spend the RGGI auction proceeds. We cannot estimate the impact of this action on our business or results of operations at this time.

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. Note 14. Commitments and Contingent Liabilities.

Early Plant Retirements

Nuclear

In May 2018, the governor of New Jersey signed legislation, referred to as the ZEC legislation, that recognizes that nuclear power is a critical component of New Jersey’s clean energy portfolio and an important element of a diverse energy generation portfolio that currently meets approximately 40 percent of New Jersey’s electric power needs. The ZEC legislation creates a Zero Emission Certificate (ZEC) program to be administered by the BPU. The BPU subsequently established processes to evaluate applications by qualified nuclear plants and to review and approve changes to the New Jersey’s electric distribution companies’ tariffs to provide for the purchase of ZECs from selected nuclear plants and recover those ZEC payments through a non-bypassable distribution charge (ZEC charge) in the amount of $0.004 per kilowatt-hour (which is equivalent to approximately $10 per megawatt hour (MWh) in payments to selected nuclear plants. ZECs will be awarded to selected nuclear plants, if any, in April 2019 at which time ZEC revenue would commence and would continue for approximately three years. Nuclear plants receiving ZEC payments will be obligated to maintain operations, subject to exceptions specified in the ZEC legislation. The ZEC legislation requires nuclear plants to reapply for any subsequent three year periods. The ZEC payment may be adjusted by the BPU (a) at any time to offset environmental or fuel diversity payments that a selected nuclear plant may receive from another source or (b) at certain times specified in the ZEC legislation if the BPU determines that the purposes of the ZEC legislation can be achieved through a reduced charge that will nonetheless be sufficient to achieve the state’s air quality and other environmental objectives by preventing the retirement of nuclear plants.

In December 2018, Power submitted applications to the BPU for the Salem 1 and 2 and Hope Creek nuclear plants. These were the only applications received by the BPU. As required, Power’s three applications each included a certification pursuant to which Power confirmed that each of the Salem 1, Salem 2 and Hope Creek plants will cease operations within three years absent a material financial change. Power’s submittal further attested that the nuclear plants are not expected to cover their costs and operating and market risks as defined in the ZEC legislation, absent a material financial change. As a result, absent a material financial change, Power will retire all three plants unless all of the plants receive ZECs. Power operates its nuclear plants as an interdependent fleet on a common site with shared costs and services, which allows them to achieve economies of scale. A decision to retire one nuclear plant would also adversely impact Power’s ability to attract and retain qualified employees at its remaining plants. Power believes that the retirement of any individual nuclear plant would have the effect of decreasing the scale of its nuclear operations; however, the complex nature of operating nuclear plants would not decrease the attention required from management for the safe operation of the remaining nuclear operations. As a result, Power’s decision to retire any nuclear plant would be made at the site level and would result in the retirement of all of these New Jersey nuclear plants.

Given the anticipated timing of the BPU’s decision on which nuclear plants, if any, have been selected to receive ZECs, which is expected in April 2019, in March 2019 Power will submit to the PJM Independent Market Monitor and the PJM Office of Interconnection a request for a preliminary exception to PJM’s Reliability Pricing Model must-offer requirement with respect to Power’s interest for each of the Salem 1, Salem 2 and Hope Creek plants in connection with the 2022/2023 capacity auction expected to be held in August 2019. Power will also submit a deactivation notice to the extent that its filing deadline occurs prior to the award of ZECs by the BPU. If all of the Salem and Hope Creek plants are selected to receive ZECs, the preliminary exception and requested deactivation notice, as applicable, would be withdrawn.

In the event that any of the Salem 1, Salem 2 and Hope Creek plants is not selected to receive ZEC payments in April 2019 by the BPU and do not otherwise experience a material financial change, Power will take all necessary steps to retire all of these plants at or prior to their refueling outages scheduled for the Fall 2019 in the case of Hope Creek, Spring 2020 in the case of Salem 2 and Fall 2020 in the case of Salem 1. Alternatively, if all of the Salem 1, Salem 2 and Hope Creek plants are selected to receive ZEC payments in April 2019 but the financial condition of the plants is materially adversely impacted by potential changes to the capacity market construct being considered by FERC (absent sufficient capacity revenues provided under a program approved by the BPU in accordance with a FERC authorized capacity mechanism), Power would still take all necessary steps to retire all of these plants. The costs and accounting charges associated with any such retirement, which may include, among other things, accelerated depreciation and amortization or impairment charges, potential penalties associated with the early termination of capacity obligations and fuel contracts, accelerated asset retirement costs, severance costs, environmental remediation costs and, in certain circumstances, potential additional funding of the Nuclear Decommissioning Trust (NDT) Fund, would be material to both PSEG and Power.

Following any action to retire its nuclear plants, Power would take the necessary steps to satisfy its capacity obligations through 2022 with other assets in its fleet or through market purchases. Power intends to decommission any retired nuclear plant using the “SAFESTOR” process, which is a process approved by the NRC. As a result, Power believes adequate funds are available in the NDT Fund for the early retirement of the nuclear plants. To the extent another decommissioning process is employed, the NDT Fund would not be sufficient to cover the costs of decommissioning all the nuclear plants upon early retirement.

