Primarily all of PSE&G’s property is located in New Jersey and PSE&G’s First and Refunding Mortgage, which secures the bonds issued thereunder, constitutes a direct first mortgage lien on substantially all of PSE&G’s property. PSE&G’s electric lines and gas mains are located over or under public highways, streets, alleys or lands, except where they are located over or under property owned by PSE&G or occupied by it under easements or other rights. PSE&G deems these easements and other rights to be adequate for the purposes for which they are being used.
We are party to various lawsuits and environmental and regulatory matters, including in the ordinary course of business. For information regarding material legal proceedings, see Item 1. Business—Regulatory Issues and Environmental Matters and Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities.
Not applicable.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is listed on the New York Stock Exchange, Inc. under the trading symbol “PEG.” As of February 16, 2018,2024, there were 60,86847,943 registered holders.
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| Three Months Ended December 31, 2017 | | Total Number of Shares Purchased | | Average Price Paid per Share | |
| October 1-October 31 | | — |
| | $ | — |
| |
| November 1-November 30 | | 486,635 |
| | $ | 49.86 |
| |
| December 1-December 31 | | — |
| | $ | — |
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| | | | | | |
In December 2017, we entered into a share repurchase plan that complies with Rule 10b5-1 of the Securities Exchange Act of 1934, as amended, solely with respect to the repurchase of shares to satisfy obligations under equity compensation awards that are expected to vest or be exercised in 2018.
The following table indicates the securities authorized for issuance under equity compensation plans as of December 31, 2017:2023:
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| Plan Category | | Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights (a) | | Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b) | | Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans (excluding securities reflected in column (a)) (c) | |
| Equity Compensation Plans Approved by Security Holders | | — | | | $ | — | | | 8,162,450 | | |
| Equity Compensation Plans Not Approved by Security Holders | | — | | | — | | | — | | |
| Total | | — | | | $ | — | | | 8,162,450 | | |
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| Plan Category | | Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights | | Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights | | Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans | |
| Long-Term Incentive Plan | | 347,900 |
| | $ | 33.49 |
| | 13,771,542 |
| |
| Employee Stock Purchase Plan | | — |
| | — |
| | 3,174,168 |
| |
| Total | | 347,900 |
| | $ | 33.49 |
| | 16,945,710 |
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| | | | | | | | |
The number of shares available for future issuance includes amounts remaining under our 2021 Long-Term Incentive Plan (2021 LTIP) and 2021 Equity Compensation Plan for Outside Directors and the Employee Stock Purchase Plan and reflect a reduction for non-vested restricted stock units and performance share units (PSUs) (assumed at target payout). The number of shares available for future issuance may be increased or decreased depending on actual payouts for the PSUs based on achievement of targets and is increased by the number of shares that are forfeited, canceled or otherwise terminated without the issuance of shares. For additional discussion of specific plans concerning equity-based compensation, see Item 8. Financial Statements and Supplementary Data—Note 18. Stock Based Compensation.
PSE&G
We own all of the common stock of PSE&G. For additional information regarding PSE&G’s ability to continue to pay dividends, see Item 7. MD&A—Liquidity and Capital Resources.
Power
We own all of Power’s outstanding limited liability company membership interests. For additional information regarding Power’s ability to pay dividends, see Item 7. MD&A—Liquidity and Capital Resources.
ITEM 6. SELECTED FINANCIAL DATA[RESERVED]
PSEG
The information presented below should be read in conjunction with the MD&A and the Consolidated Financial Statements and Notes to Consolidated Financial Statements (Notes).
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| PSEG | | | | | | | | | | | |
| Years Ended December 31, | | 2017 | | 2016 | | 2015 | | 2014 | | 2013 | |
| | | Millions, except Earnings per Share | |
| Operating Revenues (A) | | $ | 9,084 |
| | $ | 9,061 |
| | $ | 10,415 |
| | $ | 10,886 |
| | $ | 9,968 |
| |
| Income from Continuing Operations (B)(C) | | $ | 1,574 |
| | $ | 887 |
| | $ | 1,679 |
| | $ | 1,518 |
| | $ | 1,243 |
| |
| Net Income (B)(C) | | $ | 1,574 |
| | $ | 887 |
| | $ | 1,679 |
| | $ | 1,518 |
| | $ | 1,243 |
| |
| Earnings per Share: | | | | | | | | | | | |
| Income from Continuing Operations | | | | | | | | | | | |
| Basic | | $ | 3.12 |
| | $ | 1.76 |
| | $ | 3.32 |
| | $ | 3.00 |
| | $ | 2.46 |
| |
| Diluted | | $ | 3.10 |
| | $ | 1.75 |
| | $ | 3.30 |
| | $ | 2.99 |
| | $ | 2.45 |
| |
| Net Income | | | | | | | | | | | |
| Basic | | $ | 3.12 |
| | $ | 1.76 |
| | $ | 3.32 |
| | $ | 3.00 |
| | $ | 2.46 |
| |
| Diluted | | $ | 3.10 |
| | $ | 1.75 |
| | $ | 3.30 |
| | $ | 2.99 |
| | $ | 2.45 |
| |
| Dividends Declared per Share | | $ | 1.72 |
| | $ | 1.64 |
| | $ | 1.56 |
| | $ | 1.48 |
| | $ | 1.44 |
| |
| As of December 31, | | | | | | | | | | | |
| Total Assets | | $ | 42,716 |
| | $ | 40,070 |
| | $ | 37,535 |
| | $ | 35,287 |
| | $ | 32,480 |
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| Long-Term Obligations (D) | | $ | 12,071 |
| | $ | 10,897 |
| | $ | 8,837 |
| | $ | 8,218 |
| | $ | 7,830 |
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(A) | Operating Revenues for 2017, 2016 and 2015 includes $438 million, $410 million and $375 million, respectively, for Long Island Electric Utility Servco, LLC (Servco), a wholly owned subsidiary of PSEG LI. See Item 8. Financial Statements and Supplementary Data—Note 4. Variable Interest Entity for additional information. |
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(B) | Income from Continuing Operations and Net Income for 2017 and 2016 includes after-tax expenses of $577 million and $396 million, respectively, related to the early retirement of Power’s Hudson and Mercer coal/gas generation plants and after-tax charges for 2017 and 2016 totaling $45 million and $92 million, respectively, related to investments in REMA’s leveraged leases and an after-tax insurance recovery for Superstorm Sandy of $102 million for 2015. See Item 8. Financial Statements and Supplementary Data—Note 3. Early Plant Retirements, Note 7. Long-Term Investments and Note 8. Financing Receivables for additional information for 2017. |
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(C) | Income from Continuing Operations and Net Income for 2017, include the non-cash net income benefit of $745 million, primarily resulting from the remeasurement of deferred tax liabilities required due to the enactment of the Tax Act in December 2017. See Item 8. Financial Statements and Supplementary Data—See Note 20. Income Taxes for additional information for 2017. |
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(D) | Includes capital lease obligations. |
PSE&G and Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
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), and 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, PSE&G and PSEG Power LLC (PSEG Power) & Other, primarily comprised of 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)., and other federal and New Jersey state regulators. PSE&G also invests in regulated solar generation projects and energy efficiency (EE) and related programs in New Jersey, which are regulated by the BPU, and
•PSEG Power—which is a multi-regionalan 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 throughvia its principal direct wholly owned subsidiaries. In addition, Power owns and operates solar generation in various states.PSEG Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and other federal regulators and state regulators in the states in which they operate.
The PSEG Power & Other reportable segment also includes amounts related to the parent company as well as PSEG’s other direct wholly owned subsidiaries, which are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) transmission and distribution (T&D) system under an Operations Services Agreement (OSA); PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily hasholds legacy lease investments in leveraged leases;and competitively bid, FERC regulated transmission; 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 20172023 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 20172023 AND FUTURE OUTLOOK
2017 Overview
We are a public utility holding company that, acting through our wholly owned subsidiaries, is a predominantly regulated electric and gas utility and a nuclear generation business. Our business plan is designedfocuses on achieving growth by allocating capital primarily toward regulated investments in an effort to achieve growth while managingcontinue to improve the risks associated with fluctuating commodity pricessustainability and changes in customer demand.predictability of our business. We continueare focused on investing to modernize our focus on operational excellence, financial strength and disciplined investment. These guiding principles have provided the base from which we have been able to execute our strategic initiatives, including:
improving utility operations through growth in investment in T&D and otherenergy infrastructure, projects designed to enhance systemimprove reliability and resiliencyresilience, increase EE and deliver cleaner energy to meet customer expectations and be well aligned with public policy objectives, and
maintaining and expanding a reliable generation fleet with the flexibility to utilize a diverse mixobjectives. In furtherance of fuels which allows us to respond to market volatility and capitalize on opportunities as they arise.
Financial Results
The results for PSEG, PSE&G and Power for the years ended December 31, 2017 and 2016 are presented below:
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| | | Years Ended December 31, | |
| | | 2017 | | 2016 | |
| Earnings (Losses) | | Millions, except per share data | |
| PSE&G | | $ | 973 |
| | $ | 889 |
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| Power | | 479 |
| | 18 |
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| Other | | 122 |
| | (20 | ) | |
| PSEG Net Income | | $ | 1,574 |
| | $ | 887 |
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| PSEG Net Income Per Share (Diluted) | | $ | 3.10 |
| | $ | 1.75 |
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Our 2017 over 2016 increase in Net Income was due primarily to the favorable impacts of new tax legislation at Power and Energy Holdings in 2017, discussed below, partially offset by higher charges in 2017 related to the early retirement ofthese goals, our Hudson and Mercer units. Higher transmission revenues in 2017 at PSE&G, lower charges in 2017 related to investments in certain leveraged leases at Energy Holdings and lower plant outage costs at Power, partially offset by lower volumes of electricity sold at lower average prices, also contributed to the increase in Net Income. For a more detailed discussion of our financial results, see Results of Operations.
During 2017, we maintained a strong balance sheet. We continued to effectively deploy capital without the need for additional equity, while our solid credit ratings aided our ability to access capital and credit markets. The greater emphasis on capital spending for projects on which we receive contemporaneous returns at PSE&G our regulated utility, in recent years has yielded strong results, which when combined with the cash flow generated by Power, our merchant generator and power marketer, has allowed us to increase our dividend. These actions to transition our business to meet market conditions and investor expectations reflect our multi-year, long-term approach to managing our company. Our focus has been to invest capital in T&D and other infrastructure projects aimed at maintaining service reliability to our customers and bolstering our system resiliency. At Power, we strive to improve performance and reduce costs in order to enhance the value of our generation fleet in light of low gas prices, environmental considerations and competitive market forces that reward efficiency and reliability.
At PSE&G, we continue to invest in transmission projects that focus on reliability improvements and replacement of aging infrastructure. We also continue to make investments to improve the resiliency of our gas and electric distribution system as part of our Energy Strong program that was approved by the BPU in 2014 and to seek recovery on such investments. We are modernizing PSE&G’s gas distribution systems as part of our Gas System Modernization Program (GSMP) that was approved by the BPU in late 2015. In July 2017, we filed a petition with the BPU for a GSMP II program, an extension of GSMP to continue to modernize our gas system, through which PSE&G has proposed investing $2.7 billion over five years beginning in 2019. This matter is pending. We believe the petition is consistent with the Infrastructure Investment Program (IIP) regulations that the BPU approved in December 2017. In August 2017, the BPU approved PSE&G’s petition for an Energy Efficiency 2017 Program (EE 2017) to extend three existing energy efficiency subprograms (multi-family, direct install and hospital efficiency) and establish two new residential energy efficiency offerings. The EE 2017 allows for $69 million of additional investment and $16 million of additional administrative and information technology costs. The EE 2017 was added as the eleventh component of the Green Program Recovery Charges (GPRC) rate effective September 1, 2017. Over the past few years, these types of investments have alteredadjusted our business mix to reflect a higher percentage of earnings contribution by PSE&G. In addition, the passage of the Inflation Reduction Act of 2022 (IRA) established a production tax credit (PTC) for existing nuclear facilities from 2024 through 2032. The PTC is expected to provide downside price protection for our nuclear generation fleet as the tax credit value is directly linked to a nuclear facility’s gross receipts.
For the years 2024-2028, our regulated capital investment program is estimated to be in a range of $18 billion to $21 billion. We expect these capital investments to result in a compound annual growth rate in our regulated rate base in a range of 6% to 7.5% from year-end 2023 to year-end 2028. The regulated capital investments represent the majority of PSEG’s total capital investment program of $19 billion to $22.5 billion. The low end of the range includes an extension of our Gas System Modernization Program (GSMP) and Clean Energy Future (CEF)-EE program at their current average annual investment levels plus inflation, as these programs are expected to continue beyond their currently approved timeframes. The upper end of our capital investment range includes incremental investments, particularly for an expansion of our current EE programs as well as other clean energy and infrastructure investments.
PSE&G
At PSE&G, our focus is on investing capital in T&D infrastructure and clean energy programs to enhance the reliability and resiliency of our T&D system, meet customer expectations and support public policy objectives.
During 2023, the BPU approved a $280 million nine-month extension of our CEF-EE program through June 2024 and a two-year extension of our current GSMP program to replace at least 400 miles of cast iron and unprotected steel mains and services in our gas system. The GSMP program extension provides for main replacement through December 2025 plus trailing services replacement and paving costs into 2026 and totals approximately $900 million of investment. Of the $900 million, $750 million is recovered through three periodic rate updates with the balance recovered through a future distribution base rate case.
Our broader GSMP III, which also included projects to introduce renewable natural gas and hydrogen blending into our existing distribution system is being held in abeyance, with negotiations reinitiated by January 2025 with the intent of beginning the work in January 2026. A remaining component of our CEF-Electric Vehicle (EV) program related to medium- and heavy-duty charging infrastructure has been the subject of a stakeholder process that the BPU began in 2021 and we expect that this effort will result in PSE&G submitting a filing targeting infrastructure investments for the medium-and heavy-duty EV market in 2024. In September 2022, the BPU released a draft Storage Incentive Program proposal and is currently undertaking a stakeholder process to determine the details of the program. In the meantime, our CEF-Energy Storage (ES) program is being held in abeyance.
In November 2023, we filed for a second extension of our CEF-EE program, which would cover a commitment period of six months from July 2024 through December 2024 for approximately $300 million. In December 2023, we filed for our CEF-EE II program, which proposed a $3.1 billion investment for a second program cycle covering commitments from January 2018, PSE&G2025 through June 2027, with investments being made over a six-year period. This EE filing is a significant increase from our prior filings, driven by an increase in the savings targets required under the BPU Energy Efficiency Framework and higher costs to achieve those targeted savings. The filing also includes demand response programs and building decarbonization programs. The CEF-EE extension filing is expected to be resolved in the first half of 2024 and the EE II filing is expected to be resolved in the second half of 2024.
Pursuant to our GSMP II and Energy Strong II programs, we filed a distribution base rate case as required by the BPU in December 2023. Among other things, the distribution base rate case will seek to recover capital expenditures associated with our infrastructure investment programs that are not already in rates, as a conditionwell as the Advanced Metering Infrastructure (AMI) and EV programs, other investments that are not recovered through periodic rate roll-ins, and several other cost and return factors.
The filing requestsproposes an approximate one percentoverall revenue increase in revenues and seeks to recover investments made to strengthenof 9% with a 12% increase for the combined typical residential electric and gas customer. We expect to conclude the distribution systems. Inbase rate case later in 2024.
PSEG Power
At PSEG Power, we seek to produce low-cost, reliable and resilient electricity by efficiently operating our nuclear generation assets, mitigate earnings volatility through the PTC mechanism and hedging, and support public policies that preserve these existing carbon-free base load nuclear generating plants. During 2023, our nuclear units generated approximately 32 terawatt hours and operated at a capacity factor of approximately 93%. As of the end of 2023, PSEG Power has hedged approximately 90% to 95% of its filing, expected generation output for 2024. Beginning in 2024, our hedging strategy will incorporate an estimated range of risk reduction impacts from the PTCs on our nuclear generation portfolio. This is expected to result in changes to our current approach given PTC guidance uncertainty, and potential incremental changes upon final U.S. Treasury guidance.
Climate Strategy and Sustainability Efforts
For more than a century, our purpose has been to provide safe access to an around-the-clock supply of reliable, affordable energy. Today, our vision is to power a future where people use less energy, and it is cleaner, safer and delivered more reliably than ever. We have established a net zero greenhouse gas (GHG) emissions by 2030 goal that includes direct GHG emissions (Scope 1) and indirect GHG emissions from operations (Scope 2) across our business operations, assuming advances in technology, public policy and customer behavior. Scope 1 emissions include power generation, fuel combustion at PSEG facilities, methane leaks, vehicle fleet emissions, sulfur hexafluoride emissions, and refrigerant leaks. Scope 2 emissions include purchased electric and steam energy for our PSEG facilities and emissions associated with line losses. Consistent with our commitment to the United Nations-backed Race to Zero campaign, we had submitted proposed targets encompassing Scopes 1, 2 and 3 emissions to the Science-Based Targets initiative (SBTi). SBTi recently informed us that they have rejected our submittal because, while our Scope 1 and 2 and Scope 3 electric targets meet requirements to proceed to the validation process, our Scope 3 natural gas target aligns with a Well Below 2C temperature scenario, rather than a more ambitious 1.5C scenario.
PSE&G requestedhas undertaken a number of initiatives that these rates takesupport the reduction of GHG emissions and the implementation of EE initiatives. PSE&G’s approved CEF-EE, CEF-Energy Cloud and CEF-EV programs and the proposed CEF-ES and CEF-EE II programs are intended to support New Jersey’s Energy Master Plan and recent Gubernatorial Executive Orders through programs designed to help customers use energy more efficiently, reduce GHG emissions, support the expansion of the EV infrastructure in New Jersey, install energy storage capacity to supplement solar generation and enhance grid resiliency, install smart meters and supporting infrastructure to allow for the integration of other clean energy technologies and to more efficiently respond to weather and other outage events.
In addition, PSE&G is committed to the safe and reliable delivery of natural gas to approximately 1.9 million customers throughout New Jersey and we are equally committed to reducing GHG emissions associated with such operations. The first phase of our GSMP replaced approximately 450 miles of cast-iron and unprotected steel gas main infrastructure, and the second phase of this program replaced an additional 1,090 miles of gas pipes and was completed in the first quarter of 2023. As mentioned above, the BPU approved a two-year extension of GSMP in October 2023. The GSMP is designed to significantly reduce natural gas leaks in our distribution system, which would reduce the release of methane, a potent GHG, into account athe air. Through GSMP II, from 2018 through 2023 we reduced methane leaks by approximately 22% system wide and assuming continuation of GSMP, we expect to achieve an overall reduction in methane emissions of at least 60% over the revenue requirement as a2011 baselinethrough 2030 period. We also continue to assess physical risks of climate change and adapt our capital investment program to improve the reliability and resiliency of our system in an environment of increasing frequency and severity of weather events, notably through our investments in our Energy Strong program and Infrastructure Advancement Program and our investments in transmission infrastructure upgrades. These investments have shown benefits in recent severe weather events, including Tropical Storm Ida in 2021, which brought significant flooding to our service territory but did not result in the loss of any of our electric distribution substations.
We also continue to focus on providing cleaner energy for our customers by working to preserve the economic viability of our nuclear units, which provide over 85% of the carbon-free energy in New Jersey. These efforts include reducing market risk by advocating for state and federal corporate income tax rate reduction from 35%policies, such as the PTC established by the IRA, and capacity market reform at PJM that recognize the value of our nuclear fleet’s carbon-free generation and its contribution to 21% providedgrid reliability.
Offshore Wind
In May 2023, PSEG sold to Ørsted North America Inc. (Ørsted) its 25% equity interest in new tax legislation enactedOcean Wind JV HoldCo, LLC. The sale proceeds approximated PSEG’s carrying value of the investment; therefore, no material gain or loss was recognized upon disposition.
Additionally, PSEG and Ørsted each owns 50% of Garden State Offshore Energy LLC (GSOE) which holds rights to an offshore wind lease area just south of New Jersey.PSEG is evaluating its options for the potential sale of its interest in GSOE.
Competitively Bid, FERC Regulated Transmission Projects
PSEG continues to evaluate investment opportunities in regulated transmission beyond PSE&G.In December 2017 (Tax Act), including2023, PJM awarded a one-time credit for estimated excess income taxes collected between January 1, 2018subsidiary of Energy Holdings an approximately $424 million project to address increasing load and the time new rates go into effect, and the flow-backreliability issues in Maryland as part of its 2022 Window 3 competitive solicitation. The project has an expected in-service date of 2027.
We also continue to customers of certain additional tax benefits. PSE&G anticipates the new base rates will take effectevaluate regulated transmission opportunities to support offshore wind development in the fourth quarter of 2018.
Separately, in January 2018, New Jersey area. In April 2023,the BPU issued an order commencingrequesting that PJM conduct a proceedingsecond public policy transmission solicitation process utilizing the State Agreement Approach for transmission projects to ensuresupport New Jersey’s expanded offshore wind goal. The solicitation will seek to procure both onshore and offshore transmission solutions. PJM stated that the rate revenue resulting from expenses relatingsolicitation process is tentatively expected to taxes reflectedcommence in rates but no longer owed as the result of the Tax Act shall be passed onto the ratepayers. The BPU directed New Jersey utilities (including PSE&G) to make filings by March 2, 2018 setting forth interim rates to be effective April 1, 2018, reflecting the new federal corporate tax rate, and to subsequently file proposed final rates, effective July 1, 2018, incorporating all other effects of the Tax Act. This proceeding is currently pending.2024.
As a result of the enactment of the Tax Act, various state regulatory authorities, includingIn November 2023, the BPU have taken actionissued an order directing its staff to ensure that excess federal income taxes previously collected in ratesconduct a solicitation for “pre-build infrastructure” to support landing and routing of underground transmission cables of future offshore wind projects. PSEG is evaluating this opportunity and may submit a bid or bids into the solicitation.
Financial Results
The financial results for PSEG, PSE&G and PSEG Power & Other for the years ended December 31, 2023 and 2022 are returned to ratepayers. We have made filings to adjust the revenue requirement in certainpresented as follows:
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| | | Years Ended December 31, | |
| | | 2023 | | 2022 | |
| | | Millions, except per share data | |
| PSE&G | | $ | 1,515 | | | $ | 1,565 | | |
| PSEG Power & Other | | 1,048 | | | (534) | | |
| PSEG Net Income | | $ | 2,563 | | | $ | 1,031 | | |
| | | | | | |
| PSEG Net Income Per Share (Diluted) | | $ | 5.13 | | | $ | 2.06 | | |
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For a detailed discussion of our rate matters as a resultfinancial results, see Results of the change in federal income tax rate. We continue to assess whether any further action needs to be taken by the company at this time.
For additional information on our specific filings, see Item 8. Financial Statements and Supplementary Data—Note 6. Regulatory Assets and Liabilities.
Power manages its existing firm pipeline transportation contracts for the benefit of PSE&G’s customers through the basic gas supply service (BGSS) arrangement. The contracts are sized to provide for delivery of a reliable gas supply to PSE&G customers on peak winter days. When pipeline capacity beyond the customers’ needs is available, Power may use it to make third-party sales and supply gas to its generating units in New Jersey. Alternatively, gas supply and pipeline capacity constraints could adversely impact our ability to meet the needs of our utility customers and generating units. Power’s hedging practices and ability to capitalize on market opportunities help it to balance some of the volatility of the merchant power business. More than half of Power’s expected gross margin in 2018 relates to our hedging strategy, our expected revenues from the capacity market mechanisms and certain ancillary service payments such as reactive power.
Our investments in Keys Energy Center (Keys), Sewaren 7 and Bridgeport Harbor Station 5 (BH5) reflect our recognition of the value of opportunistic growth in the Power business. See Item 1. Business—Power for additional information on major growth projects. These additions to our fleet both expand our geographic diversity and adjust our fuel mix and are expected to contribute to the overall efficiency of operations.
Since 2013, several nuclear generating stations in the United States have closed or announced early retirement due to economic reasons, or have announced being at risk for early retirement. Most recently, in February 2018, Exelon, a co-owner of the Salem units, announced its intention to accelerate the closure of its Oyster Creek nuclear plant located in New Jersey, one year earlier than previously planned for economic reasons. These closures and retirements are generally due to the decline in market prices of energy, resulting from low natural gas prices driven by the growth of shale gas production since 2007, the continuing cost of regulatory compliance and enhanced security for nuclear facilities, both federal and state-level policies that provide financial incentives to construct renewable energy such as wind and solar and the failure to adequately compensate nuclear generating stations for the attributes they bring similar to renewable energy production. These trends have significantly reduced the revenues of nuclear generating stations while limiting their ability to reduce the unit cost of production. This may result in the electric generation industry experiencing a further shift from nuclear generation to natural gas-fired generation, creating less diversity of the generation fleet.
If any or all of the Salem and Hope Creek units were shut down, it would significantly alter New Jersey’s energy supply predominately by increasing New Jersey’s reliance on natural gas generation. Such a decrease in fuel diversity could also increase the market’s vulnerability to price fluctuations and power disruptions in times of high demand. The New Jersey Legislature is assessing legislation that would provide a safety net in order to prevent the loss of environmental attributes from nuclear generating stations. We cannot predict whether the legislation will be enacted or, if enacted, whether our nuclear generating stations in New Jersey will be selected or whether the legislation will provide a sufficient safety net for the continued operation of nuclear generating stations in New Jersey.
In the ordinary course, management, and in the case of the Salem units the co-owner, each makes a number of decisions that impact the operation of our nuclear units beyond the current year, including whether and to what extent these units participate in RPM capacity auctions, commitments relating to refueling outages and significant capital expenditures, and decisions regarding our hedging arrangements. When considering whether to make these future commitments, management’s decisions will primarily be influenced by the financial outlook of the units, including the progress, timing and continued outlook for enactment of proposed legislation in the state of New Jersey.
If market prices continue to be depressed and legislation is not enacted that adequately compensates nuclear generating stations for their attributes, Power anticipates it will no longer be covering its costs nor be adequately compensated for its market and operational risks at the Salem and Hope Creek nuclear units and would anticipate retiring these units early. The costs associated with any such retirement, which may include, among other things, accelerated depreciation and amortization or impairment charges, accelerated asset retirement costs, severance costs, environmental remediation costs and additional funding of the Nuclear Decommissioning Trust Fund (NDT) would be material to both PSEG and Power.Operations.
Regulatory, Legislative and Other Developments
In our pursuit of operational excellence, financial strength and disciplined investment, weWe closely monitor and engage with stakeholders on significant regulatory and legislative developments.
Transmission planningRate Proceedings and Return on Equity (ROE)
Under current FERC rules, PSE&G continues to earn a 50 basis point adder to its base ROE for its membership in PJM as a transmission owner. In April 2021, FERC proposed eliminating this ROE adder for Regional Transmission Owner participation. FERC has not acted on the proposal. If the adder was eliminated, it would reduce PSE&G’s annual Net Income and wholesale power market design areannual cash inflows by approximately $40 million.
New Jersey Stakeholder Proceedings
In February 2023, the governor of particular importanceNew Jersey issued executive orders (EOs) that establish or accelerate previously established 2050 targets for clean-sourced energy, building decarbonization, and EV adoption goals, with new target dates of 2030 or 2035, as applicable. The EOs direct the BPU and other state agencies to our results and we continuecollaborate with stakeholders to advocate for policies and rules that promote fair and efficient electricity markets.
Transmission Planning
There are several matters pending before FERCdevelop plans to reach the targets and the U. S. CourtBPU has convened a stakeholder proceeding to develop a plan for gas distribution utilities to reach the target of Appeals for50% natural gas emissions reductions over 2006 levels by 2030. We are unable to predict the Districtoutcomes of Columbia Circuit that concern the allocation of costs associated with transmission projects being constructed by PSE&G. Regardless of how these proceedings are resolved, PSE&G’s ability to recover the costs of these projects will not be affected. However, the result of these proceedingsthis proceeding, but it could ultimately impact the amount of costs borne by ratepayers in New Jersey. In addition, as a basic generation service (BGS) supplier, Power provides services that include specified transmission costs. If the allocation of the costs associated with the transmission projects were to increase these BGS-related transmission costs, BGS suppliers may be entitled to recovery, subject to BPU approval. We do not believe that these matters will have a material effectimpact on Power’sour business, or results of operations.
Several complaints have been filedoperations and several remain pending at FERC against transmission owners around the country, challenging those transmission owners’ base return on equity (ROE). Certain of those complaints have resulted in decisions and others have been settled, resulting in reductions of those transmission owners’ base ROEs. The results of these other proceedings could set precedents for other transmission owners with formula rates in place, including PSE&G.
Wholesale Power Market Design
Capacity market design, including the Reliability Pricing Model (RPM) in PJM, remains an important focus for us. During 2015, PJM implemented a new “Capacity Performance” (CP) mechanism that created a more robust capacity product with enhanced incentives for performance during emergency conditions and significant penalties for non-performance. The CP product was implemented fully in the May 2017 RPM auction for the 2020-2021 Delivery Year. Subsequent to its implementation, FERC approved changes to the CP construct that will enhance the participation of intermittent and demand response resources (seasonal resources). However, two complaints remain pending that ask FERC to investigate the rules governing the participation of seasonal resources and extend the participation of the base resources for future auctions.
In May 2017, PJM announced the results of the RPM capacity auction for the 2020-2021 Delivery Year. Power cleared approximately 7,800 MW of its generating capacity at an average price of $174 per MW-day for the 2020-2021 delivery period. In the two prior capacity auctions covering the 2019-2020 and 2018-2019 delivery years, Power cleared approximately 8,900 MW at an average price of $116 per MW-day and approximately 8,700 MW at an average price of $215 per MW-day, respectively. Prices in the most recent auction reflect PJM’s downwardly-revised demand forecast, changes in the emergency transfer limits due to transmission expansion and the effects of both the new generation and uncleared generation from the prior year’s auction.
As a result of the efforts of certain entities in PJM to obtain financial support arrangements from their state commissions, a group of suppliers requested that FERC direct PJM to expand the currently effective “minimum offer price rule” to apply to certain existing units seeking subsidies. The suppliers’ request was intended to avoid a scenario where the subsidized generators would submit bids into the PJM capacity market that did not reflect their actual costs of operation and could artificially suppress capacity market prices. We are currently awaiting FERC action on the suppliers’ request and cannot predict the outcome of the proceeding.
In June 2017, PJM issued an energy price formation proposal to address a flaw in the energy market in which energy prices during off-peak periods often do not reflect the production costs of generators during these periods even though they are serving load. PJM’s proposal would allow large, inflexible units to set price. If placed into effect, this proposal will improve price formation by ensuring that the marginal costs of units serving load will be better reflected in clearing prices. We cannot predict the outcome of this matter.
See Item 1. Business—Federal Regulation for additional information.
Distribution
The BPU has enacted IIP regulations that allow utilities to construct, install, or remediate utility plant and facilities related to reliability, resiliency, and/or safety to support the provision of safe and adequate service. Under these regulations, utilities can seek authority to make specified infrastructure investments in programs extending for up to five years with accelerated cost recovery mechanisms. The BPU characterized the IIP regulations as a regulatory initiative intended to create a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing infrastructure that enhances reliability, resiliency, and/or safety. cash flows.
Environmental Regulation
We continue to advocate for the development and implementation of fair and reasonable rules by the EPA and state environmental regulators. In particular, section 316(b) of the Federal Water Pollution Control Act requires that cooling water intake structures, which are a significant part of the generation of electricity at steam-electric generating stations, reflect the
best technology available for minimizing adverse environmental impacts. Implementation of Section 316(b) and related state regulations could adversely impact future nuclear and fossil operations and costs.
In March 2017, the President of the United States issued an Executive Order that instructed the EPA to review the New Source Performance Standards that establish emissions standards for CO2 for certain new fossil power plants, and the Clean Power Plan (CPP), a greenhouse gas emissions regulation under the Clean Air Act for existing power plants that establishes state-specific emission rate targets based on implementation of the best system of emission reduction. In October 2017, the EPA Administrator signed a proposed repeal of the CPP. The EPA Administrator concluded that the CPP exceeds the EPA’s statutory authority by considering measures that are beyond the control of the owners of the affected sources (fossil fuel-fired electric generating units). The EPA is considering rulemaking to replace the CPP. PSEG cannot assess the impact of any such rulemaking on its business and future results of operations at this time.
We are subject to liability under environmental laws for the costs and penalties 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 Federalfederal and Statestate agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of variousstatutes. In addition, PSEG Power has retained ownership of certain liabilities excluded from the sale of its fossil generation portfolio, primarily related to obligations under New Jersey and Connecticut state law to investigate and remediate the sites. 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 and penalties of any such remediation efforts could be material.
For further information regarding the matters described above, as well as other matters that may impact our financial condition and results of operations, see Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities.
FERC Compliance
Since September 2014, FERC Staff has been conducting a preliminary non-public investigation regarding errors in the calculation of certain components of Power’s cost-based bids for its New Jersey fossil generating units in the PJM energy market and the quantity of energy that Power offered into the energy market for its fossil peaking units compared to the amounts for which Power was compensated in the capacity market for those units. While considerable uncertainty remains as to the final resolution of these matters, based upon developments in the investigation in the first quarter of 2017, Power believes the disgorgement and interest costs related to the cost-based bidding matter may range between approximately $35 million and $135 million, depending on the legal interpretation of the principles under the PJM Tariff, plus penalties. Since no point within this range is more likely than any other, Power has accrued the low end of this range of $35 million by recording an additional pre-tax charge to income of $10 million during the three months ended March 31, 2017. PSEG is unable to reasonably estimate the range of possible loss, if any, for the quantity of energy offered matter or the penalties that FERC would impose relating to either the cost-based bidding or quantity of energy matter. However, any of these amounts could be individually material to PSEG and Power. We cannot predict the final outcome of these matters. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities.
Early RetirementNuclear
In April 2021, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded zero emission certificates (ZECs) for the three-year eligibility period starting June 2022 at the same approximate $10 per megawatt hour (MWh) received during the prior ZEC period through May 2022. Pursuant to a process established by the BPU, ZECs are purchased from selected nuclear plants and recovered through a non-bypassable distribution charge in the amount of Hudson$0.004 per kilowatt-hour used (which is equivalent to approximately $10 per MWh generated in payments to selected nuclear plants (ZEC payment)). As previously noted, in August 2022, the IRA was signed into law expanding incentives promoting carbon-free generation. The enacted legislation established the PTC for electricity generation using existing nuclear energy set to begin January 1, 2024 and Mercer Units
On June 1, 2017, Power completed its previously announced retirementcontinue through 2032. The expected PTC rate is up to $15/MWh subject to adjustment based upon a facility’s gross receipts. The PTC rate and the gross receipts threshold are subject to annual inflation adjustments. The establishment of the generation operationsPTC impacted PSEG Power’s decision not to apply for the next ZEC three-year eligibility period starting June 2025. We continue to analyze the impact of the existing coal/gasIRA on our nuclear units, and will analyze any future guidance from the U.S. Treasury to assess any impact of PTCs on expected ZEC payments and/or any future ZEC application periods.
Pension and Interest Rate Matters
In February 2023, PSE&G received an accounting order from the BPU authorizing PSE&G to modify its method for calculating the amortization of the net actuarial gain or loss component of pension expense for ratemaking purposes. This order mitigates some of the volatility in earnings and customer rates related to our pension trust performance and became effective for calendar year 2023 and forward.
In July 2023, PSEG and Fiduciary Counselors Inc., as independent fiduciary of the Pension Plan I and Pension Plan II (Plans), entered into a commitment agreement ( for a “lift-out”) with The Prudential Insurance Company of America (the Insurer) under which the Plans agreed to purchase a group annuity contract that would transfer to the Insurer approximately $1 billion of the Plans’ defined benefit pension obligations and associated Plan assets related to certain pension benefits covering approximately 2,000 retirees from PSEG Power & Other. In August 2023, assets were transferred to the Insurer and the transaction was closed, which reduces future volatility due to lowering our pension assets and liabilities. See Item 8. Note 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plans for additional information.
Federal Reserve policy to reduce inflation has resulted in a higher interest rate environment which may persist as the Federal Reserve continues to assess the economic outlook. If it persists, higher interest rates on borrowings will contribute to higher interest expense on variable-rate debt and long-term rates on future financing plans. As of December 31, 2023, PSEG had entered into floating-to-fixed interest rate swaps totaling $1.4 billion in order to reduce the volatility in interest expense related to $900 million of a $1.25 billion variable rate term loan at the HudsonPSEG Power due March 2025 and Mercer generating stations. The decisionPSEG’s $500 million variable rate term loan due April 2024. PSE&G’s interest rate risk is moderated due to retire the Hudsonannual transmission rate filings and Mercer units haddistribution recoveries through base rate filings and clause-based investment programs.
Tax Legislation
Future federal and state tax legislation and clarification of enacted legislation could have a material effectimpact on our effective tax rate and cash tax position.
In April 2023, the U.S. Treasury issued Revenue Procedure 2023-15 that provides a safe harbor method of accounting to determine the annual repair tax deduction for gas T&D property. The impact, if any, this may have on PSEG and PSE&G’s financial statements has not yet been determined.
The IRA enacted a new 15% corporate alternative minimum tax (CAMT), effective in 2023, a PTC for existing nuclear generation facilities and allows energy tax credits to be transferable. The U.S. Treasury has issued proposed regulations and several Notices pertaining to the CAMT and the prevailing wage and transferability rules of energy tax credits. Many aspects of the IRA remain unclear and in need of further guidance; therefore, we continue to analyze the impact the IRA will have on PSEG’s and Power’sPSE&G’s results of operations, in 2016financial condition and continued to adversely impact their results of operations in 2017. As of June 1, 2017, Power completed recognition of the incremental Depreciation and Amortization (D&A) of $938 million ($964 million in total) due to the significant shortening of the expected economic useful lives of Hudson and Mercer. During 2017, Energy Costs of $15 million and Operation and Maintenance (O&M) of $23 million were also incurred. See Item 8. Financial Statements and Supplementary Data—Note 3. Early Plant Retirements for additional information.
Power is exploring various opportunities with these sites, including using the sites for alternative industrial activity or the disposition of one or both of the sites. If Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would trigger obligations under certain environmental regulations, including possible remediation. The amounts for any such remediation are neither currently probable nor estimable but may be material.
In addition, PSEG and Power continue to monitor their other coal assets, including the Keystone and Conemaugh generating stations, to assess their economic viability through the end of their designated useful lives and their continued classification as held for use. The precise timing of a change in useful lives may be dependent upon events out of PSEG’s and Power’s control and may impact their ability to operate or maintain certain assets in the future. These generating stations may be impacted by factors such as environmental legislation, co-owner capital requirements and continued depressed wholesale power prices or capacity factors, among other things. Any early retirement or change in the classification as held for use of our remaining coal units may have a material adverse impact on PSEG’s and Power’s future financial results.
Leveraged Lease Impairments
GenOn Energy, Inc. (GenOn) and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code on June 14, 2017. NRG REMA, LLC (REMA) was not included in the GenOn bankruptcy filing. GenOn is currently engaged in a balance sheet restructuring,cash flows, which will take an undetermined time to complete. PSEG cannot predict the outcome of GenOn’s efforts to restructure its balance sheet and improve its liquidity.
During the first quarter of 2017, due to continuing liquidity issues facing REMA, economic challenges facing coal generation in PJM, and based upon an ongoing review of available alternatives as well as discussions with REMA management, Energy Holdings recorded an additional $55 million pre-tax charge for its current best estimate of loss relating to its REMA leveraged lease receivables, which was reflected in Operating Revenues. During the second quarter of 2017, Energy Holdings recorded an additional $22 million pre-tax charge for its current best estimate of loss related to lease receivables due to collectability of payments ($15 million) and economics impacting the residual value ($7 million) of certain leased assets. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments, which could include further write-downs of the values of Energy Holdings’ leveraged lease receivables, and continue to discuss the situation with various parties relevant to this matter. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 7. Long-Term Investments and Note 8. Financing Receivables. There can be no assurance that a continuation or worsening of the adverse economic conditions would not lead to additional write-downs at any of our other generation units in our leveraged lease portfolio, and such write-downs could be material.
Additional facilities in our leveraged lease portfolio include the Joliet and Powerton generating facilities. Similar to Shawville, Joliet was recently converted to use natural gas. Converted natural gas units such as Shawville and Joliet may have higher operating costs and fuel consumption as well as longer start-up times compared to newer combined cycle gas units. Powerton is a coal-fired generating facility in Illinois. Each of these three facilities may not be as economically competitive as newer combined cycle gas units and could continue to be adversely impacted by the same economic conditions experienced by other less efficient natural gas and coal generation facilities, which could require Energy Holdings to write down the residual value of the leveraged lease receivables associated with these facilities.
Tax Legislation
In December 2017, the U.S. government enacted comprehensive tax legislation (Tax Act), which, among other things, decreased the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018, and made certain changes to bonus depreciation rules.
As a result of the enacted reduction in the statutory U.S. corporate income tax rate, as well as other aspects of the Tax Act, we have recorded a one-time, non-cash earnings benefit of $745 million, including $588 million related to Power and $147 million related to Energy Holdings. This benefit is primarily due to the remeasurement of deferred tax balances. In addition, PSE&G had excess deferred taxes of approximately $2.1 billion as of December 31, 2017 and recorded an approximate $2.9 billion revenue impact of these excess deferred taxes as Regulatory Liabilities where it is probable that refunds will be made to customers in future rates. The amount and timing of any such refund cannot be determined at this time.
Beginning in 2018, PSEG, on a consolidated basis, will incur lower income tax expense resulting in a decrease in its projected effective income tax rate. This is also expected to increase PSEG’s and Power’s net income. To the extent allowed under the Tax Act, Power’s operating cash flows will reflect the full expensing of capital investments for income tax purposes. PSEG and Power expect that the interest on their debt will continue to be fully tax deductible albeit at a lower tax rate. For PSE&G, the Tax Act is expected to lead to lower customer rates due to lower income tax expense recoveries and the refund of deferred income tax regulatory liabilities, partially offset by the impacts of higher rate base. The impact of the lower federal income tax rate on PSE&G was reflected in PSE&G’s recently filed distribution base rate case and its transmission formula rate filings. The Tax Act is generally expected to result in lower operating cash flows for PSE&G resulting from the elimination of bonus depreciation, partially offset by higher revenues due to the higher rate base. The full impact of these and other provisions of the Tax Act cannot be determined at this time.
The impact of the Tax Act may differ from these estimates, possibly materially, due to, among other things, changes in interpretations and assumptions PSEG has made, guidance that may be issued and actions PSEG may take as a result of the Tax Act. For additional information, see Note 20. Income Taxes.
Operational Excellence
We emphasize operational performance while developing opportunities in both our competitive and regulated businesses. Flexibility in our generating fleet has allowed us to take advantage of opportunities in a rapidly evolving market as we remain diligent in managing costs. In 2017, our
diverse fuel mix and dispatch flexibility allowed us to generate approximately 51 terra-watt hours while addressing
fuel availability and price volatility,
total nuclear fleet achieved an average capacity factor of 94%, and
utility was recognized for the sixteenth consecutive year as the most reliable utility in the Mid-Atlantic region.
Financial Strength
Our financial strength is predicated on a solid balance sheet, positive operating cash flow and reasonable risk-adjusted returns on increased investment. Our financial position remained strong during 2017 as we:
maintained sufficient liquidity,
maintained solid investment grade credit ratings, and
increased our indicative annual dividend for 2017 to $1.72 per share.
We expect to be able to fund our planned capital requirements, as described in Liquidity and Capital Resources, and manage the impacts of the Tax Act without the issuance of new equity.
Disciplined Investment
We utilize rigorous investment criteria when deploying capital and seek to invest in areas that complement our existing business and provide reasonable risk-adjusted returns. These areas include upgrading our energy infrastructure, responding to trends in environmental protection and providing new energy supplies in domestic markets with growing demand. In 2017, we
made additional investments in transmission infrastructure projects,
continued to execute our GSMP, Energy Strong, Energy Efficiency, solar and other existing BPU-approved utility programs,
continued construction of our Keys and Sewaren 7 generation projects for targeted commercial operation in 2018 and commenced construction of our BH5 generation project for targeted commercial operation in mid-2019, and
acquired six solar energy projects in various states totaling 88 MW-direct current (dc), for a total of 414 MW (dc) of installed capacity in 14 states throughout the U.S.
Future Outlook
Our future success will depend on our ability to continue to maintain strong operational and financial performance, in a slow-growing economy and a cost-constrained environment with low gas prices, to capitalize on or otherwise address appropriately regulatory and legislative developments that impact our business and to respond to the issues and challenges described below. In order to do this, we mustwill continue to:
focus•seek approval of and execute on controlling costs while maintaining safety and reliability and complying with applicable standards and requirements,
successfully manage our energy obligations and re-contract our open supply positions in response to changes in demand,
execute our utility capital investment program including our Energy Strong program, GSMP and other investments for growth that yield contemporaneous and reasonable risk-adjusted returns, while enhancing the resiliency ofto modernize our infrastructure, and maintainingimprove the reliability and resilience of the service we provide to our customers, and obtain approvalalign our sustainability and climate goals with New Jersey’s energy policy,
•seek a fair return for extension of theseour T&D investments through our transmission formula rate, existing rate incentives, distribution infrastructure and clean energy investment programs and periodic distribution base rate case proceedings,
effectively •focus on controlling costs while maintaining safety, reliability and customer satisfaction and complying with applicable standards and requirements,
•manage construction of our Keys, Sewaren 7, BH5the risks and other generation projects,opportunities in federal and state clean energy policies,
•advocate for measuresappropriate regulatory guidance on the federal nuclear PTC to ensure the implementation by PJMlong-term support for New Jersey’s largest carbon-free generation resource, and FERC of market design and transmission planning rules that continue to promote fair and efficient electricity markets,adapt our hedging program accordingly,
•engage constructively with our multiple stakeholders, including regulators, government officials, customers, employees, investors, suppliers and investors,the communities in which we do business, and
successfully operate•deliver on our human capital management strategy to attract, develop and retain a diverse, high-performing workforce.
In addition to the LIPA T&D system and manage LIPA’s fuel supply and generation dispatch obligations.