Fossil

In December 2018, Power completed the sale of the sites of the retired Hudson and Mercer units. Power transferred all land rights and structures on the sites to a third-party purchaser, along with the assumption of the environmental liabilities for the sites. As a result of the sale and transfer of liabilities, Power recorded a pre-tax gain in 2018 of $54 million in Operation and Maintenance (O&M) Expense.

In addition, PSEG and Power continue to monitor their other coal assets, including their interest in 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.

California Solar Facilities

As part of its solar production portfolio, Power owns and operates two California-based solar facilities with an aggregate capacity of approximately 30 MW direct current whose output is sold to Pacific Gas and Electric Company (PG&E) under power purchase agreements (PPAs) with twenty year terms. The net book value of these solar facilities was approximately $57 million as of December 31, 2018. In January 2019, PG&E and its parent company PG&E Corporation filed for Chapter 11 bankruptcy protection. Power cannot predict the ultimate outcome that this bankruptcy proceeding will have on our ability to collect all of the future revenues from these facilities due under the PPAs; however, any adverse changes to the terms of Power’s PPAs as a result of this bankruptcy proceeding could result in the future impairment of these assets in amounts up to their current net book value.

Offshore Wind

In January 2018, the governor of New Jersey signed Executive Order No. 8 directing the BPU to begin the process of moving the state toward its 2030 goal of 3,500 MW of offshore wind energy generation. An initial solicitation was established for 1,100 MW of offshore wind, with bids due in December 2018. In connection with the bid submitted by Ocean Wind, LLC, a wholly owned subsidiary of Ørsted US Offshore Wind, referred to as the Ocean Wind project, PSEG agreed to provide energy management services and the potential lease of land for use in project development. We also retained an option to acquire an equity interest in the project. We expect to make a decision regarding an equity investment in the Ocean Wind project in the second half of 2019.

Leveraged Leases

In December 2018, NRG REMA, LLC (REMA) emerged from its in-court proceeding under Chapter 11 of the Bankruptcy Code. Upon emergence, PSEG received $31.5 million in cash in exchange for transferring the ownership interests in Keystone and Conemaugh to the debtholders of REMA and satisfaction of all other claims asserted against REMA, as well as certain amendments to the Shawville lease. The Shawville lease amendments, among other things, will allow REMA to express interest in a renewal on or after November 24, 2019. In addition, REMA has agreed to fund qualifying credit support up to $36 million. As a result of the restructuring, Energy Holdings recognized a pre-tax gain in Operating Revenues of approximately $12 million ($9 million after tax). In addition, the remaining deferred tax liabilities related to these lease investments were reclassified to current tax liabilities. PSEG expects to pay approximately $120 million to taxing authorities resulting from this restructuring activity.

Additional facilities in our leveraged lease portfolio include the Joliet and Powerton generating facilities. 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 Tax Act, 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 and interest disallowance rules.

As a result of the Tax Act, we recorded a one-time, non-cash earnings benefit of $745 million in 2017, including $588 million related to Power and $147 million related to Energy Holdings. This benefit was primarily due to the remeasurement of deferred tax balances. In addition, PSE&G recorded excess deferred taxes of approximately $2.1 billion and recorded an approximate $2.9 billion revenue impact of these excess deferred taxes as Regulatory Liabilities.

Beginning in 2018, PSEG, on a consolidated basis, is incurring lower income tax expense resulting in a decrease in its effective income tax rate that has led to an increase in 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. For PSE&G, the Tax Act has led to lower customer rates due to lower income tax expense recoveries and the BPU and FERC have approved our proposal to refund excess deferred income tax Regulatory Liabilities. See Item 8. Note 7. Regulatory Assets and Liabilities for additional information. The impact of the lower federal income tax rate on PSE&G was reflected in PSE&G’s distribution base rate proceeding and its 2018 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.

In August 2018, the Internal Revenue Service (IRS) issued a Notice of Proposed Rulemaking (Notice) regarding the application of tax depreciation rules as amended by the Tax Act. While the Notice provides some guidance as to the application of the changes made by the Tax Act to the bonus depreciation rules, certain aspects remain unclear. Further, in November 2018 the IRS issued Proposed Regulations addressing the interest disallowance rules contained in the Tax Act. For non-regulated businesses, these rules set a cap on the amount of interest that can be deducted in a given year. Any amount that is disallowed can be carried forward indefinitely. For 2018, PSEG and Power expect that a portion of their interest will be disallowed in the current period but realized in future periods. However, certain aspects of the proposed regulations are unclear; therefore, we recorded taxes based on our interpretation of the relevant statute.

We recorded amounts based on our interpretation of the Tax Act, the depreciation rules contained in the Notice and proposed interest disallowance regulations. Such amounts are subject to change based on several factors, including but not limited to, the IRS and state taxing authorities issuing final guidance and/or further clarification. Any further guidance or clarification could impact PSEG’s, PSE&G’s and Power’s financial statements. For additional information, see Item 8. Note 21. Income Taxes.

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 customers. We adjusted the revenue requirement in certain of our rate matters as a result of the change in the federal income tax rate. See Item 8. Note 7. Regulatory Assets and Liabilities for additional information.

In July 2018, the State of New Jersey made changes to its income tax laws, including imposing a temporary surtax on allocated corporate taxable income of 2.5% effective January 1, 2018 and 2019 and 1.5% in 2020 and 2021, as well as requiring corporate taxpayers to file in a combined reporting group as defined under New Jersey law starting in 2019. Both provisions include an exemption for public utilities. We believe PSE&G meets the definition of a public utility and, therefore, will not be impacted by the temporary surtax or be included in the combined reporting group. We expect these new provisions to unfavorably affect our non-utility business. In accordance with GAAP accounting for income taxes, deferred taxes are required to be measured at the enacted tax rate expected to apply to taxable income in the periods in which the deferred taxes are expected to settle. The newly enacted New Jersey tax legislation did not have a material impact on PSEG’s deferred income tax balance.

Amendments to Other Postretirement Employee Benefit (OPEB) Plans

In December 2018, PSEG amended certain provisions of its OPEB plans applicable to all current and future Medicare-eligible retirees and spouses who receive or will receive subsidized healthcare from PSEG. Effective January 1, 2021, the PSEG-sponsored Medicare-eligible plans will be replaced by a Medicare private exchange. For each Medicare-eligible retiree and spouse, PSEG will provide annual credits to a Health Reimbursement Arrangement, which can be used to pay for medical, prescription drug, and dental plan premiums, as well as certain out-of-pocket costs. The amendment resulted in a $559 million reduction in PSEG’s OPEB obligation as of December 31, 2018 and is expected to decrease net periodic benefit costs in 2019.

Future Outlook

Our future success will depend on our ability to continue to maintain strong operational and financial performance in an environment with low gas prices, to capitalize on or otherwise address 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, reliability and customer satisfaction and complying with applicable standards and requirements,
•successfully manage our energy obligations and re-contract our open supply positions in response to changes in prices and demand,
•obtain approval of and execute our utility capital investment program, including ES II, GSMP II, our CEF program and other investments for growth that yield contemporaneous and reasonable risk-adjusted returns, while enhancing the resiliency of our infrastructure and maintaining the reliability of the service we provide to our customers,
•effectively manage construction of BH5 and our 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.

In addition to the risks described elsewhere in this Form 10-K for 2019 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 proceedings,
•the review by the BPU of our application to select our New Jersey nuclear generation units to receive payments under the ZEC program,
•the continuing impacts of the Tax Act and changes in state tax laws, and
•the impact of reductions in demand and lower natural gas and electricity prices and increasing environmental compliance costs.

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, customers 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, clean energy investments and/or generation projects, including offshore wind opportunities,
•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, including the operation of T&D facilities outside of our traditional service territory, 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.

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,
201820172016
Earnings (Losses)Millions
PSE&G$1,067$973$889
Power (A)(B)36547918
Other (B)(C)6122(20)
PSEG Net Income$1,438$1,574$887
PSEG Net Income Per Share (Diluted)$2.83$3.10$1.75
(A)Power’s results in 2018 include an after-tax gain of $39 million from the sale of its Hudson and Mercer coal/gas generation plants and after-tax expenses of $577 million and $396 million in 2017 and 2016, respectively, related to

the early retirement of these generation plants. See Item 8. Note 4. Early Plant Retirements for additional information.

(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 $5 million, $45 million and $92 million related to its investments in REMA’s leveraged leases in 2018, 2017 and 2016, respectively. See Item 8. Note 8. Long-Term Investments and Note 9. Financing Receivables for further information.

Power’s results above include the NDT Fund activity and the impacts of non-trading commodity mark-to-market (MTM) activity, which consist of the financial impact from positions with future delivery dates.

The variances in our Net Income attributable to changes related to the NDT Fund and MTM are shown in the following table:

Years Ended December 31,201820172016
Millions, after tax
NDT Fund and Related Activity (A) (B)$(90)$62$—
Non-Trading MTM Gains (Losses) (C)$(84)$(99)$(100)
(A)NDT Fund Income (Expense) includes gains and losses on NDT securities which are recorded in Net Gains (Losses) on Trust Investments. See Item 8. Note 10. Trust Investments for additional information. NDT Fund Income (Expense) also includes interest and dividend income and other costs related to the NDT Fund recorded in Other Income (Deductions), interest accretion expense on Power’s nuclear Asset Retirement Obligation (ARO) recorded in O&M Expense and the depreciation related to the ARO asset recorded in Depreciation and Amortization (D&A) Expense.
(B)Net of tax (expense) benefit of $54 million, $(72) million and $(5) million for the years ended December 31, 2018, 2017 and 2016, respectively.
(C)Net of tax benefit of $33 million, $68 million and $68 million for the years ended December 31, 2018, 2017 and 2016, respectively.