For 2018risks described elsewhere in this Form 10-K for 2023 and beyond, the key issues and challenges we expect our business to confront include:
•regulatory and political uncertainty, both with regard to transmission planning and rates policy, the role of distribution utilities and decarbonization impacts, future energy policy, tax regulations, design of energy and capacity markets, transmission policy and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other proceeding, settlement, investigation or claim, applicableproceedings,
•performance of the financial markets, including the impact on our pension and interest rates on our future financing plans,
•continuing to manage costs and maintain affordable customer rates in an inflationary environment, which could impact customer collections and future regulatory proceedings,
•the increasing frequency, sophistication and magnitude of cybersecurity attacks against us and our respective vendors and business partners who may have our sensitive information and/or the energy industry,
fair and timely rate relief from the BPU and FERC for recovery of costs and return on investments, including with respectaccess to our distribution base rate case which was filed withenvironment, and the BPUincreasing frequency and magnitude of physical attacks on electric and gas infrastructure,
•future changes in January 2018,federal and state tax laws or any other associated tax guidance, and
continuing discussions regarding •the restructuring of GenOn and REMA and its potential impact on the value of our Keystone, Conemaugh and Shawville leveraged leases,
the continuing impact of the Tax Act,
uncertainty in the national and regional economic recovery, continuing customer conservation efforts, changes in energy usage patterns and evolving technologies, which impact customer behaviors and demand,
the potential for continued reductions in demand and sustained lower natural gas and electricity prices, both at market hubs and expanded efforts to decarbonize several sectors of the locations where we operate,economy.
the impact of lower natural gas prices and increasing environmental compliance costs on the competitiveness of our nuclear and remaining coal-fired generation plants, and the potential for retirement of such plants earlier than their current useful lives,
delays and other obstacles that might arise in connection with the construction of our T&D, generation and other development projects, including in connection with permitting and regulatory approvals,
maintaining a diverse mix of fuels to mitigate risks associated with fuel price volatility and market demand cycles, and
FERC Staff’s continuing investigation of certain of Power’s New Jersey fossil generating unit bids in the PJM energy market.
Our primary investment opportunities are in two areas: our regulated utility business and our merchant power business. We continually assess a broad range of strategic options to maximize long-term stockholder value. In assessingshareholder value and address the interests of our options, wemultiple stakeholders. We consider a wide variety of factors when determining how and when to efficiently deploy capital, including the performance and prospects of our businesses; returns and the sustainability and predictability of future earnings streams; the views of investors, regulators, public policy initiatives, rating agencies, customers and rating agencies;employees; 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•investments in PSE&G, including T&D facilities and/or generation units,to enhance reliability, resiliency and modernize the system to meet the growing needs and increasingly higher expectations of customers, and clean energy investments such as CEF-EE, CEF-EV, CEF-ES and solar,
the disposition or reorganization•continued operation of our merchantnuclear generation business or other existing businesses orfacilities that are expected to be supported through the acquisition or developmentPTC through 2032 and can enable certain investments to increase the capacity of new businesses,the units as well as potential license extensions,
the expansion of our geographic footprint,
continued or expanded participation in solar, demand response and energy efficiency programs, and
•investments in capital improvementscompetitive, regulated transmission investments through PJM processes and additions, including the installation of environmental upgradesBPU solicitations that provide revenue predictability and retrofits, improvementsreasonable risk-adjusted returns, and
•acquisitions, dispositions, developmentand other transactions involving our common stock, assets or businesses that could provide value to system resiliency, modernizing existing infrastructurecustomers and participation in transmission projects through FERC’s “open window” solicitation process.
Power is developing a retail energy business to sell energy, which we believe complements our existing wholesale marketing business. Power began these marketing activities in 2017 and has been granted retail energy supplier licenses in New Jersey, Pennsylvania and Maryland.shareholders.
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
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| | | Years Ended December 31, | |
| | | 2023 | | 2022 | | 2021 | |
| Earnings (Losses) | | Millions, except per share data | |
| PSE&G | | $ | 1,515 | | | $ | 1,565 | | | $ | 1,446 | | |
| PSEG Power & Other (A)(B) | | 1,048 | | | (534) | | | (2,094) | | |
| PSEG Net Income (Loss) | | $ | 2,563 | | | $ | 1,031 | | | $ | (648) | | |
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| PSEG Net Income (Loss) Per Share (Diluted) | | $ | 5.13 | | | $ | 2.06 | | | $ | (1.29) | | |
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| | | Years Ended December 31, | |
| | | 2017 | | 2016 | | 2015 | |
| Earnings (Losses) | | Millions | |
| PSE&G | | $ | 973 |
| | $ | 889 |
| | $ | 787 |
| |
| Power (A)(B) | | 479 |
| | 18 |
| | 856 |
| |
| Other (B)(C) | | 122 |
| | (20 | ) | | 36 |
| |
| PSEG Net Income | | $ | 1,574 |
| | $ | 887 |
| | $ | 1,679 |
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| PSEG Net Income Per Share (Diluted) | | $ | 3.10 |
| | $ | 1.75 |
| | $ | 3.30 |
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(A)PSEG Power & Other results in 2023 include a $239 million after-tax pension charge due to the settlement of a portion of the qualified pension plans. PSEG Power & Other results in 2022 include after-tax impairments of $92 million related to certain Energy Holdings investments and additional adjustments related to the sale of PSEG Power’s fossil generation assets. PSEG Power & Other results in 2021 include an after-tax impairment loss and other associated charges, including debt extinguishment costs of $2,158 million related to the sale of PSEG Power’s fossil generation assets. See Item 8. Note 3. Asset Dispositions and Impairments for additional information.
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(A) | Power’s results in 2017 and 2016 include after-tax expenses of $577 million and $396 million, respectively, related to the early retirement of its Hudson and Mercer coal/gas generation plants. See Item 8. Financial Statements and Supplementary Data—Note 3. Early Plant Retirements for additional information. Power’s results in 2015 include an after-tax insurance recovery for Superstorm Sandy of $102 million. |
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(B) | Results in 2017(B)Other includes after-tax activities at the parent company, PSEG LI and Energy Holdings as well as intercompany eliminations. PSEG Power’s results above 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. |
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(C) | Other includes after-tax activities at the parent company, PSEG LI and Energy Holdings as well as intercompany eliminations. Energy Holdings recorded after-tax charges totaling $45 million and $92 million related to its investments in REMA’s leveraged leases in 2017 and 2016. See Item 8. Financial Statements and Supplementary Data—Note 7. Long-Term Investments and Note 8. Financing Receivables for further information. |
Our results include the realized gains, losses and earnings on Power’s Nuclear Decommissioning Trust (NDT) Fund activity and otherthe 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 (Loss) attributable to changes related to the NDT activity. RealizedFund and MTM are shown in the following table:
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| | | Years Ended December 31, | |
| | | 2023 | | 2022 | | 2021 | |
| | | Millions, after tax | |
| NDT Fund and Related Activity (A) (B) | | $ | 109 | | | $ | (174) | | | $ | 108 | | |
| Non-Trading MTM Gains (Losses) (C) | | $ | 959 | | | $ | (457) | | | $ | (446) | | |
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(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 are recorded in Net Other Income (Deductions), and impairments on certain NDT securities are recorded as Other-Than-Temporary Impairments. Interestinterest accretion expense on PSEG Power’s nuclear Asset Retirement Obligation (ARO) is recorded in O&MOperation & Maintenance (O&M) Expense and the depreciation related to the ARO asset is recorded in D&ADepreciation and Amortization (D&A) Expense.
Our results also include the after-tax impacts(B)Net of non-trading mark-to-market (MTM) activity, which consisttax (expense) benefit of the financial impact from positions with forward delivery dates.
The combined after-tax impact on Net Income$(74) million, $97 million and $(70) million for the years ended December 31, 2017, 20162023, 2022 and 2015 include2021, respectively.
(C)Net of tax (expense)benefit of $(376) million, $178 million and $174 million for the years ended December 31, 2023, 2022 and 2021, respectively.
Our increase in Net Income for 2023 as compared to 2022 was driven primarily by
•changes related toin the MTM and NDT Fund and MTM activityas shown in the chart below:table above, and
•higher earnings due to continued investments in T&D clause programs at PSE&G, |
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| | | | | | | | |
| Years Ended December 31, | | 2017 | | 2016 | | 2015 | |
| | | Millions, after tax | |
| NDT Fund and Related Activity (A) | | $ | 62 |
| | $ | — |
| | $ | 8 |
| |
| Non-Trading MTM Gains (Losses) (B) | | $ | (99 | ) | | $ | (100 | ) | | $ | 93 |
| |
| | | | | | | | |
| |
(A) | Net of tax (expense) benefit of $(72) million, $(5) million and $(16) million for the years ended December 31, 2017, 2016 and 2015, respectively. |
| |
(B) | Net of tax (expense) benefit of $68 million, $68 million and $(65) million for the years ended December 31, 2017, 2016 and 2015, respectively. |
The 2017 year-over-year increase•partially offset by a pension settlement charge in our Net Income was driven primarily by:
non-cash net income benefits related to new tax legislation (See2023 See Item 8. Financial StatementsNote 12. Pension, Other Postretirement Benefits (OPEB) and Supplementary Data—Note 20. Income Taxes) at PowerSavings Plans, and Energy Holdings,
higher transmission revenues,
higher net NDT gains•lower pension and other postretirement benefit (OPEB) credits in 2017, and
lower charges related to investments in certain leveraged leases at Energy Holdings (See Item 8. Financial Statements and Supplementary Data—Note 8. Financing Receivables).
These increases were partially offset by:
higher charges related to the early retirement of two coal/gas generation units at Power (See Item 8. Financial Statements and Supplementary Data—Note 3. Early Plant Retirements), and
lower volumes of energy sold at lower average realized sales prices under the BGS contracts and in the PJM and New England regions.
The 2016 year-over-year decrease in our Net Income was driven primarily by:
charges related to the early retirement of two coal/gas generation units at Power (See Item 8. Financial Statements and Supplementary Data—Note 3. Early Plant Retirements),
MTM losses in 2016 as compared to MTM gains in 2015,
lower volumes of energy sold at lower average realized sales prices,
lower capacity and operating reserve revenues in PJM,
higher 2016 congestion costs in PJM due primarily to realized gains on financial transmission rights (FTR) in PJM in the prior year due to extremely cold weather,
lower volumes of gas sold at lower average prices under the BGSS contract,
insurance recoveries received primarily by Power in 2015 related to Superstorm Sandy, and
an impairment related to investments in certain leveraged leases at Energy Holdings (See Item 8. Financial Statements and Supplementary Data—Note 8. Financing Receivables).
These decreases were partially offset by:
lower generation costs driven by lower fuel costs, particularly for natural gas, and reduced generation output at Power,
•higher costs incurred at Power for planned outages in 2015,
higher transmission revenues, and
higher management fee revenues at PSEG LI pursuant to the OSA.
PSEG2023.
Our results of operations are primarily comprised of the results of operations of our principal operating subsidiaries,segments, PSE&G and PSEG Power, excluding charges related to intercompany transactions, which are eliminated in consolidation. For additional information on intercompany transactions, see Item 8. Financial Statements and Supplementary Data—Note 24. Related-Party Transactions.
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | Increase / (Decrease) | | Increase / (Decrease) | |
| | | Years Ended December 31, | | |
| | | 2017 | | 2016 | | 2015 | | 2017 vs. 2016 | 2016 vs. 2015 | |
| | | Millions | | Millions | | % |
| | Millions | | % |
| |
| Operating Revenues | | $ | 9,084 |
| | $ | 9,061 |
| | $ | 10,415 |
| | $ | 23 |
| | — |
| | $ | (1,354 | ) | | (13 | ) | |
| Energy Costs | | 2,800 |
| | 3,001 |
| | 3,261 |
| | (201 | ) | | (7 | ) | | (260 | ) | | (8 | ) | |
| Operation and Maintenance | | 2,869 |
| | 3,008 |
| | 2,978 |
| | (139 | ) | | (5 | ) | | 30 |
| | 1 |
| |
| Depreciation and Amortization | | 1,986 |
| | 1,476 |
| | 1,214 |
| | 510 |
| | 35 |
| | 262 |
| | 22 |
| |
| Income from Equity Method Investments | | 14 |
| | 11 |
| | 12 |
| | 3 |
| | 27 |
| | (1 | ) | | (8 | ) | |
| Other Income (Deductions) | | 228 |
| | 124 |
| | 152 |
| | 104 |
| | 84 |
| | (28 | ) | | (18 | ) | |
| Other-Than-Temporary Impairments | | 12 |
| | 28 |
| | 53 |
| | (16 | ) | | (57 | ) | | (25 | ) | | (47 | ) | |
| Interest Expense | | 391 |
| | 385 |
| | 393 |
| | 6 |
| | 2 |
| | (8 | ) | | (2 | ) | |
| Income Tax (Benefit) Expense | | (306 | ) | | 411 |
| | 1,001 |
| | (717 | ) | | (174 | ) | | (590 | ) | | (59 | ) | |
| | | | | | | | | | | | | | | | |
PSEG | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | Increase / (Decrease) | | Increase / (Decrease) | |
| | | Years Ended December 31, | | |
| | | 2023 | | 2022 | | 2021 | | 2023 vs. 2022 | 2022 vs. 2021 | |
| | | Millions | | Millions | | % | | Millions | | % | |
| Operating Revenues | | $ | 11,237 | | | $ | 9,800 | | | $ | 9,722 | | | $ | 1,437 | | | 15 | | | $ | 78 | | | 1 | | |
| Energy Costs | | 3,260 | | | 4,018 | | | 3,499 | | | (758) | | | (19) | | | 519 | | | 15 | | |
| Operation and Maintenance | | 3,150 | | | 3,178 | | | 3,226 | | | (28) | | | (1) | | | (48) | | | (1) | | |
| Depreciation and Amortization | | 1,135 | | | 1,100 | | | 1,216 | | | 35 | | | 3 | | | (116) | | | (10) | | |
| Losses on Asset Dispositions and Impairments | | 7 | | | 123 | | | 2,637 | | | (116) | | | (94) | | | (2,514) | | | (95) | | |
| Income from Equity Method Investments | | 1 | | | 14 | | | 16 | | | (13) | | | (93) | | | (2) | | | (13) | | |
| Net Gains (Losses) on Trust Investments | | 189 | | | (265) | | | 194 | | | 454 | | | N/A | | (459) | | | N/A | |
| Net Other Income (Deductions) | | 172 | | | 124 | | | 98 | | | 48 | | | 39 | | | 26 | | | 27 | | |
| Net Non-Operating Pension and OPEB (Costs) Credits | | (218) | | | 376 | | | 328 | | | (594) | | | N/A | | 48 | | | 15 | | |
| Loss on Extinguishment of Debt | | — | | | — | | | (298) | | | — | | | N/A | | 298 | | | N/A | |
| Interest Expense | | 748 | | | 628 | | | 571 | | | 120 | | | 19 | | | 57 | | | 10 | | |
| Income Tax Expense (Benefit) | | 518 | | | (29) | | | (441) | | | 547 | | | N/A | | 412 | | | (93) | | |
| | | | | | | | | | | | | | | | |
The 2017, 20162023, 2022 and 20152021 amounts in the preceding table for Operating Revenues and O&M costs each include $438$533 million, $410$516 million and $375$511 million, respectively, for Servco.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. Financial Statements and Supplementary Data—Note 4. Variable Interest Entity for further explanation. The Income Tax Benefit in 2017 includes the non-cash benefit resulting from the remeasurement of deferred tax liabilities required due to the enactment of the Tax Act in December 2017.additional information. The following discussions for PSE&G and PSEG Power provide a detailed explanation of their respective variances.
PSE&G | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | Increase / (Decrease) | | Increase / (Decrease) | |
| | | 2023 | | 2022 | | 2021 | | 2023 vs. 2022 | 2022 vs. 2021 | |
| | | Millions | | Millions | | % | | Millions | | % | |
| Operating Revenues | | $ | 7,807 | | | $ | 7,935 | | | $ | 7,122 | | | $ | (128) | | | (2) | | | $ | 813 | | | 11 | | |
| Energy Costs | | 3,010 | | | 3,270 | | | 2,688 | | | (260) | | | (8) | | | 582 | | | 22 | | |
| Operation and Maintenance (A) | | 1,843 | | | 1,838 | | | 1,692 | | | 5 | | | — | | | 146 | | | 9 | | |
| Depreciation and Amortization | | 980 | | | 935 | | | 928 | | | 45 | | | 5 | | | 7 | | | 1 | | |
| Gain on Asset Dispositions | | — | | | — | | | (4) | | | — | | | — | | | 4 | | | N/A | |
| Net Gains (Losses) on Trust Investments | | — | | | (2) | | | 2 | | | 2 | | | N/A | | (4) | | | N/A | |
| Net Other Income (Deductions) | | 80 | | | 88 | | | 88 | | | (8) | | | (9) | | | — | | | — | | |
| Net Non-Operating Pension and OPEB Credits | | 114 | | | 281 | | | 264 | | | (167) | | | (59) | | | 17 | | | 6 | | |
| Interest Expense | | 493 | | | 427 | | | 402 | | | 66 | | | 15 | | | 25 | | | 6 | | |
| Income Tax Expense | | 160 | | | 267 | | | 324 | | | (107) | | | (40) | | | (57) | | | (18) | | |
| | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | Increase / (Decrease) | | Increase / (Decrease) | |
| | | 2017 | | 2016 | | 2015 | | 2017 vs. 2016 | 2016 vs. 2015 | |
| | | Millions | | Millions | | % |
| | Millions | | % |
| |
| Operating Revenues | | $ | 6,234 |
| | $ | 6,221 |
| | $ | 6,636 |
| | $ | 13 |
| | — |
| | $ | (415 | ) | | (6 | ) | |
| Energy Costs | | 2,363 |
| | 2,567 |
| | 2,722 |
| | (204 | ) | | (8 | ) | | (155 | ) | | (6 | ) | |
| Operation and Maintenance | | 1,434 |
| | 1,475 |
| | 1,560 |
| | (41 | ) | | (3 | ) | | (85 | ) | | (5 | ) | |
| Depreciation and Amortization | | 685 |
| | 565 |
| | 892 |
| | 120 |
| | 21 |
| | (327 | ) | | (37 | ) | |
| Other Income (Deductions) | | 87 |
| | 79 |
| | 75 |
| | 8 |
| | 10 |
| | 4 |
| | 5 |
| |
| Interest Expense | | 303 |
| | 289 |
| | 280 |
| | 14 |
| | 5 |
| | 9 |
| | 3 |
| |
| Income Tax Expense | | 563 |
| | 515 |
| | 470 |
| | 48 |
| | 9 |
| | 45 |
| | 10 |
| |
| | | | | | | | | | | | | | | | |
(A)Includes amortization of EE programs regulatory investment expenditures of $82 million, $48 million and $31 million for the years ended December 31, 2023, 2022 and 2021, respectively.Year Ended December 31, 20172023 as compared to 20162022
Operating Revenuesincreased$13 decreased $128 million due to changes in delivery, clause, commodity and other operating revenues.
Delivery Revenuesincreased$166 $184 million.
•Transmission revenues increased $112 million in revenue requirements attributable to higher rate base investment.
•Electric distribution and gas distribution revenues were $36 million higher due primarily to an increasea decrease in transmission revenues.the flowback to customers of excess deferred income tax liabilities and tax repair-related accumulated deferred income taxes, which is offset in Income Tax Expense.
Transmission•Electric distribution revenues were $152increased $22 millionhigher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.
$38 million from Conservation Incentive Program (CIP) decoupling revenues and $16 million from an Energy Strong II rate roll-in, partially offset by a $34 million decrease in sales volumes.
•Gas distribution revenues increased $30$14 million due primarily to a $16 million increase due to Energy Strong, $10increases of $39 million from inclusion of theadditional GSMP revenues in base rates $4and $24 million in higher collections of GPRC and an increase of $2 million due to higher sales volumes. These increases wereCIP decoupling revenues, partially offset by $50 million from lower Weather Normalization sales volumes.
Clause (WNC) revenues of $2 million.
Electric distribution revenuesRevenues decreased $16$80 million due primarily to a $28$48 million net decrease in sales volumeTax Adjustment Credits (TAC) and $14Green Program Recovery Charge (GPRC) deferrals and $33 million in lower collections of GPRC, partially offset by a $26 million increase in Energy Strong revenues.
Societal Benefits Clause Revenues increased $47 million due to the absence of the return in 2016 to customers of overcollections of Securitization Transition Charge (STC) revenues of $59 million and higher Margin Adjustment Clause (MAC) revenues of $4 million. These increases were partially offset by lower Societal Benefit Charges (SBC) of $17 million.collections. The changes in STC, MACTAC and GPRC deferrals and SBC amountscollections were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, D&A and Interest Expense.and Income Tax Expenses. PSE&G does not earn margin on STC,TAC and GPRC deferrals or on SBC Solar Pilot Recovery Charges (SPRC) or MAC collections.
Commodity Revenues decreased $204$289 million due to lower Gas revenues and Electric revenues partiallyrevenues. The changes in Commodity Revenues for both gas and electric are entirely offset by higher Gas revenues. This decrease is entirely offset with decreasedchanges in Energy Costs. PSE&G earns no margin on the provision of BGSbasic gas supply service (BGSS) and BGSSbasic generation service (BGS) to retail customers.
•Gas revenues decreased $254 million due to $133 million from lower BGSS sales volumes and $121 million from lower BGSS prices.
•Electric revenues decreased $274$35 million due primarily to $199 million in lower BGS revenues reflecting $109$64 million from lower BGS sales volumes, and $90 million from lower prices, $61 million in lower collections of Non-Utility Generation Charges (NGC) due primarily to lower prices and $14 million in lower revenues from the decreased sales volume of Non-Utility Generation (NUG) energy.
Gas revenues increased $70 million due to higher BGSS prices of $68 million and $2partially offset by $29 million from higher sales volumes.prices.
Other Operating Expenses
Energy Costs decreased $204 million. This is entirely offset by Commodity Revenues.
Operation and Maintenance decreased $41 million due to
a $28 million net reduction related to various clause mechanisms and GPRC expenditures,
a $15 million decrease in appliance service costs, and
a $7 million net decrease in pension and OPEB expenses, net of amounts capitalized,
partially offset by a $9 million net increase in other operating expenses.
Depreciation and Amortizationincreased$120 million due primarily to a $61 million net increase in amortization of Regulatory Assets, including the absence of the STC liability that ended in 2016, and an increase in depreciation of $59 million due to additional plant placed into service in 2017.
Other Income (Deductions)Revenues increased $8$57 million due primarily to a $7$45 million increase in Allowance for Funds Used During Construction (AFUDC).
Interest Expense increased $14Transition Renewable Energy Certificates (TREC) revenues, a $13 million primarily due to
$11 million due to net long-term debt issuancesincrease in 2016appliance service revenues, and a $9 million due to net long-term debt issuances in 2017,increase from the Successor Solar Incentive Program (SuSI), partially offset by an $18 million reduction in Solar Renewable Energy Credits (SREC) and ZEC revenues. The changes in TREC, SuSI, SREC and ZEC revenues are entirely offset by changes to Energy Costs.
a decrease of $6 million due to clause-related interest for BGSSOperating Expenses
Energy Costs decreased $260 million. This is offset by changes in 2016.Commodity Revenues and Other Operating Revenues.
Income Tax ExpenseOperation and Maintenance increased $48$5 million due primarily to increased amortization of EE programs regulatory investment expenditures and higher pre-tax income.T&D expenditures, partially offset by decreases in other clause related and various other operational expenses.
Year Ended December 31, 2016 as compared to 2015
Operating Revenues decreased $415 million due to changes in delivery, clause, commodityDepreciation and other operating revenues.
Delivery RevenuesAmortization increased $191$45 million due primarily to an increase in transmission revenues.
Transmission revenues were $223 million higherdepreciation due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.plant placed in service, partially offset by a net decrease in the amortization of Regulatory Assets and Liabilities.
Electric distribution revenuesNet Other Income (Deductions) decreased $27$8 million due primarily to $47lower Allowance for Funds Used During Construction and a reduction in solar loan interest income.
Net Non-Operating Pension and OPEB Credits decreased $167 million in lower collections of GPRC, partially offset bydue primarily to an $18$86 million increase in Energy Strong revenues.
Gas distribution revenues decreased $5interest cost, a $63 million due todecrease in the expected return on plan assets and a decrease of $43$62 million due to lower sales volumes and $7 million in lower collections of GPRC. These decreases were partially offset by higher WNC revenues of $25 million due to warmer weather in 2016 compared to 2015 and $20 million due to the inclusion of Energy Strong in base rates.
Clause Revenues decreased $445 million due to lower STC revenues of $419 million, lower SBC of $33 million and lower SPRC of $8 million. These decreases were partially offset by higher MAC revenues of $15 million. The changes in STC, SBC, SPRC and MAC amounts were entirely offset by changesdecrease in the amortization of related costs (Regulatory Assets)service credits, partially offset by a $47 million decrease in O&M, D&A and amortization of the net actuarial loss.
Interest Expense. PSE&G does not earn margin on STC, SBC, SPRC or MAC collections.
Commodity Revenues decreased $155Expense increased $66 million due primarily to lower Electriclong-term debt net issuances at higher rates in 2023 and Gas revenues. This is entirely offset withincremental issuances in 2022.
Income Tax Expense decreased Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.
Electric revenues decreased $136$107 million due to $73 million in lower collections of NGC due primarily to lower prices, $42 millionpre-tax income, an increase in lower revenuesthe flowback of excess deferred income tax benefits, an increase in tax benefits from the saleCEF program investments, and an increase in bad debt write-offs.
Year Ended December 31, 2022 as compared to 2021
See Item 7. Management’s Discussion and Analysis of NUG energyFinancial Condition and $21 millionResults of Operations in lower prices BGS revenues primarily due to lower sales volumes.
Gas revenues decreased $19 million due to $80 million from lower sales volumes, partially offset by higher BGSS prices of $61 million.
Operating Expenses
Energy Costs decreased $155 million. This is entirely offset by Commodity Revenues.
Operation and Maintenance decreased $85 million due to
a $98 million net reductionour Annual Report on Form 10-K for the year ended December 31, 2022 as filed with the SEC on February 22, 2023 for information related to various clause mechanisms and GPRC, andthe year ended December 31, 2022 as compared to 2021, which information is incorporated herein by reference.
a $13 million decrease in pension and OPEB expenses, net
partially offset by $10 million of insurance recovery proceeds in 2015,PSEG Power & Other
a $10 million increase in vegetation management costs, and | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | Increase / (Decrease) | | Increase / (Decrease) | |
| | | 2023 | | 2022 | | 2021 | | 2023 vs. 2022 | 2022 vs. 2021 | |
| | | Millions | | Millions | | % | | Millions | | % | |
| Operating Revenues | | $ | 4,533 | | | $ | 3,266 | | | $ | 3,767 | | | $ | 1,267 | | | 39 | | | $ | (501) | | | (13) | | |
| Energy Costs | | 1,353 | | | 2,149 | | | 1,978 | | | (796) | | | (37) | | | 171 | | | 9 | | |
| Operation and Maintenance | | 1,307 | | | 1,340 | | | 1,534 | | | (33) | | | (2) | | | (194) | | | (13) | | |
| Depreciation and Amortization | | 155 | | | 165 | | | 288 | | | (10) | | | (6) | | | (123) | | | (43) | | |
| Losses on Asset Dispositions and Impairments | | 7 | | | 123 | | | 2,641 | | | (116) | | | (94) | | | (2,518) | | | (95) | | |
| Income from Equity Method Investments | | 1 | | | 14 | | | 16 | | | (13) | | | (93) | | | (2) | | | (13) | | |
| Net Gains (Losses) on Trust Investments | | 189 | | | (263) | | | 192 | | | 452 | | | N/A | | (455) | | | N/A | |
| Net Other Income (Deductions) | | 96 | | | 36 | | | 10 | | | 60 | | | N/A | | 26 | | | N/A | |
| Net Non-Operating Pension and OPEB (Costs) Credits | | (332) | | | 95 | | | 64 | | | (427) | | | N/A | | 31 | | | 48 | | |
| Loss on Extinguishment of Debt | | — | | | — | | | (298) | | | — | | | N/A | | 298 | | | N/A | |
| Interest Expense | | 259 | | | 201 | | | 169 | | | 58 | | | 29 | | | 32 | | | 19 | | |
| Income Tax Expense (Benefit) | | 358 | | | (296) | | | (765) | | | 654 | | | N/A | | 469 | | | (61) | | |
| | | | | | | | | | | | | | | | |
a $6 million net increase due primarilyYear Ended December 31, 2023 as compared to T&D corrective maintenance and appliance service costs.2022
Depreciation and Amortization decreased $327Operating Revenues increased $1,267 million due primarily to a $396 million net decrease in amortization of Regulatory Assets, partially offset by an increase in depreciation of $65 million due to additional plant in service in 2016.
Interest Expense increased $9 million due to increases of
$14 million due to net debt issuances in 2015, and
$13 million due to net debt issuances in 2016,
partially offset by a decrease of $11 million due to the redemption of securitization debt in 2015, and
$7 million of higher interest related to BGSS in 2015.
Income Tax Expense increased $45 million due primarily to higher pre-tax income partially offset by changes in the reserve for uncertain tax positions and flow through items.
Power
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | Increase / (Decrease) | | Increase / (Decrease) | |
| | | 2017 | | 2016 | | 2015 | | 2017 vs. 2016 | 2016 vs. 2015 | |
| | | Millions | | Millions | | % |
| | Millions | | % |
| |
| Operating Revenues | | $ | 3,930 |
| | $ | 4,023 |
| | $ | 4,928 |
| | $ | (93 | ) | | (2 | ) | | $ | (905 | ) | | (18 | ) | |
| Energy Costs | | 1,983 |
| | 1,986 |
| | 2,150 |
| | (3 | ) | | N/A |
| | (164 | ) | | (8 | ) | |
| Operation and Maintenance | | 1,038 |
| | 1,143 |
| | 1,057 |
| | (105 | ) | | (9 | ) | | 86 |
| | 8 |
| |
| Depreciation and Amortization | | 1,268 |
| | 881 |
| | 291 |
| | 387 |
| | 44 |
| | 590 |
| | N/A |
| |
| Income from Equity Method Investments | | 14 |
| | 11 |
| | 14 |
| | 3 |
| | 27 |
| | (3 | ) | | (21 | ) | |
| Other Income (Deductions) | | 157 |
| | 45 |
| | 97 |
| | 112 |
| | N/A |
| | (52 | ) | | (54 | ) | |
| Other-Than-Temporary Impairments | | 12 |
| | 28 |
| | 53 |
| | (16 | ) | | (57 | ) | | (25 | ) | | (47 | ) | |
| Interest Expense | | 50 |
| | 84 |
| | 121 |
| | (34 | ) | | (40 | ) | | (37 | ) | | (31 | ) | |
| Income Tax Expense (Benefit) | | (729 | ) | | (61 | ) | | 511 |
| | (668 | ) | | N/A |
| | (572 | ) | | N/A |
| |
| | | | | | | | | | | | | | | | |
Year Ended December 31, 2017 as compared to 2016
Operating Revenuesdecreased$93 million due to changes in generation and gas supply and other operating revenues.
Generation Revenuesdecreased$204 increased $1,868 million due primarily to
•a decreasenet increase of $126 million in energy sales in the PJM and New England (NE) regions due primarily to lower average realized prices,
a decrease of $100 million in electricity sold under our BGS contracts due primarily to lower volumes coupled with lower prices,
a decrease of $24 million in revenue expected to be returned to ratepayers associated with excess federal income tax previously collected by Power’s subsidiary, PSEG New Haven LLC, due to the change in federal tax rates effective January 1, 2018,
a decrease of $18 million in operating reserves in the PJM region,
a charge of $10$2,023 million due to an increaseMTM gains in the FERC accrual related2023 as compared to the PJM bidding matter,
a decrease of $7 million due to higher MTM losses in 20172022. Of this amount, there was a $1,539 million increase due to changes in forward prices in 2023 as compared to 2016. Of this amount, $1202022 coupled with a $484 million wasincrease due to increased forward prices, partially offset by a decrease of $113 million due to lower gains on positions reclassified to realized upon settlement, and
•a net increase of $99 million due primarily to higher average realized prices and volumes sold in 2017 as compared2023 in the PJM region, partially offset by volumes sold in the New England and New York regions in 2022 related to 2016,the fossil generating plants sold in February 2022 and lower ZEC revenue,
•partially offset by a net increasedecrease of $53$190 million due primarily to higher volumes of electricity sold under wholesalethe BGS contracts, which ended in May 2023, and lower volumes of other load contracts, and
•a net decrease of $57 million in capacity revenue due primarily to the sale of the fossil generating plants coupled with lower capacity prices in the PJM and NE regions,
a net increase of $18 millionregion, partially offset by decreases in capacity revenues in the PJM and NE regionsexpenses due to increases in cleared capacity and capacity auction prices, andlower load volumes served.
an increase of $11 million due to higher sales related to new solar projects.
Gas Supply Revenuesincreased $110 decreased $619 million due primarily to
an increase•a net decrease of $67$288 million related to sales to third parties, due primarily to $384 million from lower sales prices, partially offset by $96 million from higher sales volumes,
•a net decrease of $275 million in sales under the BGSS contract of which $40 million was due to higher average$148 million from lower sales volumes and $127 million due to lower prices, and
•a net decrease of $56 million due primarily to MTM losses in 2023 as compared to MTM gains in 2022. Of this amount, there was a $29 million decrease due to positions reclassified to realized upon settlement, coupled with a $27 million increase in sales volumesdecrease due to periods of colder weatherchanges 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.
forward prices.
Operating Expenses
Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet PSEG Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $3
$796 million due to
GenerationGas costsdecreased $69$536 million due primarily to
•a net decrease of $83 million primarily due to lower congestion costs in PJM due to lower rates coupled with less volumes, partially offset by higher transmission charges due to higher rates,
a net decrease of $50 million due to charges associated with the announced early retirement of the Mercer and Hudson units in 2016, primarily related to lower coal inventory write-downs in 2017, partially offset by additional retirement costs incurred in 2017,
partially offset by higher fuel costs of $31 million reflecting higher average realized prices for natural gas coupled with the utilization of higher volumes of coal, partially offset by the utilization of lower volumes of gas,
an increase of $17 million due to MTM losses in 2017 as compared to MTM gains in 2016, and
a net increase of $16 million primarily due to an increase in the volume of energy purchases in the NE region to serve load obligations.
Gas costs increased $66 million due to
an increase of $50$273 million related to sales under the BGSS contract, of which $31$143 million was due to higherthe lower average cost of gas costs, coupled with a $19 million increase in volumes sold due to periods of colder weather in the heating season, and
an increase of $16 million related to sales to third parties, of which $44 million was due to higher average gas costs, partially offset by a $28 million decrease in volumes sold.
Operation and Maintenance decreased $105 million due to
a $72 million decrease at our fossil plants, due primarily to the retirement of the Hudson and Mercer units and higher planned outage costs in 2016,
a $35 million net decrease related to our nuclear plants due primarily to lower labor-related expenses and outage costs,
an $8 million net decrease due to lower pension and OPEB costs,
partially offset by $5 million of costs related to new solar plants placed into service in 2017.
Depreciation and Amortization increased $387 million due primarily to
$346 million of higher depreciation for Hudson and Mercer, primarily due to the accelerated expense related to the early retirement of those units,
a $15 million increase due to the accelerated retirement date for the Bridgeport Harbor unit 3,
an $11 million increase due primarily to a higher nuclear asset base, and
$11 million of higher depreciation due to new solar projects.
Other Income (Deductions) increased $112 million due primarily to higher net realized gains from the NDT Fund in 2017.
Other-Than-Temporary Impairments decreased $16$130 million due to lower impairments of equity securities in the NDT Fund in 2017.send out volumes, and
Interest Expense decreased $34 million due primarily to
a $24 million decrease due to higher interest capitalized for the construction of three new fossil stations: BH5, Sewaren 7 and Keys, and
•a net $7 million decrease due to debt maturities in September 2016, partially offset by a debt issuance in June 2016.
Income Tax Expense decreased $668 million due primarily to the one-time benefit recorded as a result of the remeasurement of deferred tax balances required due to the enactment of the Tax Act in December 2017.
Year Ended December 31, 2016 as compared to 2015
Operating Revenues decreased $905 million due to changes in generation, gas supply and other operating revenues.
Generation Revenues decreased $714 million due primarily to
a decrease of $317 million due to MTM losses in 2016 as compared to MTM gains in 2015. Of this amount, $199 million was due to changes in forward power prices resulting in lower MTM gains in 2016 compared to 2015. Also contributing to the decrease was $118 million of higher gains on positions reclassified to realized upon settlement in 2016 compared to 2015,
a decrease of $298 million in energy sales volumes in the PJM, NE and NY regions due primarily to milder weather in 2016 and lower average realized prices,
a decrease of $80 million in capacity revenue primarily in the PJM region due to the retirement of older peaking units in June 2015, and
a decrease of $49 million due to lower operating reserve revenues in the PJM region due to less congestion and lower prices,
partially offset by a net increase of $19 million due primarily to higher volumes of electricity sold under wholesale load contract in the PJM and NE regions, partially offset by lower average prices, and
a net increase of $8 million due to new solar projects beginning commercial operations.
Gas Supply Revenues decreased $191 million due primarily to
a decrease of $183 million in sales under the BGSS contract due primarily to lower average sales prices and a decrease in sales volumes due to warmer average temperatures in the 2016 heating season, and
a decrease of $9 million due to MTM losses in 2016 due to changes in forward prices.
Operating Expenses
Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $164 million due to
Generation costs decreased $95 million due primarily to
lower fuel costs of $288 million reflecting lower average realized prices for natural gas and the utilization of lower volumes of fuel,
partially offset by a net increase of $143 million primarily due to realized gains on FTRs in PJM in 2015 due to extremely cold weather, and
a $62 million charge associated with the announced early retirement of the Mercer and Hudson units, primarily related to a coal inventory write-down.
Gas costs decreased $69 million due to
a decrease of $101 million related to sales under the BGSS contract due primarily to lower average gas costs and a decrease in volumes sold due to warmer average temperatures during the 2016 winter heating season,
partially offset by an increase of $32$261 million related to sales to third parties, due primarily to higher$332 million from the lower average cost of gas, costs and an increase inpartially offset by $71 million due to higher volumes sold.
Generation costs decreased $260 million due primarily to
•a net decrease of $185 million in fuel and emission costs due primarily to the sale of the fossil generating plants, and
•a net decrease of $65 million in energy purchases due primarily to lower renewable energy credit requirements caused by decreases in load served in the PJM region.
Operation and Maintenance increased $86decreased $33 million due primarily to the sale of the fossil generating plants in February 2022.
$145Losses on Asset Dispositions and Impairments The $7 million of insurance recoveries receivedloss in 20152023 reflects an impairment at Energy Holdings related to Superstorm Sandy, and
$53one of its real estate assets. The $123 million loss in 2022 reflects an impairment loss of charges$78 million at Energy Holdings related to one of its domestic energy generating facilities and its real estate assets, and a $50 million impairment loss due to the early retirementsale of the Hudson and Mercer units,
fossil generating plants in February 2022, partially offset by a net decrease of $73$5 million related to our fossil plants, largely due to higher costs incurred in 2015 for our planned major outagesgain on a land sale at the Bethlehem Energy CenterPSEG Power. See Item 8. Note 3. Asset Dispositions and Bergen generating plants,Impairments.
a net decrease of $31 million related to our nuclear plants due primarily to lower planned outage costs at our 100%-owned Hope Creek plant and our 57%-owned Salem Unit 1 plant, and
an $8 million decrease due to lower pension and OPEB costs.
Depreciation and Amortization increased $590 million due primarily to
$555 million of accelerated depreciation due to the early retirement of the Hudson and Mercer units,
a $24 million increase due primarily to a higher nuclear asset base, and
$5 million of higher depreciation due to new solar projects
Other Income (Deductions) from Equity Method Investments decreased $52$13 million due primarily to $28the sale of our ownership interest in Kalaeloa completed in July 2023.
Net Gains (Losses) on Trust Investments increased $452 million due primarily to NDT investments with $146 million of insurance recoveries receivednet unrealized gains on equity securities in 2015 related2023 as compared to Superstorm Sandy and $38$205 million of lowernet unrealized losses in 2022 and $42 million of net realized gains from the NDT Fund in 2016, partially offset by $10 million of lower purchased tax credits in 2016.
Other-Than-Temporary Impairments decreased $25 million due2023 as compared to lower impairments of equity securities in the NDT Fund in 2016.
Interest Expense decreased $37 million due to
$27 million of interest capitalized for the construction of three new fossil stations: Bridgeport Harbor 5, Sewaren 7 and Keys Energy Center, and
a $15 million decrease due to the maturity of 5.50% of Senior Notes in December 2015,
partially offset by an increase of $5 million due to net debt issuances in 2016.
Income Tax Expense decreased $572$50 million in 2016net realized losses in 2022.
Net Other Income (Deductions) increased $60 million due primarily to purchases of net operating loss (NOL) tax benefits under the New Jersey Technology Tax Benefit Transfer Program in 2022 and higher interest income in 2023.
Net Non-Operating Pension and OPEB (Costs) Credits increased $427 million due primarily to the pension lift-out settlement charge, a decrease in the expected return on plan assets, an increase in interest cost, and a decrease in the amortization of the net prior service credit.
Interest Expense increased $58 million due primarily to the replacement of maturing debt at the parent company at higher rates, the issuance of a PSEG Power term loan in March 2022, as well as higher rates on PSEG Power and parent company variable rate term loans in 2023.
Income Tax Expense increased $654 million due primarily to higher pre-tax lossincome in 20162023.
Year Ended December 31, 2022 as compared to pre-tax income2021
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in 2015.our Annual Report on Form 10-K for the year ended December 31, 2022 as filed with the SEC on February 22, 2023 for information related to the year ended December 31, 2022 as compared to 2021, which information is incorporated herein by reference.
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$1 billion 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 credit 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, PSEG Power, Energy Holdings, PSEG LI and Services participate in a corporate money pool, an aggregation of daily cash balances designed to efficiently manage their respective short-term liquidity needs. PSEG LI’s subsidiary, Long Island Electric Utilityneeds, which are accounted for as intercompany loans. Servco LLC (Servco), does not participate in the corporate money pool. Servco’s short-term liquidity needs are met through an account funded and owned by LIPA.
PSEG and PSEG Power have access through sub-limits to a revolving Master Credit Facility, which provides for $2.75 billion of multi-year credit capacity. The current PSEG sub-limit is $1.5 billion and current PSEG Power sub-limit is $1.25 billion. Sub-limits can be adjusted subject to the terms of the Master Credit Facility.
PSEG’s available sources of external liquidity may include the issuance of long-term debt securities and the incurrence of additional indebtedness underthrough our commercial paper program back-stopped by our credit facilities. Our current sources of external liquidity include multi-year revolving credit facilities totaling $1.5 billion. These facilities arethe Master Credit Facility. This facility is 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 facilitiesMaster Credit Facility and the commercial paper program are available to support PSEGPSEG’s working capital needs orand are also available to temporarily fund growth opportunities in advance of obtaining permanent financing. PSEG also has a $700 million term loan credit agreement that is scheduled to expire in June 2019. From time to time, PSEG may make equity contributions or provide creditliquidity 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 creditPSEG enters into short-term loan agreements designed to enhance its liquidity position.
PSEG Power’s sources of external liquidity include the Master Credit Facility and PSEG Power’s letter of credit facilities. Credit capacity is primarily used to provide collateral in support of PSEG 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 PSEG Power is downgraded to below investment grade by Standard & Poor’s (S&P&P) or Moody’s. PSEG 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 continue to expect our operating cash flows combined with cash on hand and financing activities to be sufficient to fund planned capital expenditures and shareholder dividend payments.dividends.
For the year ended December 31, 2017, our operating cash flow decreased by $50 million. For the year ended December 31, 2016,2023, our operating cash flow decreased by $608increased $2,303 million. The net changes wereincrease was primarily due to an inflow of $1,408 million in net cash collateral postings in 2023 as compared to a $677 million outflow in 2022 at PSEG Power and lower tax payments at PSEG and its other subsidiaries in 20172023, partially offset by a net changes from our subsidiarieschange at PSE&G, as discussed below.
PSE&G
PSE&G’s operating cash flow decreased $55$488 million from $1,894$2,028 million to $1,839$1,540 million for the year ended December 31, 2017,2023, as compared to 2016,2022, due primarily to lower tax refundscash collateral postings received from BGS suppliers, increases in materials and supplies to support our electric AMI and other infrastructure programs, an increase in vendor and electric energy payments, and a decrease of $50 million related to a changenet increase in regulatory deferrals. These amounts were partially offset by higher earnings and $30 million in decreased vendor payments.
PSE&G’s operating cash flow decreased $231 million from $2,125 million to $1,894 million for the year ended December 31, 2016, as compared to 2015, due primarily to a decrease from lower collections for securitization debt principal repayments which were $259 million in 2015, a decrease of $249 million in cash receipts from customers due to lower sales driven by warmer winter weather in 2016 compared to 2015, a decrease of $90 million related to a change in regulatory deferrals, primarily driven by net returns to customers in 2016 related to 2015 overcollections, partially offset by higher bill credits and $74 million in increased vendor payments. These amounts were partially offset by higher earnings and higher tax refunds in 2016.
Power
Power’s operating cash flow increased $71 million from $1,255 million to $1,326 million for the year ended December 31, 2017, as compared to 2016, primarily resulting from a decrease of $61 million in payments to counterparties, a $26 million increase from higher net collections of counterparty receivables, and higher earnings. These amounts were partially offset by higher tax payments and an increase in margin deposit requirements of $14 million.
Power’s operating cash flow decreased $451 million from $1,706 million to $1,255 million for the year ended December 31, 2016, as compared to 2015, primarily resulting from lower earnings, an increase in margin deposit requirements of $198 million, and a $134 million decrease from net collection of counterparty receivables,This was partially offset by a reductiondecrease in tax payments.net accounts receivable due to improved collections following the delays from COVID-19 moratoriums.
Short-Term Liquidity
We continually monitor ourPSEG meets its short-term liquidity requirements, as well as those of PSEG Power, primarily through the issuance of commercial paper and, seekfrom time to add capacity as neededtime, short-term loans. PSE&G maintains its own separate commercial paper program to meet ourits short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facility.
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.
In January 2023, PSEG repaid $750 million of the $1.5 billion 364-day variable rate term loan that was issued in April 2022 and in April 2023 the remaining $750 million matured. In April 2023, PSEG entered into a new 364-day variable rate term loan agreement for $750 million. In May 2023, PSEG’s $500 million 364-day variable rate term loan matured. In August 2023, PSEG repaid $250 million of the $750 million 364-day variable rate term loan that was issued in April 2023.These term loans are not included in the credit facility amounts presented in the following table.
In December 2023, PSEG Power converted a $100 million letter of credit facility from committed to uncommitted. PSEG Power also decreased a letter of credit facility, from $100 million to $75 million.
Our total committed credit facilities and available liquidity as of December 31, 20172023 were as follows:
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| Company/Facility | | As of December 31, 2023 | |
| Total Facility | | Usage | | Available Liquidity | |
| | | Millions | |
| PSEG | | $ | 1,500 | | | $ | 27 | | | $ | 1,473 | | |
| PSE&G | | 1,000 | | | 445 | | | 555 | | |
| PSEG Power | | 1,525 | | | 188 | | | 1,337 | | |
| Total | | $ | 4,025 | | | $ | 660 | | | $ | 3,365 | | |
| | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| Company/Facility | | As of December 31, 2017 | |
| Total Facility | | Usage | | Available Liquidity | |
| | | Millions | |
| PSEG | | $ | 1,500 |
| | $ | 556 |
| | $ | 944 |
| |
| PSE&G | | 600 |
| | 15 |
| | 585 |
| |
| Power | | 2,100 |
| | 151 |
| | 1,949 |
| |
| Total | | $ | 4,200 |
| | $ | 722 |
| | $ | 3,478 |
| |
| | | | | | | | |
For additional information, see Item 8. Note 14. Debt and Credit Facilities.We continually monitor our liquidity and seek to add capacity as needed to meet our liquidity requirements, including to satisfy any additional collateral requirements. As of December 31, 2017,2023, our liquidity position, including our credit facility capacityfacilities and access to external financing, was in excess ofexpected to be sufficient to meet our projected maximum liquiditystressed requirements over our 12-month planning horizon. Our maximumPSEG analyzes its liquidity requirements are based onusing stress scenarios that incorporateconsider different events, including changes in commodity prices and thepotential impact of PSEG Power losing its investment grade credit rating from S&P or Moody’s, which would represent a threetwo level downgrade from its current Moody’s and S&P or Moody’s ratings. In the event of a deterioration of PSEG Power’s credit rating, certain of PSEG 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 PSEG Power were to lose its investment grade credit rating was approximately $848$751 million and $783$878 million as of December 31, 20172023 and 2016,2022, respectively. The early retirement of Power’s Hudson and Mercer coal/gas generation units did not have a material impact on Power’s debt covenant ratios or its ability to obtain credit facilities. See Item 8. Financial StatementsNote 13. Commitments and Supplementary Data—Note 3. Early Plant Retirements.Contingent Liabilities for additional discussion of PSEG Power’s agreements.
Long-Term Debt Financing
During the next twelve months,
63
•PSE&G has $250 million of 3.75% of Medium-Term Notes Series I, due March 2024,
•PSE&G has $250 million of 3.15% of Medium-Term Notes, Series J, due August 2024, and
•PSE&G has $250 million of 3.05% of Medium-Term Notes, Series J, due November 2024.
For additional information, see Item 8.Financial Statements and Supplementary Data—8. Note 14. Debt and Credit Facilities.
Long-Term Debt FinancingNDT Fund Obligation
PSE&G has $400 millionThe NRC requires a biennial filing of 5.30% Medium Term Notes maturing in May 2018 and $350 millionthe NDT fund balances against the decommissioning liability estimate. Any funding shortfalls are required to be cured prior to the next NDT reporting period. We do not currently expect to be required to provide supplemental funding of 2.30% Medium Term Notes maturing in September 2018.
Power has $250 million of 2.45% Senior Notes maturing in November 2018.
For a discussion of our long-term debt transactions during 2017 and into 2018, see Item 8. Financial Statements and Supplementary Data—Note 14. Debt and Credit Facilities.the NDT Fund.
Debt Covenants
Our credit agreements contain maximum debt to equity ratios and other restrictive covenants and conditions to borrowing. We are currently in compliance with all of our debt covenants. Continued compliance with applicable financial covenants will depend upon our future financial position, level of earnings and cash flows, as to which no assurances can be given.
In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements, provided that its ratio of earnings to fixed charges calculated in accordance with its Mortgage is at least 2 to 1,, and/or against retired Mortgage Bonds. As of December 31, 2017,2023, PSE&G’s Mortgage coverage ratio was 5.23.8 to 1 and the Mortgage would permit up to approximately $6.9$9.3 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 PSEG Power’s respective financing agreements, a failure by PSE&G or PSEG Power to satisfy certain final judgments and certain bankruptcy events by PSE&G or PSEG 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 PSEG Power ceases to be wholly owned by PSEG. The PSE&G and PSEG 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 PSEG Power bank credit agreements do not include cross default provisions relating to PSEG.
There are no cross acceleration provisions in PSEG’s or Each of PSE&G’s indentures. However, and PSEG Power’s bank credit agreements also contain limitations on the incurrence of liens by it and certain of its subsidiaries and PSEG Power’s bank credit agreements contain restrictions on the incurrence of certain subsidiary debt.
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’sUnder PSE&G’s medium-term note indenture, includes a cross acceleration provision similar to that described above for PSEG’s existing notes except that such provision may be triggered upon thean event of default under PSE&G’s mortgage indenture and acceleration of more than $50 millionthe mortgage bonds would constitute an event 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.default.
Ratings Triggers
Our debt indentures and credit agreements do not contain any material ‘ratings triggers’“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 PSEG Power’s credit rating to below investment grade could increase PSEG Power’s required margin postings under various agreements entered into in the normal course of business. PSEG 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
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| | | | | | | | |
| | | Years Ended December 31, | |
| Dividend Payments on Common Stock | | 2023 | | 2022 | | 2021 | |
| Per Share | | $ | 2.28 | | | $ | 2.16 | | | $ | 2.04 | | |
| in Millions | | $ | 1,137 | | | $ | 1,079 | | | $ | 1,031 | | |
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|
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| | | | | | | | |
| | | Years Ended December 31, | |
| Dividend Payments on Common Stock | | 2017 | | 2016 | | 2015 | |
| Per Share | | $ | 1.72 |
| | $ | 1.64 |
| | $ | 1.56 |
| |
| in Millions | | $ | 870 |
| | $ | 830 |
| | $ | 789 |
| |
| | | | | | | | |
On February 20, 2018,13, 2024, our Board of Directors approved a $0.45$0.60 per share of common stock dividend for the first quarter of 2018.2024. This reflects an indicative annual dividend rate of $1.80$2.40 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant. For additional information related to cash dividends on our common stock, see Item 8. Financial Statements and Supplementary Data—Note16.Note 22. Earnings Per Share (EPS) and Dividends.
Credit Ratings
If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Credit Ratings shown are for securities that we typically issue. Outlooks are shown for Corporate Credit Ratings (S&P) and Issuer Credit Ratings (Moody’s)the credit ratings at each entity and can be Stable, Negative, or Positive. There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security.
In April 2017, S&P published updated research and affirmed the ratings and outlooks on PSEG and PSE&G. In June 2017, S&P published updated research on Power and the rating and outlook remained unchanged. In July 2017, Moody’s upgraded PSEG’s senior unsecured rating to Baa1 from Baa2 and revised its outlook to Stable from Positive. Also in July, Moody’s affirmed the ratings at PSE&G and Power.
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| | | | | |
| | | | | |
| | Moody’s (A) | | S&P (B) | |
| PSEG | | PSEG | | | |
| Outlook | OutlookStable | Stable | Stable | | Stable |
| Senior Notes | Baa1Baa2 | | BBB | | BBB |
| Commercial Paper | P2 | | A2 | |
| PSE&G | | PSE&G | | | |
| Outlook | OutlookStable | Stable | Stable | | Stable |
| Mortgage Bonds | Aa3A1 | | A | |
| Commercial Paper | P1P2 | | A2 | |
| PSEG Power | | Power | | | |
| Outlook | OutlookPositive | Stable | Stable | | Stable |
| Issuer Rating | Senior NotesBaa2 | Baa1 | BBB | | BBB+ |
| | | | | |
| |
(A) | Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities. |
| |
(B) | S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities. |
(A)Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities.
(B)S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities.
Other Comprehensive Income
For the year ended December 31, 2017,2023, we had Other Comprehensive Income of $34$371 million on a consolidated basis. The Other Comprehensive Income was due primarily to a $44$324 million increase inrelated to pension and other postretirement benefits, $41 million of net unrealized gains related to Available-for-Sale Securities, partially offset by a decrease of $8 million in our consolidated liability for pensionavailable-for-sale debt securities, and postretirement benefits and $2$6 million of unrealized lossesgains on derivative contracts accounted for as hedges. See Item 8. Financial Statements and Supplementary Data—Note 21. Accumulated Other Comprehensive Income (Loss), Net of Tax for additional information.
CAPITAL REQUIREMENTS
We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. Projected capital construction and investment expenditures, excluding nuclear fuel purchases, for the next three years are presented in the table below.following table. These projections include Allowance for Funds Used During Construction for PSE&G and Interest Capitalized During Construction for PSE&G and Power, respectively.PSEG’s other subsidiaries. These amounts are subject to change, based on various factors. Amounts shown below for Energy Strong, GSMP and Solar/Energy Efficiency programs are forPSE&G include currently approved programs. We intend to continue to invest in infrastructure modernization and will seek to extend these and related programs as appropriate. We will also continue to approach potential growth investments for Power opportunistically, seeking projects that will provide attractive risk-adjusted returns for our shareholders.
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | 2018 | | 2019 | | 2020 | |
| | | | | Millions | | | |
| PSE&G: | | | | | | | |
| Transmission | | $ | 1,235 |
| | $ | 1,290 |
| | $ | 1,280 |
| |
| Distribution | | 1,015 |
| | 715 |
| | 705 |
| |
| Energy Strong | | 35 |
| | — |
| | — |
| |
| Gas System Modernization Program | | 300 |
| | 40 |
| | — |
| |
| Solar/Energy Efficiency | | 85 |
| | 75 |
| | 55 |
| |
| Total PSE&G | | $ | 2,670 |
| | $ | 2,120 |
| | $ | 2,040 |
| |
| Power: | | | | | | | |
| Baseline | | $ | 170 |
| | $ | 165 |
| | $ | 165 |
| |
| Fossil Growth Opportunities | | 445 |
| | 65 |
| | 10 |
| |
| Other | | 30 |
| | 30 |
| | 20 |
| |
| Total Power | | $ | 645 |
| | $ | 260 |
| | $ | 195 |
| |
| Other | | $ | 40 |
| | $ | 30 |
| | $ | 20 |
| |
| Total PSEG | | $ | 3,355 |
| | $ | 2,410 |
| | $ | 2,255 |
| |
| | |
|
| | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | 2024 | | 2025 | | 2026 | |
| | | | | Millions | | | |
| PSE&G: | | | | | | | |
| Transmission | | $ | 610 | | | $ | 785 | | | $ | 725 | | |
| Electric Distribution | | 1,155 | | | 1,160 | | | 1,255 | | |
| Gas Distribution | | 1,145 | | | 1,090 | | | 1,095 | | |
| Clean Energy | | 440 | | | 605 | | | 585 | | |
| Total PSE&G | | $ | 3,350 | | | $ | 3,640 | | | $ | 3,660 | | |
| Competitively Bid, FERC Regulated Transmission | | 15 | | | 70 | | | 240 | | |
| PSEG Power & Other | | 265 | | | 205 | | | 170 | | |
| Total PSEG | | $ | 3,630 | | | $ | 3,915 | | | $ | 4,070 | | |
| | | | | | | | |
PSE&G
PSE&G’s projections for future capital expenditures include material additions and replacements to its transmission and distributionT&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.
•Electric and Gas Distribution—investments for new business, reliability improvements, flood mitigation, and modernization and replacement of equipment that has reached the end of its useful life.
Energy Strong—Electric and Gas Distribution reliability investment program focused on system hardening and resiliency.
Gas System Modernization Program—Gas Distribution investment program to replace aging infrastructure.
Solar/Energy Efficiency—•Clean Energy—investments associated with customer EE programs, infrastructure supporting EVs and grid-connected solar, solar loan programs, and customer energy efficiency programs.
solar.
In November 2017, the BPU issued an order approving PSE&G’s net investment of $100 million to rebuild New Jersey Transit’s Mason electric distribution substation and related facilities in Kearny, New Jersey. This project is expected to be completed in December 2021.
In July 2017, PSE&G filed a petition with the BPU requesting approval of the $2.7 billion next phase of the Gas System Modernization Program (GSMP II) and associated cost recovery mechanism. The GSMP II program will enable PSE&G to continue to accelerate the replacement of its aging cast-iron and unprotected steel gas pipes. This matter is currently pending before the BPU and is not included in the PSE&G’s projected capital expenditures above.
In 2017,2023, PSE&G made $2,919$2,998 million of capital expenditures, primarily for transmission and distributionT&D system reliability. This does not include expenditures forIn addition, PSE&G had cost of removal, net of salvage, of $107$166 million associated with capital replacements, and expenditures for EE programs of approximately $466 million, which are included in operating cash flows.
PowerCompetitively Bid, FERC Regulated Transmission
Power’sIn December 2023, PJM awarded a subsidiary of Energy Holdings a project to address increasing load and reliability issues in Maryland as part of its 2022 Window 3 competitive solicitation.
PSEG Power & Other
PSEG’s other projected expenditures for the various items listed above are primarily comprised of the following:
Baseline—investments to replace major partsmaintain and enhance operational performance.
Fossil Growth Opportunities—investments associated with new construction, including Keys, Sewaren 7current nuclear operations and BH5, and with upgradesopportunities to increase efficiencynuclear generation at PSEG Power and outputto purchase software and office equipment at combined cycle plants.Services.
Other—includes investmentsIn 2023, PSEG Power & Other made in response to environmental, regulatory and legal mandates and other capital projects.
In 2017, Power made $1,040 million of capital expenditures of $140 million, excluding $191$187 million for nuclear fuel, primarily related to various nuclear projects at Fossil, SolarPSEG Power and Nuclear.to purchase hardware, software and office equipment at Services.
Disclosures about Contractual ObligationsOther Material Cash Requirements
The following table reflects our contractualother material cash obligationsrequirements which include debt maturities and interest payments, operating lease payments and energy related purchase commitments in the respective periods in which they are due. In addition, the table summarizes anticipated debt maturities for the years shown. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 14. Debt and Credit Facilities.Facilities, Note 7. Leases and Note 13. Commitments and Contingent Liabilities.
The table below does not reflect any anticipated cash payments for pension obligationsand OPEB or AROs 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.payments. See Item 8. Financial StatementsNote 12. Pension, Other Postretirement Benefits (OPEB) and Supplementary Data—Savings Plans and Note 20. Income Taxes11. Asset Retirement Obligations (AROs) for additional information.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | Total Amount Committed | | Less Than 1 Year | | 2 - 3 Years | | 4 - 5 Years | | Over 5 Years | |
| | | Millions | |
| Long-Term Recourse Debt Maturities | | | | | | | | | | | |
| PSEG | | $ | 4,396 | | | $ | 750 | | | $ | 550 | | | $ | 1,300 | | | $ | 1,796 | | |
| PSE&G | | 13,765 | | | 750 | | | 1,225 | | | 1,125 | | | 10,665 | | |
| PSEG Power | | 1,250 | | | — | | | 1,250 | | | — | | | — | | |
| Interest on Recourse Debt | | | | | | | | | | | |
| PSEG | | 877 | | | 153 | | | 277 | | | 231 | | | 216 | | |
| PSE&G | | 7,997 | | | 506 | | | 955 | | | 898 | | | 5,638 | | |
| PSEG Power (A) | | 79 | | | 66 | | | 13 | | | — | | | — | | |
| Operating Leases | | | | | | | | | | | |
| PSE&G | | 125 | | | 18 | | | 28 | | | 22 | | | 57 | | |
| Other | | 111 | | | 17 | | | 33 | | | 33 | | | 28 | | |
| | | | | | | | | | | | |
| Energy-Related Purchase Commitments | | | | | | | | | | | |
| PSEG Power | | 2,486 | | | 745 | | | 981 | | | 524 | | | 236 | | |
| Total | | $ | 31,086 | | | $ | 3,005 | | | $ | 5,312 | | | $ | 4,133 | | | $ | 18,636 | | |
| | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | Total Amount Committed | | Less Than 1 Year | | 2 - 3 Years | | 4- 5 Years | | Over 5 Years | |
| | | Millions | |
| Contractual Cash Obligations | | | | | | | | | | | |
| Long-Term Recourse Debt Maturities | | | | | | | | | | | |
| PSEG | | $ | 2,100 |
| | $ | — |
| | $ | 1,100 |
| | $ | 1,000 |
| | $ | — |
| |
| PSE&G | | 8,658 |
| | 750 |
| | 759 |
| | 434 |
| | 6,715 |
| |
| Power | | 2,400 |
| | 250 |
| | 450 |
| | 950 |
| | 750 |
| |
| Interest on Recourse Debt | | | | | | | | | | | |
| PSEG | | 157 |
| | 49 |
| | 65 |
| | 43 |
| | — |
| |
| PSE&G | | 5,186 |
| | 313 |
| | 578 |
| | 525 |
| | 3,770 |
| |
| Power | | 821 |
| | 113 |
| | 202 |
| | 129 |
| | 377 |
| |
| Capital Lease Obligations | | | | | | | | | | | |
| Power | | 2 |
| | 1 |
| | 1 |
| | — |
| | — |
| |
| Operating Leases | | | | | | | | | | | |
| PSE&G | | 113 |
| | 16 |
| | 17 |
| | 15 |
| | 65 |
| |
| Power | | 58 |
| | 5 |
| | 9 |
| | 6 |
| | 38 |
| |
| Services | | 194 |
| | 14 |
| | 30 |
| | 30 |
| | 120 |
| |
| Other | | 6 |
| | 1 |
| | 2 |
| | 2 |
| | 1 |
| |
| Energy-Related Purchase Commitments | | | | | | | | | | | |
| Power | | 2,670 |
| | 730 |
| | 938 |
| | 468 |
| | 534 |
| |
| Total Contractual Cash Obligations | | $ | 22,365 |
| | $ | 2,242 |
| | $ | 4,151 |
| | $ | 3,602 |
| | $ | 12,370 |
| |
| | | | | | | | | | | | |
| Liability Payments for Uncertain Tax Positions | | | | | | | | | | | |
| PSEG | | $ | 69 |
| | $ | 69 |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| PSE&G | | 35 |
| | 35 |
| | — |
| | — |
| | — |
| |
| Power | | 30 |
| | 30 |
| | — |
| | — |
| | — |
| |
| | | | | | | | | | | | |
(A)Based on a blended rate including effects of floating to fixed rate hedging transacted at the Parent level.
OFF-BALANCE SHEET ARRANGEMENTS
PSEG and Power issue guarantees, primarily in conjunction with certain of Power’s energy contracts. See Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities for further discussion.
Through Energy Holdings, we have investments in leveraged leases that are accounted for in accordance with GAAP Accounting for Leases. Leveraged lease investments generally involve three parties: an owner/lessor, a creditor and a lessee. In a typical leveraged lease arrangement, the lessor purchases an asset to be leased. The purchase price is typically financed 80% with debt provided by the creditor and the balance comes from equity funds provided by the lessor. The creditor provides long-term financing to the transaction secured by the property subject to the lease. Such long-term financing is non-recourse to the lessor and is not presented on our Consolidated Balance Sheets. In the event of default, the leased asset, and in some cases the lessee, secures the loan. As a lessor, Energy Holdings has ownership rights to the property and rents the property to the lessees for use in their business operations. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 7. Long-Term Investments and Note 8. Financing Receivables.
In the event that collection of the minimum lease payments to be received by Energy Holdings is no longer reasonably assured, Energy Holdings may deem that a lessee has a high probability of defaulting on the lease obligation, and would consider the need to record an impairment of its investment. In the event the lease is ultimately rejected by the lessee in a Bankruptcy Court proceeding, the fair value of the underlying asset and the associated debt would be recorded on the Consolidated Balance Sheets instead of the net equity investment in the lease.
CRITICAL ACCOUNTING ESTIMATES
Under GAAP,accounting guidance 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 and Other Postretirement Benefits (OPEB)
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 thePSEG’s qualified pension planand OPEB plans 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. Plan assets also include investments in unlisted real estate which is valued via third-party appraisals. We calculate pension and OPEB costs using various economic and demographic assumptions.
Assumptions and Approach Used: Economic assumptions include the discount rate and the long-termexpected rate of return on trustplan assets. Demographic pension and OPEB assumptions include projections of future mortality rates, pay increases and retirement patterns.patterns, as well as projected health care costs for OPEB.
|
| | | | | | | | | | | |
| | | | | | | | |
| Assumption | | 2017 |
| | 2016 |
| | 2015 |
| |
| Discount Rate | | 3.73 | % | | 4.29 | % | | 4.54 | % | |
| Expected Rate of Return on Plan Assets | | 7.80 | % | | 8.00 | % | | 8.00 | % | |
| | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| Assumption | | 2023 | | 2022 | | 2021 | |
| Pension | | | | | | | |
| Discount Rate | | 5.02 | % | | 5.20 | % | | 2.94 | % | |
| Expected Rate of Return on Plan Assets | | 8.10 | % | | 7.20 | % | | 7.70 | % | |
| OPEB | | | | | | | |
| Discount Rate | | 4.96 | % | | 5.16 | % | | 2.82 | % | |
| Expected Rate of Return on Plan Assets | | 8.10 | % | | 7.20 | % | | 7.69 | % | |
| | | | | | | | |
The discount rate used to calculate PSEG’s pension and OPEB obligations is determined as of December 31 each year, our measurement date. The discount rate is determined by developing a spot rate curve based on the yield to maturity of a universe of high quality corporate bonds with similar maturities to the plan obligations. The spot rates are used to discount the estimated plan distributions. The discount rate is the single equivalent rate that produces the same result as the full spot rate curve.
Our expected rate of return on plan assets reflects current asset allocations, historical long-term investment performance and an estimate of future long-term returns by asset class, long-term inflation assumptions and a premium for active management.
Based on the above assumptions, we have estimated a net periodic pension credit in 2018 of approximately $(36) million, or $(87) million, net of amounts capitalized.
We utilize a corridor approach that reduces the volatility of reported pension expense/income.costs/credits. The corridor requires differences between actuarial assumptions and plan results be deferred and amortized as part of expense/income.the costs/credits. 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. TheFor one of PSEG’s qualified pension plans, the excess would be amortized over the average remaining expected life of inactive participants, which is approximately eighteen years. For PSEG’s other qualified pension plan, the excess would be amortized over the average remaining service period of the active employees, which is approximately thirteenfifteen years.
Effect if Different Assumptions Used: As part of the business planning process, we have modeled future costs assuming a 7.80%an 8.10% expected rate of return and a 3.73%5.02% discount rate for 2018. 2024 pension costs/credits and a 4.96% discount rate for 2024 OPEB costs/credits. Based upon these assumptions, we have estimated a net periodic pension expense in 2024 of approximately $21 million, or a net periodic pension credit of $19 million, net of amounts capitalized, and a net periodic OPEB expense in 2024 of approximately $6 million, or $5 million, net of amounts capitalized. Beginning in 2023, our net periodic pension amounts include the impact of the accounting order approved by the BPU authorizing PSE&G to modify its pension accounting for ratemaking purposes. See a discussion in Item 7. MD&A—Executive Overview of 2023 and Future Outlook for further details. Actual future pension expense/incomecosts/credits 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. Actual future OPEB costs/credits will depend on future investment performance, changes in discount rates, market conditions, and various other factors.
The following chart reflects the sensitivities associated with a change in certain assumptions. The effects of the assumption changes shown belowin the chart solely reflect the impact of that specific assumption.assumption and therefore does not reflect the impact of the 2023 BPU accounting order.
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | % Change | | Impact on Pension Benefit Obligation as of December 31, 2017 | | Increase to Pension Expense in 2018 | | Increase to Pension Expense, net of Amounts Capitalized in 2018 | |
| Assumption | | | | Millions | |
| Discount Rate | | (1)% | | $ | 866 |
| | $ | 46 |
| | $ | 36 |
| |
| Expected Rate of Return on Plan Assets | | (1)% | | N/A |
| | $ | 57 |
| | $ | 57 |
| |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | % Change | | Impact on Benefit Obligation as of December 31, 2023 | | Increase to Costs in 2024 | | Increase to Costs, net of Amounts Capitalized in 2024 | |
| Assumption | | | | Millions | |
| Pension | | | | | | | | | |
| Discount Rate | | (1)% | | $ | 536 | | | $ | 23 | | | $ | 16 | | |
| Expected Rate of Return on Plan Assets | | (1)% | | N/A | | $ | 40 | | | $ | 40 | | |
| OPEB | | | | | | | | | |
| Discount Rate | | (1)% | | $ | 72 | | | $ | (2) | | | $ | (3) | | |
| Expected Rate of Return on Plan Assets | | (1)% | | N/A | | $ | 4 | | | $ | 4 | | |
| | | | | | | | | | |
See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for additional information.
Derivative Instruments
The operations of PSEG, 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,the New York Mercantile Exchange, Intercontinental Exchange and Nodal Exchange, or auction prices. Fair values of other energy contracts may be based on broker quotes.
For a small number of contracts where limited observable inputs or pricing information are available, modeling techniques are employed in determination of their fair value using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable.
For our wholesale energy business, many of the forward sale, forward purchase, option and other contracts are derivative instruments that hedge commodity price risk, but do not meet the requirements for, or are not designated as, either cash flow or fair value hedge accounting. The changes in value of such derivative contracts are marked to market through earnings as the related commodity prices fluctuate. As a result, our earnings may experience significant fluctuations depending on the volatility of commodity prices.
Effect if Different Assumptions Used: Any significant changes to the fair market values of our derivatives instruments could result in a material change in the value of the assets or liabilities recorded on our Consolidated Balance Sheets and could result in a material change to the unrealized gains or losses recorded in our Consolidated Statements of Operations.
For additional information regarding Derivative Financial Instruments, see Item 8. Financial Statements and Supplementary Data – Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies, Note 16. Financial Risk Management Activities and Note 17. Fair Value Measurements.
Long-Lived Assets
Management evaluates long-lived assets for impairment and reassesses the reasonableness of their related estimated useful lives whenever events or changes in circumstances suchwarrant assessment. Such events or changes in circumstances may be as a result of significant adverse changes in regulation, business climate, orcounterparty credit worthiness, market conditions, could potentially indicateor a determination that it is more-likely-than-not that an asset’sasset or asset group’s carrying amount may notgroup will be recoverable. sold or retired before the end of its estimated useful life.
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.
For PSEG Power, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the nuclear generation units are evaluated at the portfolio level. These tests require significant estimates and judgment when developing expected future cash flows. Significant inputs may include, but are not limited to, forward power prices, expectation of PTCs, ZEC payments for the New Jersey nuclear assets, fuel costs, dispatch rates, other operating and capital expenditures, and the cost of borrowing.
borrowing and asset sale prices and probabilities associated with any potential sale prior to the end of the estimated useful life or the early retirement of assets. 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.
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, make 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.
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 write-offs.
Lease Investments
Our Investments in Leases, included in Long-Term Investmentsaccelerated depreciation. For additional information on the potential impacts on our Consolidated Balance Sheets, are comprised of Lease Receivables (net of non-recourse debt),future financial statements that may be caused by a change in 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. Seeassumptions noted above, see Item 8. Financial StatementsNote 3. Asset Dispositions and Supplementary Data – Note 7. Long-Term Investments and Note 8. Financing Receivables.
Assumptions and Approach Used: Residual values are the estimated values of the leased assets at the end of the respective lease per the original lease terms, net of any subsequent impairments. The estimated values are calculated by discounting the cash flows related to the leased assets after the lease term. For the merchant power plants, the estimated discounted cash flows are dependent upon various assumptions, including:
estimated forward power and capacity prices in the years after the lease,
related prices of fuel for the plants,
dispatch rates for the plants,
future capital expenditures required to maintain the plants,
future operation and maintenance expenses,
discount rates, and
the current estimated economic viability of the plants after the end of the base lease term.
A review of the residual valuations is performed at least annually for each plant subject to lease using specific assumptions tailored to each plant. Those valuations are compared to the recorded residual values to determine if an impairment is warranted.
Effect if Different Assumptions Used: A significant change to the assumptions, such as a large decrease in near-term power prices that affects the market’s view of long-term power prices, could result in an impairment of one or more of the residual values, but not necessarily to all of the residual values. However, if, because of changes in assumptions, all the residual values related to the merchant energy plants were deemed to be zero, we would recognize an after-tax charge to income of approximately $78 million.Impairments.
Asset Retirement Obligations (ARO)
PSE&G, PSEG 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 assetsRegulatory Assets or liabilitiesLiabilities as a result of timing differences between the recording of costs and costs recovered through the rate-making process. We accrete the ARO liability to reflect the passage of time with the corresponding expense recorded in Operation and Maintenance.O&M Expense.
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 nuclear decommissioning cost studies triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2015.2021. 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 PSEG Power’s nuclear facilities comprised 93%approximately 72% or $1,057 million of Power’sPSEG’s total AROs as of December 31, 2017.2023. PSEG Power determines its AROs for its nuclear units by assigning probability weighting to various discounted cash flow outcomes for each of its nuclear units that incorporate the assumptions above as well as:
•license renewals,
•SAFSTOR 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,
•recovery from the federal government of assumed specificcosts incurred for spent nuclear fuel, and
•financial feasibility and impacts on potential early shutdown,shutdown.
license renewals,
safe storage for a period of time after retirement, and
recovery from the federal government of costs incurred for spent nuclear fuel.
Effect if Different Assumptions Used: Changes in the assumptions could result in a material change in the ARO balance sheet obligation and the period over which we accrete to the ultimate liability. For example, aHad the following assumptions been applied, our estimates of the approximate impacts on the Nuclear ARO as of December 31, 2023 are as follows:
•A decrease of 1% in the discount rate would result in a $120$43 million increase in the Nuclear ARO asARO.
•An increase of 1% in the inflation rate would result in a $324$303 million increase in the Nuclear ARO as of December 31, 2017. Also, if we did not assume that we would recover fromARO.
•If the federal government were to discontinue reimbursing us for assumed specific spent fuel costs as prescribed under the costs incurred for spent nuclear fuel,Nuclear Waste Policy Act, the Nuclear ARO would increase by $550 million$139 million.
•If we would elect or be required to decommission under a DECON alternative at December 31, 2017. If Power were to increase its early shutdown probability to 100% and retire Salem and Hope Creek, in 2021 (when the current capacity obligations for Salem and Hope Creek expire), which is significantly earlier than the end of their current license periods, the Nuclear ARO would increase by $428$497 million.
Accounting for Regulated Businesses
PSE&G prepares its financial statements to comply with GAAP for rate-regulated enterprises, which differs in some respects from accounting for non-regulated businesses. In general, accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (Regulatory Asset) or recognize obligations (Regulatory Liability) if the rates established are designed to recover the costs and if the competitive environment makes it probable that such rates can be charged or collected. This accounting results in the recognition of revenues and expenses in different time periods than that of enterprises that are not regulated.
Assumptions and Approach Used: PSE&G recognizes Regulatory Assets where it is probable that such costs will be recoverable in future rates from customers and Regulatory Liabilities where it is probable that refunds will be made to customers in future billings. The highest degree of probability is an order from the BPU either approving recovery of the deferred costs over a future period or requiring the refund of a liability over a future period.
Virtually all of PSE&G’s regulatory assetsRegulatory Assets and liabilitiesRegulatory Liabilities are supported by BPU orders. In the absence of an order, PSE&G will consider the following when determining whether to record a Regulatory Asset or Liability:
•past experience regarding similar items with the BPU,
•treatment of a similar item in an order by the BPU for another utility,
•passage of new legislation, and
•recent discussions with the BPU.
All deferred costs are subject to prudence reviews by the BPU. When the recovery of a Regulatory Asset or payment of a Regulatory Liability is no longer probable, PSE&G charges or credits earnings, as appropriate.
Effect if Different Assumptions Used: A change in the above assumptions may result in a material impact on our results of operations or our cash flows. See Item 8. Financial Statements and Supplementary Data—Note 6. Regulatory Assets and Liabilities for a description of the amounts and nature of regulatory balance sheet amounts.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK
The risk inherent in our market-risk sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, equity security prices and interest rates as discussed in the Notes to Consolidated Financial Statements. It is our policy to use derivatives to manage risk consistent with business plans and prudent practices. We have a Risk Management
Committee comprised of executive officers who utilize a risk oversight function to ensure compliance with our corporate policies and risk management practices.
Additionally, we are exposed to counterparty credit losses in the event of non-performance or non-payment. We have a credit management process, which is used to assess, monitor and mitigate counterparty exposure. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on our financial condition, results of operations or net cash flows.
Commodity Contracts
The availability and price of energy-related commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market rules and other events. To reduce price risk caused by market fluctuations, we enter into supply contracts and derivative contracts, including forwards, futures, swaps, treasury locks, and options with approved counterparties. These contracts, in conjunction with physical sales and other services, help reduce risk and optimize the value of owned electric generation capacity.
Value-at-Risk (VaR) Models
VaR represents the potential losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. We estimate VaR across our commodity businesses.
MTM VaR consists of MTM derivatives that are economic hedges. The MTM VaR calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and some load servingload-serving activities.
The VaR models used are variance/covariance models adjusted for the change of positions with 95% and 99.5% confidence levels and a one-day holding period for the MTM activities. The models assume no new positions throughout the holding periods; however, we actively manage our portfolio.
|
| | | | | | | | | | |
| | | | | | |
| | | MTM VaR | |
| | | Millions | |
| Years Ended December 31, | | 2017 | | 2016 | |
| | | | |
| 95% Confidence Level, Loss could exceed VaR one day in 20 days | | | | | |
| Period End | | $ | 39 |
| | $ | 26 |
| |
| Average for the Period | | $ | 10 |
| | $ | 16 |
| |
| High | | $ | 39 |
| | $ | 32 |
| |
| Low | | $ | 5 |
| | $ | 10 |
| |
| | | | | | |
| 99.5% Confidence Level, Loss could exceed VaR one day in 200 days | | | | | |
| Period End | | $ | 60 |
| | $ | 40 |
| |
| Average for the Period | | $ | 15 |
| | $ | 25 |
| |
| High | | $ | 60 |
| | $ | 51 |
| |
| Low | | $ | 8 |
| | $ | 16 |
| |
| | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | MTM VaR | |
| | | Years Ended December 31, | |
| | | 2023 | | 2022 | |
| | | Millions | |
| 95% Confidence Level, Loss could exceed VaR one day in 20 days | | | | | |
| Period End | | $ | 48 | | | $ | 122 | | |
| Average for the Period | | $ | 56 | | | $ | 152 | | |
| High | | $ | 127 | | | $ | 365 | | |
| Low | | $ | 24 | | | $ | 70 | | |
| | | | | | |
| 99.5% Confidence Level, Loss could exceed VaR one day in 200 days | | | | | |
| Period End | | $ | 75 | | | $ | 191 | | |
| Average for the Period | | $ | 87 | | | $ | 239 | | |
| High | | $ | 198 | | | $ | 572 | | |
| Low | | $ | 38 | | | $ | 110 | | |
| | | | | | |
See Item 8. Financial Statements and Supplementary Data—Note 16. Financial Risk Management Activities for a discussion of credit risk.
Interest Rates
We are subject to the risk of fluctuating interest rates in the normal course of business. We manage interest rate risk by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, we use a mix of fixed and floating rate debt, interest rate swaps and interest rate lock agreements.
As of December 31, 2017,2023, a hypothetical 10% increase in market interest rates would result in
$1 an additional $2 million of additionalin pre-tax annual interest costs related to botheither the current andor the long-term portion of long-term debt, and
a $370 million decrease in the fair value of debt, including a $16 million decrease at PSEG, a $309 million decrease at PSE&G and a $45 million decrease at Power.
term loan agreements.
Debt and Equity Securities
We have $6.3As of December 31, 2023, we had $4.6 billion of net assets in a trust for our pension and OPEB plans. Although fluctuations in market prices of securities within this portfolio do not directly affect our earnings in the current period, changes in the value of these investments could affect
•our future contributions to these plans,
•our financial position if our accumulated benefit obligation under our pension plans exceeds the fair value of the pension trust funds, and
•future earnings, as we could be required to adjust pension expense and the assumed rate of return.
The NDT Fund is comprised primarily of fixed income and equity securities. As of December 31, 2017,2023, the portfolio included $1.1$1.3 billion of equity securities inclusive of $0.3 billion of investments in listed real assets, and $986 million$1.2 billion in fixed income securities. The fair market value of the assets in the NDT Fund will fluctuate primarily depending upon the performance of equity markets. As of December 31, 2017,2023, a hypothetical 10% change in the equity market would impact the value of the equity securities in the NDT Fund by approximately $106$131 million.
We use duration to measure the interest rate sensitivity of the fixed income portfolio. Duration is a summary statistic of the effective average maturity of the fixed income portfolio. The benchmark for the fixed income component of the NDT Fund currently has a duration of 5.986.24 years and a yield of 2.72%4.53%. The portfolio’s value will appreciate or depreciate by the duration with a 1% change in interest rates. As of December 31, 2017,2023, a hypothetical 1% increase in interest rates would result in a decline in the market value for the fixed income portfolio of approximately $59$76 million.
Credit Risk
See Item 8. Financial Statements and Supplementary Data—Note 16. Financial Risk Management Activities for a discussion of credit risk and a discussion about Power’s and PSE&G’s credit risk.
Energy Holdings has credit risk related to its investments in leases, which totaled $85 million, net of deferred taxes of $480 million, as of December 31, 2017. These leveraged leases are concentrated in the U.S. energy industry. See Item 8. Financial Statements and Supplementary Data—Note 8. Financing Receivables for counterparties’ credit ratings and other information. The credit exposure to the lessees is partially mitigated through various credit enhancement mechanisms within the lease transactions. These credit enhancement features vary from lease to lease. Some of the leasing transactions include covenants that restrict the flow of dividends from the lessee to its parent, over-collateralization of the lessee with non-leased assets, and historical and forward cash flow coverage tests that prohibit discretionary capital expenditures and dividend payments to the parent/lessee if stated minimum coverages are not met. These covenants are designed to maintain cash reserves in the transaction entity for the benefit of the non-recourse lenders and the lessor/equity participants in the event of a temporary market downturn or degradation in operating performance of the leased assets.
In any lease transaction, in the event of a default, Energy Holdings would exercise its rights and attempt to seek recovery of its investment. The results of such efforts may not be known for a period of time. A bankruptcy of a lessee and failure to recover adequate value could lead to a foreclosure of the lease. Under a worst-case scenario, if a foreclosure were to occur, Energy Holdings would record a pre-tax write-off up to its outstanding gross investment in these facilities. Also, in the event of a potential foreclosure, the net tax benefits generated by Energy Holdings’ portfolio of investments could be materially reduced in the period in which gains associated with the potential forgiveness of debt at these projects occurs. The amount and timing of any potential reduction in net tax benefits is dependent upon a number of factors including, but not limited to, the time of a potential foreclosure, the amount of lease debt outstanding, any cash trapped at the projects and negotiations during such potential foreclosure process. The potential loss of earnings, impairment and/or tax payments could have a material impact to our financial position, results of operations and net cash flows.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
This combined Form 10-K is separately filed by PSEG PSE&G and Power.PSE&G. Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G and Power each makemakes representations only as to itself and makemakes no representations as to any other company.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Public Service Enterprise Group Incorporated
Newark, New Jersey
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Public Service Enterprise Group Incorporated and subsidiaries (the “Company”) or PSEG) as of December 31, 20172023 and 2016,2022, the related consolidated statements of operations, comprehensive income (loss), stockholders' equity, and cash flows, for each of the three years in the period ended December 31, 2017,2023, the related notes and the consolidated financial statement schedule listed in the Index at Item 15(B)(a) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172023 and 2016,2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2023, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”)(PCAOB), the Company's internal control over financial reporting as of December 31, 2017,2023, based on criteria established inInternal Control -— Integrated Framework (2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 26, 2018,2024, expressed an unqualified opinion on the Company's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Regulation – Refer to Notes 1 and 6 to the financial statements
Critical Audit Matter Description
PSEG’s subsidiary, Public Service Electric and Gas Company (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. Management believes that PSE&G’s transmission and distribution businesses continue to meet the accounting requirements for rate-regulated entities, and PSE&G’s financial statements reflect the economic effects of regulation. PSE&G has deferred certain costs based on rate orders issued by the New Jersey Board of Public Utilities (“BPU”) or Federal Energy Regulatory Commission (“FERC”) or based on PSE&G’s experience with prior rate proceedings.
PSE&G defers the recognition of costs as a regulatory asset or records the recognition of obligations as a regulatory liability if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. This accounting results in the recognition of revenues and expenses in different time periods than that of enterprises that are not regulated. Regulatory assets and other investments and costs incurred under various infrastructure filings and clause mechanisms are subject to prudence reviews and can be disallowed in the future by regulatory authorities. To the extent that
collection of any infrastructure or clause mechanism revenue, regulatory assets or payments of regulatory liabilities is no longer probable, the amounts would be charged or credited to income.
We identified the accounting for the effects of rate regulation as a critical audit matter due to the significant judgments made by management in assessing the probable recovery of regulatory assets and incurred costs or the likelihood of refunds of regulatory liabilities. Auditing these judgments required specialized knowledge of accounting for rate regulation and the ratemaking process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures to evaluate the accounting for the effects of cost-based rate regulation, including the probable recovery or refund of regulatory assets and liabilities, included the following, among others:
•We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management's controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We obtained and read relevant regulatory orders issued by the BPU and FERC for PSE&G and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances. We evaluated the external information and compared it to management’s recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected associated documents and testimony filed with the BPU or FERC for any evidence that might contradict management's assertions.
•We evaluated the financial statement presentation and disclosures related to the impacts of cost-based rate-regulation, including the balances recorded and regulatory developments.
| | |
|
|
/s/ DELOITTE & TOUCHE LLP |
|
Parsippany,Morristown, New Jersey |
February 26, 20182024 |
We have served as the Company's auditor since 1934.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Sole Stockholder of
Public Service Electric and Gas Company
Newark, New Jersey
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Public Service Electric and Gas Company and subsidiaries (the “Company”) or PSE&G) as of December 31, 20172023 and 2016, and2022, the related consolidated statements of operations, comprehensive income, common stockholder’s equity, and cash flows, for each of the three years in the period ended December 31, 2017, and2023, the related notes and the consolidated financial statement schedule listed in the Index at Item 15(B)(b) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172023 and 2016,2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2023, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”)(PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Regulation – Refer to Notes 1 and 6 to the financial statements
Critical Audit Matter Description
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. Management believes that PSE&G’s transmission and distribution businesses continue to meet the accounting requirements for rate-regulated entities, and PSE&G’s financial statements reflect the economic effects of regulation. PSE&G has deferred certain costs based on rate orders issued by the New Jersey Board of Public Utilities (“BPU”) or Federal Energy Regulatory Commission (“FERC”) or based on PSE&G’s experience with prior rate proceedings.
PSE&G defers the recognition of costs as a regulatory asset or records the recognition of obligations as a regulatory liability if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. This accounting results in the recognition of revenues and expenses in different time periods than that of enterprises that are not regulated. Regulatory assets and other investments and costs incurred under various infrastructure filings and clause mechanisms are subject to prudence reviews and can be disallowed in the future by regulatory authorities. To the extent that
collection of any infrastructure or clause mechanism revenue, regulatory assets or payments of regulatory liabilities is no longer probable, the amounts would be charged or credited to income.
We identified the accounting for the effects of rate regulation as a critical audit matter due to the significant judgments made by management in assessing the probable recovery of regulatory assets and incurred costs or the likelihood of refunds of regulatory liabilities. Auditing these judgments required specialized knowledge of accounting for rate regulation and the ratemaking process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures to evaluate the accounting for the effects of cost-based rate regulation, including the probable recovery or refund of regulatory assets and liabilities, included the following, among others:
• We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management's controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
• We obtained and read relevant regulatory orders issued by the BPU and FERC for PSE&G and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances. We evaluated the external information and compared it to management’s recorded regulatory asset and liability balances for completeness.
• For regulatory matters in process, we inspected associated documents and testimony filed with the BPU or FERC for any evidence that might contradict management's assertions.