The 2018 year-over-year decrease in Net Income was driven largely by

•non-cash Net Income benefits in 2017 related to new tax legislation (See Item 8. Note 21. Income Taxes) at Power and Energy Holdings, and
•recognition in 2018 of net unrealized losses on equity securities in the NDT Fund in accordance with new accounting guidance effective January 1, 2018 (See Item 8. Note 2. Recent Accounting Standards and Note 10. Trust Investments),

These decreases were partially offset by

•accelerated depreciation in 2017 related to early retirement of our Hudson and Mercer coal/gas generation units at Power (See Item 8. Note 4. Early Plant Retirements),
•the favorable impact at Power from the lower federal tax rate effective January 1, 2018, and
•higher earnings due to investments in T&D programs and the favorable impact of new rates effective November 1, 2018 as a result of the BPU approval of our distribution base rate proceeding.

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. Note 21. 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. Note 8. Long-Term Investments).

These increases were partially offset by:

•higher charges related to the early retirement of our Hudson and Mercer coal/gas generation units at Power (See Item 8. Note 4. 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.

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. Note 25. Related-Party Transactions.

Increase / (Decrease)Increase / (Decrease)
Years Ended December 31,
2018201720162018 vs. 20172017 vs. 2016
MillionsMillions%Millions%
Operating Revenues$9,696$9,094$8,966$6027$1281
Energy Costs3,2252,7782,90144716(123)(4)
Operation and Maintenance3,0152,9012,9911144(90)(3)
Depreciation and Amortization1,1581,9861,476(828)(42)51035
Income from Equity Method Investments15141117327
Net Gains (Losses) on Trust Investments(143)134(6)(277)N/A140N/A
Other Income (Deductions)858210234(20)(20)
Non-Operating Pension and OPEB Credits (Costs)76—(22)76N/A22N/A
Interest Expense476391385852262
Income Tax (Benefit) Expense417(306)411723N/A(717)N/A

The 2018, 2017 and 2016 amounts in the preceding table for Operating Revenues and O&M costs each include $458 million, $438 million and $410 million, respectively, for PSEG LI’s subsidiary, Long Island Electric Utility Servco, LLC (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. Note 5. 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)
2018201720162018 vs. 20172017 vs. 2016
MillionsMillions%Millions%
Operating Revenues$6,471$6,324$6,303$1472$21—
Energy Costs2,5202,4212,644994(223)(8)
Operation and Maintenance1,5751,4581,4651178(7)—
Depreciation and Amortization770685565851212021
Net Gains (Losses) on Trust Investments(1)2—(3)N/A2N/A
Other Income (Deductions)808579(5)(6)68
Non-Operating Pension and OPEB Credits (Costs)59(8)(15)67N/A7(47)
Interest Expense3333032893010145
Income Tax Expense344563515(219)(39)489

Year Ended December 31, 2018 as compared to 2017

Operating Revenues increased $147 million due to changes in delivery, clause, commodity and other operating revenues.

Delivery Revenues increased $44 million.

•Transmission revenues increased $180 million due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.
•Gas distribution revenues increased $67 million due to $63 million from higher sales volumes, $36 million from the inclusion of the GSMP I in base rates, $25 million from an increase in the distribution tariff rates effective November 1, 2018 and $2 million in higher collections of Green Program Recovery Charges (GPRC). These increases were partially offset by lower Weather Normalization Clause (WNC) revenues of $31 million, a $26 million reduction for Tax Adjustment Credits (TAC) and a $2 million reduction in ES I collections.
•Electric distribution revenues increased $62 million due primarily to a $49 million increase in sales volume, a $17 million increase in ES I collections, $6 million from an increase in the distribution tariff rates effective November 1, 2018 and $4 million in higher collections of GPRC. These increases were partially offset by a reduction of $14 million in TAC.
•Transmission, electric distribution and gas distribution revenue requirements were $265 million lower as a result of rate reductions due to the Tax Act which reduced the corporate income tax rate. This decrease is offset in Income Tax Expense.

Clause Revenues increased $2 million due to higher Societal Benefit Charges (SBC) of $14 million, and $2 million in higher Solar Pilot Recovery Charge (SPRC) collections, partially offset by decreases of $7 million in Margin Adjustment Clause (MAC) revenues and $7 million in TAC and GPRC deferrals. The changes in SBC, SPRC and MAC collections and TAC and GPRC deferrals were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, D&A and Interest and Tax Expense. PSE&G does not earn margin on SBC, SPRC or MAC collections or on TAC or GPRC deferrals.

Commodity Revenues increased $99 million due to higher Electric revenues and higher Gas revenues. This increase is entirely offset with increased Energy Costs. PSE&G earns no margin on the provision of BGS and basic gas supply service (BGSS) to retail customers.

•Electric revenues increased $73 million due to $67 million in higher net BGS revenues reflecting $148 million from higher BGS sales volumes partially offset by $81 million from lower prices, and $6 million in higher revenues from solar renewable energy credit (SREC) sales.
•Gas revenues increased $26 million due to $65 million from higher BGSS sales volumes, which were partially offset by lower BGSS prices of $42 million, and $3 million in higher BGSS Asset Charges.

Operating Expenses

Energy Costs increased $99 million. This is entirely offset by Commodity Revenues.