• We evaluated the financial statement presentation and disclosures related to the impacts of cost-based rate-regulation, including the balances recorded and regulatory developments.
| | |
|
|
/s/ DELOITTE & TOUCHE LLP |
|
Parsippany,Morristown, New Jersey |
February 26, 20182024 |
We have served as the Company's auditor since 1934.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Sole Member of
PSEG Power LLC
Newark, New Jersey
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of PSEG Power LLC and subsidiaries (the “Company”) as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive income, member’s equity, and cash flows for each of the three years in the period ended December 31, 2017, the related notes and the consolidated financial statement schedule listed in the Index at Item 15(B)(c) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
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|
/s/ DELOITTE & TOUCHE LLP |
|
Parsippany, New Jersey |
February 26, 2018 |
We have served as the Company's auditor since 2000.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF OPERATIONS
Millions, except per share data
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| | | 2017 | | 2016 | | 2015 | |
| OPERATING REVENUES | | $ | 9,084 |
| | $ | 9,061 |
| | $ | 10,415 |
| |
| OPERATING EXPENSES | | | | | | | |
| Energy Costs | | 2,800 |
| | 3,001 |
| | 3,261 |
| |
| Operation and Maintenance | | 2,869 |
| | 3,008 |
| | 2,978 |
| |
| Depreciation and Amortization | | 1,986 |
| | 1,476 |
| | 1,214 |
| |
| Total Operating Expenses | | 7,655 |
| | 7,485 |
| | 7,453 |
| |
| OPERATING INCOME | | 1,429 |
| | 1,576 |
| | 2,962 |
| |
| Income from Equity Method Investments | | 14 |
| | 11 |
| | 12 |
| |
| Other Income | | 319 |
| | 191 |
| | 254 |
| |
| Other Deductions | | (91 | ) | | (67 | ) | | (102 | ) | |
| Other-Than-Temporary Impairments | | (12 | ) | | (28 | ) | | (53 | ) | |
| Interest Expense | | (391 | ) | | (385 | ) | | (393 | ) | |
| INCOME BEFORE INCOME TAXES | | 1,268 |
| | 1,298 |
| | 2,680 |
| |
| Income Tax Benefit (Expense) | | 306 |
| | (411 | ) | | (1,001 | ) | |
| NET INCOME | | $ | 1,574 |
| | $ | 887 |
| | $ | 1,679 |
| |
| WEIGHTED AVERAGE COMMON SHARES OUTSTANDING: | | | | | | | |
| BASIC | | 505 |
| | 505 |
| | 505 |
| |
| DILUTED | | 507 |
| | 508 |
| | 508 |
| |
| NET INCOME PER SHARE: | | | | | | | |
| BASIC | | $ | 3.12 |
| | $ | 1.76 |
| | $ | 3.32 |
| |
| DILUTED | | $ | 3.10 |
| | $ | 1.75 |
| | $ | 3.30 |
| |
| | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| | | 2023 | | 2022 | | 2021 | |
| OPERATING REVENUES | | $ | 11,237 | | | $ | 9,800 | | | $ | 9,722 | | |
| OPERATING EXPENSES | | | | | | | |
| Energy Costs | | 3,260 | | | 4,018 | | | 3,499 | | |
| Operation and Maintenance | | 3,150 | | | 3,178 | | | 3,226 | | |
| Depreciation and Amortization | | 1,135 | | | 1,100 | | | 1,216 | | |
| Losses on Asset Dispositions and Impairments | | 7 | | | 123 | | | 2,637 | | |
| Total Operating Expenses | | 7,552 | | | 8,419 | | | 10,578 | | |
| OPERATING INCOME (LOSS) | | 3,685 | | | 1,381 | | | (856) | | |
| Income from Equity Method Investments | | 1 | | | 14 | | | 16 | | |
| Net Gains (Losses) on Trust Investments | | 189 | | | (265) | | | 194 | | |
| Net Other Income (Deductions) | | 172 | | | 124 | | | 98 | | |
| Net Non-Operating Pension and Other Postretirement Benefit (OPEB) (Costs) Credits | | (218) | | | 376 | | | 328 | | |
| Loss on Extinguishment of Debt | | — | | | — | | | (298) | | |
| Interest Expense | | (748) | | | (628) | | | (571) | | |
| INCOME (LOSS) BEFORE INCOME TAXES | | 3,081 | | | 1,002 | | | (1,089) | | |
| Income Tax (Expense) Benefit | | (518) | | | 29 | | | 441 | | |
| NET INCOME (LOSS) | | $ | 2,563 | | | $ | 1,031 | | | $ | (648) | | |
| WEIGHTED AVERAGE COMMON SHARES OUTSTANDING: | | | | | | | |
| BASIC | | 498 | | | 498 | | | 504 | | |
| DILUTED | | 500 | | | 501 | | | 504 | | |
| NET INCOME (LOSS) PER SHARE: | | | | | | | |
| BASIC | | $ | 5.15 | | | $ | 2.07 | | | $ | (1.29) | | |
| DILUTED | | $ | 5.13 | | | $ | 2.06 | | | $ | (1.29) | | |
| | | | | | | | |
| | | | | | | | |
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Millions
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | Years Ended December 31, | |
| | | 2017 | | 2016 | | 2015 | |
| NET INCOME | | $ | 1,574 |
| | $ | 887 |
| | $ | 1,679 |
| |
| Other Comprehensive Income (Loss), net of tax | | | | | | | |
| Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(37), $(41) and $34 for the years ended 2017, 2016 and 2015, respectively | | 44 |
| | 42 |
| | (27 | ) | |
| Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $1, $(1), and $7 for the years ended 2017, 2016 and 2015, respectively | | (2 | ) | | 2 |
| | (10 | ) | |
| Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(4), $8 and $(18) for the years ended 2017, 2016 and 2015, respectively | | (8 | ) | | (12 | ) | | 25 |
| |
| Other Comprehensive Income (Loss), net of tax | | 34 |
| | 32 |
| | (12 | ) | |
| COMPREHENSIVE INCOME | | $ | 1,608 |
| | $ | 919 |
| | $ | 1,667 |
| |
| | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | Years Ended December 31, | |
| | | 2023 | | 2022 | | 2021 | |
| NET INCOME (LOSS) | | $ | 2,563 | | | $ | 1,031 | | | $ | (648) | | |
| Other Comprehensive Income (Loss), net of tax | | | | | | | |
| Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(27), $85 and $25 for the years ended 2023, 2022 and 2021, respectively | | 41 | | | (132) | | | (39) | | |
| Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $(2), $(2) and $(1) for the years ended 2023, 2022 and 2021, respectively | | 6 | | | 3 | | | 3 | | |
| Pension/OPEB adjustment, net of tax (expense) benefit of $(127), $28 and $(75) for the years ended 2023, 2022 and 2021, respectively | | 324 | | | (71) | | | 190 | | |
| Other Comprehensive Income (Loss), net of tax | | 371 | | | (200) | | | 154 | | |
| COMPREHENSIVE INCOME (LOSS) | | $ | 2,934 | | | $ | 831 | | | $ | (494) | | |
| | | | | | | | |
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
Millions
| | | | | | | | | | | | | | | | | |
| | | | | |
| | December 31, | |
| | 2023 | | 2022 | |
| ASSETS | |
| CURRENT ASSETS | | | | |
| Cash and Cash Equivalents | $ | 54 | | | $ | 465 | | |
| Accounts Receivable, net of allowance of $279 in 2023 and $323 in 2022 | 1,482 | | | 1,944 | | |
| Tax Receivable | 10 | | | 79 | | |
| Unbilled Revenues, net of allowance of $4 in 2023 and $16 in 2022 | 244 | | | 322 | | |
| Fuel | 264 | | | 420 | | |
| Materials and Supplies, net | 759 | | | 540 | | |
| Prepayments | 144 | | | 93 | | |
| Derivative Contracts | 112 | | | 18 | | |
| | | | | |
| Regulatory Assets | 273 | | | 369 | | |
| Assets Held for Sale | — | | | 20 | | |
| Other | 31 | | | 33 | | |
| Total Current Assets | 3,373 | | | 4,303 | | |
| PROPERTY, PLANT AND EQUIPMENT | 48,603 | | | 45,924 | | |
| Less: Accumulated Depreciation and Amortization | (10,572) | | | (9,982) | | |
| Net Property, Plant and Equipment | 38,031 | | | 35,942 | | |
| NONCURRENT ASSETS | | | | |
| Regulatory Assets | 5,157 | | | 4,404 | | |
| Operating Lease Right-of-Use Assets | 179 | | | 176 | | |
| Long-Term Investments | 295 | | | 624 | | |
| Nuclear Decommissioning Trust (NDT) Fund | 2,524 | | | 2,230 | | |
| Long-Term Tax Receivable | — | | | 5 | | |
| Long-Term Receivable of Variable Interest Entity | 632 | | | 551 | | |
| Rabbi Trust Fund | 179 | | | 183 | | |
| | | | | |
| Derivative Contracts | 29 | | | 15 | | |
| Other | 342 | | | 285 | | |
| Total Noncurrent Assets | 9,337 | | | 8,473 | | |
| TOTAL ASSETS | $ | 50,741 | | | $ | 48,718 | | |
| | | | | |
|
| | | | | | | | | |
| | | | | |
| | December 31, | |
| | 2017 | | 2016 | |
| ASSETS | |
| CURRENT ASSETS | | | | |
| Cash and Cash Equivalents | $ | 313 |
| | $ | 423 |
| |
| Accounts Receivable, net of allowances of $59 in 2017 and $68 in 2016 | 1,348 |
| | 1,161 |
| |
| Tax Receivable | 127 |
| | 78 |
| |
| Unbilled Revenues | 296 |
| | 260 |
| |
| Fuel | 289 |
| | 326 |
| |
| Materials and Supplies, net | 577 |
| | 561 |
| |
| Prepayments | 118 |
| | 76 |
| |
| Derivative Contracts | 29 |
| | 163 |
| |
| Regulatory Assets | 211 |
| | 199 |
| |
| Other | 4 |
| | 7 |
| |
| Total Current Assets | 3,312 |
| | 3,254 |
| |
| PROPERTY, PLANT AND EQUIPMENT | 41,231 |
| | 39,337 |
| |
| Less: Accumulated Depreciation and Amortization | (9,434 | ) | | (10,051 | ) | |
| Net Property, Plant and Equipment | 31,797 |
| | 29,286 |
| |
| NONCURRENT ASSETS | | | | |
| Regulatory Assets | 3,222 |
| | 3,319 |
| |
| Long-Term Investments | 932 |
| | 1,050 |
| |
| Nuclear Decommissioning Trust (NDT) Fund | 2,133 |
| | 1,859 |
| |
| Long-Term Tax Receivable | — |
| | 104 |
| |
| Long-Term Receivable of VIEs | 686 |
| | 589 |
| |
| Other Special Funds | 231 |
| | 217 |
| |
| Goodwill | 16 |
| | 16 |
| |
| Other Intangibles | 114 |
| | 98 |
| |
| Derivative Contracts | 7 |
| | 24 |
| |
| Other | 266 |
| | 254 |
| |
| Total Noncurrent Assets | 7,607 |
| | 7,530 |
| |
| TOTAL ASSETS | $ | 42,716 |
| | $ | 40,070 |
| |
| | | | | |
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
Millions
|
| | | | | | | | | |
| | | | | |
| | December 31, | |
| | 2017 | | 2016 | |
| LIABILITIES AND CAPITALIZATION | |
| CURRENT LIABILITIES |
| |
| |
| Long-Term Debt Due Within One Year | $ | 1,000 |
| | $ | 500 |
| |
| Commercial Paper and Loans | 542 |
| | 388 |
| |
| Accounts Payable | 1,694 |
| | 1,459 |
| |
| Derivative Contracts | 16 |
| | 13 |
| |
| Accrued Interest | 103 |
| | 97 |
| |
| Accrued Taxes | 48 |
| | 31 |
| |
| Clean Energy Program | 128 |
| | 142 |
| |
| Obligation to Return Cash Collateral | 129 |
| | 132 |
| |
| Regulatory Liabilities | 47 |
| | 88 |
| |
| Other | 461 |
| | 426 |
| |
| Total Current Liabilities | 4,168 |
| | 3,276 |
| |
| NONCURRENT LIABILITIES | | | | |
| Deferred Income Taxes and Investment Tax Credits (ITC) | 5,240 |
| | 8,658 |
| |
| Regulatory Liabilities | 2,948 |
| | 118 |
| |
| Asset Retirement Obligations | 1,024 |
| | 726 |
| |
| Other Postretirement Benefit (OPEB) Costs | 1,455 |
| | 1,324 |
| |
| OPEB Costs of Servco | 542 |
| | 452 |
| |
| Accrued Pension Costs | 537 |
| | 568 |
| |
| Accrued Pension Costs of Servco | 129 |
| | 128 |
| |
| Environmental Costs | 357 |
| | 401 |
| |
| Derivative Contracts | 5 |
| | 3 |
| |
| Long-Term Accrued Taxes | 175 |
| | 180 |
| |
| Other | 221 |
| | 211 |
| |
| Total Noncurrent Liabilities | 12,633 |
| | 12,769 |
| |
| COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13) |
|
| |
| |
| CAPITALIZATION | | | | |
| LONG-TERM DEBT
| 12,068 |
| | 10,895 |
| |
| STOCKHOLDERS’ EQUITY | | | | |
| Common Stock, no par, authorized 1,000 shares; issued, 2017 and 2016— 534 shares | 4,961 |
| | 4,936 |
| |
| Treasury Stock, at cost, 2017 and 2016—29 shares | (763 | ) | | (717 | ) | |
| Retained Earnings | 9,878 |
| | 9,174 |
| |
| Accumulated Other Comprehensive Loss | (229 | ) | | (263 | ) | |
| Total Stockholders’ Equity | 13,847 |
| | 13,130 |
| |
| Total Capitalization | 25,915 |
| | 24,025 |
| |
| TOTAL LIABILITIES AND CAPITALIZATION | $ | 42,716 |
| | $ | 40,070 |
| |
| | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | |
| | December 31, | |
| | 2023 | | 2022 | |
| LIABILITIES AND CAPITALIZATION | |
| CURRENT LIABILITIES | | | | |
| Long-Term Debt Due Within One Year | $ | 1,500 | | | $ | 1,575 | | |
| Commercial Paper and Loans | 949 | | | 2,200 | | |
| Accounts Payable | 1,214 | | | 1,271 | | |
| Derivative Contracts | 86 | | | 124 | | |
| Accrued Interest | 170 | | | 134 | | |
| Accrued Taxes | 8 | | | 12 | | |
| New Jersey Clean Energy Program | 145 | | | 145 | | |
| Obligation to Return Cash Collateral | 89 | | | 290 | | |
| Regulatory Liabilities | 349 | | | 384 | | |
| Other | 547 | | | 545 | | |
| Total Current Liabilities | 5,057 | | | 6,680 | | |
| NONCURRENT LIABILITIES | | | | |
| Deferred Income Taxes and Investment Tax Credits (ITC) | 6,671 | | | 5,725 | | |
| Regulatory Liabilities | 2,075 | | | 2,240 | | |
| Operating Leases | 173 | | | 169 | | |
| Asset Retirement Obligations | 1,468 | | | 1,499 | | |
| Other Postretirement Benefit (OPEB) Costs | 349 | | | 410 | | |
| OPEB Costs of Servco | 514 | | | 455 | | |
| Accrued Pension Costs | 606 | | | 705 | | |
| Accrued Pension Costs of Servco | 102 | | | 82 | | |
| | | | | |
| Environmental Costs | 213 | | | 231 | | |
| Derivative Contracts | 6 | | | 33 | | |
| Long-Term Accrued Taxes | 45 | | | 66 | | |
| Other | 201 | | | 199 | | |
| Total Noncurrent Liabilities | 12,423 | | | 11,814 | | |
| COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13) | | | | |
| CAPITALIZATION | | | | |
| LONG-TERM DEBT
| 17,784 | | | 16,495 | | |
| STOCKHOLDERS’ EQUITY | | | | |
| Common Stock, no par, authorized 1,000 shares; issued, 2023 and 2022—534 shares | 5,018 | | | 5,065 | | |
| Treasury Stock, at cost, 2023 and 2022—36 and 37 shares, respectively | (1,379) | | | (1,377) | | |
| Retained Earnings | 12,017 | | | 10,591 | | |
| Accumulated Other Comprehensive Loss | (179) | | | (550) | | |
| | | | | |
| | | | | |
| Total Stockholders’ Equity | 15,477 | | | 13,729 | | |
| Total Capitalization | 33,261 | | | 30,224 | | |
| TOTAL LIABILITIES AND CAPITALIZATION | $ | 50,741 | | | $ | 48,718 | | |
| | | | | |
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| | | 2017 | | 2016 | | 2015 | |
| CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | |
| Net Income | | $ | 1,574 |
| | $ | 887 |
| | $ | 1,679 |
| |
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | |
| Depreciation and Amortization | | 1,986 |
| | 1,476 |
| | 1,214 |
| |
| Amortization of Nuclear Fuel | | 199 |
| | 203 |
| | 213 |
| |
| Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual | | 103 |
| | 109 |
| | 104 |
| |
| Impairment Costs for Early Plant Retirements | | — |
| | 102 |
| | — |
| |
| Provision for Deferred Income Taxes (Other than Leases) and ITC | | (167 | ) | | 474 |
| | 685 |
| |
| Non-Cash Employee Benefit Plan Costs | | 89 |
| | 127 |
| | 161 |
| |
| Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes | | (159 | ) | | (6 | ) | | 26 |
| |
| Net (Gain) Loss on Lease Investments | | 48 |
| | 92 |
| | — |
| |
| Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives | | 188 |
| | 183 |
| | (143 | ) | |
| Net Change in Regulatory Assets and Liabilities | | (188 | ) | | (138 | ) | | (48 | ) | |
| Cost of Removal | | (107 | ) | | (131 | ) | | (120 | ) | |
| Net Realized (Gains) Losses and (Income) Expense from NDT Fund | | (156 | ) | | (26 | ) | | (38 | ) | |
| Net Change in Certain Current Assets and Liabilities | | | | | | | |
| Tax Receivable | | 65 |
| | 303 |
| | (94 | ) | |
| Accrued Taxes | | 16 |
| | 3 |
| | (91 | ) | |
| Margin Deposit | | (90 | ) | | (76 | ) | | 122 |
| |
| Other Current Assets and Liabilities | | (70 | ) | | (180 | ) | | 288 |
| |
| Employee Benefit Plan Funding and Related Payments | | (81 | ) | | (103 | ) | | (109 | ) | |
| Other | | 11 |
| | 12 |
| | 70 |
| |
| Net Cash Provided By (Used In) Operating Activities | | 3,261 |
| | 3,311 |
| | 3,919 |
| |
| CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | |
| Additions to Property, Plant and Equipment | | (4,190 | ) | | (4,199 | ) | | (3,863 | ) | |
| Purchase of Emissions Allowances and RECs | | (117 | ) | | (99 | ) | | (106 | ) | |
| Proceeds from Sales of Available-for-Sale Securities | | 2,319 |
| | 824 |
| | 1,501 |
| |
| Investments in Available-for-Sale Securities | | (2,340 | ) | | (856 | ) | | (1,552 | ) | |
| Other | | 72 |
| | 82 |
| | 78 |
| |
| Net Cash Provided By (Used In) Investing Activities | | (4,256 | ) | | (4,248 | ) | | (3,942 | ) | |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | |
| Net Change in Commercial Paper and Loans | | 154 |
| | 24 |
| | 364 |
| |
| Issuance of Long-Term Debt | | 2,175 |
| | 2,675 |
| | 1,350 |
| |
| Redemption of Long-Term Debt | | (500 | ) | | (824 | ) | | (600 | ) | |
| Redemption of Securitization Debt | | — |
| | — |
| | (259 | ) | |
| Cash Dividends Paid on Common Stock | | (870 | ) | | (830 | ) | | (789 | ) | |
| Other | | (74 | ) | | (79 | ) | | (51 | ) | |
| Net Cash Provided By (Used In) Financing Activities | | 885 |
| | 966 |
| | 15 |
| |
| Net Increase (Decrease) in Cash and Cash Equivalents | | (110 | ) | | 29 |
| | (8 | ) | |
| Cash and Cash Equivalents at Beginning of Period | | 423 |
| | 394 |
| | 402 |
| |
| Cash and Cash Equivalents at End of Period | | $ | 313 |
| | $ | 423 |
| | $ | 394 |
| |
| Supplemental Disclosure of Cash Flow Information: | | | | | | | |
| Income Taxes Paid (Received) | | $ | (8 | ) | | $ | (245 | ) | | $ | 447 |
| |
| Interest Paid, Net of Amounts Capitalized | | $ | 377 |
| | $ | 365 |
| | $ | 381 |
| |
| Accrued Property, Plant and Equipment Expenditures | | $ | 722 |
| | $ | 664 |
| | $ | 510 |
| |
| | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| CASH FLOWS FROM OPERATING ACTIVITIES | | 2023 | | 2022 | | 2021 | |
| | | | | | | | |
| | | | | | | | |
| Net Income (Loss) | | $ | 2,563 | | | $ | 1,031 | | | $ | (648) | | |
| Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities: | | | | | | | |
| Depreciation and Amortization | | 1,135 | | | 1,100 | | | 1,216 | | |
| Amortization of Nuclear Fuel | | 189 | | | 183 | | | 187 | | |
| (Gains) Losses on Asset Dispositions and Impairments | | 7 | | | 123 | | | 2,637 | | |
| Loss on Extinguishment of Debt | | — | | | — | | | 298 | | |
| Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual | | 3 | | | 55 | | | 138 | | |
| Provision for Deferred Income Taxes and ITC | | 355 | | | (261) | | | (845) | | |
| Non-Cash Employee Benefit Plan (Credits) Costs | | 366 | | | (239) | | | (178) | | |
| Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives | | (1,333) | | | 639 | | | 614 | | |
| Cost of Removal | | (166) | | | (129) | | | (121) | | |
| Energy Efficiency Programs Regulatory Investment Expenditures | | (466) | | | (286) | | | (117) | | |
| Amortization of Energy Efficiency Programs Regulatory Investment Expenditures | | 82 | | | 48 | | | 31 | | |
| Net Change in Other Regulatory Assets and Liabilities | | 2 | | | (78) | | | (185) | | |
| Net (Gains) Losses and (Income) Expense from NDT Fund | | (248) | | | 202 | | | (229) | | |
| Net Change in Certain Current Assets and Liabilities: | | | | | | | |
| Cash Collateral | | 1,408 | | | (677) | | | (790) | | |
| Obligation to Return Cash Collateral | | (201) | | | 111 | | | 81 | | |
| Accrued Taxes | | (10) | | | (94) | | | (127) | | |
| Other Current Assets and Liabilities | | 110 | | | (187) | | | (263) | | |
| Employee Benefit Plan Funding and Related Payments | | (40) | | | (35) | | | (25) | | |
| Other | | 50 | | | (3) | | | 62 | | |
| Net Cash Provided By (Used In) Operating Activities | | 3,806 | | | 1,503 | | | 1,736 | | |
| CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | |
| Additions to Property, Plant and Equipment | | (3,325) | | | (2,888) | | | (2,719) | | |
| Proceeds from Sales of Trust Investments | | 1,714 | | | 1,586 | | | 2,100 | | |
| Purchases of Trust Investments | | (1,751) | | | (1,611) | | | (2,092) | | |
| Proceeds from Sales of Long-Lived Assets and Lease Investments | | 37 | | | 1,918 | | | 569 | | |
| Proceeds from Sales of Equity Method Investments | | 291 | | | — | | | — | | |
| Contributions to Equity Method Investments | | — | | | (124) | | | (111) | | |
| Other | | 76 | | | 18 | | | 9 | | |
| Net Cash Provided By (Used In) Investing Activities | | (2,958) | | | (1,101) | | | (2,244) | | |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | |
| Net Change in Commercial Paper | | 250 | | | (819) | | | 256 | | |
| Proceeds from Short-Term Loans | | 750 | | | 2,000 | | | 2,500 | | |
| Repayment of Short-Term Loans | | (2,250) | | | (2,500) | | | (300) | | |
| Issuance of Long-Term Debt | | 2,800 | | | 2,850 | | | 2,825 | | |
| Redemption of Long-Term Debt | | (1,575) | | | (700) | | | (3,082) | | |
| Payments for Share Repurchase Program | | — | | | (500) | | | — | | |
| Premium Paid on Early Extinguishment of Debt | | — | | | — | | | (294) | | |
| Cash Dividends Paid on Common Stock | | (1,137) | | | (1,079) | | | (1,031) | | |
| Other | | (98) | | | (6) | | | (75) | | |
| Net Cash Provided By (Used In) Financing Activities | | (1,260) | | | (754) | | | 799 | | |
| Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | | (412) | | | (352) | | | 291 | | |
| Cash, Cash Equivalents and Restricted Cash at Beginning of Period | | 511 | | | 863 | | | 572 | | |
| Cash, Cash Equivalents and Restricted Cash at End of Period | | $ | 99 | | | $ | 511 | | | $ | 863 | | |
| Supplemental Disclosure of Cash Flow Information: | | | | | | | |
| Income Taxes Paid (Received) | | $ | 144 | | | $ | 353 | | | $ | 425 | | |
| Interest Paid, Net of Amounts Capitalized | | $ | 683 | | | $ | 602 | | | $ | 547 | | |
| Accrued Property, Plant and Equipment Expenditures | | $ | 443 | | | $ | 366 | | | $ | 331 | | |
| | | | | | | | |
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
Millions
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | Common Stock | | Treasury Stock | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Noncontrolling Interest | |
| | | Shs. | | Amount | | Shs. | | Amount | | | Total | |
| Balance as of January 1, 2015 | | 534 |
| | $ | 4,876 |
| | (28 | ) | | $ | (635 | ) | | $ | 8,227 |
| | $ | (283 | ) | | $ | 1 |
| | $ | 12,186 |
| |
| Net Income | | — |
| | — |
| | — |
| | — |
| | 1,679 |
| | — |
| | — |
| | 1,679 |
| |
| Other Comprehensive Income (Loss), net of tax (expense) benefit of $23 | | — |
| | — |
| | — |
| | — |
| | — |
| | (12 | ) | | — |
| | (12 | ) | |
| Comprehensive Income | | | | | | | | | | | | | | | | 1,667 |
| |
| Cash Dividends on Common Stock | | — |
| | — |
| | — |
| | — |
| | (789 | ) | | — |
| | — |
| | (789 | ) | |
| Other | | — |
| | 39 |
| | — |
| | (36 | ) | | — |
| | — |
| | — |
| | 3 |
| |
| Balance as of December 31, 2015 | | 534 |
| | $ | 4,915 |
| | (28 | ) | | $ | (671 | ) | | $ | 9,117 |
| | $ | (295 | ) | | $ | 1 |
| | $ | 13,067 |
| |
| Net Income | | — |
| | — |
| | — |
| | — |
| | 887 |
| | — |
| | — |
| | 887 |
| |
| Other Comprehensive Income (Loss), net of tax (expense) benefit of $(34) | | — |
| | — |
| | — |
| | — |
| | — |
| | 32 |
| | — |
| | 32 |
| |
| Comprehensive Income | | | | | | | | | | | | | | | | 919 |
| |
| Cash Dividends on Common Stock | | — |
| | — |
| | — |
| | — |
| | (830 | ) | | — |
| | — |
| | (830 | ) | |
| Other | | — |
| | 21 |
| | (1 | ) | | (46 | ) | | — |
| | — |
| | (1 | ) | | (26 | ) | |
| Balance as of December 31, 2016 | | 534 |
| | $ | 4,936 |
| | (29 | ) | | $ | (717 | ) | | $ | 9,174 |
| | $ | (263 | ) | | $ | — |
| | $ | 13,130 |
| |
| Net Income | | — |
| | — |
| | — |
| | — |
| | 1,574 |
| | — |
| | — |
| | 1,574 |
| |
| Other Comprehensive Income (Loss), net of tax (expense) benefit of $(40) | | — |
| | — |
| | — |
| | — |
| | — |
| | 34 |
| | — |
| | 34 |
| |
| Comprehensive Income | | | | | | | | | | | | | | | | 1,608 |
| |
| Cash Dividends on Common Stock | | — |
| | — |
| | — |
| | — |
| | (870 | ) | | — |
| | — |
| | (870 | ) | |
| Other | | — |
| | 25 |
| | — |
| | (46 | ) | | — |
| | — |
| | — |
| | (21 | ) | |
| Balance as of December 31, 2017 | | 534 |
| | $ | 4,961 |
| | (29 | ) | | $ | (763 | ) | | $ | 9,878 |
| | $ | (229 | ) | | $ | — |
| | $ | 13,847 |
| |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | Common Stock | | Treasury Stock | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | |
| | | Shs. | | Amount | | Shs. | | Amount | | Total | |
| Balance as of December 31, 2020 | | 534 | | | $ | 5,031 | | | (30) | | | $ | (861) | | | $ | 12,318 | | | $ | (504) | | | $ | 15,984 | | |
| Net Loss | | — | | | — | | | — | | | — | | | (648) | | | — | | | (648) | | |
| Other Comprehensive Income (Loss), net of tax (expense) benefit of $(51) | | — | | | — | | | — | | | — | | | — | | | 154 | | | 154 | | |
| Comprehensive Loss | | | | | | | | | | | | | | (494) | | |
| Cash Dividends at $2.04 per share on Common Stock | | — | | | — | | | — | | | — | | | (1,031) | | | — | | | (1,031) | | |
| Other | | — | | | 14 | | | — | | | (35) | | | — | | | — | | | (21) | | |
| Balance as of December 31, 2021 | | 534 | | | $ | 5,045 | | | (30) | | | $ | (896) | | | $ | 10,639 | | | $ | (350) | | | $ | 14,438 | | |
| Net Income | | — | | | — | | | — | | | — | | | 1,031 | | | — | | | 1,031 | | |
| Other Comprehensive Income (Loss), net of tax (expense) benefit of $111 | | — | | | — | | | — | | | — | | | — | | | (200) | | | (200) | | |
| Comprehensive Income | | | | | | | | | | | | | | 831 | | |
| Cash Dividends at $2.16 per share on Common Stock | | — | | | — | | | — | | | | | (1,079) | | | — | | | (1,079) | | |
| Payments for Share Repurchase Program | | — | | | — | | | (7) | | | (500) | | | — | | | — | | | (500) | | |
| Other | | — | | | 20 | | | — | | | 19 | | | — | | | — | | | 39 | | |
| Balance as of December 31, 2022 | | 534 | | | $ | 5,065 | | | (37) | | | $ | (1,377) | | | $ | 10,591 | | | $ | (550) | | | $ | 13,729 | | |
| Net Income | | — | | | — | | | — | | | — | | | 2,563 | | | — | | | 2,563 | | |
| Other Comprehensive Income (Loss), net of tax (expense) benefit of $(156) | | — | | | — | | | — | | | — | | | — | | | 371 | | | 371 | | |
| Comprehensive Income | | | | | | | | | | | | | | 2,934 | | |
| | | | | | | | | | | | | | | | |
| Cash Dividends at $2.28 per share on Common Stock | | — | | | — | | | — | | | — | | | (1,137) | | | — | | | (1,137) | | |
| | | | | | | | | | | | | | | | |
| Other | | — | | | (47) | | | 1 | | | (2) | | | — | | | — | | | (49) | | |
| Balance as of December 31, 2023 | | 534 | | | $ | 5,018 | | | (36) | | | $ | (1,379) | | | $ | 12,017 | | | $ | (179) | | | $ | 15,477 | | |
| | | | | | | | | | | | | | | | |
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
Millions
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| | | 2017 | | 2016 | | 2015 | |
| OPERATING REVENUES | | $ | 6,234 |
| | $ | 6,221 |
| | $ | 6,636 |
| |
| OPERATING EXPENSES | | | | | | | |
| Energy Costs | | 2,363 |
| | 2,567 |
| | 2,722 |
| |
| Operation and Maintenance | | 1,434 |
| | 1,475 |
| | 1,560 |
| |
| Depreciation and Amortization | | 685 |
| | 565 |
| | 892 |
| |
| Total Operating Expenses | | 4,482 |
| | 4,607 |
| | 5,174 |
| |
| OPERATING INCOME | | 1,752 |
| | 1,614 |
| | 1,462 |
| |
| Other Income | | 92 |
| | 83 |
| | 79 |
| |
| Other Deductions | | (5 | ) | | (4 | ) | | (4 | ) | |
| Interest Expense | | (303 | ) | | (289 | ) | | (280 | ) | |
| INCOME BEFORE INCOME TAXES | | 1,536 |
| | 1,404 |
| | 1,257 |
| |
| Income Tax Expense | | (563 | ) | | (515 | ) | | (470 | ) | |
| NET INCOME | | $ | 973 |
| | $ | 889 |
| | $ | 787 |
| |
| | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| | | 2023 | | 2022 | | 2021 | |
| OPERATING REVENUES | | $ | 7,807 | | | $ | 7,935 | | | $ | 7,122 | | |
| OPERATING EXPENSES | | | | | | | |
| Energy Costs | | 3,010 | | | 3,270 | | | 2,688 | | |
| Operation and Maintenance | | 1,843 | | | 1,838 | | | 1,692 | | |
| Depreciation and Amortization | | 980 | | | 935 | | | 928 | | |
| Gain on Asset Dispositions | | — | | | — | | | (4) | | |
| Total Operating Expenses | | 5,833 | | | 6,043 | | | 5,304 | | |
| OPERATING INCOME | | 1,974 | | | 1,892 | | | 1,818 | | |
| Net Gains (Losses) on Trust Investments | | — | | | (2) | | | 2 | | |
| Net Other Income (Deductions) | | 80 | | | 88 | | | 88 | | |
| Net Non-Operating Pension and OPEB Credits | | 114 | | | 281 | | | 264 | | |
| Interest Expense | | (493) | | | (427) | | | (402) | | |
| INCOME BEFORE INCOME TAXES | | 1,675 | | | 1,832 | | | 1,770 | | |
| Income Tax Expense | | (160) | | | (267) | | | (324) | | |
| NET INCOME | | $ | 1,515 | | | $ | 1,565 | | | $ | 1,446 | | |
| | | | | | | | |
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Millions
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | Years Ended December 31, | |
| | | 2017 | | 2016 | | 2015 | |
| NET INCOME | | $ | 973 |
| | $ | 889 |
| | $ | 787 |
| |
| Other Comprehensive Income (Loss), net of tax | | | | | | | |
| Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0, $0 and $0 for the years ended 2017, 2016 and 2015, respectively | | (1 | ) | | — |
| | (1 | ) | |
| COMPREHENSIVE INCOME | | $ | 972 |
| | $ | 889 |
| | $ | 786 |
| |
| | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | Years Ended December 31, | |
| | | 2023 | | 2022 | | 2021 | |
| NET INCOME | | $ | 1,515 | | | $ | 1,565 | | | $ | 1,446 | | |
| Other Comprehensive Income (Loss), net of tax | | | | | | | |
| Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0, $2 and $1 for the years ended 2023, 2022 and 2021, respectively | | 1 | | | (6) | | | (2) | | |
| COMPREHENSIVE INCOME | | $ | 1,516 | | | $ | 1,559 | | | $ | 1,444 | | |
| | | | | | | | |
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Millions
|
| | | | | | | | | |
| | | | | |
| | December 31, | |
| | 2017 | | 2016 | |
| ASSETS | |
| CURRENT ASSETS | | | | |
| Cash and Cash Equivalents | $ | 242 |
| | $ | 390 |
| |
| Accounts Receivable, net of allowances of $59 in 2017 and $68 in 2016 | 882 |
| | 810 |
| |
| Accounts Receivable—Affiliated Companies | — |
| | 76 |
| |
| Unbilled Revenues | 296 |
| | 260 |
| |
| Materials and Supplies | 197 |
| | 180 |
| |
| Prepayments | 44 |
| | 9 |
| |
| Regulatory Assets | 211 |
| | 199 |
| |
| Other | 4 |
| | 6 |
| |
| Total Current Assets | 1,876 |
| | 1,930 |
| |
| PROPERTY, PLANT AND EQUIPMENT | 29,117 |
| | 26,347 |
| |
| Less: Accumulated Depreciation and Amortization | (6,101 | ) | | (5,760 | ) | |
| Net Property, Plant and Equipment | 23,016 |
| | 20,587 |
| |
| NONCURRENT ASSETS | | | | |
| Regulatory Assets | 3,222 |
| | 3,319 |
| |
| Long-Term Investments | 280 |
| | 299 |
| |
| Other Special Funds | 46 |
| | 43 |
| |
| Other | 114 |
| | 110 |
| |
| Total Noncurrent Assets | 3,662 |
| | 3,771 |
| |
| TOTAL ASSETS | $ | 28,554 |
| | $ | 26,288 |
| |
| | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | |
| | December 31, | |
| | 2023 | | 2022 | |
| ASSETS | |
| CURRENT ASSETS | | | | |
| Cash and Cash Equivalents | $ | 30 | | | $ | 220 | | |
| Accounts Receivable, net of allowance of $279 in 2023 and $323 in 2022 | 1,076 | | | 1,075 | | |
| | | | | |
| | | | | |
| Unbilled Revenues, net of allowance of $4 in 2023 and $16 in 2022 | 244 | | | 322 | | |
| Materials and Supplies, net | 519 | | | 307 | | |
| Prepayments | 57 | | | 7 | | |
| Regulatory Assets | 273 | | | 369 | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Other | 31 | | | 32 | | |
| Total Current Assets | 2,230 | | | 2,332 | | |
| PROPERTY, PLANT AND EQUIPMENT | 43,753 | | | 41,045 | | |
| Less: Accumulated Depreciation and Amortization | (8,711) | | | (8,215) | | |
| Net Property, Plant and Equipment | 35,042 | | | 32,830 | | |
| NONCURRENT ASSETS | | | | |
| Regulatory Assets | 5,157 | | | 4,404 | | |
| Operating Lease Right-of-Use Assets | 99 | | | 86 | | |
| Long-Term Investments | 117 | | | 143 | | |
| Rabbi Trust Fund | 32 | | | 32 | | |
| | | | | |
| | | | | |
| Other | 196 | | | 133 | | |
| Total Noncurrent Assets | 5,601 | | | 4,798 | | |
| TOTAL ASSETS | $ | 42,873 | | | $ | 39,960 | | |
| | | | | |
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Millions
|
| | | | | | | | | |
| | | | | |
| | December 31, | |
| | 2017 | | 2016 | |
| LIABILITIES AND CAPITALIZATION | |
| CURRENT LIABILITIES | | | | |
| Long-Term Debt Due Within One Year | $ | 750 |
| | $ | — |
| |
| Accounts Payable | 728 |
| | 718 |
| |
| Accounts Payable—Affiliated Companies | 340 |
| | 260 |
| |
| Accrued Interest | 78 |
| | 76 |
| |
| Clean Energy Program | 128 |
| | 142 |
| |
| Derivative Contracts | — |
| | 5 |
| |
| Obligation to Return Cash Collateral | 129 |
| | 132 |
| |
| Regulatory Liabilities | 47 |
| | 88 |
| |
| Other | 311 |
| | 296 |
| |
| Total Current Liabilities | 2,511 |
| | 1,717 |
| |
| NONCURRENT LIABILITIES | | | | |
| Deferred Income Taxes and ITC | 3,391 |
| | 5,873 |
| |
| OPEB Costs | 1,103 |
| | 1,009 |
| |
| Accrued Pension Costs | 226 |
| | 250 |
| |
| Regulatory Liabilities | 2,948 |
| | 118 |
| |
| Environmental Costs | 283 |
| | 332 |
| |
| Asset Retirement Obligations | 212 |
| | 213 |
| |
| Long-Term Accrued Taxes | 91 |
| | 130 |
| |
| Other | 114 |
| | 116 |
| |
| Total Noncurrent Liabilities | 8,368 |
| | 8,041 |
| |
| COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13) |
| |
| |
| CAPITALIZATION |
| | | |
| LONG-TERM DEBT | 7,841 |
| | 7,818 |
| |
| STOCKHOLDER’S EQUITY | | | | |
| Common Stock; 150 shares authorized; issued and outstanding, 2017 and 2016—132 shares | 892 |
| | 892 |
| |
| Contributed Capital | 1,095 |
| | 945 |
| |
| Basis Adjustment | 986 |
| | 986 |
| |
| Retained Earnings | 6,861 |
| | 5,888 |
| |
| Accumulated Other Comprehensive Income | — |
| | 1 |
| |
| Total Stockholder’s Equity | 9,834 |
| | 8,712 |
| |
| Total Capitalization | 17,675 |
| | 16,530 |
| |
| TOTAL LIABILITIES AND CAPITALIZATION | $ | 28,554 |
| | $ | 26,288 |
| |
| | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | |
| | December 31, | |
| | 2023 | | 2022 | |
| LIABILITIES AND CAPITALIZATION | |
| CURRENT LIABILITIES | | | | |
| Long-Term Debt Due Within One Year | $ | 750 | | | $ | 825 | | |
| Commercial Paper and Loans | 425 | | | — | | |
| Accounts Payable | 780 | | | 703 | | |
| | | | | |
| Accounts Payable—Affiliated Companies | 504 | | | 485 | | |
| Accrued Interest | 139 | | | 113 | | |
| New Jersey Clean Energy Program | 145 | | | 145 | | |
| | | | | |
| Obligation to Return Cash Collateral | 89 | | | 290 | | |
| Regulatory Liabilities | 349 | | | 384 | | |
| Other | 434 | | | 416 | | |
| Total Current Liabilities | 3,615 | | | 3,361 | | |
| NONCURRENT LIABILITIES | | | | |
| Deferred Income Taxes and ITC | 5,813 | | | 5,348 | | |
| Regulatory Liabilities | 2,075 | | | 2,240 | | |
| Operating Leases | 89 | | | 77 | | |
| Asset Retirement Obligations | 401 | | | 384 | | |
| OPEB Costs | 210 | | | 255 | | |
| Accrued Pension Costs | 396 | | | 397 | | |
| | | | | |
| | | | | |
| Environmental Costs | 151 | | | 173 | | |
| | | | | |
| Long-Term Accrued Taxes | 2 | | | 9 | | |
| Other | 160 | | | 163 | | |
| Total Noncurrent Liabilities | 9,297 | | | 9,046 | | |
| COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13) | | | | |
| CAPITALIZATION | | | | |
| LONG-TERM DEBT | 12,913 | | | 11,871 | | |
| STOCKHOLDER’S EQUITY | | | | |
| Common Stock; 150 shares authorized; issued and outstanding, 2023 and 2022—132 shares | 892 | | | 892 | | |
| Contributed Capital | 2,156 | | | 2,156 | | |
| Retained Earnings | 14,004 | | | 12,639 | | |
| Accumulated Other Comprehensive Loss | (4) | | | (5) | | |
| Total Stockholder’s Equity | 17,048 | | | 15,682 | | |
| Total Capitalization | 29,961 | | | 27,553 | | |
| TOTAL LIABILITIES AND CAPITALIZATION | $ | 42,873 | | | $ | 39,960 | | |
| | | | | |
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| | | 2017 | | 2016 | | 2015 | |
| CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | |
| Net Income | | $ | 973 |
| | $ | 889 |
| | $ | 787 |
| |
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | |
| Depreciation and Amortization | | 685 |
| | 565 |
| | 892 |
| |
| Provision for Deferred Income Taxes and ITC | | 616 |
| | 658 |
| | 386 |
| |
| Non-Cash Employee Benefit Plan Costs | | 50 |
| | 72 |
| | 95 |
| |
| Cost of Removal | | (107 | ) | | (131 | ) | | (120 | ) | |
| Net Change in Other Regulatory Assets and Liabilities | | (188 | ) | | (138 | ) | | (48 | ) | |
| Net Change in Certain Current Assets and Liabilities | | | | | | | |
| Accounts Receivable and Unbilled Revenues | | (106 | ) | | (84 | ) | | 165 |
| |
| Materials and Supplies | | (13 | ) | | (7 | ) | | (15 | ) | |
| Prepayments | | (35 | ) | | 22 |
| | 11 |
| |
| Accounts Payable | | 1 |
| | (29 | ) | | 45 |
| |
| Accounts Receivable/Payable—Affiliated Companies, net | | 101 |
| | 199 |
| | — |
| |
| Other Current Assets and Liabilities | | 17 |
| | 8 |
| | (29 | ) | |
| Employee Benefit Plan Funding and Related Payments | | (68 | ) | | (82 | ) | | (91 | ) | |
| Other | | (87 | ) | | (48 | ) | | 47 |
| |
| Net Cash Provided By (Used In) Operating Activities | | 1,839 |
| | 1,894 |
| | 2,125 |
| |
| CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | |
| Additions to Property, Plant and Equipment | | (2,919 | ) | | (2,816 | ) | | (2,692 | ) | |
| Proceeds from Sales of Available-for-Sale Securities | | 36 |
| | 22 |
| | 21 |
| |
| Investments in Available-for-Sale Securities | | (37 | ) | | (24 | ) | | (22 | ) | |
| Solar Loan Investments | | 7 |
| | 14 |
| | 11 |
| |
| Other | | 10 |
| | 15 |
| | 11 |
| |
| Net Cash Provided By (Used In) Investing Activities | | (2,903 | ) | | (2,789 | ) | | (2,671 | ) | |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | |
| Net Change in Short-Term Debt | | — |
| | (153 | ) | | 153 |
| |
| Issuance of Long-Term Debt | | 775 |
| | 1,275 |
| | 850 |
| |
| Redemption of Long-Term Debt | | — |
| | (271 | ) | | (300 | ) | |
| Redemption of Securitization Debt | | — |
| | — |
| | (259 | ) | |
| Contributed Capital | | 150 |
| | 250 |
| | — |
| |
| Other | | (9 | ) | | (14 | ) | | (10 | ) | |
| Net Cash Provided By (Used In) Financing Activities | | 916 |
| | 1,087 |
| | 434 |
| |
| Net Increase (Decrease) in Cash and Cash Equivalents | | (148 | ) | | 192 |
| | (112 | ) | |
| Cash and Cash Equivalents at Beginning of Period | | 390 |
| | 198 |
| | 310 |
| |
| Cash and Cash Equivalents at End of Period | | $ | 242 |
| | $ | 390 |
| | $ | 198 |
| |
| Supplemental Disclosure of Cash Flow Information: | | | | | | | |
| Income Taxes Paid (Received) | | $ | (104 | ) | | $ | (295 | ) | | $ | (28 | ) | |
| Interest Paid, Net of Amounts Capitalized | | $ | 294 |
| | $ | 273 |
| | $ | 261 |
| |
| Accrued Property, Plant and Equipment Expenditures | | $ | 429 |
| | $ | 420 |
| | $ | 396 |
| |
| | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| | | 2023 | | 2022 | | 2021 | |
| CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | |
| Net Income | | $ | 1,515 | | | $ | 1,565 | | | $ | 1,446 | | |
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | |
| Depreciation and Amortization | | 980 | | | 935 | | | 928 | | |
| | | | | | | | |
| Provision for Deferred Income Taxes and ITC | | 29 | | | 137 | | | 116 | | |
| Non-Cash Employee Benefit Plan (Credits) Costs | | 8 | | | (179) | | | (156) | | |
| Cost of Removal | | (166) | | | (129) | | | (121) | | |
| Energy Efficiency Programs Regulatory Investment Expenditures | | (466) | | | (286) | | | (117) | | |
| Amortization of Energy Efficiency Programs Regulatory Investment Expenditures | | 82 | | | 48 | | | 31 | | |
| Net Change in Other Regulatory Assets and Liabilities | | 2 | | | (78) | | | (185) | | |
| Net Change in Certain Current Assets and Liabilities | | | | | | | |
| Accounts Receivable and Unbilled Revenues | | 72 | | | (132) | | | (34) | | |
| Materials and Supplies | | (211) | | | (73) | | | (16) | | |
| Prepayments | | (50) | | | 8 | | | (1) | | |
| Accounts Payable | | 13 | | | 96 | | | (71) | | |
| Accounts Receivable/Payable—Affiliated Companies, net | | (3) | | | 18 | | | (32) | | |
| Obligation to Return Cash Collateral | | (201) | | | 111 | | | 81 | | |
| Other Current Assets and Liabilities | | 23 | | | 44 | | | (71) | | |
| Employee Benefit Plan Funding and Related Payments | | (20) | | | (17) | | | (10) | | |
| Other | | (67) | | | (40) | | | (64) | | |
| Net Cash Provided By (Used In) Operating Activities | | 1,540 | | | 2,028 | | | 1,724 | | |
| CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | |
| Additions to Property, Plant and Equipment | | (2,998) | | | (2,590) | | | (2,447) | | |
| Proceeds from Sales of Trust Investments | | 4 | | | 12 | | | 35 | | |
| Purchases of Trust Investments | | (3) | | | (10) | | | (29) | | |
| Solar Loan Investments | | 27 | | | 34 | | | 29 | | |
| Other | | 6 | | | 11 | | | 16 | | |
| Net Cash Provided By (Used In) Investing Activities | | (2,964) | | | (2,543) | | | (2,396) | | |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | |
| Net Change in Commercial Paper and Loans | | 425 | | | — | | | (100) | | |
| Issuance of Long-Term Debt | | 1,800 | | | 900 | | | 1,325 | | |
| Redemption of Long-Term Debt | | (825) | | | — | | | (434) | | |
| | | | | | | | |
| Cash Dividends Paid | | (150) | | | (450) | | | — | | |
| Other | | (17) | | | (8) | | | (13) | | |
| Net Cash Provided By (Used In) Financing Activities | | 1,233 | | | 442 | | | 778 | | |
| Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | | (191) | | | (73) | | | 106 | | |
| Cash, Cash Equivalents and Restricted Cash at Beginning of Period | | 266 | | | 339 | | | 233 | | |
| Cash, Cash Equivalents and Restricted Cash at End of Period | | $ | 75 | | | $ | 266 | | | $ | 339 | | |
| Supplemental Disclosure of Cash Flow Information: | | | | | | | |
| Income Taxes Paid (Received) | | $ | 77 | | | $ | 137 | | | $ | 266 | | |
| Interest Paid, Net of Amounts Capitalized | | $ | 449 | | | $ | 409 | | | $ | 383 | | |
| Accrued Property, Plant and Equipment Expenditures | | $ | 395 | | | $ | 331 | | | $ | 294 | | |
| | | | | | | | |
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
Millions
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | Common Stock | | Contributed Capital | | Basis Adjustment | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total | |
| Balance as of January 1, 2015 | | $ | 892 |
| | $ | 695 |
| | $ | 986 |
| | $ | 4,212 |
| | $ | 2 |
| | $ | 6,787 |
| |
| Net Income | | — |
| | — |
| | — |
| | 787 |
| | — |
| | 787 |
| |
| Other Comprehensive Income, net of tax (expense) benefit of $0 | | — |
| | — |
| | — |
| | — |
| | (1 | ) | | (1 | ) | |
| Comprehensive Income | | | | | | | | | | |
| 786 |
| |
| Balance as of December 31, 2015 | | $ | 892 |
| | $ | 695 |
| | $ | 986 |
| | $ | 4,999 |
| | $ | 1 |
| | $ | 7,573 |
| |
| Net Income | | — |
| | — |
| | — |
| | 889 |
| | — |
| | 889 |
| |
| Other Comprehensive Income, net of tax (expense) benefit of $0 | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
| Comprehensive Income | | | | | | | | | | |
| 889 |
| |
| Contributed Capital | |
| | 250 |
| | — |
| | — |
| | — |
| | 250 |
| |
| Balance as of December 31, 2016 | | $ | 892 |
| | $ | 945 |
| | $ | 986 |
| | $ | 5,888 |
| | $ | 1 |
| | $ | 8,712 |
| |
| Net Income | | — |
| | — |
| | — |
| | 973 |
| | — |
| | 973 |
| |
| Other Comprehensive Income, net of tax (expense) benefit of $0 | | — |
| | — |
| | — |
| | — |
| | (1 | ) | | (1 | ) | |
| Comprehensive Income | | | | | | | | | | |
| 972 |
| |
| Contributed Capital | | — |
| | 150 |
| | — |
| | — |
| | — |
| | 150 |
| |
| Balance as of December 31, 2017 | | $ | 892 |
| | $ | 1,095 |
| | $ | 986 |
| | $ | 6,861 |
| | $ | — |
| | $ | 9,834 |
| |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | Common Stock | | Contributed Capital | | | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total | |
| Balance as of December 31, 2020 | | $ | 892 | | | $ | 2,156 | | | | | $ | 10,078 | | | $ | 3 | | | $ | 13,129 | | |
| Net Income | | — | | | — | | | | | 1,446 | | | — | | | 1,446 | | |
| Other Comprehensive Income (Loss), net of tax (expense) benefit of $1 | | — | | | — | | | | | — | | | (2) | | | (2) | | |
| Comprehensive Income | | | | | | | | | | | | 1,444 | | |
| Balance as of December 31, 2021 | | $ | 892 | | | $ | 2,156 | | | | | $ | 11,524 | | | $ | 1 | | | $ | 14,573 | | |
| Net Income | | — | | | — | | | | | 1,565 | | | — | | | 1,565 | | |
| Other Comprehensive Income (Loss), net of tax (expense) benefit of $2 | | — | | | — | | | | | — | | | (6) | | | (6) | | |
| Comprehensive Income | | | | | | | | | | | | 1,559 | | |
| Cash Dividend Paid | | $ | — | | | $ | — | | | | | $ | (450) | | | $ | — | | | (450) | | |
| Balance as of December 31, 2022 | | $ | 892 | | | $ | 2,156 | | | | | $ | 12,639 | | | $ | (5) | | | $ | 15,682 | | |
| Net Income | | — | | | — | | | | | 1,515 | | | — | | | 1,515 | | |
| Other Comprehensive Income (Loss), net of tax (expense) benefit of $0 | | — | | | — | | | | | — | | | 1 | | | 1 | | |
| Comprehensive Income | | | | | | | | | | | | 1,516 | | |
| | | | | | | | | | | | | | |
| Cash Dividends Paid | | — | | | — | | | | | (150) | | | — | | | (150) | | |
| | | | | | | | | | | | | | |
| Balance as of December 31, 2023 | | $ | 892 | | | $ | 2,156 | | | | | $ | 14,004 | | | $ | (4) | | | $ | 17,048 | | |
| | | | | | | | | | | | | | |
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
Millions
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| | | 2017 | | 2016 | | 2015 | |
| OPERATING REVENUES | | $ | 3,930 |
| | $ | 4,023 |
| | $ | 4,928 |
| |
| OPERATING EXPENSES | | | | | | | |
| Energy Costs | | 1,983 |
| | 1,986 |
| | 2,150 |
| |
| Operation and Maintenance | | 1,038 |
| | 1,143 |
| | 1,057 |
| |
| Depreciation and Amortization | | 1,268 |
| | 881 |
| | 291 |
| |
| Total Operating Expenses | | 4,289 |
| | 4,010 |
| | 3,498 |
| |
| OPERATING INCOME (LOSS) | | (359 | ) | | 13 |
| | 1,430 |
| |
| Income from Equity Method Investments | | 14 |
| | 11 |
| | 14 |
| |
| Other Income | | 213 |
| | 102 |
| | 169 |
| |
| Other Deductions | | (56 | ) | | (57 | ) | | (72 | ) | |
| Other-Than-Temporary Impairments | | (12 | ) | | (28 | ) | | (53 | ) | |
| Interest Expense | | (50 | ) | | (84 | ) | | (121 | ) | |
| INCOME (LOSS) BEFORE INCOME TAXES | | (250 | ) | | (43 | ) | | 1,367 |
| |
| Income Tax Benefit (Expense) | | 729 |
| | 61 |
| | (511 | ) | |
| NET INCOME | | $ | 479 |
| | $ | 18 |
| | $ | 856 |
| |
| | | | | | | | |
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Millions
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | Years Ended December 31, | |
| | | 2017 | | 2016 | | 2015 | |
| NET INCOME | | $ | 479 |
| | $ | 18 |
| | $ | 856 |
| |
| Other Comprehensive Income (Loss), net of tax | | | | | | | |
| Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(39), $(41) and $32 for the years ended 2017, 2016 and 2015, respectively | | 46 |
| | 42 |
| | (25 | ) | |
| Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0, $0 and $7 for the years ended 2017, 2016 and 2015, respectively | | — |
| | — |
| | (11 | ) | |
| Pension/OPEB adjustment, net of tax (expense) benefit of $(3), $9 and $(16) for the years ended 2017, 2016 and 2015, respectively | | (7 | ) | | (13 | ) | | 24 |
| |
| Other Comprehensive Income (Loss), net of tax | | 39 |
| | 29 |
| | (12 | ) | |
| COMPREHENSIVE INCOME | | $ | 518 |
| | $ | 47 |
| | $ | 844 |
| |
| | | | | | | | |
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.
PSEG POWER LLC
CONSOLIDATED BALANCE SHEETS
Millions
|
| | | | | | | | | |
| | | | | |
| | December 31, | |
| | 2017 | | 2016 | |
| ASSETS | |
| CURRENT ASSETS | | | | |
| Cash and Cash Equivalents | $ | 32 |
| | $ | 11 |
| |
| Accounts Receivable | 380 |
| | 276 |
| |
| Accounts Receivable—Affiliated Companies | 221 |
| | 205 |
| |
| Short-Term Loan to Affiliate | — |
| | 87 |
| |
| Fuel | 289 |
| | 326 |
| |
| Materials and Supplies, net | 376 |
| | 381 |
| |
| Derivative Contracts | 29 |
| | 162 |
| |
| Prepayments | 11 |
| | 10 |
| |
| Other | 3 |
| | 2 |
| |
| Total Current Assets | 1,341 |
| | 1,460 |
| |
| PROPERTY, PLANT AND EQUIPMENT | 11,755 |
| | 12,655 |
| |
| Less: Accumulated Depreciation and Amortization | (3,159 | ) | | (4,135 | ) | |
| Net Property, Plant and Equipment | 8,596 |
| | 8,520 |
| |
| NONCURRENT ASSETS | | | | |
| NDT Fund | 2,133 |
| | 1,859 |
| |
| Long-Term Investments | 87 |
| | 102 |
| |
| Goodwill | 16 |
| | 16 |
| |
| Other Intangibles | 114 |
| | 98 |
| |
| Other Special Funds | 57 |
| | 53 |
| |
| Derivative Contracts | 7 |
| | 24 |
| |
| Other | 67 |
| | 61 |
| |
| Total Noncurrent Assets | 2,481 |
| | 2,213 |
| |
| TOTAL ASSETS | $ | 12,418 |
| | $ | 12,193 |
| |
| | | | | |
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.
PSEG POWER LLC
CONSOLIDATED BALANCE SHEETS
Millions
|
| | | | | | | | | |
| | | | | |
| | December 31, | |
| | 2017 | | 2016 | |
| LIABILITIES AND MEMBER’S EQUITY | |
| CURRENT LIABILITIES | | | | |
| Long-Term Debt Due Within One Year | $ | 250 |
| | $ | — |
| |
| Accounts Payable | 712 |
| | 539 |
| |
| Accounts Payable—Affiliated Companies | 57 |
| | 25 |
| |
| Short-Term Loan from Affiliate | 281 |
| | — |
| |
| Derivative Contracts | 16 |
| | 8 |
| |
| Accrued Interest | 20 |
| | 20 |
| |
| Other | 99 |
| | 88 |
| |
| Total Current Liabilities | 1,435 |
| | 680 |
| |
| NONCURRENT LIABILITIES | | | | |
| Deferred Income Taxes and ITC | 1,406 |
| | 2,170 |
| |
| Asset Retirement Obligations | 810 |
| | 511 |
| |
| OPEB Costs | 283 |
| | 251 |
| |
| Derivative Contracts | 5 |
| | 3 |
| |
| Accrued Pension Costs | 184 |
| | 191 |
| |
| Long-Term Accrued Taxes | 52 |
| | 77 |
| |
| Other | 140 |
| | 129 |
| |
| Total Noncurrent Liabilities | 2,880 |
| | 3,332 |
| |
| COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13) |
| |
| |
| LONG-TERM DEBT
| 2,136 |
| | 2,382 |
| |
| MEMBER’S EQUITY | | | | |
| Contributed Capital | 2,214 |
| | 2,214 |
| |
| Basis Adjustment | (986 | ) | | (986 | ) | |
| Retained Earnings | 4,911 |
| | 4,782 |
| |
| Accumulated Other Comprehensive Loss | (172 | ) | | (211 | ) | |
| Total Member’s Equity | 5,967 |
| | 5,799 |
| |
| TOTAL LIABILITIES AND MEMBER’S EQUITY | $ | 12,418 |
| | $ | 12,193 |
| |
| | | | | |
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| | | 2017 | | 2016 | | 2015 | |
| CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | |
| Net Income | | $ | 479 |
| | $ | 18 |
| | $ | 856 |
| |
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | |
| Depreciation and Amortization | | 1,268 |
| | 881 |
| | 291 |
| |
| Amortization of Nuclear Fuel | | 199 |
| | 203 |
| | 213 |
| |
| Provision for Deferred Income Taxes and ITC | | (807 | ) | | (208 | ) | | 261 |
| |
| Interest Accretion on Asset Retirement Obligation | | 30 |
| | 26 |
| | 26 |
| |
| Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives | | 188 |
| | 183 |
| | (143 | ) | |
| Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual | | 103 |
| | 109 |
| | 104 |
| |
| Impairment Costs for Early Plant Retirements | | — |
| | 102 |
| | — |
| |
| Non-Cash Employee Benefit Plan Costs | | 28 |
| | 39 |
| | 48 |
| |
| Net Realized (Gains) Losses and (Income) Expense from NDT Fund | | (156 | ) | | (26 | ) | | (38 | ) | |
| Net Change in Certain Current Assets and Liabilities | | | | | | | |
| Fuel, Materials and Supplies | | 42 |
| | 31 |
| | 62 |
| |
| Margin Deposit | | (90 | ) | | (76 | ) | | 122 |
| |
| Accounts Receivable | | (45 | ) | | (71 | ) | | 63 |
| |
| Accounts Payable | | 39 |
| | (22 | ) | | (46 | ) | |
| Accounts Receivable/Payable—Affiliated Companies, net | | (2 | ) | | 6 |
| | (84 | ) | |
| Other Current Assets and Liabilities | | 10 |
| | 10 |
| | (36 | ) | |
| Employee Benefit Plan Funding and Related Payments | | (7 | ) | | (13 | ) | | (11 | ) | |
| Other | | 47 |
| | 63 |
| | 18 |
| |
| Net Cash Provided By (Used In) Operating Activities | | 1,326 |
| | 1,255 |
| | 1,706 |
| |
| CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | |
| Additions to Property, Plant and Equipment | | (1,231 | ) | | (1,343 | ) | | (1,117 | ) | |
| Purchase of Emissions Allowances and RECs | | (117 | ) | | (99 | ) | | (106 | ) | |
| Proceeds from Sales of Available-for-Sale Securities | | 2,182 |
| | 739 |
| | 1,422 |
| |
| Investments in Available-for-Sale Securities | | (2,199 | ) | | (766 | ) | | (1,455 | ) | |
| Short-Term Loan—Affiliated Company | | 87 |
| | 276 |
| | 221 |
| |
| Other | | 46 |
| | 46 |
| | 34 |
| |
| Net Cash Provided By (Used In) Investing Activities | | (1,232 | ) | | (1,147 | ) | | (1,001 | ) | |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | |
| Issuance of Long-Term Debt | | — |
| | 700 |
| | — |
| |
| Cash Dividend Paid | | (350 | ) | | (250 | ) | | (400 | ) | |
| Redemption of Long-Term Debt | | — |
| | (553 | ) | | (300 | ) | |
| Short-Term Loan—Affiliated Company | | 281 |
| | — |
| | — |
| |
| Other | | (4 | ) | | (6 | ) | | (2 | ) | |
| Net Cash Provided By (Used In) Financing Activities | | (73 | ) | | (109 | ) | | (702 | ) | |
| Net Increase (Decrease) in Cash and Cash Equivalents | | 21 |
| | (1 | ) | | 3 |
| |
| Cash and Cash Equivalents at Beginning of Period | | 11 |
| | 12 |
| | 9 |
| |
| Cash and Cash Equivalents at End of Period | | $ | 32 |
| | $ | 11 |
| | $ | 12 |
| |
| Supplemental Disclosure of Cash Flow Information: | | | | | | | |
| Income Taxes Paid (Received) | | $ | 77 |
| | $ | 50 |
| | $ | 393 |
| |
| Interest Paid, Net of Amounts Capitalized | | $ | 48 |
| | $ | 81 |
| | $ | 116 |
| |
| Accrued Property, Plant and Equipment Expenditures | | $ | 293 |
| | $ | 244 |
| | $ | 114 |
| |
| | | | | | | | |
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY
Millions
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | Contributed Capital | | Basis Adjustment | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total | |
| Balance as of January 1, 2015 | | $ | 2,214 |
| | $ | (986 | ) | | $ | 4,558 |
| | $ | (228 | ) | | $ | 5,558 |
| |
| Net Income | | — |
| | — |
| | 856 |
| | — |
| | 856 |
| |
| Other Comprehensive Income (Loss), net of tax (expense) benefit of $23 | | — |
| | — |
| | — |
| | (12 | ) | | (12 | ) | |
| Comprehensive Income | | | | | | | | | | 844 |
| |
| Cash Dividends Paid | | — |
| | — |
| | (400 | ) | | — |
| | (400 | ) | |
| Balance as of December 31, 2015 | | $ | 2,214 |
| | $ | (986 | ) | | $ | 5,014 |
| | $ | (240 | ) | | $ | 6,002 |
| |
| Net Income | | — |
| | — |
| | 18 |
| | — |
| | 18 |
| |
| Other Comprehensive Income (Loss), net of tax (expense) benefit of $(32) | | — |
| | — |
| | — |
| | 29 |
| | 29 |
| |
| Comprehensive Income | | | | | | | | | | 47 |
| |
| Cash Dividends Paid | | — |
| | — |
| | (250 | ) | | — |
| | (250 | ) | |
| Balance as of December 31, 2016 | | $ | 2,214 |
| | $ | (986 | ) | | $ | 4,782 |
| | $ | (211 | ) | | $ | 5,799 |
| |
| Net Income | | — |
| | — |
| | 479 |
| | — |
| | 479 |
| |
| Other Comprehensive Income (Loss), net of tax (expense) benefit of $(42) | | — |
| | — |
| | — |
| | 39 |
| | 39 |
| |
| Comprehensive Income | | | | | | | | | | 518 |
| |
| Cash Dividends Paid | | — |
| | — |
| | (350 | ) | | — |
| | (350 | ) | |
| Balance as of December 31, 2017 | | $ | 2,214 |
| | $ | (986 | ) | | $ | 4,911 |
| | $ | (172 | ) | | $ | 5,967 |
| |
| | | | | | | | | | | | |
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies
Organization
Public Service Enterprise Group Incorporated (PSEG) is a public utility holding company with a diversified business mix within the energy industry. Its operations are primarily in the Northeastern and Mid-Atlantic United States and in other select markets. PSEG’s principal directthat, acting through its wholly owned subsidiaries, is a predominantly regulated electric and gas utility and a nuclear generation business. PSEG’s principal operating subsidiaries are:
•Public Service Electric and Gas Company (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). and other federal and New Jersey state regulators. PSE&G also invests in regulated solar generation projects and energy efficiency (EE) and related programs in New Jersey, which are regulated by the BPU.
•PSEG Power LLC (Power)(PSEG Power)—which is a multi-regionalan 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 throughvia its principal direct wholly owned subsidiaries. In addition, Power owns and operates solar generation in various states.PSEG Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and other federal regulators and state regulators in 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) electric transmission and distribution (T&D) system under an Operations Services Agreement (OSA); PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily hasholds legacy lease investments in leveraged leases;and competitively bid, FERC regulated transmission; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.
Basis of Presentation
The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Annual Reports on Form 10-K and in accordance with accounting guidance generally accepted in the United States (GAAP). Certain reclassifications have been made to prior year financial statements to conform with current year presentation. These reclassifications had no impact on PSEG’s or PSE&G’s results of operations, financial condition or cash flows.
Significant Accounting Policies
Principles of Consolidation
Each company consolidates those entities in which it has a controlling interest or is the primary beneficiary. See Note 4. Variable Interest Entity. Entities over which the companies exhibit significant influence, but do not have a controlling interest and/or are not the primary beneficiary, are accounted for under the equity method of accounting. ForEquity investments in which significant influence doesthat do not exist and the investorqualify for consolidation or equity method accounting are recorded at fair value or, if fair value is not readily determinable, are initially recognized at cost and subsequently remeasured if there is an orderly transaction in an identical or similar investment of the primary beneficiary,same issuer or if the cost method of accountinginvestment is applied.impaired. All significant intercompany accounts and transactions are eliminated in consolidation.
PSE&G and PSEG Power also have undivided interests in certain jointly-owned facilities, with each responsible for paying its respective ownership share of construction costs, fuel purchases and operating expenses. PSE&G and PSEG Power consolidate their portion of any revenues and expenses related to their respective jointly-owned facilities in the appropriate revenue and expense categories.
Accounting for the Effects of Regulation
In accordance with accounting guidance for rate-regulated entities, PSE&G’s financial statements reflect the economic effects of regulation. PSE&G defers the recognition of costs (a Regulatory Asset) or records the recognition of obligations (a Regulatory Liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs and recoveries, which are being amortized over various future periods. To the extent that collection of any such costs or payment of liabilities becomes no longer probable as a result of changes in regulation, and/or competitive position, the associated Regulatory Asset or Liability is charged or credited to income. Management believes that PSE&G’s transmission and distributionT&D businesses continue to meet the accounting requirements for rate-regulated entities. For additional information, see Note 6. Regulatory Assets and Liabilities.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cash, Cash Equivalents and Restricted Cash
The followingprovides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the same such amounts in the Consolidated Statements of Cash Flows for the years ended December 31, 2022 and 2023. Restricted cash consists primarily of deposits received related to a construction project at PSE&G.
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| | PSE&G | | PSEG Power & Other (A) | | Consolidated | |
| | Millions | |
| As of December 31, 2022 | | | | | | |
| Cash and Cash Equivalents | $ | 220 | | | $ | 245 | | | $ | 465 | | |
| Restricted Cash in Other Current Assets | 27 | | | — | | | 27 | | |
| Restricted Cash in Other Noncurrent Assets | 19 | | | — | | | 19 | | |
| Cash, Cash Equivalents and Restricted Cash | $ | 266 | | | $ | 245 | | | $ | 511 | | |
| As of December 31, 2023 | | | | | | |
| Cash and Cash Equivalents | $ | 30 | | | $ | 24 | | | $ | 54 | | |
| Restricted Cash in Other Current Assets | 23 | | | — | | | 23 | | |
| Restricted Cash in Other Noncurrent Assets | 22 | | | — | | | 22 | | |
| Cash, Cash Equivalents and Restricted Cash | $ | 75 | | | $ | 24 | | | $ | 99 | | |
| | | | | | | |
(A) Includes amounts applicable to PSEG Power, Energy Holdings, Services and PSEG (parent company).
Derivative Instruments
Each company uses derivative instruments to manage risk pursuant to its business plans and prudent practices.
Within PSEG and its affiliate companies, PSEG Power has the most exposure to commodity price risk. PSEG Power is exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuelsnatural gas and other commodities.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. PSEG Power uses a variety of derivative and non-derivative instruments, such as financial options, futures swaps, fuel purchases and forward purchases and sales of electricity,swaps to manage the exposure to fluctuations in commodity prices and optimize the value of PSEG Power’s expected generation. Changes in the fair market value of the derivative contracts are recorded in earnings.
Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing the contract’s market liquidity. PSEG has determined that contracts to purchase and sell certain products do not meet the definition of a derivative under the current authoritative guidance since they do not provide for net settlement, or the markets are not sufficiently liquid to conclude that physical forward contracts are readily convertible to cash.
Under current authoritative guidance, all derivatives are recognized on the balance sheet at their fair value, except for derivatives that aremay be designated as normal purchases and normal sales (NPNS). Further, derivatives that qualify for hedge accounting can be designated as fair value or cash flow hedges. For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period.
Certain offsetting derivative assets and liabilities are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, these positions are offset on the Consolidated Balance Sheets of Power and PSEG.
For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the hedgedon a derivative instrument designated and qualifying as a cash flows of the underlying exposureflow hedge is deferred in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. Any hedge ineffectiveness is included in current period earnings.
For derivative contracts that do not qualify or are not designated as cash flow or fair value hedges or as NPNS, changes in fair value are recorded in current period earnings. PSEG does not currently elect fair value or cash flow hedge accounting on its commodity derivative positions.
Contracts that qualify for, and are designated, as NPNS are accounted for upon settlement. Contracts which qualify for NPNS are contracts for which physical delivery is probable, they will not be financially settled, and the quantities under contract are expected to be used or sold in the normal course of business over a reasonable period of time.
For additional information regarding derivative financial instruments, see Note 16. Financial Risk Management Activities.
Revenue Recognition
PSE&G’s regulated electric and gas revenues are recorded primarily based on services rendered to customers. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period. The unbilled revenue is estimated each month based on usage per day, the number
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
of unbilled days in the period, estimated seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms.
Regulated revenues from the transmission of electricity are recognized as services are provided based on a FERC-approved annual formula rate mechanism. This mechanism provides for an annual filing of estimated revenue requirement with rates effective January 1 of each year. After completion of the annual period ending December 31, PSE&G files a true-up whereby it compares its actual revenue requirement to the original estimate to determine any over or under collection of revenue. PSE&G records the estimated financial statement impact of the difference between the actual and the filed revenue requirement as a refund or deferral for future recovery when such amounts are probable and can be reasonably estimated in accordance with accounting guidance for rate-regulated entities.
The majority of Power’s revenues relate to bilateral contracts, which are accounted for on the accrual basis as the energy is delivered. Power’s revenue also includes changes in the value of energy derivative contracts that are not designated as NPNS. See Note 16. Financial Risk Management Activities for further discussion.
PSEG Power currently owns generation within PJM Interconnection, L.L.C. (PJM), the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO) facilitatewhich facilitates the dispatch of energy and energy-related products. PowerPSEG generally reports electricity sales and purchases conducted with those individual ISOsthe PJM Independent System Operator (ISO) at PSEG Power on a net hourly basis in either Revenues or Energy Costs in its Consolidated Statement of Operations, the classification of which depends on the net hourly activity. Capacity revenue and expense isare also reported net based on PSEG Power’s monthly net sale or purchase position in PJM. PSEG Power also has revenues that relate to bilateral contracts, which are accounted for on the individual ISOs.accrual basis as the energy is delivered. PSEG Power’s revenue also includes changes in the value of energy derivative contracts. See Note 16. Financial Risk Management Activities for further discussion.
PSEG LI is the primary beneficiary of Long Island Electric Utility Servco, LLC (Servco). For transactions in which Servco acts as principal, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and OperationsOperation and Maintenance (O&M) Expense, respectively. See Note 4. Variable Interest Entity for further information.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The majority of Energy Holdings' revenues relate to its investments in leveraged leases. Income on leveraged leases is recognized by a method which produces a constant rate of return on the outstanding net investment in the lease, net of the related deferred tax liability, in the years in which the net investment is positive. Any gains or losses incurred as a result of a lease termination are recorded as revenues as these events occur in the ordinary course of business of managing the investment portfolio.For additional information regarding Revenues, see Note 2. Revenues.
Depreciation and Amortization
PSE&G calculates depreciation under the straight-line method based on estimated average remaining lives of the several classes of depreciable property. These estimates are reviewed on a periodic basis and necessary adjustments are made as approved by the BPU or FERC. The average depreciation rate stated as a percentage of original cost of depreciable property was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | Average Rate | |
| | | 2023 | | 2022 | | 2021 | |
| Electric Transmission | | 2.09 | % | | 2.18 | % | | 2.29 | % | |
| Electric Distribution | | 2.54 | % | | 2.56 | % | | 2.56 | % | |
| Gas Distribution | | 1.84 | % | | 1.93 | % | | 1.84 | % | |
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|
| | | | | | | | | | | |
| | | | | | | | |
| | | 2017 | | 2016 | | 2015 | |
| | | Avg Rate | | Avg Rate | | Avg Rate | |
| Electric Transmission | | 2.41 | % | | 2.39 | % | | 2.42 | % | |
| Electric Distribution | | 2.51 | % | | 2.49 | % | | 2.50 | % | |
| Gas Distribution | | 1.63 | % | | 1.63 | % | | 1.64 | % | |
| | | | | | | | |
PowerPSEG calculates depreciation on its nuclear generation-related assets under the straight-line method based on the assets’ estimated useful lives. The estimated useful lives are:
general plant assets—3of approximately 60 years to 20 years
fossil production assets—30 years to 70 years
nuclear generation assets—approximately 60 years
pumped storage facilities—76 years
solar assets—25 years80 years.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized During Construction (IDC)
AFUDC represents the cost of debt and equity funds used to finance the construction of new utility assets at PSE&G. IDC represents the cost of debt used to finance construction at Power.PSEG’s other subsidiaries. The amount of AFUDC or IDC capitalized as Property, Plant and Equipment is included as a reduction of interest charges or other income for the equity portion. The amounts and average rates used to calculate AFUDC or IDC for the years ended December 31, 2017, 20162023, 2022 and 20152021 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | AFUDC/IDC Capitalized | |
| | | 2017 | | 2016 | | 2015 | |
| | | Millions | | Avg Rate | | Millions | | Avg Rate | | Millions | | Avg Rate | |
| PSE&G | | $ | 73 |
| | 7.42 | % | | $ | 66 |
| | 7.81 | % | | $ | 65 |
| | 8.01 | % | |
| Power | | $ | 78 |
| | 4.60 | % | | $ | 54 |
| | 4.87 | % | | $ | 27 |
| | 5.14 | % | |
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | AFUDC/IDC Capitalized | |
| | | 2023 | | 2022 | | 2021 | |
| | | Millions | | Avg Rate | | Millions | | Avg Rate | | Millions | | Avg Rate | |
| PSE&G | | $ | 83 | | | 7.13 | % | | $ | 84 | | | 7.39 | % | | $ | 93 | | | 7.37 | % | |
| Other | | $ | 9 | | | 5.66 | % | | $ | 4 | | | 2.24 | % | | $ | 9 | | | 4.90 | % | |
| | | | | | | | | | | | | | |
Income Taxes
PSEG and its subsidiaries file a consolidated federal income tax return and income taxes are allocated to PSEG’s subsidiaries based on the taxable income or loss of each subsidiary on a stand-alone basis in accordance with a tax sharingtax-sharing agreement between PSEG and each of its affiliated subsidiaries. Allocations between PSEG and its subsidiaries are recorded through intercompany accounts. Investment tax credits (ITC) deferred in prior years are being amortized over the useful lives of the related property.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Uncertain income tax positions are accounted for using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. See Note 20. Income Taxes for further discussion.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Impairment of Long-Lived Assets and Leveraged Leases
Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate, counterparty credit worthiness or market conditions, including prolonged periods of adverse commodity and capacity prices or a current expectation that a long-lived asset will be sold or disposed of significantly before the end of its previously estimated useful life, could potentially indicate an asset’s or asset group’s carrying amount may not be recoverable. In such an event, an undiscounted cash flow analysis is performed to determine if an impairment exists. When a long-lived asset’s or asset group’s carrying amount exceeds the associated undiscounted estimated future cash flows, the asset/asset group is considered impaired to the extent that its fair value is less than its carrying amount. An impairment would result in a reduction of the value of the long-lived asset/asset group through a non-cash charge to earnings. See Note 3. Early Plant Retirements for more information.
For Power,PSEG, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the nuclear generation units are generally evaluated at a regionalthe portfolio level (PJM, NYISO, ISO-NE) along with cash flows generated from the customer supplylevel. See Note 3. Asset Dispositions and risk management activities, inclusive of cash flows from contracts, including those that are accountedImpairments for as derivatives and meet the NPNS scope exception. In certain cases, generation assets are evaluatedmore information on an individual basis where those assets are individually contractedimpairment assessments performed on a long-term basis with a third party and operations are independent of other generation assets (typically Power’s solar plants and Kalaeloa).
Energy Holdings’ leveraged leases are comprised of Lease Receivables (net of non-recourse debt), the estimated residual value of leased assets, and unearned and deferred income. 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. A review of the residual valuations, which are calculated by discounting the cash flows related to the leased assets after the lease term, 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.
Cash and Cash Equivalents
Cash equivalents consist of short-term, highly liquid investments with original maturities of three months or less.PSEG’s long-lived assets.
Accounts Receivable—Allowance for Doubtful AccountsCredit Losses
PSE&G’s accounts receivable, including unbilled revenues, are primarily comprised of utility customer receivables for the provision of electric and gas service and appliance services, and are reported in the balance sheet as gross outstanding amounts adjusted for doubtful accounts.an allowance for credit losses. The allowance for doubtful accountscredit losses reflects PSE&G’s best estimatesestimate of losses on the accounts receivableaccount balances. The allowance is based on PSE&G’s projection of accounts receivable aging, historical experience, write-off forecastseconomic factors and other currently available evidence.evidence, including the estimated impact of the coronavirus pandemic on the outstanding balances as of December 31, 2023. PSE&G’s electric bad debt expense is recovered through the Societal Benefits Clause (SBC) mechanism and incremental gas bad debt has been deferred for future recovery through the coronavirus (COVID-19) Regulatory Asset. See Note 2. Revenues and Note 6. Regulatory Assets and Liabilities.
Accounts receivable are charged off in the period in which the receivable is deemed uncollectible. Recoveries of accounts receivable are recorded when it is known they will be received.
Materials and Supplies and Fuel
PSEG and PSE&G’s and Power’s materials and supplies are carried at average cost and charged to inventory when purchased and expensed or capitalized to Property, Plant and Equipment, as appropriate, when installed or used. Fuel inventory at PowerPSEG is valued at the lower of average cost or market and primarily includes stored natural gas coal, fuel oil and propane used to generate power and to satisfy obligations under PSEG Power’s gas supply contracts with PSE&G. The costs of fuel, including initial transportation costs, are included in inventory when purchased and charged to Energy Costs when used or sold. The cost of nuclear fuel is capitalized within Property, Plant and Equipment and amortized to fuel expense using the units-of-production method.
Property, Plant and Equipment
PSE&G’s additions to and replacements of existing property, plant and equipment are capitalized at cost. The cost of maintenance, repair and replacement of minor items of property is charged to expense as incurred. At the time units of depreciable property are retired or otherwise disposed of, the original cost, adjusted for net salvage value, is charged to accumulated depreciation.
PowerPSEG capitalizes costs related to its generating assets, including those related to its jointly-owned facilities whichthat increase the capacity, improve or extend the life of an existing asset,asset; represent a newly acquired or constructed assetasset; or represent the replacement of a retired asset. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. Environmental costs are capitalized if the costs mitigate or prevent future environmental contamination or if the costs improve existing assets’ environmental safety or efficiency. All other environmental expenditures are expensed as incurred. PowerPSEG also capitalizes spare parts for its generating assets that meet specific criteria. Capitalized sparesspare parts are depreciated over the remaining lives of their associated assets.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Leases
PSEG and its subsidiaries, when acting as lessee or lessor, determine if an arrangement is a lease at inception. PSEG assesses contracts to determine if the arrangement conveys (i) the right to control the use of the identified property, (ii) the right to obtain substantially all of the economic benefits from the use of the property, and (iii) the right to direct the use of the property.
Available-for-Sale SecuritiesPSEG and its subsidiaries are neither the lessee nor the lessor in any material leases that are not classified as operating leases.
Lessee—Operating Lease Right-of-Use Assets represent the right to use an underlying asset for the lease term and Operating Lease Liabilities represent the obligation to make lease payments arising from the lease. Operating Lease Right-of-Use Assets and Operating Lease Liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term.
The current portion of Operating Lease Liabilities is included in Other Current Liabilities. Operating Lease Right-of-Use Assets and noncurrent Operating Lease Liabilities are included as separate captions in Noncurrent Assets and Noncurrent Liabilities, respectively, on the Consolidated Balance Sheets of PSEG and PSE&G. PSEG and its subsidiaries do not recognize Operating Lease Right-of-Use Assets and Operating Lease Liabilities for leases where the term is twelve months or less.
PSEG and its subsidiaries recognize the lease payments on a straight-line basis over the term of the leases and variable lease payments in the period in which the obligations for those payments are incurred.
As lessee, most of the operating leases of PSEG and its subsidiaries do not provide an implicit rate; therefore, incremental borrowing rates are used based on the information available at commencement date in determining the present value of lease payments. The implicit rate is used when readily determinable. PSE&G’s incremental borrowing rates are based on secured borrowing rates. PSEG’s incremental borrowing rates are generally unsecured rates. Having calculated simulated secured rates for each of PSEG and PSEG Power, it was determined that the difference between the unsecured borrowing rates and the simulated secured rates had an immaterial effect on their recorded Operating Lease Right-of-Use Assets and Operating Lease Liabilities. Services, PSEG LI and other subsidiaries of PSEG that do not borrow funds or issue debt may enter into leases. Since these companies do not have credit ratings and related incremental borrowing rates, PSEG has determined that it is appropriate for these companies to use the incremental borrowing rate of PSEG, the parent company.
Lease terms may include options to extend or terminate the lease when it is reasonably certain that such options will be exercised.
PSEG and its subsidiaries have lease agreements with lease and non-lease components. For real estate, equipment and vehicle leases, the lease and non-lease components are accounted for as a single lease component.
Lessor—Property subject to operating leases, where PSEG or one of its subsidiaries is the lessor, is included in Property, Plant and Equipment and rental income from these leases is included in Operating Revenues.
PSEG and its subsidiaries have lease agreements with lease and non-lease components, which are primarily related to domestic energy generation. PSEG and subsidiaries account for the lease and non-lease components as a single lease component. See Note 7. Leases for detailed information on leases.
Energy Holdings is the lessor in leveraged leases. Leveraged lease accounting guidance is grandfathered for existing leveraged leases. Energy Holdings’ leveraged leases are accounted for in Operating Revenues and in Noncurrent Long-Term Investments. If modified after January 1, 2019, those leveraged leases will be accounted for as operating or financing leases. See Note 8. Long-Term Investments and Note 9. Financing Receivables.
Trust Investments
These securities comprise the Nuclear Decommissioning Trust (NDT) Fund, a master independent external trust account maintained to provide for the costs of decommissioning upon termination of operations of Power’sPSEG’s nuclear facilities and amounts that are deposited to fund a Rabbi Trust which was established to meet the obligations related to non-qualified pension plans and deferred compensation plans.
RealizedUnrealized gains and losses on available-for-sale securitiesequity security investments are recorded in earnings andNet Income. The debt securities are classified as available-for-sale with the unrealized gains and losses on such securities are recorded as a component of Accumulated Other Comprehensive Income (Loss). Securities with unrealizedRealized gains and losses that are deemed to be other-than-temporarily impairedon both equity and available-for-sale debt security investments are recorded in earnings.earnings and are included with the unrealized gains and losses on equity securities in Net Gains (Losses) on Trust Investments. Other-than-temporary impairments on NDT and Rabbi Trust debt securities are also included in Net Gains (Losses) on Trust Investments. See Note 9. Available-for-Sale Securities10. Trust Investments for further discussion.
Pension and Other Postretirement Benefits (OPEB) Plans
The market-related value of plan assets held for the qualified pension and OPEB plans is equal to the fair value of those assets as of year-end. Fair value is determined using quoted market prices and independent pricing services based upon the security
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
type as reported by the trustee at the measurement date (December 31) for all plan assets.as well as investments in unlisted real estate which are valued via third-party appraisals.
PSEG recognizes a long-term receivable primarily related to future funding by LIPA of Servco’s recognized pension and OPEB liabilities. This receivable is presented separately on the Consolidated Balance Sheet of PSEG as a noncurrent asset because it is restricted.
asset. Pursuant to the OSA, Servco records expense only to the extent of itsfor contributions to its pension plan trusts and for OPEB payments made to retirees.
See Note 12. Pension, and Other Postretirement Benefits (OPEB) and Savings Plans for further discussion.
Basis Adjustment
PSE&G and Power havehas recorded a Basis Adjustment in their respectiveits Consolidated Balance SheetsSheet related to the generation assets that were transferred from PSE&G to PSEG Power in August 2000 at the price specified by the BPU. Because the transfer was between affiliates, the transaction was recorded at the net book value of the assets and liabilities rather than the transfer price. The difference between the total transfer price and the net book value of the generation-related assets and liabilities, $986$986 million,, net of tax, was recorded as a Basis Adjustment on PSE&G’s and PSEG Power’s Consolidated Balance Sheets. The $986$986 million is an addition to PSE&G’s Common Stockholder’s Equity and a reduction of PSEG Power’s Member’s Equity. These amounts are eliminated on PSEG’s consolidated financial statements.
On December 31, 2023, PSE&G reclassified certain stockholder’s equity amounts on its Consolidated Balance Sheets and Consolidated Statements of Common Stockholder's Equity. The previously disclosed Basis Adjustment amount of $986 million was combined with Contributed Capital, based on the underlying nature of the Basis Adjustment. This reclassification had no impact on previously reported total stockholder's equity amounts.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Note 2. Recent Accounting Standards
NewImprovements to Reportable Segment Disclosures—Accounting Standards Issued and Adopted
Business Combinations: Clarifying the Definition of a BusinessUpdate (ASU) 2023-07
This accounting standard was issued mainlyASU requires disclosure of incremental segment information, including additional detail on certain significant segment expenses, on an annual and interim basis to provideenable investors to develop more consistency in how the definition of a business is applied to acquisitions or dispositions.decision-useful financial analyses. The new guidance will generally reduce the number of transactions that will require treatment as a business combination. The definition of a business now includes consideration of whether substantially all the fair value of the gross assets acquired or disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets. If this condition is met, the transaction would not qualify as a business.
The standardASU is effective for annualfiscal years beginning after December 15, 2023 and interim periods beginning after December 15, 2017; however, entities were able to adopt it for transactions that closed before2024. PSEG and PSE&G are currently analyzing the effective date but had not been reported in financial statements that had been issued or made available for issuance. PSEG adoptedimpact of this standard inon their future disclosures.
Improvements to Income Tax Disclosures—ASU 2023-09
This ASU makes amendments to the third quarter 2017 withcurrent reconciliation disclosure to improve transparency by requiring consistent categories and greater jurisdictional disaggregation. The ASU also provides for the acquisitioninclusion of an income taxes paid disclosure by jurisdiction. The ASU is effective for annual periods beginning after December 15, 2024. PSEG and PSE&G are currently analyzing the impact of this ASU on their future disclosures.
Note 2. Revenues
Nature of Goods and Services
The following is a solar project. This standard upon adoption had no impact on PSEG’s financial statements.description of principal activities by which PSEG and its subsidiaries generate their revenues.
RevenuePSE&G
Revenues from Contracts with Customers
ThisElectric and Gas Distribution and Transmission Revenues—PSE&G sells gas and electricity to customers under default commodity supply tariffs. PSE&G’s regulated electric and gas default commodity supply and distribution services are separate tariffs which are satisfied as the product(s) and/or service(s) are delivered to the customer. The electric and gas commodity and delivery tariffs are recurring contracts in effect until modified through the regulatory approval process as appropriate. Revenue is recognized over time as the service is rendered to the customer. Included in PSE&G’s regulated revenues are unbilled electric and gas revenues which represent the estimated amount customers will be billed for services rendered from the most recent meter reading to the end of the respective accounting standard clarifiesperiod.
PSE&G’s transmission revenues are earned under a separate tariff using a FERC-approved annual formula rate mechanism. The performance obligation of transmission service is satisfied and revenue is recognized as it is provided to the principlescustomer. The formula rate mechanism provides for recognizingan annual filing of an estimated revenue and removes inconsistencies in revenue recognition requirements; improves comparabilityrequirement with rates effective January 1 of revenue recognition practices across entities, industries, jurisdictions and capital markets; and provides improved disclosures.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
each year and a true-up to that estimate based on actual revenue requirements. The guidance provides a five-step model to be used for recognizingtrue-up mechanism is an alternative revenue for the transfer of promised goods and services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services.
The standard is effective for annual and interim reporting periods beginning after December 15, 2017. PSEG adopted this standard on January 1, 2018. PSEG will elect the full retrospective method of transition. Under this method, PSEG will restate its prior period financial statements to align with the 2018 presentation.
PSEG has evaluated existing contracts and revenue streams for potential changes under the new revenue recognition standard. Included inoutside the scope of the new standard are PSE&G’s regulated revenue recorded under tariffs, including the sale of default supply of electric and gas commodity, and the distribution of electricity and gas to retail residential and commercial and industrial customers, and transmission revenues. Tariff revenues comprise substantially all of PSE&G’s revenue. PSEG expects no material change in revenue recognition of PSE&G’s regulated revenue recorded under tariffs. PSE&G’s revenue from contracts with customers will continue to be recorded as electricity or gas is delivered to the customer. Certain reclassifications of PSE&G’s revenue streams will affect Operating Revenues and Operating Expenses due to the application of this standard.customers.
Also included in the scope of the new standard are Power’s electricity, gas and related product sales. Certain reclassifications of Power’s revenue streams will also affect Operating Revenues and Energy Costs due to the application of this standard.
PSEG, PSE&G and Power do not anticipate any material impact to net income as a result of adoption of this new standard.
The new standard will result in more detailed disclosures of revenue compared to current guidance and changes in presentation. PSEG will disaggregate its revenues by operating segment. PSE&G will further disaggregate its revenue by product line (i.e. electric distribution, gas distribution, and transmission). Power will further disaggregate its revenues by product line (i.e. electricity, gas). Electricity revenues will be further disaggregated by region (i.e. PJM, New York ISO and ISO New England). Gas revenues will be further disaggregated by third party sales and sales to affiliates. Other Revenues from Contracts with Customers will
Other revenues from contracts with customers, which are not a material source of PSE&G revenues, are generated primarily from appliance repair services and solar generation projects. The performance obligations under these contracts are satisfied and revenue is recognized as control of products is delivered or services are rendered.
Revenues Unrelated to Contracts with Customers
Other PSE&G revenues unrelated to contracts with customers are derived from alternative revenue mechanisms recorded pursuant to regulatory accounting guidance. These revenues, which include the Conservation Incentive Program (CIP), green energy program true-ups and transmission formula rate true-ups, are not a material source of PSE&G revenues.