Operation and Maintenance increased $117 million, due to a $24 million increase in electric distribution maintenance expenditures, a $24 million increase in transmission maintenance expenditures, a $16 million increase in appliance service costs, a $12 million net increase for various clause mechanisms and GPRC expenditures, a $9 million increase in storm-related costs, an $8 million increase in gas distribution expenditures, a $6 million net increase in pension and OPEB expenses, net of amounts capitalized, a $3 million increase in damage claims, and a $15 million increase in other operating expenses.

Depreciation and Amortization increased $85 million due primarily to an increase in depreciation of $81 million due to additional plant placed into service, a $7 million net increase in amortization of Regulatory Assets primarily due to the settlement of our base rate proceeding and an increase of $5 million in software amortization, partially offset by a $7 million increase in capitalized depreciation.

Non-Operating Pension and OPEB Credits (Costs) reflect an increase of $67 million in credits primarily due to the adoption of new accounting guidance effective January 1, 2018 which no longer allows for the capitalization of any portion of these benefit costs. See Item 8. Note 2. Recent Accounting Standards.

Other Income (Deductions) decreased $5 million due primarily to a $2 million decrease in the Allowance for Funds Used During Construction (AFUDC) and a $3 million decrease in solar loan interest.

Interest Expense increased $30 million due primarily to increases of $16 million due to long-term debt issuances in May and December 2017, $8 million due to net long-term debt issuances in 2018 and $4 million in clause-related interest.

Income Tax Expense decreased $219 million due primarily to the decrease in the federal statutory income tax rate from 35% in 2017 to 21% in 2018 and lower pretax income.

Year Ended December 31, 2017 as compared to 2016

Operating Revenues increased $21 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 I, $10 million from inclusion of the GSMP I 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 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 I revenues.

Clause Revenues increased $75 million due to the absence of the return in 2016 to customers of overcollections of Securitization Transition Charge (STC) revenues of $59 million, higher GPRC collections of $28 million and higher MAC revenues of $4 million. These increases were partially offset by lower SBC of $17 million. The changes in STC, GPRC, 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, GPRC, MAC or SBC collections.

Commodity Revenues decreased $223 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 $288 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 (NUG) Charges due primarily to lower prices, a $14 million decrease from sales of SRECs and $14 million in lower revenues from the decreased sales volume of NUG energy.
•Gas revenues increased $65 million due to higher BGSS prices of $68 million and $2 million from higher sales volumes, partially offset by $5 million in lower BGSS Asset Charges.

Operating Expenses

Energy Costs decreased $223 million. This is entirely offset by Commodity Revenues.

Operation and Maintenance decreased $7 million due primarily to a $15 million decrease in appliance service costs, partially offset by an $8 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.

Non-Operating Pension and OPEB Credits (Costs) reflect a decrease in costs of $7 million due primarily to a decrease in the amortization of the net unrecognized actuarial pension loss, partially offset by the impacts of capitalization.

Other Income (Deductions) increased $6 million due primarily to an increase in AFUDC.

Interest Expense increased $14 million due primarily to an $11 million increase 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.

Power

Years Ended December 31,Increase / (Decrease)Increase / (Decrease)
2018201720162018 vs. 20172017 vs. 2016
MillionsMillions%Millions%
Operating Revenues$4,146$3,860$3,861$2867$(1)—
Energy Costs2,1971,9131,82428415895
Operation and Maintenance9991,0461,139(47)(4)(93)(8)
Depreciation and Amortization3541,268881(914)(72)38744
Income from Equity Method Investments15141117327
Net Gains (Losses) on Trust Investments(140)125(6)(265)N/A131N/A
Other Income (Deductions)21202315(3)(13)
Non-Operating Pension and OPEB Credits (Costs)158(4)78812N/A
Interest Expense7650842652(34)(40)
Income Tax Expense (Benefit)66(729)(61)795N/A(668)N/A

Year Ended December 31, 2018 as compared to 2017

Operating Revenues increased $286 million due to changes in generation, gas supply and other operating revenues.

Generation Revenues increased $199 million due primarily to

•a net increase of $113 million due primarily to higher volumes of electricity sold under wholesale load contracts in the PJM region coupled with the commencement of commercial operations for Keys and Sewaren 7 in mid-2018, partially offset by lower average realized prices and higher purchases for wholesale load contracts in the PJM region,
•a net increase of $110 million due to lower MTM net losses in 2018 as compared to 2017. Of this amount, there was a $153 million increase due to gains on positions reclassified to realized upon settlement, partially offset by a net decrease of $43 million due to changes in forward prices,
•a net increase of $26 million in capacity revenues due primarily to increases in auction prices in the PJM region,
•a net increase of $24 million resulting from a prior year reduction to revenue for excess federal income tax previously collected by Power’s subsidiary, PSEG New Haven LLC, from ratepayers due to the change in federal tax rates, and
•a net increase of $7 million due to higher sales related to new solar projects,
•partially offset by a decrease of $82 million in electricity sold under our BGS contracts due to lower prices and lower volumes.

Gas Supply Revenues increased $87 million due primarily to

•an increase of $61 million in sales under the BGSS contract, of which $53 million was due to increases in sales volumes as a result of periods of colder weather in the heating season, coupled with $8 million due to higher average sales prices, and
•an increase of $42 million related to sales to third parties, of which $26 million was due to higher sales volumes and $16 million to higher average sales prices,
•partially offset by a decrease of $16 million due to net MTM losses in 2018 compared to net gains in 2017.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs increased $284 million due to

Generation costs increased $167 million due primarily to

•higher fuel costs of $158 million reflecting utilization of higher volumes of gas and oil in the PJM region, primarily due to the commencement of commercial operations of Keys and Sewaren 7 fossil stations in mid-2018, coupled with higher prices of natural gas in the PJM and New York regions and higher coal costs in the PJM and New England (NE) regions, and
•an increase of $40 million due to MTM losses in 2018 as compared to gains in 2017 due to changes in forward prices,
•partially offset by a net decrease of $22 million primarily due to a decrease in the volume of energy purchased in the NE region to serve load obligations, and
•a net decrease of $14 million due to charges primarily related to additional retirement costs incurred in 2017 associated with the early retirement of the Hudson and Mercer units.

Gas costs increased $117 million due primarily to

•an increase of $75 million related to sales under the BGSS contract due primarily to a $51 million increase in volumes sold due to periods of colder weather during the heating season in 2018 as compared to 2017, and $24 million of higher average gas costs, and
•an increase of $38 million related to sales to third parties, of which $25 million was due to an increase in volumes sold coupled with $13 million due to higher average gas costs.

Operation and Maintenance decreased $47 million due primarily to

•a $67 million decrease at our fossil plants, due primarily to a pre-tax gain of $54 million on the sale of the Hudson and Mercer units in 2018 and associated shutdown costs incurred in 2017, partially offset by higher planned outage costs in 2018 associated with our various other fossil plants,
•partially offset by a $22 million net increase at our nuclear facilities primarily due to higher planned outage costs at our 100%-owned Hope Creek nuclear plant in 2018 as compared to our 57%-owned Salem Unit 1 nuclear plant in 2017, coupled with higher accretion directly related to an increase in the nuclear ARO in 2017.

Depreciation and Amortization decreased $914 million due primarily to

•a $964 million decrease primarily due to accelerated depreciation recorded in 2017 for the early retirement of the Hudson and Mercer units,
•partially offset by a $23 million increase due to Keys and Sewaren 7 fossil stations being placed into service,
•an increase of $12 million in depreciation due to the increase in the nuclear ARO in late 2017, and
•a $7 million increase in 2018 due primarily to a higher nuclear asset base from increased capitalized asset retirement costs.

Net Gains (Losses) on Trust Investments decreased $265 million due primarily to

•the inclusion in 2018 of $209 million of net unrealized losses on equity investments in the NDT Fund in accordance with new accounting guidance, and
•a $64 million decrease in net realized gains on NDT Fund investments,
•partially offset by a $12 million decrease in other-than-temporary impairments of equity securities in the NDT Fund.

Non-Operating Pension and OPEB Credits (Costs) reflect an increase in credits of $7 million due primarily to an increase in the expected return on pension plan assets.

Interest Expense increased $26 million due primarily to a $15 million increase due to a June 2018 debt issuance and $11 million in lower capitalized interest as a result of Keys and Sewaren 7 fossil stations being placed into service.

Income Tax Expense increased $795 million due primarily to a one-time benefit recorded in 2017 as a result of the remeasurement of deferred tax balances and higher pre-tax income in 2018. This increase was partially offset by the favorable impacts in 2018 of a decrease in the federal statutory income tax rate from 35% in 2017 to 21% and the remeasurement of the reserve for uncertain tax positions in connection with a 2015 claim to carry back tax-defined nuclear decommissioning costs and the 2011 and 2012 federal tax audit.

Year Ended December 31, 2017 as compared to 2016

Operating Revenues decreased $1 million due to changes in generation, gas supply and other operating revenues.

Generation Revenues decreased $112 million due primarily to

•a decrease of $100 million in electricity sold under our BGS contracts due primarily to lower volumes coupled with lower prices,
•a decrease of $41 million in energy sales in the PJM and NE regions due primarily to lower average realized 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 $12 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 increased $89 million due to

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.

Generation costs increased $23 million due primarily to

•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,
•a net increase of $17 million primarily due to an increase in the volume of energy purchases in the NE region to serve load obligations, and
•a net increase of $10 million primarily due to higher transmission charges resulting from higher rates,
•partially offset by 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.

Operation and Maintenance decreased $93 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, and
•a $35 million net decrease at our nuclear facilities primarily due to lower planned outage costs at our 57%-owned Salem nuclear plants in 2017 as compared to our 100%-owned Hope Creek nuclear plant and Salem Unit 1 nuclear plant in 2016,
•partially offset by a $5 million increase 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.

Net Gains (Losses) on Trust Investments increased $131 million due primarily to a $113 million increase in net realized gains on NDT Fund investments and lower other-than-temporary impairments of equity securities of $16 million in the NDT Fund.

Non-Operating Pension and OPEB Credits (Costs) reflect an increase in credits of $12 million due primarily to a decrease in the amortization of the net unrecognized actuarial pension loss.