PSEG Power & Other
Revenues from Contracts with Customers
Electricity and Related Products—PSEG Power owns generation solely within PJM, which facilitates the dispatch of energy and energy-related products. Prior to the sale of the fossil generation assets in 2022, PSEG Power also had significant sales in the New York Independent System Operator (NYISO) and the New England Independent System Operator (ISO-NE) regions.
PSEG Power primarily sells to the PJM ISO energy and ancillary services which are separately transacted in the day-ahead or real-time energy markets. The energy and ancillary services performance obligations are typically satisfied over time as delivered and revenue is recognized accordingly. Historically, wholesale load contracts have been executed in PJM for the bundled supply of energy, capacity, renewable energy credits (RECs) and ancillary services representing PSEG Power’s performance obligations. Revenue for these contracts is recognized over time as the bundled service is provided to the customer. PSEG generally reports electricity sales and purchases conducted with PJM net on an hourly basis in either Operating Revenues or Energy Costs in its Consolidated Statements of Operations. The classification depends on the net hourly activity.
PSEG Power enters into capacity sales and capacity purchases through PJM. The transactions are reported on a net basis dependent on PSEG Power’s monthly net sale or purchase position through PJM. The performance obligations with PJM are satisfied over time upon delivery of the capacity and revenue is recognized accordingly. In addition to capacity sold through PJM, PSEG Power sells capacity through bilateral contracts and the related revenue is reported on a gross basis and recognized over time upon delivery of the capacity.
In late December 2022, PJM called its first ISO-wide Maximum Generation Emergency Action as a result of Winter Storm Elliott, which triggered a Performance Assessment Interval (PAI) event. During the PAI, PSEG Power’s Salem 2 nuclear plant incurred penalties due to an unplanned outage during the second day of the event. Our remaining nuclear plants earned bonus payments during the entire event. Additional revenue has been recorded in 2023 upon clarification from the ISO on expected bonus payments and receipts to date. The estimated impact of Salem 2’s penalties and bonuses earned by the other units was not material to PSEG’s financial results in 2022 or 2023.
PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants have been awarded zero emission certificates (ZECs) by the BPU through May 2025. These nuclear plants are expected to receive ZEC revenue from the electric distribution companies (EDCs) in New Jersey. PSEG Power recognizes revenue when the units generate electricity, which is when the performance obligation is satisfied. These revenues are included in PJM Sales in the following tables. The number of ZECs purchased by each EDC from a selected nuclear power plant for an energy year is expected to be disclosed includingreduced by the number of ZECs equal in value to the dollar amount of production tax credits (PTCs) received by the same plants. In May 2021, the New Jersey Rate Counsel filed an appeal with the New Jersey Appellate Division of the BPU’s decision in 2021 to award ZECs to the nuclear plants. In December 2023, the Appellate Division rejected Rate Counsel’s appeal and affirmed the BPU’s April 2021 decision and the period during which Rate Counsel could appeal the Appellate Division decision to the New Jersey Supreme Court has expired. No further appeals are permitted.
Gas Contracts—PSEG Power sells wholesale natural gas, primarily through an index based full-requirements Basic Gas Supply Service (BGSS) contract with PSE&G to meet the gas supply requirements of PSE&G’s customers. The BGSS contract remains in effect unless terminated by either party with a two-year notice. Based upon the availability of natural gas, storage and pipeline capacity beyond PSE&G’s daily needs, PSEG Power also sells gas and pipeline capacity to other counterparties under bilateral contracts. The performance obligation is primarily the delivery of gas which is satisfied over time. Revenue is recognized as gas is delivered or pipeline capacity is released.
PSEG LI Contract—PSEG LI has a contract with LIPA which generates revenues. PSEG LI’s subsidiary, Servco records costs which are recovered from LIPA and records the recovery of those costs as revenues when Servco is a principal in the transaction.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Other Revenues from Contracts with Customers
PSEG Power has entered into long-term contracts with LIPA for energy management and fuel procurement services. Revenue is recognized over time as services are rendered.
Revenues Unrelated to Contracts with Customers
PSEG Power’s revenues unrelated to contracts with customers include electric, gas and certain energy-related transactions accounted for in accordance with Derivatives and Hedging accounting guidance. See Note 16. Financial Risk Management Activities for further discussion.
Energy Holdings generates lease revenues which are recorded pursuant to lease accounting guidance.
Disaggregation of Revenues
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| | PSE&G | | PSEG Power & Other (A) | | Eliminations | | Consolidated | |
| | Millions | |
| Year Ended December 31, 2023 | | | | | | | | |
| Revenues from Contracts with Customers | | | | | | | | |
| Electric Distribution | $ | 3,494 | | | $ | — | | | $ | — | | | $ | 3,494 | | |
| Gas Distribution | 1,982 | | | — | | | — | | | 1,982 | | |
| Transmission | 1,673 | | | — | | | — | | | 1,673 | | |
| Electricity and Related Product Sales | | | | | | | | |
| PJM | | | | | | | | |
| Third-Party Sales | — | | | 892 | | | — | | | 892 | | |
| Sales to Affiliates | — | | | 114 | | | (114) | | | — | | |
| | | | | | | | | |
| ISO-NE | — | | | 13 | | | — | | | 13 | | |
| Gas Sales | | | | | | | | |
| Third-Party Sales | — | | | 206 | | | — | | | 206 | | |
| Sales to Affiliates | — | | | 984 | | | (984) | | | — | | |
| Other Revenues from Contracts with Customers (B) | 368 | | | 631 | | | (5) | | | 994 | | |
| Total Revenues from Contracts with Customers | 7,517 | | | 2,840 | | | (1,103) | | | 9,254 | | |
| Revenues Unrelated to Contracts with Customers (C) | 290 | | | 1,693 | | | — | | | 1,983 | | |
| Total Operating Revenues | $ | 7,807 | | | $ | 4,533 | | | $ | (1,103) | | | $ | 11,237 | | |
| | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| | PSE&G | | PSEG Power & Other (A) | | Eliminations | | Consolidated | |
| | Millions | |
| Year Ended December 31, 2022 | | | | | | | | |
| Revenues from Contracts with Customers | | | | | | | | |
| Electric Distribution | $ | 3,503 | | | $ | — | | | $ | — | | | $ | 3,503 | | |
| Gas Distribution | 2,357 | | | — | | | (1) | | | 2,356 | | |
| Transmission | 1,589 | | | — | | | — | | | 1,589 | | |
| Electricity and Related Product Sales | | | | | | | | |
| PJM | | | | | | | | |
| Third-Party Sales | — | | | 2,152 | | | — | | | 2,152 | | |
| Sales to Affiliates | — | | | 151 | | | (151) | | | — | | |
| NYISO | — | | | 88 | | | — | | | 88 | | |
| ISO-NE | — | | | 96 | | | — | | | 96 | | |
| Gas Sales | | | | | | | | |
| Third-Party Sales | — | | | 458 | | | — | | | 458 | | |
| Sales to Affiliates | — | | | 1,243 | | | (1,243) | | | — | | |
| Other Revenues from Contracts with Customers (B) | 390 | | | 605 | | | (6) | | | 989 | | |
| Total Revenues from Contracts with Customers | 7,839 | | | 4,793 | | | (1,401) | | | 11,231 | | |
| Revenues Unrelated to Contracts with Customers (C) | 96 | | | (1,527) | | | — | | | (1,431) | | |
| Total Operating Revenues | $ | 7,935 | | | $ | 3,266 | | | $ | (1,401) | | | $ | 9,800 | | |
| | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| | PSE&G | | PSEG Power & Other (A) | | Eliminations | | Consolidated | |
| | Millions | |
| Year Ended December 31, 2021 | | | | | | | | |
| Revenues from Contracts with Customers | | | | | | | | |
| Electric Distribution | $ | 3,279 | | | $ | — | | | $ | — | | | $ | 3,279 | | |
| Gas Distribution | 1,875 | | | — | | | (13) | | | 1,862 | | |
| Transmission | 1,611 | | | — | | | — | | | 1,611 | | |
| Electricity and Related Product Sales | | | | | | | | |
| PJM | | | | | | | | |
| Third-Party Sales | — | | | 2,003 | | | — | | | 2,003 | | |
| Sales to Affiliates | — | | | 265 | | | (265) | | | — | | |
| NYISO | — | | | 247 | | | — | | | 247 | | |
| ISO-NE | — | | | 172 | | | — | | | 172 | | |
| Gas Sales | | | | | | | | |
| Third-Party Sales | — | | | 181 | | | — | | | 181 | | |
| Sales to Affiliates | — | | | 886 | | | (886) | | | — | | |
| Other Revenues from Contracts with Customers (B) | 343 | | | 620 | | | (3) | | | 960 | | |
| Total Revenues from Contracts with Customers | 7,108 | | | 4,374 | | | (1,167) | | | 10,315 | | |
| Revenues Unrelated to Contracts with Customers (C) | 14 | | | (607) | | | — | | | (593) | | |
| Total Operating Revenues | $ | 7,122 | | | $ | 3,767 | | | $ | (1,167) | | | $ | 9,722 | | |
| | | | | | | | | |
(A)Includes revenues applicable to PSEG Power, PSEG LI and Energy Holdings.
(B)Includes primarily revenues from appliance repair services and the sale of solar renewable energy credits (SRECs) at auction at PSE&G. PSEG Power & Other includes PSEG Power’s energy management fee with LIPA and PSEG LI’s OSA with LIPA.
(C)Includes primarily alternative revenues at PSE&G principally from the CIP program in 2022 and 2023 and net realized and unrealized gains (losses) on derivative contracts and lease contracts at PSEG Power & Other.
Contract Balances
PSE&G
PSE&G did not have any material contract balances (rights to consideration for services already provided or obligations to provide services in the future for consideration already received) as of December 31, 2023 and 2022. Substantially all of PSE&G’s accounts receivable and unbilled revenues result from contracts with customers that are priced at tariff rates. Allowances represented approximately 18% and 20% of accounts receivable (including unbilled revenues) as of December 31, 2023 and 2022, respectively.
Accounts Receivable—Allowance for Credit Losses
PSE&G’s accounts receivable, including unbilled revenues, is primarily comprised of utility customer receivables for the provision of electric and gas service and repairappliance services, and Power solar power revenues.are reported on the balance sheet as gross outstanding amounts adjusted for an allowance for credit losses. The allowance for credit losses reflects PSE&G’s best estimate of losses on the account balances. The allowance is based on PSE&G’s projection of accounts receivable aging, historical experience, economic factors and other currently available evidence, including the estimated impact of the COVID-19 pandemic on the outstanding balances as of December 31, 2023. PSE&G’s electric bad debt expense is recoverable through its SBC mechanism. As of December 31, 2023, PSE&G had a deferred balance of $149 million from electric bad debts recorded as a Regulatory Asset. In addition, as of December 31, 2023, PSE&G had deferred incremental gas bad debt expense of $68 million recorded as a Regulatory Asset for future regulatory recovery due to the impact of the coronavirus pandemic. See Note 6. Regulatory Assets and Liabilities for additional information.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following provides a reconciliation of PSE&G’s allowance for credit losses for the years ended December 31, 2023 and 2022.
| | | | | | | | | | | | | | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | Years Ended December 31, | |
| | 2023 | | 2022 | |
| | Millions | |
| Balance at Beginning of Year | $ | 339 | | | $ | 337 | | |
| Utility Customer and Other Accounts | | | | |
| Provision | 100 | | | 114 | | |
| Write-offs, net of Recoveries of $25 million and $46 million for 2023 and 2022, respectively | (156) | | | (112) | | |
| Balance at End of Year | $ | 283 | | | $ | 339 | | |
| | | | | |
PSEG will electPower & Other
PSEG Power generally collects consideration upon satisfaction of performance obligations, and therefore, PSEG Power had no material contract balances as of December 31, 2023 and 2022.
PSEG Power’s accounts receivable include amounts resulting from contracts with customers and other contracts which are out of scope of accounting guidance for revenues from contracts with customers. The majority of these accounts receivable are subject to master netting agreements. As a result, accounts receivable resulting from contracts with customers and receivables unrelated to contracts with customers are netted within Accounts Receivable and Accounts Payable on the invoice practical expedient, where applicable,Consolidated Balance Sheets.
PSEG Power’s accounts receivable consist mainly of revenues from energy and ancillary services sold directly to ISOs and other counterparties. In the wholesale energy markets in recordingwhich PSEG Power operates, payment for services rendered and products transferred are typically due within 30 days of delivery. As such, there is little credit risk associated with these receivables. PSEG Power did not record an allowance for credit losses for these receivables as of December 31, 2023 and 2022. PSEG Power monitors the status of its revenue. Undercounterparties on an ongoing basis to assess whether there are any anticipated credit losses.
PSEG LI did not have any material contract balances as of December 31, 2023 and 2022.
Remaining Performance Obligations under Fixed Consideration Contracts
PSEG primarily records revenues as allowed by the practical expedient, PSEGguidance, which states that if an entity has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of PSEG’sthe entity’s performance completed to date. PSEGdate, the entity may recognize revenue in the amount to which itthe entity has a right to invoice. As such under this practical expedient, there are noPSEG has future performance obligations under contracts with fixed consideration as follows:
Capacity Revenues from the PJM Annual Base Residual and Incremental Auctions—The Base Residual Auction is generally conducted annually three years in advance of the operating period. The 2023/2024 auction was held in June 2022. In February 2023, the results of the 2024/2025 auction held in December 2022 were released. PSEG Power expects to disclose. Whererealize the following average capacity prices resulting from the base and incremental auctions, including unit specific bilateral contracts for previously cleared capacity obligations.
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| Delivery Year | | $ per MW-Day | | MW Cleared | |
| June 2023 to May 2024 | | $50 | | 3,700 | |
| June 2024 to May 2025 | | $55 | | 3,500 | |
| | | | | | |
Capacity transactions with the PJM Regional Transmission Organization are reported on a net basis dependent on PSEG hasPower’s monthly net sale or purchase position.
Amended OSA—In April 2022, PSEG LI entered into an amended OSA with LIPA. The OSA remains a 12-year services contract ending in 2025 with annual fixed consideration contracts, it will disclose its remaining performance obligations under these agreements.
Recognition and Measurementvariable components. The fixed fee for the provision of Financial Assetsservices thereunder in 2024 is approximately $44 million and Financial Liabilities
This accounting standard will change how entities measure equity investments that are not consolidated or accounted for underis updated each year based on the equity method. Under the new guidance, equity investments (other than those accounted for using the equity method) will be measured at fair value through Net Income instead of Other Comprehensive Income (Loss). Entities that have elected the fair value option for financial liabilities will present changes in fair value due to a change in their own credit risk through Other Comprehensive Income (Loss). For equity investments which do not have readily determinable fair values, the impairment assessment will be simplified by requiring a qualitative assessment to identify impairments. The new standard also changes certain disclosures.Consumer Price Index (CPI).
The standard is effective for annual and interim reporting periods beginning after December 15, 2017. PSEG recorded a cumulative effect adjustment by reclassifying the unrealized gain related to equity investments of $342 million ($176 million, net of tax) from Accumulated Other Comprehensive Income to Retained Earnings on January 1, 2018, and expects increased volatility in Net Income due to changes in fair value of its equity securities within the NDT and Rabbi Trust Funds.
Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments
This accounting standard reduces the diversity in practice in how certain cash receipts and cash payments are presented and classified in the Statement of Cash Flows.
The standard is effective for annual and interim periods beginning after December 15, 2017; early adoption was permitted. PSEG expects no changes in its presentation of its Statement of Cash Flows as a result of adopting this new standard. PSEG adopted this standard on January 1, 2018 using a retrospective transition method to each period presented.
Statement of Cash Flows: Restricted Cash
This accounting standard requires entities to explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents, either in a narrative or a tabular format. Amounts generally described as restricted cash or restricted cash equivalents should be included in entities’ reconciliation of beginning-of-period and end-of-period amounts in the Statement of Cash Flows.
The standard is effective for annual and interim periods beginning after December 15, 2017; early adoption was permitted. PSEG adopted this standard on January 1, 2018 using a retrospective transition method for each period presented. PSEG will
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 3. Asset Dispositions and Impairments
continueIn May 2023, PSEG sold its 25% equity interest in Ocean Wind JV HoldCo, LLC. The sale proceeds approximated PSEG’s carrying value of the current balance sheet classificationinvestment; therefore, no material gain or loss was recognized upon disposition.
In July 2023, PSEG Power completed the sale of restricted cashits 50% ownership interest in Kalaeloa. The sale proceeds approximated PSEG Power's carrying value of the investment; therefore, no material gain or restricted cash equivalents.loss was recognized upon disposition.
In 2022, Energy Holdings recorded pre-tax impairments of $78 million related to one of its domestic energy generating facilities and its real estate assets. In March 2023, Energy Holdings completed the sale of its domestic energy generating facility and recorded an immaterial pre-tax gain. In December 2023, Energy Holdings completed the sale of its real estate assets and recorded an immaterial pre-tax gain.
In August 2021, PSEG will provide a reconciliation of cash and cash equivalents and restricted cash or restricted cash equivalents and include a description of these amounts.
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (OPEB)
This accounting standard was issuedentered into two agreements to improve the presentation of net periodic pension cost and net periodic OPEB cost.
Under the new guidance, entities are required to report the service cost component in the same line item or items as other compensation costs arising from services rendered by their employees during the period. The other components of net benefit cost are required to be presented in the Statement of Operations separately from the service cost component after Operating Income. Additionally, only the service cost component will be eligible for capitalization, when applicable.
The standard requires the amendments to be applied retrospectivelysell PSEG Power’s 6,750 MW fossil generating portfolio, one agreement for the presentationsale of assets in New Jersey and Maryland and another agreement for the sale of assets located in New York and Connecticut, to newly formed subsidiaries of ArcLight Energy Partners Fund VII, L.P., a fund controlled by ArcLight Capital Partners, LLC for aggregate consideration of approximately $1,920 million. In 2021, PSEG recorded a pre-tax impairment loss on sale of approximately $2,691 million as the purchase price was lower than the carrying value in 2021. In addition to the impairment loss, all of PSEG Power’s outstanding debt obligations were redeemed and PSEG incurred a pre-tax loss of $298 million for the make-whole provision payable upon early redemption and other non-cash debt extinguishment costs and also recorded approximately $13 million in pre-tax severance and retention charges, environmental accruals and other adjustments.
As defined in each agreement, further adjustments were required as a result of any purchase price or working capital adjustments, including an adjustment for positive or negative cash flow of the service cost component and the other cost components of net periodic pension cost and net periodic OPEB cost in the Statement of Operations and prospectively,fossil generating assets based on and after the effective date, for the capitalization of the service cost component of net periodic pension and OPEB costs.
The standard is effective for annual and interim reporting periods beginningactual performance starting after December 15, 2017. PSEG adopted this standard as of January 1, 2018. Beginning January 1, 2018, PSEG and each of its subsidiaries began to classify31, 2021 through the total net pension and OPEB non-service benefit costs in a separate line item in the Statement of Operations after Operating Income. PSEG will also recast those amounts for prior years in accordance with the new standard by using the practical expedient of using the previously disclosed non-service components of pension and OPEB costs. The service cost component of pension and OPEB costs will continue to be classified in O&M Expense, except for that portion capitalized, as appropriate, within Property, Plant and Equipment.closing dates. As a result, in 2022 PSEG Power recorded an additional pre-tax impairment of adoptingapproximately $50 million prior to completing the sale of this new standard, PSE&G expects to reduce its charge to expense by approximately $55 million to $65 millionfossil generating portfolio in 2018.February 2022.
Stock Compensation - ScopePSEG Power has retained ownership of Modification Accounting
This accounting standard provides clarity and reduces both diversity in practice and complexity when applyingcertain liabilities excluded from the stock compensation guidance to a change in the terms or conditions of a stock-based payment award. Specifically, the standard provides guidance as to which changes to the terms or conditions of a stock-based payment award require an entity to apply modification accounting.
The standard is effective for all entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2017, early adoption was permitted. This standard should be applied prospectively to an award modified on or after the adoption date. PSEG adopted this standard effective January 1, 2018.
New Standards Issued But Not Yet Adopted
Leases
This accounting standard replaces existing lease accounting guidance and requires lessees to recognize all leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases based on whether control of the underlying assets has transferred to the lessee. A lessor will classify its leases as operating or direct financing leases, or as sales-type leases based on whether control of the underlying assets has transferred to the lessee. Both the lessee and lessor models require additional disclosure of key information. The standard requires lessees and lessors to apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. However, existing guidancetransactions primarily related to leveraged leases will not change.
The standard is effective for annual and interim periods beginning after December 15, 2018 with retrospective application to previously issued financial statements for 2018 and 2017. Early application is permitted. PSEG is currently analyzing the impact of this standard on its financial statements.
Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities
This accounting standard’s amendments more closely align hedge accounting with the companies’ risk management activities in the financial statements. The amendments expand hedge accounting for both non-financial and financial risk components by permitting contractually specified components to designate as the hedged risk in a cash flow hedge involving the purchase or sale of non-financial assets or variable rate financial instruments. Additionally, the amendments ease the operational burden of applying hedge accounting by allowing more time to prepare hedge documentation, and allow effectiveness assessments to be performed on a qualitative basis after hedge inception.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The new guidance is effective for annual and interim periods beginning after December 15, 2018. The standard requires using a modified retrospective method upon adoption. Early adoption is permitted. PSEG is currently analyzing the impact of this standard on its consolidated financial statements.
Premium Amortization on Purchased Callable Debt Securities
This accounting standard was issued to shorten the amortization period for certain callable debt securities held at a premium. Specifically, the standard requires the premium to be amortized to the earliest call date. The amendments do not require an accounting change for securities held at a discount; the discount continues to be amortized to maturity.
The standard is effective for annual and interim reporting periods beginning after December 15, 2018. Early adoption is permitted for an entity in any interim or annual period. If an entity early adopts the standard in an interim period, any
adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity should apply this standard on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. Additionally, in the period of adoption, an entity should provide disclosures about a change in accounting principle. PSEG is currently analyzing the impact of this standard on its financial statements.
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income
This accounting standard would affect any entity that is required to apply the provisions of the Accounting Standards Codification topic, “Income Statement-Reporting Comprehensive Income,” and has items of other comprehensive income for which the related tax effects are presented in other comprehensive income as required by GAAP. Specifically, this standard would allow entities to record a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the newly enacted federal corporate income tax rate. The amount of the reclassification would be the difference between the historical corporate income tax rate and the newly enacted 21% corporate income tax rate.
The standard is effective for all entities for annual periods, and interim periods within those annual periods beginning after December 15, 2018. Early adoption is permitted for an entity in any interim or annual period for public business entities for reporting periods for which financial statements have not yet been issued or made available for issuance.
An entity would be able to choose to apply this standard retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the new tax legislation enacted in 2017 is recognized or apply the standard in the reporting period adopted. PSEG is currently analyzing the impact this standard, if adopted, could have on its consolidated financial statements.
Measurement of Credit Losses on Financial Instruments
This accounting standard provides a new model for recognizing credit losses on financial assets carried at amortized cost. The new model requires entities to use an estimate of expected credit losses that will be recognized as an impairment allowance rather than a direct write-down of the amortized cost basis. The estimate of expected credit losses is to be based on past events, current conditions and supportable forecasts over a reasonable period. For purchased financial assets with credit deterioration, a similar model is to be used; however, the initial allowance will be added to the purchase price rather than reported as an allowance. Credit losses on available-for-sale securities should be measured in a manner similar to current GAAP; however, this standard requires those credit losses to be presented as an allowance, rather than a write-down. This new standard also requires additional disclosures of credit quality indicators for each class of financial asset disaggregated by year of origination.
The standard is effective for annual and interim periods beginning after December 15, 2019; however, entities may adopt early beginning in the annual or interim periods after December 15, 2018. PSEG is currently analyzing the impact of this standard on its financial statements.
Simplifying the Test for Goodwill Impairment
This accounting standard requires an entity to perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable.
An entity should apply this standard on a prospective basis and will be required to disclose the nature of and reason for the change in accounting principle upon transition. The new standard is effective for impairment tests for periods beginning January 1, 2020. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. PSEG is currently assessing the impact of this guidance upon its financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 3. Early Plant Retirements
Fossil
In October 2016, Power determined that it would cease generation operations of the existing coal/gas units at the Hudson and Mercer generating stations on June 1, 2017. Both units were available to operate through May 31, 2017 and were subsequently retired from operation on June 1, 2017. As of December 31, 2017, the retirements of both units were substantially complete.
In the latter half of 2016, PSEG and Power recognized pre-tax charges in Energy Costs and O&M of $62 million and $53 million, respectively, related to coal inventory adjustments, capacity penalties, materials and supplies inventory reserve adjustments for parts that cannot be used at other generating units, employee-related severance benefits costs and construction work in progress impairments, among other shut down items. In addition to these charges, Power recognized Depreciation and Amortization (D&A) during 2016 of $571 million due to the significant shortening of the expected economic useful lives of Hudson and Mercer.
As of June 1, 2017, Power recognized total D&A of $964 million for the Hudson and Mercer units to reflect the end of their economic useful lives in 2017. During the year ended December 31, 2017, Power recognized pre-tax charges in Energy Costs of $15 million, primarily for coal inventory lower of cost or market adjustments. During the year ended December 31, 2017, Power also recognized pre-tax charges in O&M of $23 million, including shut down costs and an increase in the Asset Retirement Obligation due to settlements and changes in cash flow estimates, partially offset by changes in employee-related severance costs. Power is exploring various opportunities with these sites, including using the sites for alternative industrial activity or the disposition of one or both of the sites. If Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would trigger obligations under certain environmental regulations, including possible remediation.remediation obligations under the New Jersey Industrial Site Recovery Act (ISRA) and the Connecticut Transfer Act (CTA). The amounts for any such environmental remediation are neithernot currently probable nor estimable, but maywill likely be material.material in the aggregate.
AsIn May 2021, PSEG Power Ventures LLC (Power Ventures), a direct wholly owned subsidiary of December 31, 2016,PSEG Power, had reduced the estimated useful lifeentered into a purchase agreement with Quattro Solar, LLC, an affiliate of Bridgeport Harbor Station unit 3 (BH3) from 2025LS Power, relating to the summersale by Power Ventures of 2021 as it was more likely than not it will retire the unit by this time.
100% of its ownership interest in PSEG Solar Source LLC (Solar Source) including its related assets and Power continue to monitor their other coal assets, including the Keystone and Conemaugh generating stations, to assess their economic viability through the end of their designated useful lives and their continued classification as held for use.liabilities. The precise timing oftransaction closed in June 2021. As 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 held for use classification of our remaining coal units may have a material adverse impact on PSEG’s and Power’s future financial results.
Nuclear
Since 2013, several nuclear generating stations in the United States have closed or announced early retirement due to economic reasons, or have announced being at risk for early retirement. Most recently, in February 2018, Exelon, a co-ownerresult of the Salem units, announced its intention to acceleratesale, PSEG Power recorded a pre-tax gain on sale of approximately $63 million, which is inclusive of the closurerecognition of its Oyster Creek nuclear plant located in New Jersey, one year earlier than previously planned for economic reasons. These closuresdeferred unamortized ITCs of $185 million, and retirements are generallyincome tax expense of approximately $62 million primarily due to the decline in market pricesrecapture of energy, resulting from low natural gas prices driven by the growth of shale gas production since 2007, the continuing cost of regulatory compliance and enhanced securityITC on units that operated for nuclear facilities, both federal and state-level policies that provide financial incentives to construct renewable energy such as wind and solar and the failure to adequately compensate nuclear generating stations for the attributes they bring similar to renewable energy production. These trends have significantly reduced the revenues of nuclear generating stations while limiting their ability to reduce the unit cost of production. This may result in the electric generation industry experiencing a further shift from nuclear generation to natural gas-fired generation, creating less diversity of the generation fleet.than five years.
If any or all of the Salem and Hope Creek units were shut down, it would significantly alter New Jersey’s energy supply predominately by increasing New Jersey’s reliance on natural gas generation. Such a decrease in fuel diversity could also increase the market’s vulnerability to price fluctuations and power disruptions in times of high demand. The New Jersey Legislature is assessing legislation that would provide a safety net in order to prevent the loss of environmental attributes from nuclear generating stations. Power cannot predict whether the legislation will be enacted or, if enacted, whether our nuclear generating stations in New Jersey will be selected or whether the legislation will provide a sufficient safety net for the continued operation of nuclear generating stations in New Jersey.
In the ordinary course, management, and in the case of the Salem units the co-owner, each makes a number of decisions that impact the operation of our nuclear units beyond the current year, including whether and to what extent these units participate in RPM capacity auctions, commitments relating to refueling outages and significant capital expenditures, and decisions regarding our hedging arrangements. When considering whether to make these future commitments, management’s decisions will primarily be
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
influenced by the financial outlook of the units, including the progress, timing and continued outlook for enactment of proposed legislation in the state of New Jersey.
If market prices continue to be depressed and legislation is not enacted that adequately compensates nuclear generating stations for their attributes, Power anticipates it will no longer be covering its costs nor be adequately compensated for its market and operational risks at the Salem and Hope Creek nuclear units and would anticipate retiring these units early. The costs associated with any such retirement, which may include, among other things, accelerated depreciation and amortization or impairment charges, accelerated asset retirement costs, severance costs, environmental remediation costs and additional funding of the Nuclear Decommissioning Trust Fund (NDT) would be material to both PSEG and Power.
The following table provides the balance sheet amounts by generating station as of December 31, 2017 for significant assets and liabilities associated with Power’s owned share of its nuclear assets.
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | As of December 31, 2017 | |
| | | Hope Creek | | Salem | | Support Facilities and Other (A) | | Peach Bottom | |
| | | Millions | |
| Assets | | | | | | | | | |
| Materials and Supplies Inventory | | $ | 86 |
| | $ | 78 |
| | $ | — |
| | $ | 41 |
| |
| Nuclear Production, net of Accumulated Depreciation | | 605 |
| | 661 |
| | 211 |
| | 802 |
| |
| Nuclear Fuel In-Service, net of Accumulated Depreciation | | 104 |
| | 124 |
| | — |
| | 153 |
| |
| Construction Work in Progress (including nuclear fuel) | | 245 |
| | 90 |
| | 1 |
| | 25 |
| |
| Total Assets | | $ | 1,040 |
| | $ | 953 |
| | $ | 212 |
| | $ | 1,021 |
| |
| Liabilities | | | | | | | | | |
| Asset Retirement Obligation | | $ | 302 |
| | $ | 249 |
| | $ | — |
| | $ | 205 |
| |
| Total Liabilities | | $ | 302 |
| | $ | 249 |
| | $ | — |
| | $ | 205 |
| |
| Net Assets | | $ | 738 |
| | $ | 704 |
| | $ | 212 |
| | $ | 816 |
| |
| NRC License Renewal Term | | 2046 | | 2036/2040 |
| | N/A |
| | 2033/2034 |
| |
| % Owned | | 100 | % | | 57 | % | | Various |
| | 50 | % | |
| | | | | | | | | | |
| |
(A) | Includes Hope Creek’s and Salem’s shared support facilities and other nuclear development capital. |
The precise timing of any potential early retirement and resulting financial statement impact may be affected by a number of factors, including co-owner considerations, the results of any transmission system reliability study assessments and decommissioning trust fund requirements and other commitments, as well as future energy prices. Power maintains a NDT Fund that funds its decommissioning obligations. See Note 9. Available-for-Sale Securities.
Note 4. Variable Interest Entity (VIE)
VIE for which PSEG LI is the Primary Beneficiary
PSEG LI consolidates Long Island Electric Utility Servco, LLC (Servco), a marginally capitalized VIE, which was created for the purpose of operating LIPA’s T&D system in Long Island, New York as well as providing administrative support functions to LIPA. PSEG LI is the primary beneficiary of Servco because it directs the operations of Servco, the activity that most significantly impacts Servco’s economic performance and it has the obligation to absorb losses of Servco that could potentially be significant to Servco. Such losses would be immaterial to PSEG.
Pursuant to the OSA, Servco’s operating costs are reimbursablepaid entirely by LIPA, and therefore, PSEG LI’s risk is limited related to the activities of Servco. PSEG LI has no current obligation to provide direct financial support to Servco. In addition to reimbursementpayment of Servco’s operating costs as provided for in the OSA, PSEG LI receives an annual contract management fee. PSEG LI’s annual contractual management fee, in certain situations, could be partially offset by Servco’s annual storm costs not approved by the Federal Emergency Management Agency, limited contingent liabilities and penalties for failing to meet certain performance metrics.
For transactions in which Servco acts as principal and controls the services provided to LIPA, such as transactions with its employees for labor and labor-related activities, including pension and OPEB-related transactions, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and O&M Expense, respectively. In 2017, 20162023, 2022 and 2015,2021, Servco recorded $438$533 million, $410$516 million
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
and $375$511 million, respectively, of O&M costs, the full reimbursement of
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
which was reflected in Operating Revenues. For transactions in which Servco acts as an agent for LIPA, it records revenues and the related expenses on a net basis, resulting in no impact on PSEG’s Consolidated Statement of Operations.
Note 5. Property, Plant and Equipment and Jointly-Owned Facilities
Information related to Property, Plant and Equipment as of December 31, 20172023 and 20162022 is detailed below:
| | | | | | | | | | | | | | | | | |
| | | | | |
| | 2023 | | 2022 | |
| | Millions | |
| PSE&G | | | | |
| Electric Transmission | $ | 17,379 | | | $ | 16,393 | | |
| Electric Distribution | 11,554 | | | 10,785 | | |
| Gas Distribution and Transmission | 11,545 | | | 10,616 | | |
| Construction Work in Progress | 1,283 | | | 1,336 | | |
| Other | 1,992 | | | 1,915 | | |
| Total PSE&G | 43,753 | | | 41,045 | | |
| Nuclear Production | 3,496 | | | 3,567 | | |
| Nuclear Fuel in Service | 772 | | | 758 | | |
| Construction Work in Progress | 224 | | | 177 | | |
| Other | 358 | | | 377 | | |
| Total | $ | 48,603 | | | $ | 45,924 | | |
| | | | | |
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| | PSE&G | | Power | | Other | | PSEG Consolidated | |
| | Millions | |
| 2017 | | | | | | | | |
| Transmission and Distribution: | | | | | | | | |
| Electric Transmission | $ | 10,425 |
| | $ | — |
| | $ | — |
| | $ | 10,425 |
| |
| Electric Distribution | 8,455 |
| | — |
| | — |
| | 8,455 |
| |
| Gas Distribution and Transmission | 7,122 |
| | — |
| | — |
| | 7,122 |
| |
| Construction Work in Progress | 1,735 |
| | — |
| | — |
| | 1,735 |
| |
| Other | 512 |
| | — |
| | — |
| | 512 |
| |
| Total Transmission and Distribution | 28,249 |
| | — |
| | — |
| | 28,249 |
| |
| Generation: | | | | | | | | |
| Fossil Production | — |
| | 4,923 |
| | — |
| | 4,923 |
| |
| Nuclear Production | — |
| | 2,893 |
| | — |
| | 2,893 |
| |
| Nuclear Fuel in Service | — |
| | 745 |
| | — |
| | 745 |
| |
| Other Production-Solar | 593 |
| | 757 |
| | — |
| | 1,350 |
| |
| Construction Work in Progress | — |
| | 2,339 |
| | — |
| | 2,339 |
| |
| Total Generation | 593 |
| | 11,657 |
| | — |
| | 12,250 |
| |
| Other | 275 |
| | 98 |
| | 359 |
| | 732 |
| |
| Total | $ | 29,117 |
| | $ | 11,755 |
| | $ | 359 |
| | $ | 41,231 |
| |
| | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | PSE&G | | Power | | Other | | PSEG Consolidated | |
| | | Millions | |
| 2016 | | | | | | | | | |
| Transmission and Distribution: | | | | | | | | | |
| Electric Transmission | | $ | 9,149 |
| | $ | — |
| | $ | — |
| | $ | 9,149 |
| |
| Electric Distribution | | 7,976 |
| | — |
| | — |
| | 7,976 |
| |
| Gas Distribution and Transmission | | 6,458 |
| | — |
| | — |
| | 6,458 |
| |
| Construction Work in Progress | | 1,501 |
| | — |
| | — |
| | 1,501 |
| |
| Other | | 439 |
| | — |
| | — |
| | 439 |
| |
| Total Transmission and Distribution | | 25,523 |
| | — |
| | — |
| | 25,523 |
| |
| Generation: | | | | | | | | | |
| Fossil Production | | — |
| | 7,096 |
| | — |
| | 7,096 |
| |
| Nuclear Production | | — |
| | 2,516 |
| | — |
| | 2,516 |
| |
| Nuclear Fuel in Service | | — |
| | 783 |
| | — |
| | 783 |
| |
| Other Production-Solar | | 591 |
| | 687 |
| | — |
| | 1,278 |
| |
| Construction Work in Progress | | — |
| | 1,483 |
| | — |
| | 1,483 |
| |
| Total Generation | | 591 |
| | 12,565 |
| | — |
| | 13,156 |
| |
| Other | | 233 |
| | 90 |
| | 335 |
| | 658 |
| |
| Total | | $ | 26,347 |
| | $ | 12,655 |
| | $ | 335 |
| | $ | 39,337 |
| |
| | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSE&G and PSEG Power have ownership interests in and are responsible for providing their respective shares of the necessary financing for the following jointly-owned facilities to which they are a party. All amounts reflect PSE&G’s or PSEG Power’s share of the jointly-owned projects and the corresponding direct expenses are included in the Consolidated Statements of Operations as operating expenses.Operating Expenses.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | As of December 31, | |
| | | | | 2023 | | 2022 | |
| | | Ownership | | | | Accumulated | | | | Accumulated | |
| | | Interest | | Plant | | Depreciation | | Plant | | Depreciation | |
| | | | | Millions | |
| PSE&G: | | | | | | | | | | | |
| Transmission Facilities | | Various | | $ | 164 | | | $ | 69 | | | $ | 164 | | | $ | 67 | | |
| PSEG Power: | | | | | | | | | | | |
| Nuclear Generating: | | | | | | | | | | | |
| Peach Bottom | | 50 | % | | $ | 1,451 | | | $ | 534 | | | $ | 1,444 | | | $ | 506 | | |
| Salem | | 57 | % | | $ | 1,461 | | | $ | 534 | | | $ | 1,455 | | | $ | 516 | | |
| Nuclear Support Facilities | | Various | | $ | 178 | | | $ | 77 | | | $ | 228 | | | $ | 119 | | |
| Other | | 14 | % | | $ | 1 | | | $ | — | | | $ | 1 | | | $ | — | | |
| | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | As of December 31, | |
| | | | | 2017 | | 2016 | |
| | | Ownership | | | | Accumulated | | | | Accumulated | |
| | | Interest | | Plant | | Depreciation | | Plant | | Depreciation | |
| | | | | Millions | |
| PSE&G: | | | | | | | | | | | |
| Transmission Facilities | | Various |
| | $ | 162 |
| | $ | 58 |
| | $ | 169 |
| | $ | 65 |
| |
| Power: | | | | | | | | | | | |
| Coal Generating: | | | | | | | | | | | |
| Conemaugh | | 23 | % | | $ | 408 |
| | $ | 178 |
| | $ | 408 |
| | $ | 166 |
| |
| Keystone | | 23 | % | | $ | 409 |
| | $ | 187 |
| | $ | 409 |
| | $ | 176 |
| |
| Nuclear Generating: | | | | | | | | | | | |
| Peach Bottom | | 50 | % | | $ | 1,328 |
| | $ | 348 |
| | $ | 1,272 |
| | $ | 306 |
| |
| Salem | | 57 | % | | $ | 1,147 |
| | $ | 277 |
| | $ | 1,077 |
| | $ | 304 |
| |
| Nuclear Support Facilities | | Various |
| | $ | 239 |
| | $ | 81 |
| | $ | 238 |
| | $ | 71 |
| |
| Pumped Storage Facilities: | | | | | | | | | | | |
| Yards Creek | | 50 | % | | $ | 44 |
| | $ | 26 |
| | $ | 42 |
| | $ | 25 |
| |
| Merrill Creek Reservoir | | 14 | % | | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | — |
| |
| | | | | | | | | | | | |
PSEG Power holds undivided ownership interests in the jointly-owned facilities above. PSEG Power is entitled to shares of the generating capability and output of each unit equal to its respective ownership interests. PSEG Power also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. PSEG Power’s share of expenses for the jointly-owned facilities is included in the appropriate expense category. Each owner is responsible for any financing with respect to its pro rata share of capital expenditures.
PSEG Power co-owns Salem and Peach Bottom with Exelon Generation.Constellation Energy Generation, LLC. PSEG Power is the operator of Salem and ExelonConstellation Energy Generation, LLC is the operator of Peach Bottom. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part of the normal PSEG Power governance process.
GenOn Northeast Management Company is a co-owner and the operator for Keystone Generating Station and Conemaugh Generating Station. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Power is a co-owner in the Yards Creek Pumped Storage Generation Facility. Jersey Central Power & Light Company (JCP&L) is also a co-owner and the operator of this facility. JCP&L submits separate capital and O&M budgets, subject to Power’s approval as part of the normal Power governance process.
Power is a minority owner in the Merrill Creek Reservoir and Environmental Preserve in Warren County, New Jersey. Merrill Creek Owners Group is the owner-operator of this facility. The operator submits separate capital and O&M budgets, subject to Power’s approval as part of the normal Power governance process.
Note 6. Regulatory Assets and Liabilities
PSE&G prepares its financial statements in accordance with GAAP for regulated utilities as described in Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies. PSE&G has deferred certain costs based on rate orders issued by the BPU or FERC or based on PSE&G’s experience with prior rate cases.proceedings. Most of PSE&G’s Regulatory Assets and Liabilities as of December 31, 20172023 are supported by written orders, either explicitly or implicitly through the BPU’s treatment of various cost items. These costs will be recovered and amortized over various future periods.
Regulatory Assets and other investments and costs incurred under our various infrastructure filings and clause mechanisms are subject to prudence reviews and can be disallowed in the future by regulatory authorities. To the extent that collection of any
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
infrastructure or clause mechanism revenue, Regulatory Assets or payments of Regulatory Liabilities is no longer probable, the amounts would be charged or credited to income.
PSE&G had the following Regulatory Assets and Liabilities: |
| | | | | | | | | | |
| | | | | | |
| | | As of December 31, | |
| | | 2017 | | 2016 | |
| | | Millions | |
| Regulatory Assets | | | | | |
| Current | | | | | |
| New Jersey Clean Energy Program | | $ | 128 |
| | $ | 142 |
| |
| Weather Normalization Clause (WNC) | | 40 |
| | 49 |
| |
| Electric Energy Costs—Basic Generation Service | | 23 |
| | 2 |
| |
| FERC Formula Rate True-up | | 12 |
| | — |
| |
| Other | | 8 |
| | 6 |
| |
| Total Current Regulatory Assets | | $ | 211 |
| | $ | 199 |
| |
| Noncurrent | | | | | |
| Pension and OPEB Costs | | $ | 1,488 |
| | $ | 1,403 |
| |
| Manufactured Gas Plant (MGP) Remediation Costs | | 358 |
| | 403 |
| |
| Deferred Income Taxes | | 282 |
| | 507 |
| |
| Storm Damage Deferrals | | 241 |
| | 239 |
| |
| Electric Transmission and Gas Cost of Removal | | 199 |
| | 189 |
| |
| Remediation Adjustment Charge (RAC) (Other SBC) | | 172 |
| | 180 |
| |
| Conditional Asset Retirement Obligation | | 162 |
| | 157 |
| |
| Green Program Recovery Charges (GPRC) | | 98 |
| | 91 |
| |
| Unamortized Loss on Reacquired Debt and Debt Expense | | 55 |
| | 61 |
| |
| Gas Costs—Basic Gas Supply Service (BGSS) | | 30 |
| | — |
| |
| FERC Formula Rate True-up | | 16 |
| | — |
| |
| Other | | 121 |
| | 89 |
| |
| Total Noncurrent Regulatory Assets | | $ | 3,222 |
| | $ | 3,319 |
| |
| Total Regulatory Assets | | $ | 3,433 |
| | $ | 3,518 |
| |
| | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | As of December 31, | |
| | | 2023 | | 2022 | |
| | | Millions | |
| Regulatory Assets | | | | | |
| Current | | | | | |
| New Jersey Clean Energy Program | | $ | 145 | | | $ | 145 | | |
| Conservation Incentive Program (CIP) | | 103 | | | 51 | | |
| Electric Energy Costs—Basic Generation Service (BGS) | | 19 | | | 54 | | |
| Societal Benefits Clause (SBC) | | 6 | | | 20 | | |
| Tax Adjustment Credit (TAC) | | — | | | 52 | | |
| | | | | | |
| 2018 Distribution Base Rate Case Regulatory Assets (BRC) | | — | | | 47 | | |
| | | | | | |
| | | | | | |
| | | | | | |
| Total Current Regulatory Assets | | 273 | | | 369 | | |
| Noncurrent | | | | | |
| Pension and OPEB Costs | | $ | 1,427 | | | $ | 1,405 | | |
| Deferred Income Tax Regulatory Assets | | 1,343 | | | 1,168 | | |
| Green Program Recovery Charges (GPRC) | | 827 | | | 447 | | |
| Asset Retirement Obligations (ARO) | | 210 | | | 200 | | |
| Manufactured Gas Plant (MGP) Remediation Costs | | 199 | | | 206 | | |
| Cost of Removal | | 172 | | | 156 | | |
| Clean Energy Future-Energy Cloud (CEF-EC) (Advanced Metering Infrastructure (AMI)) | | 153 | | | 80 | | |
| SBC (Electric Bad Debt) | | 149 | | | 145 | | |
| COVID-19 Deferral | | 131 | | | 137 | | |
| CIP | | 129 | | | 72 | | |
| Remediation Adjustment Charge (RAC) (Other SBC) | | 110 | | | 134 | | |
| Deferred Storm Costs | | 109 | | | 109 | | |
| Other | | 198 | | | 145 | | |
| Total Noncurrent Regulatory Assets | | 5,157 | | | 4,404 | | |
| Total Regulatory Assets | | $ | 5,430 | | | $ | 4,773 | | |
| | | | | | |
|
| | | | | | | | | | |
| | | | | | |
| | | As of December 31, | |
| | | 2017 | | 2016 | |
| | | Millions | |
| Regulatory Liabilities | | | | | |
| Current | | | | | |
| Gas Costs —BGSS | | $ | 30 |
| | $ | 6 |
| |
| Gas Margin Adjustment Clause | | 12 |
| | 11 |
| |
| GPRC | | 3 |
| | 28 |
| |
| FERC Formula Rate True-up | | — |
| | 34 |
| |
| Other | | 2 |
| | 9 |
| |
| Total Current Regulatory Liabilities | | $ | 47 |
| | $ | 88 |
| |
| Noncurrent | | | | | |
| Excess Deferred Income Tax Regulatory Liability | | $ | 2,868 |
| | $ | — |
| |
| Electric Distribution Cost of Removal | | 80 |
| | 94 |
| |
| Mark-to-Market (MTM) Contracts | | — |
| | 20 |
| |
| Other | | — |
| | 4 |
| |
| Total Noncurrent Regulatory Liabilities | | $ | 2,948 |
| | $ | 118 |
| |
| Total Regulatory Liabilities | | $ | 2,995 |
| | $ | 206 |
| |
| | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | As of December 31, | |
| | | 2023 | | 2022 | |
| | | Millions | |
| Regulatory Liabilities | | | | | |
| Current | | | | | |
| Deferred Income Tax Regulatory Liabilities | | $ | 170 | | | $ | 302 | | |
| | | | | | |
| Gas Costs—Basic Gas Supply Service (BGSS) | | 97 | | | 35 | | |
| Formula Rate True-up | | 22 | | | 1 | | |
| GPRC | | 20 | | | 24 | | |
| | | | | | |
| TAC | | 18 | | | — | | |
| Other | | 22 | | | 22 | | |
| Total Current Regulatory Liabilities | | 349 | | | 384 | | |
| Noncurrent | | | | | |
| Deferred Income Tax Regulatory Liabilities | | $ | 2,075 | | | $ | 2,196 | | |
| Formula Rate True-up | | — | | | 31 | | |
| | | | | | |
| Other | | — | | | 13 | | |
| Total Noncurrent Regulatory Liabilities | | 2,075 | | | 2,240 | | |
| Total Regulatory Liabilities | | $ | 2,424 | | | $ | 2,624 | | |
| | | | | | |
All Regulatory Assets and Liabilities are excluded from PSE&G’s rate base unless otherwise noted. The Regulatory Assets and Liabilities in the table above are defined as follows:
Conditional Asset Retirement Obligation:•ARO: These costs represent the differences between rate regulatedrate-regulated cost of removal accounting and asset retirement accounting under GAAP. These costs will be recovered in future rates as assets are retired.