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.

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. 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 $1.1 billion of term loan credit agreements, of which $350 million is scheduled to expire in June 2019 and $700 million in November 2020. 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 Standard & Poor’s (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, 2018, our operating cash flow decreased by $347 million. For the year ended December 31, 2017, our operating cash flow decreased by $53 million. The net changes were primarily due to net changes from our subsidiaries as discussed below and net tax payments at Energy Holdings in 2018 as compared to tax refunds in 2017.

PSE&G

PSE&G’s operating cash flow increased $15 million from $1,838 million to $1,853 million for the year ended December 31, 2018, as compared to 2017, due primarily to an increase of $171 million relating to accounts receivable and unbilled revenues resulting from higher collections and lower prices and volumes in 2018 and higher earnings, offset by tax payments in 2018 as compared to tax refunds in 2017.

PSE&G’s operating cash flow decreased $58 million from $1,896 million to $1,838 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.

Power

Power’s operating cash flow decreased $242 million from $1,326 million to $1,084 million for the year ended December 31, 2018, as compared to 2017, due to an increase in margin deposit requirements of $157 million, lower earnings, a decrease in fuels, materials and supplies of $81 million and an increase of $52 million in payments to counterparties, offset by tax refunds in 2018 as compared to tax payments in 2017, and a $96 million increase from net collections of counterparty receivables.

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.

Short-Term Liquidity

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

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, 2018 were as follows:

Company/FacilityAs of December 31, 2018
Total FacilityUsageAvailable Liquidity
Millions
PSEG$1,500$759$741
PSE&G600288312
Power2,1001541,946
Total$4,200$1,201$2,999

As of December 31, 2018, 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 $857 million and $848 million as of December 31, 2018 and 2017, respectively.

For additional information, see Item 8. Note 15. Debt and Credit Facilities.

Long-Term Debt Financing

During the next twelve months, PSEG has a $350 million floating rate term loan maturing in June 2019 and $400 million of 1.60% Senior Notes maturing in November 2019. PSE&G has $250 million of 1.80% Medium Term Notes maturing in June 2019 and $250 million of 2.00% Medium Term Notes maturing in August 2019. Power has a letter of credit backing $44 million of Pennsylvania Economic Development Financing Authority Variable Rate Demand Bonds which expires in November 2019.

For a discussion of our long-term debt transactions during 2018, see Item 8. Note 15. 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, 2018, PSE&G’s Mortgage coverage ratio was 3.8 to 1 and the Mortgage would permit up to approximately $6.3 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. Power’s bank credit agreements and outstanding notes also contain limitations on the incurrence of subsidiary debt and liens and certain of Power’s outstanding notes require Power to repurchase such notes upon certain change of control events.

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 Stock201820172016
Per Share$1.80$1.72$1.64
in Millions$910$870$830

On February 19, 2019, our Board of Directors approved a $0.47 per share common stock dividend for the first quarter of 2019. This reflects an indicative annual dividend rate of $1.88 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. Note 23. 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.

Moody’s (A)S&P (B)
PSEG
OutlookStableStable
Senior NotesBaa1BBB
Commercial PaperP2A2
PSE&G
OutlookStableStable
Mortgage BondsAa3A
Commercial PaperP1A2
Power
OutlookStableStable
Senior NotesBaa1BBB+
(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, 2018, we had Other Comprehensive Income of $28 million on a consolidated basis. Other Comprehensive Income was due primarily to an increase of $46 million related to pension and other postretirement benefits, partially offset by $17 million of net unrealized losses related to Available-for-Sale Securities and $1 million of unrealized losses on derivative contracts accounted for as hedges. See Item 8. Note 22. 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 AFUDC 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 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.

201920202021
Millions
PSE&G:
Transmission$1,350$1,145$875
Distribution740820820
Gas System Modernization Program420455435
Solar/Energy Efficiency70555
Total PSE&G$2,580$2,475$2,135
Power:
Baseline$165$130$150
Growth Opportunities2252015
Other51520
Total Power$395$165$185
Other$40$55$40
Total PSEG$3,015$2,695$2,360

PSE&G

PSE&G’s projections for future capital expenditures include material additions and replacements to its T&D 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, modernization and replacement of equipment that has reached the end of its useful life.
•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 June 2018, we filed for our ES II, a proposed five-year $2.5 billion program to harden, modernize and make our electric and gas distribution systems more resilient. The size and duration of ES II, as well as certain other elements of the program, are subject to BPU approval.

In October 2018, we filed our proposed CEF program with the BPU, a six-year estimated $3.6 billion investment program focused on achieving New Jersey’s energy efficiency targets, supporting electric vehicle infrastructure, deploying energy storage, and implementing an EC program which will include installing approximately two million electric smart meters and associated infrastructure. The size and duration of the CEF program, as well as certain other elements of the program, are subject to BPU approval.

ES II and the CEF program are not included in PSE&G’s projected capital expenditures in the above table.