Deferred Income Taxes:•BRC: Represents deferred costs, primarily comprised of storm costs incurred in the cleanup of major storms from 2010 through 2018, which are being amortized over five years pursuant to the 2018 Distribution Base Rate Case Settlement. These amounts representcosts were fully recovered as of December 31, 2023.
•CEF-EC (AMI Initiative): In January 2021, the BPU approved PSE&G’s CEF-EC filing to provide its electric customers with smart meters. All of the capital and operating costs of the program are included for recovery in PSE&G’s recently filed distribution base rate case. From the start of the program until the commencement of new base rates, the return on and of the capital portion of deferred income taxes that will be recovered or refunded through futurethe program is included for recovery in those rates, based uponas well as operating and stranded costs associated with the accelerated retirement of the existing non-AMI electric meters which PSE&G expects to conclude by the end of 2024.
•CIP: The CIP reduces the impact on electric and gas distribution revenues from changes in sales volumes and demand for most customers. The CIP provides for a true-up of current period revenue as compared to revenue established regulatory practices. In December 2017, new tax legislation was enacted (Tax Act) reducingin PSE&G’s most recent distribution base rate proceeding. Recovery under the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018. PSE&GCIP is subject to Financial Accounting Standards Board (FASB) Accounting Standards Codification 740, Income Taxes (ASC 740), which requires that the effectcertain limitations, including an actual versus allowed return on deferred tax assetsequity test and liabilities of a change in tax rates be recognized in the period the taxceilings on customer rate was enacted. The impact of reduction in tax rate is the primary reason for the decrease in the Regulatory Asset.
increases.Electric and Gas •Cost of Removal: PSE&G accrues and collects in rates for the cost of removing, dismantling and disposing of its electric distribution, electric transmission and gas distribution assets upon retirement. The regulatory assetRegulatory Asset or liabilityLiability for non-legally required cost of removal represents the difference between amounts collected in rates and costs actually incurred.
•COVID-19 Deferral: These amounts represent incremental costs related to COVID-19 as authorized for deferral in an order issued by the BPU to all New Jersey regulated utilities in July 2020. The BPU authorized such utilities to create a COVID-19-related Regulatory Asset by deferring on their books and records the prudently incurred incremental costs related to COVID-19 during the Regulatory Asset period as defined by the BPU. Deferred costs are to be offset by any federal or state assistance that the utility may receive as a direct result of the COVID-19 pandemic. Utilities must file quarterly reports of the costs incurred and offsets. As directed by the BPU, in July 2023, PSE&G filed a petition documenting its prudently incurred incremental COVID-19 costs. Rate recovery, including any prudency determinations and the appropriate period of recovery, will be addressed through that filing which is currently pending.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
•Deferred Income Tax Regulatory Assets: These amounts relate to deferred income taxes arising from utility operations that have not been included in customer rates relating to depreciation, ITCs and other flow-through items, including the flowback to customers of accumulated deferred income taxes related to tax repair deductions. As part of its distribution base rate case settlement with the BPU and the establishment of the TAC mechanism in 2018, PSE&G agreed to a ten-year flowback to customers of its accumulated deferred income taxes from previously realized tax repair deductions which resulted in the recognition of a $581 million Regulatory Asset and Regulatory Liability as of September 30, 2018. In addition, PSE&G agreed to the current flowback of tax benefits from ongoing tax repair deductions as realized which results in the recording of a Regulatory Asset upon flowback. For the years ended December 31, 2023, 2022 and 2021, PSE&G had provided $80 million, $35 million and $22 million, respectively, in current tax repair flowbacks to customers. The recovery and amortization of the tax repair-related Deferred Income Tax Regulatory Assets is being recovered through the TAC regulatory mechanism.
•Deferred Income Tax Regulatory Liabilities: These liabilities primarily relate to amounts due to customers for excess deferred income taxes as a result of the reduction in the federal corporate income tax rate provided in the Tax Cuts and Jobs Act of 2017 (Tax Act), and accumulated deferred income taxes from previously realized distribution-related tax repair deductions. As part of its settlement with its regulators, PSE&G agreed to refund the excess deferred income taxes as follows:
•Unprotected distribution-related excess deferred income taxes are being refunded to customers over five years through PSE&G’s TAC mechanism as approved in its 2018 distribution base rate proceeding. As of December 31, 2023, the balance remaining to be flowed back to customers was approximately $20 million with the remaining flowback period through 2024.
•Protected distribution-related excess deferred income taxes are being refunded to customers over the remaining useful lives of distribution property, plant and equipment through PSE&G’s TAC mechanism. As of December 31, 2023, the balance remaining to be flowed back to customers was approximately $862 million.
•Previously realized distribution-related tax repair deductions are being refunded to customers over ten years through PSE&G’s TAC mechanism. As of December 31, 2023, the balance remaining to be flowed back to customers was approximately $387 million through 2028.
•Protected transmission-related excess deferred income taxes are being refunded to customers over the remaining useful life of transmission property, plant and equipment through PSE&G’s transmission formula rate mechanism. As of December 31, 2023, the balance remaining to be flowed back to customers was approximately $931 million.
•Deferred Storm Costs: Incremental costs incurred in the restoration and related costs from major storms from 2019 through 2022 for which PSE&G is seeking recovery in its current distribution base rate proceeding.
•Electric Energy Costs—Basic Generation Service: BGS: These costs represent the over or under recovered amounts associated with Basic Generation Services (BGS),BGS, as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for electric customers within its service territory that are not served by another supplier. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for PSE&G’s operations. Over or under recovered balances with interest are returned or recovered through monthly filings.
Excess Deferred Income Tax Regulatory Liability: The $2.9 billion Regulatory Liability represents the future revenue reduction of •Formula Rate True-Up: PSE&G’s existing $2.1 billion Accumulated Deferred Income Tax liabilities thattransmission revenues are in excessearned under a FERC-approved annual formula rate mechanism which provides for an annual filing of what is needed to offset future tax liabilities as a result of the Tax Act that reduces the federal corporate income tax rate from a maximum of 35% to 21%an estimated revenue requirement with rates effective January 1 2018. The excess deferred income taxes are primarily relatedof each year and a true-up to the difference between book and tax plant depreciation and under the new tax legislation cannot be returned to customers any faster than over the remaining regulatory lives of the related property. For the remaining excess deferred taxes, the mechanism and timing of these refunds will be determined by the BPU and FERC.
that estimate based on actual revenue requirements.FERC Formula Rate True-up: Over or under collection of transmission earnings calculated using a FERC approved formula. Over or under collected balances with interest are returned or recovered through the subsequent annual filing.
•Gas Costs—Basic Gas Supply Service:BGSS: These costs represent the over or under recovered amounts associated with Basic Gas Supply Service (BGSS),BGSS, as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for gas customers within its service territory that are not served by another supplier. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for PSE&G’s operations. Over or under collected balances are returned or recovered through an annual filing. Interest is accrued only on over recovered balances.
Gas Margin Adjustment Clause: This mechanism credits Firm delivery customers for net distribution margin revenue collected from Transportation Gas Service Non-Firm (TSG-NF) delivery customers. The balance represents the difference between the net margin collected from the TSG-NF Customers versus bill credits provided to Firm delivery customers. Over or under recovered balances with interest are returned or recovered through the subsequent•GPRC: PSE&G files an annual filing.
GPRC: This amount represents costs of the over or under collected balances associated with various renewable energy and energy efficiency programs. The Company files annuallyGPRC petition with the BPU for recovery of amounts associated with the BPU Board-approved energy efficiency (EE) and solar (renewable) energy (RE) programs that include a return on and of its investments and capital assets, as well as recovery for deferred expenses and incremental costs. The GPRC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
investment program component is recovered over the lives of the underlying investments and capital assets which range from 5five to 10twenty years. Interest is accrued monthly
The approved GPRC components receiving recovery for the return on any over or under recovered balances. Componentsand of the GPRCinvestments include: Carbon Abatement, Energy Efficiency Economic Stimulus Program (EEE), EEE Extension Program, EEE Extension II Program, the Demand Response Program, Solar Generation Investment Program (Solar 4 All)All®), Solar 4 All® Extension, Solar 4 All® Extension II, Solar Loan II Program, Solar Loan III Program, EE 2017 Program and Clean Energy Future–Energy Efficiency (CEF-EE).
In addition, the GPRC components receiving cost recovery for deferred expenses include: the Transition Renewable Energy Certificate Program, Community Solar Energy Program and the Energy Efficiency 2017Successor Solar Incentive Program.
The Regulatory Asset balances represent the deferred investment and related undercollected balances with a Regulatory Liability recorded for any overrecovered balance.Interest is accrued monthly on any over-or under- recovered balances. Amortization of deferred investment and expenses are recorded in O&M expense. The capital asset portion of GPRC investments primarily in company-owned solar facilities is included in Property, Plant and Equipment, with depreciation recorded in Depreciation and Amortization Expense.
•MGP Remediation Costs: Represents the low end of the range for the remaining environmental investigation and remediation program cleanup costs for manufactured gas plantsMGPs that are probable of recovery in future rates. Once these costs are incurred, they are recovered through the RAC in the SBC over a seven year period with interest.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MTM Contracts: The estimated fair value of gas hedge contracts and gas cogeneration supply contract. The regulatory asset/liability is offset by a derivative asset/liability and, with respect to the gas hedge contracts only, an intercompany receivable/payable on the Consolidated Balance Sheets.
•New Jersey Clean Energy Program: The BPU approved future funding requirements for Energy EfficiencyEE and Renewable Energy Programs through the first half of 2018.RE Programs. The BPU funding requirements are recovered through the SBC.
•Pension and OPEB Costs: Pursuant to the adoption of accounting guidance for employers’ defined benefit pension and OPEB plans, PSE&G recordedrecords the unrecognized costs for defined benefit pension and other OPEB plans on the balance sheet as a Regulatory Asset.Assets pursuant to the adoption of accounting guidance for employers’ defined benefit pension and OPEB plans, and relevant BPU orders. These costs represent net actuarial gains or losses and prior service costs and transition obligations as a result of adoption, which have not been expensed. These costs are amortized and recovered in future rates.
•RAC (Other SBC): Costs incurred to clean up manufactured gas plantsMGPs which are recovered over seven years with interest through an annual filing.
•SBC: The SBC, as authorized by the BPU and the New Jersey Electric Discount and Energy Competition Act, includes costs related to PSE&G’s electric and gas business as follows: (1) the Universal Service Fund (USF);Fund; (2) Energy Efficiency and Renewable EnergyEE & RE Programs; (3) Electric bad debt expense; and (4) the RAC for incurred MGP remediation expenditures. Over or under recovered balances with interest are to be returned or recovered through an annual filing.
Storm Damage Deferrals: Costs incurred in the cleanup of major storms in 2010 through 2017. As of December 31, 2017, this includes the $220 million of storm costs, net of insurance recoveries, primarily as a result of Hurricane Irene and Superstorm Sandy, approved for recovery in a future base rate case proceeding under a BPU order received in September 2014.
Unamortized Loss on Reacquired Debt and Debt Expense: Represents losses on reacquired long-term debt and expenses associated with issuances of new debt, which are recovered through rates over the remaining life of the debt.
WNC:•TAC: This represents the over or under recoverycollected electric and gas balances associated with the return of excess accumulated deferred income taxes and the flowback of previously realized and current tax repair deductions under a mechanism approved by the BPU in PSE&G’s 2018 Distribution Base Rate Case Settlement. Over or under collected electric and gas margin under the BPU’s weather normalization clause which is filed annually. The WNC requires PSE&G to calculate, at the end of each October-to-May period, the level by which margin revenues differed from what would have resulted if normal weather had occurred. Over recoveriesbalances are returned to customers inor recovered through an annual filing. PSE&G includes a return component on the next winter season whileflowback of the excess accumulated deferred income taxes and the previously realized tax repairs. Interest is accrued monthly on any over or under recoveries (subject to an earnings cap) are recovered from customers in the next winter season.
balances.Significant 20172023 regulatory orders received and currently pending rate filings with FERC and the BPU or FERC by PSE&G are as follows:
•Electric and Gas Distribution Base Rate Filing—Filing—In January 2018,December 2023, PSE&G filed a distribution base rate case as required as a condition of approval of previous PSE&G programs. This distribution base rate case requests an overall revenue increase of approximately $826 million which includes the recovery of approximately $3 billion in capital investments made by PSE&G to strengthen and modernize its Energy Strong Programelectric and gas infrastructure since its last distribution base rate case in 2018. PSE&G anticipates this base rate case will be finalized later in 2024.
•BGSS—In January and February 2023, PSE&G filed with the BPU two self-implementing BGSS rate reductions of 15 cents and 3 cents per therm, effective February 1, 2023 and March 1, 2023, respectively. These reductions resulted in a new BGSS rate of approximately 47 cents per therm effective March 1, 2023. In April 2023, the BPU gave final approval to PSE&G’s BGSS rate of 47 cents per therm.
In September 2023, the BPU approved on a provisional basis PSE&G’s June 2023 request to decrease its BGSS rate to approximately 40 cents per therm, effective October 1, 2023.
The BGSS rate has decreased a total of 25 cents from approximately 65 cents per therm as of January 1, 2023 to 40 cents per therm as of October 1, 2023.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
•CIP—In February 2023, the BPU gave final approval for PSE&G to recover approximately $52 million of deficient electric revenues that resulted from the 12-month period ended May 31, 2022, with approximately $18 million approved for recovery for the first year starting on the effective date of June 15, 2022 and the remaining $34 million to be recovered starting in June 2023.
In April 2023, the BPU gave final approval for PSE&G to recover approximately $53 million of deficient gas revenues that resulted from the 12-month period ended September 30, 2022, over one year effective October 1, 2022.
In September 2023, the BPU provisionally approved PSE&G’s gas CIP petition to recover $110 million of deficient gas revenues comprised of approximately $99 million for the most recent gas CIP annual period ended September 30, 2023, and an additional $11 million carryover underrecovery from the prior CIP period. The revenue deficiency is the result of lower revenues as compared to a baseline established in PSE&G’s most recent distribution base rate proceeding. New rates were effective October 1, 2023 and PSE&G expects to recover the full $110 million deficiency over a 12-month period.
In December 2023, the BPU gave final approval for PSE&G’s updated electric CIP petition to recover approximately $75 million of deficient electric revenues over two years that resulted from the 12-month period ended May 31, 2023, with new rates effective June 1, 2023.
In February 2024, PSE&G filed its annual electric CIP petition seeking BPU approval to recover estimated deficient electric revenues of approximately $99 million based on the 12-month period ending May 31, 2024 with new rates proposed to be effective June 1, 2024. This matter is pending.
•COVID-19 Deferral—In May and June 2023, the BPU issued two Orders to all public utilities in New Jersey that stipulated a filing deadline for recovery of COVID-19 Regulatory Asset balances, and set forth certain filing requirements primarily related to recovery proposals to be included by each utility in their COVID-19 filings.
In July 2023, PSE&G filed a petition with the BPU in 2014. Thecompliance with those Orders requesting recovery of its prudently incurred incremental costs associated with the COVID-19 pandemic. This matter is pending.
As of December 31, 2023, PSE&G has deferred approximately $131 million as a Regulatory Asset for its net incremental costs, including $68 million for incremental gas bad debt expense associated with customer accounts receivable. PSE&G expects its COVID-19 Regulatory Asset balance is probable of recovery under the BPU orders.
•Energy Strong II—In April 2023, the BPU approved PSE&G’s updated filing requests an approximate one percent increase in revenues and seeks to recover investments made to strengthenfor annual electric and gas distribution systems. revenue increases of $16 million and $4 million, respectively, effective May 1, 2023. These increases represent the return on and of Energy Strong II investments placed in service through January 2023.
In itsOctober 2023, the BPU approved PSE&G’s updated filing for an annual increase in electric revenues of approximately $9 million associated with capitalized electric investment costs of the Energy Strong II program, with new rates effective November 1, 2023. This increase represents the return on and of actual investments through July 31, 2023.
In February 2024, PSE&G requested that these rates take into account a reductionfiled an updatedpetition seeking BPU approval to recover an annualized increase in theelectric revenue requirement of $13 million associated with capitalized investment costs of the Energy Strong II Program, with rates to be effective May 1, 2024. The requested electric revenue increase represents the return of and on actual Energy Strong II investments placed in service through December 31, 2023. This matter is pending.
•Gas System Modernization Program II (GSMP II)—In May 2023, the BPU approved PSE&G’s updated GSMP II cost recovery filing to recover an annual gas revenue increase of approximately $11 million effective June 1, 2023. This increase represents the return on and of GSMP II investments placed in service through February 2023.
•GPRC—In May 2023, the BPU approved PSE&G’s 2022 updated GPRC filing for annual electric and gas revenue increases of $87 million and $5 million, respectively, with new rates effective June 1, 2023.
Additionally in May 2023, the BPU approved PSE&G’s petition to increase its CEF-EE sub program investment (a component of GPRC) by $280 million and approved a nine-month extension to make investments.
In February 2024, PSE&G updated its 2023 GPRC cost recovery petition requesting BPU approval for recovery of increases of $49 million and $15 million in annual electric and gas revenues, respectively. This matter is pending.
•Infrastructure Advancement Program (IAP)—In February 2024, PSE&G filed an updated IAP cost recovery petition seeking BPU approval to recover in electric base rates an annual revenue increase of $5 million effective May 1, 2024. This increase represents the return of and on investment for IAP electric investments in service through January 31, 2024. This matter is pending.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
•Pension—In February 2023, the BPU approved an accounting order authorizing PSE&G to modify its method for calculating the amortization of the net actuarial gain or loss component of pension expense for ratemaking purposes. This methodology change for ratemaking purposes is effective for the calendar year ending December 31, 2023 and forward. As of December 31, 2023, PSE&G has deferred $55 million as a Regulatory Asset under this methodology.
•RAC—In January 2023, PSE&G filed its RAC 30 petition with the BPU seeking recovery of approximately $44 million of net MGP expenditures incurred from August 1, 2021 through July 31, 2022. This matter is pending.
•SBC—In January 2023, PSE&G filed a petition to increase its annual electric and gas rates by approximately $52 million and $32 million, respectively, in order to recover electric and gas costs incurred or expected to be incurred through February 2024 under its EE and RE and Social Programs. The increase to electric rates includes the impact of increased bad debt expense as a result of the federal corporate income tax rate reduction from 35% to 21% provided innegative economic impact of the Tax Act, including a one-time credit for estimated excess income taxes collected between January 1, 2018coronavirus pandemic and the timeresulting impact of moratoriums on collections. This matter is pending.
•TAC—In July 2023, the BPU approved PSE&G’s updated 2022 TAC filing to increase annual electric revenues by approximately $17 million and decrease annual gas revenues by approximately $42 million, with new rates go into effect, and the flow back to customers of certain additional tax benefits. PSE&G anticipates the new base rates will go into effect in the fourth quarter of 2018.
effective August 1, 2023.Separately, in January 2018,In February 2024, the BPU issued an order commencing a proceedingapproved PSE&G’s 2023 TAC filing to ensure that the rate revenue resulting from expenses relating to taxes reflected in rates but no longer owed as the result of the Tax Act shall be passed onto the ratepayers. The BPU directed New Jersey utilities (including PSE&G) to make filingsincrease annual electric and gas revenues by March 2, 2018 setting forth interim rates to be effective April 1, 2018 reflecting theapproximately $61 million and $40 million, respectively, with new federal corporate tax rate, and to subsequently file proposed final rates effective JulyMarch 1, 2018, incorporating all other effects of the Tax Act. This proceeding is currently pending.2024.
•Transmission Formula Rate Filings—Rates—In June 2017,2023, PSE&G filed with FERC its 20162022 true-up adjustment pertaining to its transmission formula rates in effect for 2016. Thiscalendar year 2022, as established by its 2022 annual forecast filing. The June 2023 true-up filing resulted in an adjustmentapproximate $21 million decrease in the 2022 annual revenue requirement from the revenue requirement numbers contained in the forecast filing. PSE&G had previously recognized the majority of $12the lower revenue requirement in its 2022 Consolidated Statement of Operations.
In October 2023, PSE&G filed its Annual Transmission Formula Rate Update with FERC, which will result in a $58 million more thanincrease in annual transmission revenue effective January 1, 2024, subject to true-up.
•ZEC Program—In January 2023, the 2016 originally filed revenues.
BPU approved PSE&G’s petition to set the ZEC refund component of the tariff rate to zero effective February 1, 2023 as overcollections for the ZEC Energy Year ended May 31, 2022 totaling $1.3 million, including interest, were refunded to customers in 2022 through January 2023.ForIn August 2023, the BPU approved the final ZEC price of $9.88 per megawatt hour (MWh) for the energy year ended May 31, 2023. As a result, PSE&G purchased approximately $165 million in ZECs including interest, from the eligible nuclear plants selected by the BPU with the final payment made in August 2023. As total customer collections equaled the required ZEC payments, there were no overcollected revenues from customers for the Energy Year ended May 31, 2023 and the ZEC refund component of the rate remains at zero.
Note 7. Leases
As of December 31, 2017, 2023, PSEG and its subsidiaries were both a lessee and a lessor in operating leases.
Lessee
PSE&G
PSE&G recordedhas operating leases for office space for customer service centers, rooftops and land for its Solar 4 All® facilities, equipment, vehicles and land for certain electric substations. These leases have remaining lease terms through 2040, some of which include options to extend the leases for up to four 5-year terms or one 10-year term; and two include options to extend the leases for one 45-year and one 48-year term, respectively. Some leases have fixed rent payments that have escalations based on certain indices, such as the CPI. Certain leases contain variable payments.
PSEG Power & Other
PSEG Power has operating leases for buildings and equipment. These leases have remaining terms through 2028, one of which includes an estimated true-up adjustment of $16 millionoption to extend the lease for up to one 5-year term. One lease has fixed rent payments that has escalations based on the CPI. Certain leases contain variable payments.
Services has operating leases for real estate and office equipment. These leases have remaining terms through 2030. Services’ lease for its 2017 Annual Formula rate. That true-up will be filed by no later than June 15, 2018.
headquarters, which ends in 2030, includes options to extend for two 5-year terms.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In October 2017, the 2018 Annual Formula Rate Update was filed with FERC and requested approximately $212 million in increased annual transmission revenues effective January 1, 2018, subject to true-up. In January 2018, PSE&G filed with FERC a revised 2018 Annual Transmission Formula Rate Update reducing the 2018 transmission annual revenue requirement to reflect the federal corporate income tax rate reduction from 35% to 21%, effective January 1, 2018, provided in the Tax Act. This change in the federal corporate tax rate reduces the annual revenue requirement by $148 million. The revised increase in annual transmission revenues effective January 1, 2018 is $64 million.
Energy Strong Recovery Filing—In March and September of each year, PSE&G files with the BPU for base rate recovery of Energy Strong investments which include a return of and on its investment.
In June 2017, PSE&G submitted the planned update to its March Energy Strong cost recovery petition, originally filed in March 2017, to include Energy Strong investments in service as of May 31, 2017. This filing requested estimated annual increases in electric and gas revenues of $16 million and $2 million, respectively. In August 2017, the BPU approved these rate increases effective September 1, 2017.
In September 2017, PSE&G filed its Energy Strong electric cost recovery petition seeking BPU approval to recover the revenue requirements associated with Energy Strong capitalized investment costs placed in service from June 1, 2017 through November 30, 2017. The filing was updated in December 2017 requesting an annual increase in electric revenues of $8 million. This matter is pending.
Gas System Modernization Program (GSMP)—In July of each year, PSE&G files with the BPU for base rate recovery of GSMP investments which include a return of and on its investment.
In December 2017, the BPU approved PSE&G’s annual GSMP cost recovery petition, originally filed in July 2017, and updated in October 2017, to include GSMP investments in service as of September 30, 2017. The BPU approved an annual increase in gas revenues of $25 million, effective January 1, 2018.
BGSS—In June 2017, PSE&G made its annual BGSS filing with the BPU requesting an increase in the BGSS rate from approximately 34 cents to 37 cents per therm effective October 1, 2017. In September 2017, the BPU approved a Stipulation in this matter on a provisional basis and the BGSS rate was increased. In December 2017 and February 2018, PSE&G filed with the BPU for self-implementing monthly bill credits of 15 cents per therm for the months of January, February and March 2018. These monthly bill credits are estimated to provide approximately $100 million in customer credits. In November 2017, a filing was made by the Retail Energy Supply Association (RESA) with the BPU requesting that the BPU revisit the BGSS process and establish a gas capacity release program. This filing, which remains pending, is applicable to all New Jersey gas utilities.
Green Program Recovery Charges (GPRC)—Each year PSE&G files with the BPU for annual recovery for the 11 combined components of its electric and gas Green Program investments which include a return on its investment and recovery of expenses.
In March 2017, the BPU gave final approval to PSE&G’s 2016 GPRC cost recovery petition to recover approximately$37 million and $13 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G’s implementation of these BPU approved GPRC programs for the period October 1, 2016 through September 30, 2017. The rates were effective May 1, 2017. This Order also included the return of approximately $5 million in remaining overcollections from the completed Securitization Transition Charge.
In June 2017, PSE&G filed its 2017 GPRC cost recovery petition requesting recovery of approximately $47 million and $13 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G’s implementation of these BPU approved programs for the period October 1, 2017 through September 30, 2018. This proceeding is ongoing.
In August 2017, the BPU approved PSE&G’s petition for an Energy Efficiency 2017 Program (EE 2017) to extend three existing energy efficiency subprograms (multi-family, direct install and hospital efficiency) and establish two new residential energy efficiency offerings. The two new offerings include deployment of smart thermostats and a pilot program to provide residential customers with energy usage information enabling them to reduce consumption. The Order allows PSE&G to extend the subprogram offerings and establish the residential energy efficiency subprograms under its existing energy efficiency clause recovery process. The EE 2017 allows for $69 million of additional investment and $16 million of additional administrative and information technology costs. The EE 2017 was added as the 11th component of the GPRC rate effective September 1, 2017.
Weather Normalization Clause—In April 2017, the BPU gave final approval to PSE&G petition to collect $54 million in net deficiency gas revenues as a result of the warmer than normal 2015-2016 Winter Period.
Operating Lease Costs
The following amounts relate to total operating lease costs, including both amounts recognized in the Consolidated Statements of Operations during the years ended December 31, 2023, 2022 and 2021 and any amounts capitalized as part of the cost of another asset, and the cash flows arising from lease transactions.
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| | PSE&G | | PSEG Power & Other | | Total | |
| | Millions | |
| Operating Lease Costs | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Year Ended December 31, 2023 | | | | | | |
| Long-term Lease Costs | $ | 34 | | | $ | 19 | | | $ | 53 | | |
| Short-term Lease Costs | 21 | | | 6 | | | 27 | | |
| Variable Lease Costs | 2 | | | 13 | | | 15 | | |
| Total Operating Lease Costs | $ | 57 | | | $ | 38 | | | $ | 95 | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Year Ended December 31, 2023 | | | | | | |
| Cash Paid for Amounts Included in the Measurement of Operating Lease Liabilities | $ | 17 | | | $ | 17 | | | $ | 34 | | |
| | | | | | | |
| Weighted Average Remaining Lease Term in Years | 10 | | 7 | | 8 | |
| Weighted Average Discount Rate | 4.0 | % | | 4.2 | % | | 4.1 | % | |
| | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| | PSE&G | | PSEG Power & Other | | Total | |
| | Millions | |
| Operating Lease Costs | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Year Ended December 31, 2022 | | | | | | |
| Long-term Lease Costs | $ | 31 | | | $ | 25 | | | $ | 56 | | |
| Short-term Lease Costs | 21 | | | 5 | | | 26 | | |
| Variable Lease Costs | 2 | | | 11 | | | 13 | | |
| Total Operating Lease Costs | $ | 54 | | | $ | 41 | | | $ | 95 | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Year Ended December 31, 2022 | | | | | | |
| Cash Paid for Amounts Included in the Measurement of Operating Lease Liabilities | $ | 17 | | | $ | 25 | | | $ | 42 | | |
| | | | | | | |
| Weighted Average Remaining Lease Term in Years | 11 | | 7 | | 9 | |
| Weighted Average Discount Rate | 3.5 | % | | 4.1 | % | | 3.9 | % | |
| | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| | PSE&G | | PSEG Power & Other | | Total | |
| | Millions | |
| Operating Lease Costs | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Year Ended December 31, 2021 | | | | | | |
| Long-term Lease Costs | $ | 24 | | | $ | 26 | | | $ | 50 | | |
| Short-term Lease Costs | 36 | | | 6 | | | 42 | | |
| Variable Lease Costs | 2 | | | 18 | | | 20 | | |
| Total Operating Lease Costs | $ | 62 | | | $ | 50 | | | $ | 112 | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Year Ended December 31, 2021 | | | | | | |
| Cash Paid for Amounts Included in the Measurement of Operating Lease Liabilities | $ | 17 | | | $ | 26 | | | $ | 43 | | |
| | | | | | | |
| Weighted Average Remaining Lease Term in Years | 12 | | 8 | | 9 | |
| Weighted Average Discount Rate | 3.4 | % | | 4.1 | % | | 3.8 | % | |
| | | | | | | |
Operating lease liabilities as of December 31, 2023 had the following maturities on an undiscounted basis:
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| | | | | | | | |
| | | PSE&G | | PSEG Power & Other | | Total | |
| | | Millions | |
| 2024 | | $ | 18 | | | $ | 17 | | | $ | 35 | | |
| 2025 | | 15 | | | 17 | | | 32 | | |
| 2026 | | 13 | | | 16 | | | 29 | | |
| 2027 | | 12 | | | 17 | | | 29 | | |
| 2028 | | 10 | | | 16 | | | 26 | | |
| Thereafter | | 57 | | | 28 | | | 85 | | |
| Total Minimum Lease Payments | | $ | 125 | | | $ | 111 | | | $ | 236 | | |
| | | | | | | | |
The following is a reconciliation of the undiscounted cash flows to the discounted Operating Lease Liabilities recognized on the Consolidated Balance Sheets:
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| | | | | | | | |
| | | As of December 31, 2023 | |
| | | PSE&G | | PSEG Power & Other | | Total | |
| | | Millions | |
| Undiscounted Cash Flows | | $ | 125 | | | $ | 111 | | | $ | 236 | | |
| Reconciling Amount due to Discount Rate | | (21) | | | (15) | | | (36) | | |
| Total Discounted Operating Lease Liabilities | | $ | 104 | | | $ | 96 | | | $ | 200 | | |
| | | | | | | | |
| | | As of December 31, 2022 | |
| | | PSE&G | | PSEG Power & Other | | Total | |
| | | Millions | |
| Undiscounted Cash Flows | | $ | 109 | | | $ | 126 | | | $ | 235 | | |
| Reconciling Amount due to Discount Rate | | (20) | | | (18) | | | (38) | | |
| Total Discounted Operating Lease Liabilities | | $ | 89 | | | $ | 108 | | | $ | 197 | | |
| | | | | | | | |
As of December 31, 2023, the current portions of Operating Lease Liabilities included in Other Current Liabilities were $27 million and $15 million for PSEG and PSE&G, respectively. As of December 31, 2022, the current portions of Operating Lease Liabilities included in Other Current Liabilities were $28 million and $12 million for PSEG and PSE&G, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Lessor
PSEG Power & Other
Energy Holdings is the lessor in leveraged leases. See Note 8. Long-Term Investments and Note 9. Financing Receivables.
Energy Holdings is the lessor in an operating lease for a domestic energy generation facility with a remaining term through 2036. As of December 31, 2023, Energy Holdings’ property subject to this lease had a total carrying value of $10 million.
In September 2017,2022, Energy Holdings recorded pre-tax impairments of $78 million related to one of its domestic energy generating facilities and its real estate assets. In March 2023, Energy Holdings completed the BPU approved on a provisional basis, PSE&G’s petitionsale of one of its domestic energy generating facilities and recorded an immaterial pre-tax gain. In December 2023, Energy Holdings completed the sale of its real estate assets and recorded an immaterial pre-tax gain.
A wholly owned subsidiary of PSEG Power is the lessor in an operating lease for certain parcels of land with terms through 2050, plus five optional renewal periods of ten years.
Prior to collect $31 millionthe sale of Solar Source in net deficiency gas revenues as a resultJune 2021, certain of the warmer than normal 2016-2017 Winter Period and a remaining carryover balance of $24 million in net deficiency gas revenues from the 2015-2016 Winter Period for a total recovery of $55 million in net deficiency revenues. The deficiency will be collected from customers over the 2017-2018 and 2018-2019 Winter Periods (October 1 through May 31). Final approval in this matter is pending.
Remediation Adjustment Charge (RAC)—In June 2017, the BPU approved PSE&G’s filing with respectPSEG Power’s sales agreements related to its RAC 24 petition allowing recoverysolar generating plants qualified as operating leases. Lease income was based on solar energy generation; therefore, all rental income recorded under these leases was variable.
The following is the operating lease income for the years ended December 31, 2023, 2022 and 2021:
| | | | | | | | | | | |
| | | |
| Operating Lease Income | Millions | |
| | | |
| | | |
| | | |
| | | |
| Year Ended December 31, 2023 | | |
| Fixed Lease Income | $ | 24 | | |
| Variable Lease Income | — | | |
| Total Operating Lease Income | $ | 24 | | |
| | | |
| Year Ended December 31, 2022 | | |
| Fixed Lease Income | $ | 31 | | |
| Variable Lease Income | — | | |
| Total Operating Lease Income | $ | 31 | | |
| | | |
| Year Ended December 31, 2021 | | |
| Fixed Lease Income | $ | 23 | | |
| Variable Lease Income | 12 | | |
| Total Operating Lease Income | $ | 35 | | |
| | | |
Operating leases had the following minimum future fixed lease receipts as of $41 million effective July 10, 2017 related to net Manufactured Gas Plant expenditures from August 1, 2015 through JulyDecember 31, 2016. In February 2018, PSE&G filed a RAC 25 Petition with the BPU requesting recovery2023:
| | | | | | | | | | | | | | |
| | | | |
| | | Millions | |
| 2024 | | $ | 14 | | |
| 2025 | | 14 | | |
| 2026 | | 14 | | |
| 2027 | | 14 | | |
| 2028 | | 13 | | |
| Thereafter | | 110 | | |
| Total Minimum Future Lease Receipts | | $ | 179 | | |
| | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Universal Service Fund (USF)/Lifeline—In September 2017, the BPU approved rates set to recover state-wide costs incurred by New Jersey electric and gas distribution companies under the State’s USF/Lifeline energy assistance programs effective October 1, 2017. PSE&G earns no margin on the collection of the USF and Lifeline programs resulting in no impact on its Consolidated Statement of Operations.
Note 7.8. Long-Term Investments
Long-Term Investments as of December 31, 20172023 and 20162022 included the following:
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | As of December 31, | |
| | | 2023 | | 2022 | |
| | | Millions | |
| PSE&G | | | | | |
| Life Insurance and Supplemental Benefits | | $ | 77 | | | $ | 81 | | |
| Solar Loans | | 40 | | | 62 | | |
| PSEG Power & Other | | | |
| Lease Investments | | 161 | | | 175 | | |
| Equity Method Investments (A) | | 17 | | | 306 | | |
| Total Long-Term Investments | | $ | 295 | | | $ | 624 | | |
| | | | | | |
|
| | | | | | | | | | |
| | | | | | |
| | | As of December 31, | |
| | | 2017 | | 2016 | |
| | | Millions | |
| PSE&G | | | | | |
| Life Insurance and Supplemental Benefits | | $ | 130 |
| | $ | 140 |
| |
| Solar Loans | | 150 |
| | 159 |
| |
| Power | | | |
| Partnerships and Corporate Joint Ventures (Equity Method Investments) (A) | | 87 |
| | 102 |
| |
| Energy Holdings | | | | | |
| Lease Investments | | 565 |
| | 649 |
| |
| Total Long-Term Investments | | $ | 932 |
| | $ | 1,050 |
| |
| | | | | | |
(A)During the year ended December 31, 2023, there were no dividends from these investments. During the years ended December 31, 2022 and 2021, dividends from these investments were $8 million and $17 million, respectively. See Note 3. Asset Dispositions and Impairments for information regarding the sales of our ownership interest in the Ocean Wind 1 project and Kalaeloa. | |
(A) | During the three years ended December 31, 2017, 2016 and 2015, dividends from these investments were $18 million, $18 million and $16 million, respectively.
|
Leases
Energy Holdings, through several of its indirect subsidiary companies,subsidiaries, has investments in domestic energy and real estate assets subject primarily to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third-party debt investor. The debt is recourse only to the assets subject to lease and is not included on PSEG’s Consolidated Balance Sheets. As an equity investor, Energy Holdings’ equity investments in the leases are comprised of the total expected lease receivables over the lease terms, plus the estimated residual values at the end of the lease terms, reduced for any income not yet earned on the leases. This amount is included in Long-Term Investments on PSEG’s Consolidated Balance Sheets. The more rapid depreciation of the leased property for tax purposes creates tax cash flow that will be repaid to the taxing authority in later periods. As such, the liability for such taxes due is recorded in Deferred Income Taxes on PSEG’s Consolidated Balance Sheets.
During the third quarter of 2016, Energy Holdings completed its annual review of estimated residual values embedded in the NRG REMA, LLC (REMA) leveraged leases. The outcome indicated that the revised residual value estimates were lower than the recorded residual values and the decline was deemed to be other than temporary due to the adverse economic conditions experienced by coal generation in PJM, as discussed in Note 3. Early Plant Retirements, negatively impacting the economic outlook of the leased assets. As a result, a pre-tax write-down of $137 million was reflected in Operating Revenues in the quarter ended September 30, 2016, calculated by comparing the gross investment in theLeveraged leases before and after the revised residual estimates. During the fourth quarter of 2016, Energy Holdings recorded a $10 million charge for its best estimate of loss as a result of the current liquidity issues facing REMA, which was reflected in Operating Revenues and is included in Gross Investments in Leasesoutstanding as of December 31, 2016. For additional information, see Note 8. Financing Receivables.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
During the first quarter of 2017, due2023 commenced in or prior to continuing liquidity issues facing REMA, economic challenges facing coal generation in PJM, and based upon an ongoing review of available alternatives as well as certain recent discussions with REMA management, Energy Holdings recorded an additional $55 million pre-tax charge for its current best estimate of loss related to the lease receivables.
In June 2017, GenOn Energy, Inc. (GenOn) and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. REMA was not included in the GenOn filing. Energy Holdings continues to monitor the restructuring of GenOn and its possible impacts on REMA and continues to discuss the situation with various parties relevant to this matter. During the second quarter of 2017, Energy Holdings completed its review of estimated residual values embedded in its leveraged lease portfolio of generating assets and the outcome indicated that one of the residual value estimates was lower than the recorded residual value due to a further deterioration of market conditions and changes to operating cost estimates. This decline was determined to be other than temporary. As a result, a pre-tax write-down of $7 million was recorded in the quarter ended June 30, 2017. In addition, based on an ongoing review of (i) the liquidity challenges facing REMA and (ii) available alternatives, Energy Holdings recorded an additional $15 million pre-tax charge in the quarter ended June 30, 2017 for its current best estimate of loss related to lease receivables. Pre-tax write-downs and additional charges are reflected in Operating Revenues and are included in Gross Investment in Leases as of December 31, 2017.
In January 2018, certain subsidiaries of Energy Holdings, REMA, certain holders of the pass-through certificates and other parties entered into a Forbearance Agreement (Forbearance) relating to the Conemaugh facility. Pursuant to the Forbearance, the parties thereto agreed to temporarily forbear from exercising rights and remedies related to certain events of default related to REMA’s obligation to procure additional qualifying credit support. The Forbearance will remain effective until the earlier of (i) the later of (a) April 15, 2018 and (b) two weeks following the date on which Energy Holdings subsidiaries, REMA and/or the consenting certificate holders provide written notice to REMA of its intention to terminate the Forbearance, and (ii) the date on which any event of termination as specified in the Forbearance occurs.
PSEG cannot predict the outcome of GenOn’s restructuring process or the possible related impact on REMA. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments. If lease rejections or foreclosures were to occur, Energy Holdings could potentially record additional pre-tax write-offs up to its gross investment in these facilities and may also be required to accelerate and pay material deferred tax liabilities to the Internal Revenue Service (IRS).
The2000.The following table shows Energy Holdings’ gross and net lease investment as of December 31, 20172023 and 2016.2022.
|
| | | | | | | | | | |
| | | | | | |
| | | As of December 31, | |
| | | 2017 | | 2016 | |
| | | Millions | |
| Lease Receivables (net of Non-Recourse Debt) | | $ | 546 |
| | $ | 629 |
| |
| Estimated Residual Value of Leased Assets | | 326 |
| | 346 |
| |
| Total Investment in Rental Receivables | | 872 |
| | 975 |
| |
| Unearned and Deferred Income | | (307 | ) | | (326 | ) | |
| Gross Investments in Leases | | 565 |
| | 649 |
| |
| Deferred Tax Liabilities | | (480 | ) | | (674 | ) | |
| Net Investments in Leases | | $ | 85 |
| | $ | (25 | ) | |
| | | | | | |
In December 2017, new tax legislation was enacted, reducing the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018. PSEG is subject to ASC 740, which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate was enacted. The impact of the reduced tax rate is the primary reason for the decrease in Deferred Tax Liabilities. For additional information, see Note 20. Income Taxes.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | As of December 31, | |
| | | 2023 | | 2022 | |
| | | Millions | |
| Lease Receivables (net of Non-Recourse Debt) | | $ | 223 | | | $ | 249 | | |
| Estimated Residual Value of Leased Assets | | — | | | — | | |
| Total Investment in Rental Receivables | | 223 | | | 249 | | |
| Unearned and Deferred Income | | (62) | | | (74) | | |
| Gross Investments in Leases | | 161 | | | 175 | | |
| Deferred Tax Liabilities | | (36) | | | (39) | | |
| Net Investments in Leases | | $ | 125 | | | $ | 136 | | |
| | | | | | |
The pre-tax income (loss) and income tax effects related to investments in leases excluding gains and losses on sales andwere immaterial for the impacts of the Tax Act, were as follows:
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| | | 2017 | | 2016 | | 2015 | |
| | | Millions | |
| Pre-Tax Income (Loss) from Leases | | $ | (69 | ) | | $ | (135 | ) | | $ | 12 |
| |
| Income Tax Expense (Benefit) on Income from Leases | | $ | (26 | ) | | $ | (51 | ) | | $ | 5 |
| |
| | | | | | | | |
Equity Method Investments
Power had the following equity method investments as ofyears ended December 31, 20172023, 2022 and 2016:2021.
|
| | | | | | | | | | | | | |
| | | | | | | |
| | As of December 31, | | | | | |
| Name | 2017 | | 2016 | | Location | | % Owned | |
| | Millions | | | | | |
| Power | | | | | | | | |
| Keystone Fuels, LLC | $ | 8 |
| | $ | 7 |
| | PA | | 23% | |
| Conemaugh Fuels, LLC | 8 |
| | 8 |
| | PA | | 23% | |
| PennEast Pipeline | — |
| | 11 |
| | PA | | 10% | |
| Kalaeloa | 71 |
| | 76 |
| | HI | | 50% | |
| Total | $ | 87 |
| | $ | 102 |
| | | | | |
| | | | | | | | | |
Note 8.9. Financing Receivables
PSE&G
PSE&G sponsors a solar loan program&G’s Solar Loan Programs are designed to help finance the installation of solar power systems throughout its electric service area. Interest income on the loans is recorded on an accrual basis. The loans are generally paid back with solar renewable energy certificates (SRECs)SRECs generated from the related installed solar electric system. InPSE&G uses collection experience as a credit quality indicator for its Solar Loan Programs and conducts a comprehensive credit review for all prospective borrowers. As of December 31, 2023, none of the solar loans were impaired; however, in the event of a loan default,becomes impaired, the basis of the solar loan would be recovered through a regulatory recovery mechanism. NoneTherefore, no current credit losses have been recorded for Solar Loan Programs I, II
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
and III. A substantial portion of these loan amounts are impaired; however,noncurrent and reported in the event a loan becomes impaired, the basis of the loan would be recovered through a regulatory recovery mechanism.