In 2018, PSE&G made $2,901 million of capital expenditures, primarily for T&D system reliability. This does not include expenditures for cost of removal, net of salvage, of $160 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.
•Growth Opportunities—investments associated with new construction, including 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 2018, Power made $815 million of capital expenditures, excluding $181 million for nuclear fuel, primarily related to various projects at Fossil 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. Note 15. 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. Note 21. Income Taxes for additional information.

Total Amount CommittedLess Than 1 Year2 - 3 Years4 - 5 YearsOver 5 Years
Millions
Contractual Cash Obligations
Long-Term Recourse Debt Maturities
PSEG$2,450$750$1,000$700$—
PSE&G9,2585006938257,240
Power2,850441,356950500
Interest on Recourse Debt
PSEG152617219—
PSE&G5,5643426516093,962
Power830134224148324
Operating Leases
PSE&G11815211666
Power11011262251
Services178142930105
Other5131—
Energy-Related Purchase Commitments
Power2,742774918586464
Total Contractual Cash Obligations$24,257$2,646$4,993$3,906$12,712
Liability Payments for Uncertain Tax Positions
PSEG$112$112$—$—$—
PSE&G6262———
Power3434———

OFF-BALANCE SHEET ARRANGEMENTS

PSEG and Power issue guarantees, primarily in conjunction with certain of Power’s energy contracts. See Item 8. Note 14. 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. Note 8. Long-Term Investments and Note 9. 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 accounting principles generally accepted in the United States (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.

Assumption201820172016
Discount Rate4.41%3.73%4.29%
Expected Rate of Return on Plan Assets7.80%7.80%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 expense in 2019 of approximately $49 million, or $11 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 fourteen 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 4.41% discount rate for 2019 expense. 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.

% ChangeImpact on Pension Benefit Obligation as of December 31, 2018Increase to Pension Expense in 2019Increase to Pension Expense, net of Amounts Capitalized in 2019
AssumptionMillions
Discount Rate(1)%$746$39$32
Expected Rate of Return on Plan Assets(1)%N/A$50$50

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. Note 1. Organization, Basis of Presentation and Significant Accounting Policies, Note 17. Financial Risk Management Activities and Note 18. Fair Value Measurements.

Long-Lived Assets

Management evaluates long-lived assets for impairment and reassesses the reasonableness of their related estimated useful lives whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate, counterparty credit worthiness, or market conditions, could potentially indicate an asset’s or asset group’s carrying amount may not be recoverable or an asset’s probability of operating through its estimated remaining useful life changes.

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.

In addition, long-lived assets are depreciated under the straight-line method based on estimated useful lives. An asset’s operating useful life is generally based upon operational experience with similar asset types and other non-operational factors. In the ordinary course, management, together with an asset’s co-owners in the case of certain of our jointly-owned assets, makes a number of decisions that impact the operation of our generation assets beyond the current year. These decisions may have a direct impact on the estimated remaining useful lives of our assets and will be influenced by the financial outlook of the assets, including future market conditions such as forward energy and capacity prices, operating and capital investment costs and any state or federal legislation and regulations, among other items.

The assumptions used by management incorporate inherent uncertainties that are at times difficult to predict and could result in impairment charges or accelerated depreciation in future periods if actual results materially differ from the estimated assumptions utilized in our forecasts.

Effect if Different Assumptions Used: The above cash flow tests, and fair value estimates and estimated remaining useful lives may be impacted by a change in the assumptions noted above and could significantly impact the outcome, triggering additional impairment tests, write-offs or accelerated depreciation. For additional information on the potential impacts on our future financial statements that may be caused by a change in useful lives of certain of our generating assets. See Item 8. Note 4. Early Plant Retirements and Note 6. Property, Plant and Equipment and Jointly-Owned Facilities.

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. Note 8. Long-Term Investments and Note 9. 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 O&M 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 $80 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 O&M.

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 2018. When we revise any assumptions used to calculate fair values of existing AROs, we adjust the ARO balance and corresponding long-lived asset which generally 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, 2018. 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,
•SAFESTOR alternative, which assumes the nuclear facility can be safely stored and subsequently decommissioned in a period within 60 years after operations,
•DECON alternative, which assumes decommissioning activities begin after operations, 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. Had the following assumptions been applied, our estimates of the approximate impacts on the Nuclear ARO as of December 31, 2018 are as follows:

•A decrease of 1% in the discount rate would result in a $32 million increase in the Nuclear ARO.
•An increase of 1% in the inflation rate would result in a $260 million increase in the Nuclear ARO.
•If we were not reimbursed by the federal government for spent fuel costs as prescribed under the Nuclear Waste Policy Act, the Nuclear ARO would increase by $346 million.
•If we would elect or be required to decommission under a DECON alternative at Salem and Hope Creek, the Nuclear ARO would increase by $635 million.
•If Power were to increase its early shutdown probability to 100% and retire Hope Creek and Salem starting in the Fall of 2019, which is significantly earlier than the end of their current license periods, the Nuclear ARO would increase by $314 million. For additional information, see Item 8. Note 4. Early Plant Retirements.

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 Regulatory 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. Note 7. Regulatory Assets and Liabilities for a description of the amounts and nature of regulatory balance sheet amounts.

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