Long-Term Investments on PSEG’s and PSE&G’s Consolidated Balance Sheets. The following table reflects the outstanding loans including the noncurrent portion reported in Note 7. Long-Term Investments, by class of customer, none of which would be considered “non-performing.”
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | As of December 31, | |
| Outstanding Loans by Class of Customer | | 2023 | | 2022 | |
| | | Millions | |
| Commercial/Industrial | | $ | 60 | | | $ | 85 | | |
| Residential | | 3 | | | 4 | | |
| Total | | 63 | | | 89 | | |
| Current Portion (included in Accounts Receivable) | | (23) | | | (27) | | |
| Noncurrent Portion (included in Long-Term Investments) | | $ | 40 | | | $ | 62 | | |
| | | | | | |
|
| | | | | | | | | | |
| | | | | | |
| Outstanding Loans by Class of Customer | |
| | | As of December 31, | |
| Consumer Loans | | 2017 | | 2016 | |
| | | Millions | |
| Commercial/Industrial | | $ | 158 |
| | $ | 164 |
| |
| Residential | | 10 |
| | 11 |
| |
| Total | | $ | 168 |
| | $ | 175 |
| |
| | | | | | |
The solar loans originated under three Solar Loan Programs are comprised as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| Programs | | Balance as of December 31, 2023 | | Funding Provided | | Residential Loan Term | | Non-Residential Loan Term | |
| | | Millions | | | | | | | |
| Solar Loan I | | $ | 4 | | | prior to 2013 | | 10 years | | 15 years | |
| Solar Loan II | | 30 | | | prior to 2015 | | 10 years | | 15 years | |
| Solar Loan III | | 29 | | | largely funded as of December 31, 2023 | | 10 years | | 10 years | |
| Total | | $ | 63 | | | | | | | | |
| | | | | | | | | | |
The average life of loans paid in full is eight years, which is lower than the loan terms of 10 to 15 years due to the generation of SRECs being greater than expected and/or cash payments made to the loan. Payments on all outstanding loans were current as of December 31, 2023 and have an average remaining life of approximately three years. There are no remaining residential loans outstanding under the Solar Loan I program.
Energy Holdings
Energy Holdings had a net investmentinvestments in domestic energy and real estate assets subject to leveraged lease accounting of $85$125 million as of December 31, 20172023 and $(25)$136 million as of December 31, 2016 (See2022 (see Note 7.8. Long-Term Investments).
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The corresponding receivables associated with the lease portfolio are reflected as follows, net of non-recourse debt. The ratings in the table represent the ratings of the entities providing payment assurance to Energy Holdings.
|
| | | | | | |
| | | | |
| | | Lease Receivables, Net of Non-Recourse Debt | |
| Counterparties’ Credit Rating Standard & Poor’s (S&P) as of December 31, 2017 | | As of December 31, 2017 | |
| | | Millions | |
| AA | | $ | 15 |
| |
| BBB+, BBB, BBB- | | 316 |
| |
| BB- | | 133 |
| |
| CCC- | | 82 |
| |
| Total | | $ | 546 |
| |
| | | | |
The “BB-” and the “CCC-” ratings in the preceding table represent lease receivables related to coal and gas-fired assets in Illinois and Pennsylvania, respectively. | | | | | | | | | | | | | | |
| | | | |
| | | Lease Receivables, Net of Non-Recourse Debt | |
| Counterparties’ Credit Rating Standard & Poor’s (S&P) as of December 31, 2023 | | As of December 31, 2023 | |
| | | Millions | |
| AA | | $ | 7 | | |
| A- | | 43 | | |
| BBB+ to BBB | | 173 | | |
| Total | | $ | 223 | | |
| | | | |
PSEG recorded no credit losses for the leveraged leases existing on December 31, 2017, the gross investment in the leases of such assets, net of non-recourse debt, was $335 million, ($(67) million, net of deferred taxes). A more detailed description of such assets under lease is presented in the following table.
|
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Asset | | Location | | Gross Investment | | % Owned | | Total MW | | Fuel Type | | Counterparties’ S&P Credit Ratings | | Counterparty | |
| | | | | Millions | | | | | | | | | | | |
| Powerton Station Units 5 and 6 | | IL | | $ | 132 |
| | 64 | % | | 1,538 |
| | Coal | | BB- | | NRG Energy, Inc. | |
| Joliet Station Units 7 and 8 | | IL | | $ | 85 |
| | 64 | % | | 1,036 |
| | Gas | | BB- | | NRG Energy, Inc. | |
| Keystone Station Units 1 and 2 | | PA | | $ | 20 |
| | 17 | % | | 1,711 |
| | Coal | | CCC- | | REMA (A) | |
| Conemaugh Station Units 1 and 2 | | PA | | $ | 20 |
| | 17 | % | | 1,711 |
| | Coal | | CCC- | | REMA (A) | |
| Shawville Station Units 1, 2, 3 and 4 | | PA | | $ | 78 |
| | 100 | % | | 596 |
| | Gas | | CCC- | | REMA (A) | |
| | | | | | | | | | | | | | | | |
| |
(A) | GenOn Energy Inc. (GenOn), and certain of its subsidiaries (which did not include REMA) filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. GenOn is currently engaged in a balance sheet restructuring, which will take an undetermined time to complete. Certain subsidiaries of Energy Holdings, REMA, consenting holders of the pass-through certificates and other parties entered into a Forbearance relating to the Conemaugh facility. For additional information, see Note 7. Long-Term Investments. |
The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease structures. These credit enhancement features vary from lease to lease.2023. Upon the occurrence of certain defaults, indirect subsidiary companiessubsidiaries of Energy Holdings would exercise their rights and seek recovery of their investment,investments, potentially including stepping into the lease directly to protect their investments. While these actions could ultimately protect or mitigate the loss of value, they could require the use of significant capital and trigger certain material tax obligations which could, for certain leases, wholly or partially be mitigated by tax indemnification claims against the counterparty. A bankruptcy of a lessee would likely delay and potentially limit any efforts on the part of the lessors to assert their rights upon default and could delay the monetization of claims. Failure to recover adequate value could ultimately lead to a foreclosure on the assets under lease by the lenders.
Additional factors that may impact future lease cash flows include, but are not limited to, new environmental legislation and regulation regarding air quality, water and other discharges in the process of generating electricity, market prices for fuel, electricity and capacity, overall financial condition of lease counterparties and their affiliates and the quality and condition of assets under lease.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 9. Available-for-Sale Securities10. Trust Investments
NDT Fund
In accordance with NRC regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operation. As a general practice, each nuclear owner places funds in independent external trust accounts it maintains to provide for decommissioning. PSEG Power is required to file periodic reports with the NRC demonstrating that its NDT Fund meets the formula-based minimum NRC funding requirements.
PSEG Power maintains an external master NDT to fund its share of decommissioning costs for its five nuclear facilities upon their respective termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. PSEG Power’s share of decommissioning costs related to its five nuclear units was estimated to be between $2.8$3.0 billion and $3.0$3.4 billion,, including contingencies. The liability for decommissioning recorded on a discounted basis as of December 31, 20172023 was approximately $756 million$1.1 billion and is included in the Asset Retirement Obligation.ARO. The funds are managed by third-party investment managers who operate under investment guidelines developed by PSEG Power.
Power classifies investments in the NDT Fund as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund.
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | As of December 31, 2017 | |
| | | Cost | | Gross Unrealized Gains | | Gross Unrealized Losses | | Fair Value | |
| | | Millions | |
| Equity Securities | | | | | | | | | |
| Domestic | | $ | 405 |
| | $ | 245 |
| | $ | (2 | ) | | $ | 648 |
| |
| International | | 311 |
| | 99 |
| | (3 | ) | | 407 |
| |
| Total Equity Securities | | 716 |
| | 344 |
| | (5 | ) | | 1,055 |
| |
| Debt Securities | | | | | | | | | |
| Government | | 586 |
| | 2 |
| | (4 | ) | | 584 |
| |
| Corporate | | 400 |
| | 4 |
| | (2 | ) | | 402 |
| |
| Total Debt Securities | | 986 |
| | 6 |
| | (6 | ) | | 986 |
| |
| Other Securities | | 92 |
| | — |
| | — |
| | 92 |
| |
| Total NDT Available-for-Sale Securities | | $ | 1,794 |
| | $ | 350 |
| | $ | (11 | ) | | $ | 2,133 |
| |
| | | | | | | | |
|
| |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | As of December 31, 2023 | |
| | | Cost | | Gross Unrealized Gains | | Gross Unrealized Losses | | Fair Value | |
| | | Millions | |
| Equity Securities | | | | | | | | | |
| Domestic | | $ | 482 | | | $ | 300 | | | $ | (2) | | | $ | 780 | | |
| International | | 423 | | | 118 | | | (11) | | | 530 | | |
| Total Equity Securities | | 905 | | | 418 | | | (13) | | | 1,310 | | |
| Available-for-Sale Debt Securities | | | | | | | | | |
| Government | | 759 | | | 4 | | | (72) | | | 691 | | |
| Corporate | | 555 | | | 6 | | | (39) | | | 522 | | |
| Total Available-for-Sale Debt Securities | | 1,314 | | | 10 | | | (111) | | | 1,213 | | |
| Total NDT Fund Investments (A) | | $ | 2,219 | | | $ | 428 | | | $ | (124) | | | $ | 2,523 | | |
| | | | | | | | | | |
(A) The NDT Fund Investments table excludes cash and foreign currency of $1 millionas of December 31, 2023,
which is part of the NDT Fund.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | As of December 31, 2022 | |
| | | Cost | | Gross Unrealized Gains | | Gross Unrealized Losses | | Fair Value | |
| | | Millions | |
| Equity Securities | | | | | | | | | |
| Domestic | | $ | 476 | | | $ | 232 | | | $ | (12) | | | $ | 696 | | |
| International | | 336 | | | 68 | | | (28) | | | 376 | | |
| Total Equity Securities | | 812 | | | 300 | | | (40) | | | 1,072 | | |
| Available-for-Sale Debt Securities | | | | | | | | | |
| Government | | 721 | | | — | | | (94) | | | 627 | | |
| Corporate | | 597 | | | 1 | | | (69) | | | 529 | | |
| Total Available-for-Sale Debt Securities | | 1,318 | | | 1 | | | (163) | | | 1,156 | | |
| Total NDT Fund Investments (A) | | $ | 2,130 | | | $ | 301 | | | $ | (203) | | | $ | 2,228 | | |
| | | | | | | | | | |
(A) The NDT Fund Investments table excludes cash and foreign currency of $2 millionas of December 31, 2022, which is part of the NDT Fund.
Net unrealized gains (losses) on debt securities of $(59) million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s Consolidated Balance Sheet as of December 31, 2023. The portion of net unrealized gains (losses) recognized
|
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | As of December 31, 2016 | |
| | | Cost | | Gross Unrealized Gains | | Gross Unrealized Losses | | Fair Value | |
| | | Millions | |
| Equity Securities | | | | | | | | | |
| Domestic | | $ | 439 |
| | $ | 214 |
| | $ | (3 | ) | | $ | 650 |
| |
| International | | 266 |
| | 49 |
| — |
| (8 | ) | | 307 |
| |
| Total Equity Securities | | 705 |
| | 263 |
| | (11 | ) | | 957 |
| |
| Debt Securities | | | | | | | | | |
| Government | | 518 |
| | 8 |
| | (6 | ) | | 520 |
| |
| Corporate | | 337 |
| | 4 |
| | (4 | ) | | 337 |
| |
| Total Debt Securities | | 855 |
| | 12 |
| | (10 | ) | | 857 |
| |
| Other Securities | | 44 |
| | — |
| | — |
| | 44 |
| |
| Total NDT Available-for-Sale Securities (A) | | $ | 1,604 |
| | $ | 275 |
| | $ | (21 | ) | | $ | 1,858 |
| |
| | | | | | | | | | |
| |
(A) | The NDT available-for-sale securities table excludes cash of $1 million as of December 31, 2016, which is part of the NDT Fund. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The costduring 2023 related to equity securities still held at the end of these securitiesDecember 31, 2023 was determined on the basis of specific identification.$166 million.
The amounts in the preceding tables do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table.
|
| | | | | | | | | | |
| | | | | | |
| | | As of December 31, 2017 | | As of December 31, 2016 | |
| | | Millions | |
| Accounts Receivable | | $ | 24 |
| | $ | 8 |
| |
| Accounts Payable | | $ | 74 |
| | $ | 5 |
| |
| | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | As of December 31, | |
| | | 2023 | | 2022 | |
| | | Millions | |
| Accounts Receivable | | $ | 19 | | | $ | 14 | | |
| Accounts Payable | | $ | 6 | | | $ | 6 | | |
| | | | | | |
The following table shows the value of securities in the NDT Fund that have been in a continuousan unrealized loss position for less than 12 months and greater than 12 months.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | As of December 31, 2023 | | As of December 31, 2022 | |
| | | Less Than 12 Months | | Greater Than 12 Months | | Less Than 12 Months | | Greater Than 12 Months | |
| | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | |
| | | Millions | |
| Equity Securities (A) | | | | | | | | | | | | | | | | | |
| Domestic | | $ | 44 | | | $ | (1) | | | $ | 4 | | | $ | — | | | $ | 90 | | | $ | (10) | | | $ | 9 | | | $ | (2) | | |
| International | | 35 | | | (4) | | | 28 | | | (8) | | | 88 | | | (12) | | | 38 | | | (16) | | |
| Total Equity Securities | | 79 | | | (5) | | | 32 | | | (8) | | | 178 | | | (22) | | | 47 | | | (18) | | |
| Available-for-Sale Debt Securities | | | | | | | | | | | | | | | | | |
| Government (B) | | 90 | | | (1) | | | 432 | | | (71) | | | 301 | | | (27) | | | 292 | | | (67) | | |
| Corporate (C) | | 19 | | | — | | | 329 | | | (39) | | | 221 | | | (21) | | | 249 | | | (48) | | |
| Total Available-for-Sale Debt Securities | | 109 | | | (1) | | | 761 | | | (110) | | | 522 | | | (48) | | | 541 | | | (115) | | |
| NDT Trust Investments | | $ | 188 | | | $ | (6) | | | $ | 793 | | | $ | (118) | | | $ | 700 | | | $ | (70) | | | $ | 588 | | | $ | (133) | | |
| | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | As of December 31, 2017 | | As of December 31, 2016 | |
| | | Less Than 12 Months | | Greater Than 12 Months | | Less Than 12 Months | | Greater Than 12 Months | |
| | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | |
| | | Millions | |
| Equity Securities (A) | | | | | | | | | | | | | | | | | |
| Domestic | | $ | 40 |
| | $ | (2 | ) | | $ | — |
| | $ | — |
| | $ | 51 |
| | $ | (3 | ) | | $ | 2 |
| | $ | — |
| |
| International | | 29 |
| | (3 | ) | | 2 |
| | — |
| | 69 |
| | (7 | ) | | 6 |
| | (1 | ) | |
| Total Equity Securities | | 69 |
| | (5 | ) | | 2 |
| | — |
| | 120 |
| | (10 | ) | | 8 |
| | (1 | ) | |
| Debt Securities | | | | | | | | | | | | | | | | | |
| Government (B) | | 343 |
| | (2 | ) | | 91 |
| | (2 | ) | | 276 |
| | (6 | ) | | 4 |
| | — |
| |
| Corporate (C) | | 191 |
| | (1 | ) | | 27 |
| | (1 | ) | | 139 |
| | (3 | ) | | 15 |
| | (1 | ) | |
| Total Debt Securities | | 534 |
| | (3 | ) | | 118 |
| | (3 | ) | | 415 |
| | (9 | ) | | 19 |
| | (1 | ) | |
| NDT Available-for-Sale Securities | | $ | 603 |
| | $ | (8 | ) | | $ | 120 |
| | $ | (3 | ) | | $ | 535 |
| | $ | (19 | ) | | $ | 27 |
| | $ | (2 | ) | |
| | | | | | | | | | | | | | | | | | |
(A)Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. Unrealized gains and losses on these securities are recorded in Net Income. | |
(A) | Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over a broad range of securities with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of December 31, 2017. |
| |
(B) | Debt Securities (Government)—Unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. Power also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since Power does not intend to sell these securities before recovery nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2017. |
| |
(C) | Debt Securities (Corporate)—Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities before recovery nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2017. |
(B)Debt Securities (Government)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on PSEG Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. PSEG Power also has investments in municipal bonds. It is not expected that these securities will settle for less than their amortized cost. PSEG Power does not intend to sell these securities nor will it be more-likely-than-not required to sell before recovery of their amortized cost. PSEG Power did not recognize credit losses for U.S. Treasury obligations and Federal Agency mortgage-backed securities because these investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG Power did not recognize credit losses for municipal bonds because they are primarily investment grade securities.
(C)Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). Unrealized losses were due to market declines. It is not expected that these securities would settle for less than their amortized cost. PSEG Power does not intend to sell these securities nor will it be more-likely-than-not required to sell before recovery of their amortized cost. PSEG Power did not recognize credit losses for corporate bonds because they are primarily investment grade securities.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The proceeds from the sales of and the net realized gains (losses) on securities in the NDT Fund were:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| | | 2023 | | 2022 | | 2021 | |
| | | Millions | |
| Proceeds from Sales (A) | | $ | 1,685 | | | $ | 1,521 | | | $ | 1,930 | | |
| Net Realized Gains (Losses): | | | | | | | |
| Gross Realized Gains | | $ | 142 | | | $ | 86 | | | $ | 236 | | |
| Gross Realized Losses | | (100) | | | (136) | | | (70) | | |
| Net Realized Gains (Losses) on NDT Fund (B) | | 42 | | | (50) | | | 166 | | |
| Net Unrealized Gains (Losses) on Equity Securities | | 146 | | | (205) | | | 19 | | |
| | | | | | | | |
| Net Gains (Losses) on NDT Fund Investments | | $ | 188 | | | $ | (255) | | | $ | 185 | | |
| | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| | | 2017 | | 2016 | | 2015 | |
| | | Millions | |
| Proceeds from Sales (A) | | $ | 2,137 |
| | $ | 711 |
| | $ | 1,397 |
| |
| Net Realized Gains (Losses): | | | | | | | |
| Gross Realized Gains | | $ | 157 |
| | $ | 53 |
| | $ | 97 |
| |
| Gross Realized Losses | | (23 | ) | | (32 | ) | | (37 | ) | |
| Net Realized Gains (Losses) on NDT Fund (B) | | $ | 134 |
| | $ | 21 |
| | $ | 60 |
| |
| | | | | | | | |
| |
(A) | (A)Includes activity in accounts related to the liquidation of funds being transitioned to new managers. |
| |
(B) | The cost of these securities was determined on the basis of specific identification. |
Gross realized gains and gross realized losses disclosed in accounts related to the preceding table were recognized in Other Income and Other Deductions, respectively, in PSEG’s and Power’s Consolidated Statementsliquidation of Operations. Net unrealized gainsfunds being transitioned within the trust.
(B)The cost of $175 million (after-tax) are included in Accumulated Other Comprehensive Lossthese securities was determined on PSEG’s and Power’s Consolidated Balance Sheets asthe basis of December 31, 2017. Under new guidance, equity investments (other than those accounted for using the equity method) will be measured at fair value through Net Income instead of Other Comprehensive Income (Loss), effective January 1, 2018. For additional information, see Note 2. Recent Accounting Standards.specific identification.
The available-for-saleNDT Fund debt securities held as of December 31, 20172023 had the following maturities:
| | | | | | | | | | | | | | |
| | | | |
| Time Frame | | Fair Value | |
| | | Millions | |
| Less than one year | | $ | 17 | | |
| 1 - 5 years | | 314 | | |
| 6 - 10 years | | 214 | | |
| 11 - 15 years | | 62 | | |
| 16 - 20 years | | 101 | | |
| Over 20 years | | 505 | | |
| Total NDT Available-for-Sale Debt Securities | | $ | 1,213 | | |
| | | | |
|
| | | | | | |
| | | | |
| Time Frame | | Fair Value | |
| | | Millions | |
| Less than one year | | $ | 42 |
| |
| 1 - 5 years | | 320 |
| |
| 6 - 10 years | | 207 |
| |
| 11 - 15 years | | 40 |
| |
| 16 - 20 years | | 65 |
| |
| Over 20 years | | 312 |
| |
| Total NDT Available-for-Sale Debt Securities | | $ | 986 |
| |
| | | | |
PSEG Power periodically assesses individual debt securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed incomethese securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). In 2017, other-than-temporary impairments of $12 million were recognized on securities in the NDT Fund. Any subsequent recoveries inof the valuenoncredit loss component of these securitiesthe impairment would be recognized inrecorded through Accumulated Other Comprehensive Income (Loss) unless. Any subsequent recoveries of the securities are sold, in which case, any gaincredit loss component would be recognized in income.through earnings. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.
Rabbi Trust
PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in a grantor trust commonly known as a “Rabbi Trust.”
PSEG classifies investments in the Rabbi Trust as available-for-sale.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following tables show the fair values, gross unrealized gains and losses and amortized cost basesbasis for the securities held in the Rabbi Trust.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | As of December 31, 2023 | |
| | | Cost | | Gross Unrealized Gains | | Gross Unrealized Losses | | Fair Value | |
| | | Millions | |
| Domestic Equity Securities | | $ | 10 | | | $ | 8 | | | $ | — | | | $ | 18 | | |
| Available-for-Sale Debt Securities | | | | | | | | | |
| Government | | 110 | | | — | | | (19) | | | 91 | | |
| Corporate | | 80 | | | — | | | (10) | | | 70 | | |
| Total Available-for-Sale Debt Securities | | 190 | | | — | | | (29) | | | 161 | | |
| Total Rabbi Trust Investments | | $ | 200 | | | $ | 8 | | | $ | (29) | | | $ | 179 | | |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | As of December 31, 2022 | |
| | | Cost | | Gross Unrealized Gains | | Gross Unrealized Losses | | Fair Value | |
| | | Millions | |
| Domestic Equity Securities | | $ | 14 | | | $ | 6 | | | $ | — | | | $ | 20 | | |
| Available-for-Sale Debt Securities | | | | | | | | | |
| Government | | 110 | | | — | | | (21) | | | 89 | | |
| Corporate | | 89 | | | — | | | (15) | | | 74 | | |
| Total Available-for-Sale Debt Securities | | 199 | | | — | | | (36) | | | 163 | | |
| Total Rabbi Trust Investments | | $ | 213 | | | $ | 6 | | | $ | (36) | | | $ | 183 | | |
| | | | | | | | | | |
117
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | As of December 31, 2017 | |
| | | Cost | | Gross Unrealized Gains | | Gross Unrealized Losses | | Fair Value | |
| | | Millions | |
| Equity Securities | | | | | | | | | |
| Domestic | | $ | 22 |
| | $ | 3 |
| | $ | — |
| | $ | 25 |
| |
| International | | — |
| | — |
| | — |
| | — |
| |
| Total Equity Securities | | $ | 22 |
| | $ | 3 |
| | $ | — |
| | $ | 25 |
| |
| Debt Securities | | | | | | | | | |
| Government | | 85 |
| | 1 |
| | (1 | ) | | 85 |
| |
| Corporate | | 118 |
| | 2 |
| | (1 | ) | | 119 |
| |
| Total Debt Securities | | 203 |
| | 3 |
| | (2 | ) | | 204 |
| |
| Other Securities | | 2 |
| | — |
| | — |
| | 2 |
| |
| Total Rabbi Trust Available-for-Sale Securities | | $ | 227 |
| | $ | 6 |
| | $ | (2 | ) | | $ | 231 |
| |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | As of December 31, 2016 | |
| | | Cost | | Gross Unrealized Gains | | Gross Unrealized Losses | | Fair Value | |
| | | Millions | |
| Equity Securities | | | | | | | | | |
| Domestic | | $ | 11 |
| | $ | 11 |
| | $ | — |
| | $ | 22 |
| |
| International | | — |
| | — |
| | — |
| | — |
| |
| Total Equity Securities | | 11 |
| | 11 |
| | — |
| | 22 |
| |
| Debt Securities | | | | | | | | | |
| Government | | 105 |
| | — |
| | (2 | ) | | 103 |
| |
| Corporate | | 92 |
| | 1 |
| | (2 | ) | | 91 |
| |
| Total Debt Securities | | 197 |
| | 1 |
| | (4 | ) | | 194 |
| |
| Other Securities | | 1 |
| | — |
| | — |
| | 1 |
| |
| Total Rabbi Trust Available-for-Sale Securities | | $ | 209 |
| | $ | 12 |
| | $ | (4 | ) | | $ | 217 |
| |
| | | | | | | | | | |
$(21) million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s Consolidated Balance Sheet as of December 31, 2023. The portion of net unrealized gains (losses) recognized during 2023 related to equity securities still held at the end of December 31, 2023 was $2 million.The amounts in the preceding tables do not include receivables and payables for Rabbi Trust Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table.
|
| | | | | | | | | | |
| | | | | | |
| | | As of December 31, 2017 | | As of December 31, 2016 | |
| | | Millions | |
| Accounts Receivable | | $ | 2 |
| | $ | 5 |
| |
| Accounts Payable | | $ | 1 |
| | $ | 3 |
| |
| | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | As of December 31, | |
| | | 2023 | | 2022 | |
| | | Millions | |
| Accounts Receivable | | $ | 1 | | | $ | 1 | | |
| Accounts Payable | | $ | — | | | $ | — | | |
| | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table shows the value of securities in the Rabbi Trust Fund that have been in a continuousan unrealized loss position for less than 12 months and greater than 12 months:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | As of December 31, 2023 | | As of December 31, 2022 | |
| | | Less Than 12 Months | | Greater Than 12 Months | | Less Than 12 Months | | Greater Than 12 Months | |
| | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | |
| | | Millions | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Available-for-Sale Debt Securities | | | | | | | | | | | | | | | | | |
| Government (A) | | $ | 3 | | | $ | — | | | $ | 83 | | | $ | (19) | | | $ | 32 | | | $ | (5) | | | $ | 57 | | | $ | (16) | | |
| Corporate (B) | | 3 | | | — | | | 60 | | | (10) | | | 35 | | | (5) | | | 39 | | | (10) | | |
| Total Available-for-Sale Debt Securities | | 6 | | | — | | | 143 | | | (29) | | | 67 | | | (10) | | | 96 | | | (26) | | |
| Rabbi Trust Investments | | $ | 6 | | | $ | — | | | $ | 143 | | | $ | (29) | | | $ | 67 | | | $ | (10) | | | $ | 96 | | | $ | (26) | | |
| | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | As of December 31, 2017 | | As of December 31, 2016 | |
| | | Less Than 12 Months | | Greater Than 12 Months | | Less Than 12 Months | | Greater Than 12 Months | |
| | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | |
| | | Millions | |
| Equity Securities (A) | | | | | | | | | | | | | | | | | |
| Domestic | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| International | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
| Total Equity Securities | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
| Debt Securities | | | | | | | | | | | | | | | | | |
| Government (B) | | 28 |
| | — |
| | 25 |
| | (1 | ) | | 60 |
| | (2 | ) | | 1 |
| | — |
| |
| Corporate (C) | | 39 |
| | (1 | ) | | 9 |
| | — |
| | 46 |
| | (2 | ) | | 3 |
| | — |
| |
| Total Debt Securities | | 67 |
| | (1 | ) | | 34 |
| | (1 | ) | | 106 |
| | (4 | ) | | 4 |
| | — |
| |
| Rabbi Trust Available-for-Sale Securities | | $ | 67 |
| | $ | (1 | ) | | $ | 34 |
| | $ | (1 | ) | | $ | 106 |
| | $ | (4 | ) | | $ | 4 |
| | $ | — |
| |
| | | | | | | | | | | | | | | | | | |
(A)Debt Securities (Government)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. PSEG also has investments in municipal bonds. It is not expected that these securities will settle for less than their amortized cost. PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell before recovery of their amortized cost. PSEG did not recognize credit losses for U.S. Treasury obligations and Federal Agency mortgage-backed securities because these investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG did not recognize credit losses for municipal bonds because they are primarily investment grade securities. | |
(A) | Equity Securities—Investments in marketable equity securities within the Rabbi Trust Fund are through a mutual fund which invests primarily in common stocks within a broad range of industries and sectors. |
| |
(B) | Debt Securities (Government)—Unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since PSEG does not intend to sell these securities before recovery nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2017. |
| |
(C) | Debt Securities (Corporate)—PSEG’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG does not intend to sell these securities before recovery nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2017. |
(B)Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). Unrealized losses were due to market declines. It is not expected that these securities would settle for less than their amortized cost. PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell before recovery of their amortized cost. PSEG did not recognize credit losses for corporate bonds because they are primarily investment grade.
The proceeds from the sales of and the net realized gains (losses) on securities in the Rabbi Trust Fund were:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| | | 2023 | | 2022 | | 2021 | |
| | | Millions | |
| Proceeds from Rabbi Trust Sales | | $ | 29 | | | $ | 65 | | | $ | 170 | | |
| Net Realized Gains (Losses): | | | | | | | |
| Gross Realized Gains | | $ | 5 | | | $ | 5 | | | $ | 16 | | |
| Gross Realized Losses | | (6) | | | (9) | | | (8) | | |
| Net Realized Gains (Losses) on Rabbi Trust (A) | | (1) | | | (4) | | | 8 | | |
| Net Unrealized Gains (Losses) on Equity Securities | | 2 | | | (6) | | | 1 | | |
| Net Gains (Losses) on Rabbi Trust Investments | | $ | 1 | | | $ | (10) | | | $ | 9 | | |
| | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| | | 2017 | | 2016 | | 2015 | |
| | | Millions | |
| Proceeds from Rabbi Trust Sales (A) | | $ | 182 |
| | $ | 113 |
| | $ | 104 |
| |
| Net Realized Gains (Losses): | | | | | | | |
| Gross Realized Gains | | $ | 17 |
| | $ | 6 |
| | $ | 3 |
| |
| Gross Realized Losses | | (5 | ) | | (5 | ) | | (2 | ) | |
| Net Realized Gains (Losses) on Rabbi Trust (B) | | $ | 12 |
| | $ | 1 |
| | $ | 1 |
| |
| | | | | | | | |
| |
(A) | Includes activity in accounts related to the liquidation of funds being transitioned to new managers. |
| |
(B) | The cost of these securities was determined on the basis of specific identification. |
(A)The cost of these securities was determined on the basis of specific identification.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Gross realized gains and gross realized losses disclosed in the above table were recognized in Other Income and Other Deductions, respectively, in the Consolidated Statements of Operations. Net unrealized gains of $2 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets as of December 31, 2017. The Rabbi Trust available-for-sale debt securities held as of December 31, 20172023 had the following maturities:
|
| | | | | | |
| | | | |
| Time Frame | | Fair Value | |
| | | Millions | |
| Less than one year | | $ | 1 |
| |
| 1 - 5 years | | 37 |
| |
| 6 - 10 years | | 30 |
| |
| 11 - 15 years | | 5 |
| |
| 16 - 20 years | | 18 |
| |
| Over 20 years | | 113 |
| |
| Total Rabbi Trust Available-for-Sale Debt Securities | | $ | 204 |
| |
| | | | |
| | | | | | | | | | | | | | |
| | | | |
| Time Frame | | Fair Value | |
| | | Millions | |
| Less than one year | | $ | 8 | | |
| 1 - 5 years | | 27 | | |
| 6 - 10 years | | 16 | | |
| 11 - 15 years | | 10 | | |
| 16 - 20 years | | 20 | | |
| Over 20 years | | 80 | | |
| Total Rabbi Trust Available-for-Sale Debt Securities | | $ | 161 | | |
| | | | |
PSEG periodically assesses individual debt securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, the Rabbi Trust is invested in a commingled indexed mutual fund. Due to the commingled nature of this fund, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). Any subsequent recoveries of the noncredit loss component of the impairment would be recorded through Accumulated Other Comprehensive Income (Loss). Any subsequent recoveries of the credit loss component would be recognized through earnings. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities. In 2017, there were no other-than-temporary impairments recognized on investments of the Rabbi Trust.
The fair value of the Rabbi Trust related to PSEG and PSE&G and Power are detailed as follows:
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | As of December 31, | | As of December 31, | |
| | | 2023 | | 2022 | |
| | | Millions | |
| PSE&G | | $ | 32 | | | $ | 32 | | |
| PSEG Power & Other | | 147 | | | 151 | | |
| Total Rabbi Trust Investments | | $ | 179 | | | $ | 183 | | |
| | | | | | |
|
| | | | | | | | | | |
| | | | | | |
| | | As of December 31, 2017 | | As of December 31, 2016 | |
| | | Millions | |
| PSE&G | | $ | 46 |
| | $ | 43 |
| |
| Power | | 57 |
| | 53 |
| |
| Other | | 128 |
| | 121 |
| |
| Total Rabbi Trust Available-for-Sale Securities | | $ | 231 |
| | $ | 217 |
| |
| | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 10. Goodwill and Other Intangibles
As of December 31, 2017 and 2016, Power had goodwill of $16 million related to the Bethlehem Energy Center facility. Power conducted an annual review for goodwill impairment in the fourth quarter of 2017 and concluded that goodwill continues to remain unimpaired. In addition to goodwill, as of December 31, 2017 and 2016, Power had intangible assets of $114 million and $98 million, respectively, related to emissions allowances and renewable energy credits. Emissions allowances and renewable energy credits are recorded at cost and evaluated for impairment at least annually. Emissions expense includes impairments of emissions allowances and costs for emissions, which is recorded as emissions occur. As load is served under contracts requiring energy from renewable sources, the related expense is recorded. The changes to Power’s intangible assets during 2016 and 2017 are presented in the following table:
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | | |
| | | Emissions Allowances | | Renewable Energy Credits | | Total Other Intangibles | |
| | | Millions | |
| Balance as of January 1, 2016 | | $ | 62 |
| | $ | 40 |
| | $ | 102 |
| |
| Retirements | | (6 | ) | | (94 | ) | | (100 | ) | |
| Purchases | | — |
| | 99 |
| | 99 |
| |
| Sales and Transfers, net | | (1 | ) | | (1 | ) | | (2 | ) | |
| Impairments | | (1 | ) | | — |
| | (1 | ) | |
| Balance as of December 31, 2016 | | $ | 54 |
| | $ | 44 |
| | $ | 98 |
| |
| Retirements | | (7 | ) | | (93 | ) | | (100 | ) | |
| Purchases | | 27 |
| | 90 |
| | 117 |
| |
| Sales and Transfers, net | | — |
| | (1 | ) | | (1 | ) | |
| Balance as of December 31, 2017 | | $ | 74 |
| | $ | 40 |
| | $ | 114 |
| |
| | | | | | | | |
Note 11. Asset Retirement Obligations (AROs)
PSEG and PSE&G and Power recognize liabilities for the expected cost of retiring long-lived assets for which a legal obligation exists to remove or dispose of an asset or some component of an asset at retirement. 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. PSEG’s subsidiaries, except for PSE&G, accrete the ARO liability to reflect the passage of time with the corresponding expense recorded in O&M. PSE&G, as a rate-regulated entity, recognizes regulatory assetsRegulatory Assets or liabilitiesLiabilities as a result of timing differences between the recording of costs and costs recovered through the rate-making process. We accrete the ARO liability to reflect the passage of time with the corresponding expense recorded in Operation and Maintenance.
PSE&G has conditional AROs primarily for legal obligations related to the removal of treated wood poles and the requirement to seal natural gas pipelines at all sources of gas when the pipelines are no longer in service. PSE&G does not record an ARO for its protected steel and poly-based natural gas lines, as management believes that these categories of gas lines have an indeterminable life.
Power’sPSEG’s other ARO liability primarily relates to the decommissioning of its nuclear power plants in accordance with NRC requirements. PowerPSEG has an independent external trust that is intended to fund decommissioning of its nuclear facilities upon termination of operation. For additional information, see Note 9. Available-for-Sale Securities. Power10. Trust Investments. PSEG also identified conditional AROs related to PSEG’s retained fossil generation sites primarily related to Power’s fossil generation units and solar facilities, including liabilities for removal of asbestos, ash ponds, stored hazardous liquid material and underground storage tanks from industrial power sites, and demolition of certain plants, and the restoration of the sites at which they reside, when the plants are no longer in service.asbestos. To estimate the fair value of its other AROs, PowerPSEG uses a probability weighted, discounted cash flow model which, on a unit by unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on third-party decommissioning cost estimates, cost escalation rates, inflation rates and discount rates.
Updated nuclear cost studies are obtained triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2015.2021. When assumptions are revised to calculate fair values of existing AROs, generally, the ARO balance and corresponding long-lived asset are adjusted which impact the amount of accretion and depreciation expense
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
recognized in future periods. For PSE&G, Regulatory Assets and Regulatory Liabilities result when accretion and amortization are adjusted to match rates established by regulators resulting in the regulatory deferral of any gain or loss.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The changes to the ARO liabilities for PSEG and PSE&G during 2022 and Power during 2016 and 20172023 are presented in the following table:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | PSEG | | PSE&G | | PSEG Power & Other | |
| | | Millions | |
| ARO Liability as of January 1, 2022 | | $ | 1,573 | | | $ | 363 | | | $ | 1,210 | | |
| Liabilities Settled | | (15) | | | (15) | | | — | | |
| Accretion Expense | | 50 | | | — | | | 50 | | |
| Accretion Expense Deferred and Recovered in Rate Base (A) | | 17 | | | 17 | | | — | | |
| Revision to Present Values of Estimated Cash Flows | | (126) | | | 19 | | | (145) | | |
| ARO Liability as of December 31, 2022 | | $ | 1,499 | | | $ | 384 | | | $ | 1,115 | | |
| Liabilities Settled | | $ | (13) | | | $ | (13) | | | $ | — | | |
| | | | | | | | |
| Accretion Expense | | 51 | | | — | | | 51 | | |
| Accretion Expense Deferred and Recovered in Rate Base (A) | | 16 | | | 16 | | | — | | |
| Revision to Present Values of Estimated Cash Flows | | (85) | | | 14 | | | (99) | | |
| ARO Liability as of December 31, 2023 | | $ | 1,468 | | | $ | 401 | | | $ | 1,067 | | |
| | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | PSEG | | PSE&G | | Power | | Other | |
| | | Millions | |
| ARO Liability as of January 1, 2016 | | $ | 679 |
| | $ | 218 |
| | $ | 457 |
| | $ | 4 |
| |
| Liabilities Settled | | (13 | ) | | (9 | ) | | (4 | ) | | — |
| |
| Liabilities Incurred | | 25 |
| | 2 |
| | 23 |
| | — |
| |
| Accretion Expense | | 26 |
| | — |
| | 26 |
| | — |
| |
| Accretion Expense Deferred and Recovered in Rate Base (A) | | 12 |
| | 12 |
| | — |
| | — |
| |
| Revision to Present Values of Estimated Cash Flows | | (3 | ) | | (10 | ) | | 9 |
| | (2 | ) | |
| ARO Liability as of December 31, 2016 | | $ | 726 |
| | $ | 213 |
| | $ | 511 |
| | $ | 2 |
| |
| Liabilities Settled | | (29 | ) | | (8 | ) | | (21 | ) | | — |
| |
| Liabilities Incurred | | 1 |
| | — |
| | 1 |
| | — |
| |
| Accretion Expense | | 30 |
| | — |
| | 30 |
| | — |
| |
| Accretion Expense Deferred and Recovered in Rate Base (A) | | 12 |
| | 12 |
| | — |
| | — |
| |
| Revision to Present Values of Estimated Cash Flows | | 284 |
| | (5 | ) | | 289 |
| | — |
| |
| ARO Liability as of December 31, 2017 | | $ | 1,024 |
| | $ | 212 |
| | $ | 810 |
| | $ | 2 |
| |
| | | | | | | | | | |
(A)Not reflected as expense in Consolidated Statements of Operations. | |
(A) | Not reflected as expense in Consolidated Statements of Operations |
During 2017, PSE&G recorded a reductionIn February 2022, the NRC issued an order related to its review of the subsequent license renewal (SLR) application for the Peach Bottom nuclear units. While the NRC had previously granted the SLR to the Peach Bottom units, the NRC was responding to pending motions that had not previously been adjudicated. In its decision, the NRC concluded that the previous environmental review required by the National Environmental Policy Act (NEPA) was incomplete because it did not adequately address environmental impacts resulting from extending the units’ licenses by 20 years. As a result, at the direction of the NRC, the NRC staff changed the expiration dates for the licenses back to 2033 and 2034, until the completion of the NEPA analysis. The NRC directed, however, that the subsequently renewed licenses themselves remain in effect. The NRC also stated that it fully expects that the staff will complete its update of the NEPA analysis before 2033. As such, at this time, PSEG has not adjusted the useful lives or the assumed shutdown probabilities assigned to the ARO liabilitiesof the units as PSEG believes that the licenses will be updated to reflect the approved 2053 and 2054 expiration dates within the current license period. PSEG will continue to monitor this matter for further developments and any change to the estimated useful lives and ARO probabilities could have an adverse financial statement impact, which may be material.
In August 2022, the Inflation Reduction Act (IRA) was signed into law expanding incentives promoting carbon-free generation. The enacted legislation established a PTC for electricity generation using nuclear energy set to begin January 1, 2024 and continue through 2032. As a result, PSEG reassessed the Asset Retirement Cost (ARC) and ARO assumptions related to its nuclear units. This resulted in a decrease to the ARC asset and ARO liability of $145 million primarily due to an adjustment in the impactassumed estimated timing of settlementscash flows associated with decommissioning the units.
In December 2023, PSEG Power reassessed its ARC and changes to cash flow estimates. These changes had no impact in PSE&G’s Consolidated Statement of Operations.
During 2017, Power recorded an increaseARO assumptions related to its Hope Creek and Salem nuclear plants, based upon the expectation of PTCs beginning in 2024. As a result, PSEG Power decreased its ARC asset and ARO liabilities primarily due toliability by $99 million, reflecting a higher assumeddecrease in the probability of early retirement and an increase in the probability the units would obtain additional license renewals.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plans
PSEG sponsors and Services administers qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. Eligible employees participate in non-contributoryPSEG’s qualified pension plans consist of two qualified defined benefit pension plans, Pension Plan of Public Service Enterprise Group Incorporated (Pension Plan I) and OPEBPension Plan of Public Service Enterprise Group Incorporated II (Pension Plan II and, together, the Plans). Each of the qualified pension plans sponsored by PSEGinclude a Final Average Pay and administered by Services.two Cash Balance components. In addition, represented and nonrepresentednon-represented employees are eligible for participation in PSEG’s two defined contribution plans described below.plans.
PSEG and PSE&G and Power are required to record the under or over funded positions of their defined benefit pension and OPEB plans on their respective balance sheets. Such funding positions of each PSEG company are required to be measured as of the date of itstheir respective year-end Consolidated Balance Sheets. For underfunded plans, the liability is equal to the difference between the plan’s benefit obligation and the fair value of plan assets. For defined benefit pension plans, the benefit obligation is the projected benefit obligation. For OPEB plans, the benefit obligation is the accumulated postretirement benefit obligation. In addition, GAAP requires that the total unrecognized costs for defined benefit pension and OPEB plans be recorded as an after-tax charge to Accumulated Other Comprehensive Income (Loss), a separate component of Stockholders’ Equity. However, for PSE&G, because the amortization of the unrecognized costs is being collected from customers, the accumulated unrecognized costs are recorded as a Regulatory Asset. The unrecognized costs represent actuarial gains or losses and prior service costs which hadhave not been expensed.
For PSE&G, the Regulatory Asset is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations. For Power, the The charge to Accumulated Other Comprehensive Income (Loss) isand the Regulatory Asset for PSE&G are amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations.
AsIn July 2023, PSEG and Fiduciary Counselors Inc,. as independent fiduciary of December 31, 2016, PSEG merged its three qualifiedthe Plans, entered into a commitment agreement (for a “lift-out”) with The Prudential Insurance Company of America (the Insurer) under which the Plans agreed to purchase a nonparticipating single premium group annuity contract that has transferred to the Insurer approximately $1 billion of the Plans’ defined benefit pension plans (excluding Servco plans) into one plan, thereby also merging allobligations and associated Plan assets related to certain pension benefits. The contract covers approximately 2,000 retirees from PSEG Power & Other, excluding Services (Participants). In August 2023, assets were transferred to the Insurer and the transaction was closed. Under the contract, the Insurer made an irrevocable commitment, and is solely responsible, to pay benefits of the pension plans’ assets. As a result, the total net periodic benefit costs, net of amounts capitalized, decreased by approximately $48 million for the year endedeach Participant that are due on and after December 31, 2017, as compared2023. The transaction resulted in no changes to the 2017 amounts that would have been recognized had the plans not been merged. This is dueamount of benefits payable to the amortization period for gains and losses for the merged plan resulting in lower amortization than that of the individual plans. No changes were made to the benefit formulas, vesting provisions, or to the employees covered by the plans.Participants.
Amounts for Servco are not included in any of the following pension and OPEB benefit information for PSEG and its affiliates but rather are separately disclosed later in this note.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table provides a roll-forward of the changes in the benefit obligation and the fair value of plan assets during each of the two years in the periods ended December 31, 20172023 and 2016.2022. It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | Pension Benefits | | Other Benefits | |
| | | 2017 | | 2016 | | 2017 | | 2016 | |
| | | Millions | |
| Change in Benefit Obligation | | | | | | | | | |
| Benefit Obligation at Beginning of Year (A) | | $ | 5,772 |
| | $ | 5,522 |
| | $ | 1,754 |
| | $ | 1,612 |
| |
| Service Cost | | 114 |
| | 109 |
| | 17 |
| | 17 |
| |
| Interest Cost | | 204 |
| | 202 |
| | 63 |
| | 59 |
| |
| Actuarial (Gain) Loss | | 564 |
| | 219 |
| | 199 |
| | 127 |
| |
| Gross Benefits Paid | | (295 | ) | | (282 | ) | | (57 | ) | | (57 | ) | |
| Plan Amendments | | — |
| | 2 |
| | — |
| | (4 | ) | |
| Benefit Obligation at End of Year (A) | | $ | 6,359 |
| | $ | 5,772 |
| | $ | 1,976 |
| | $ | 1,754 |
| |
| Change in Plan Assets | | | | | | | | | |
| Fair Value of Assets at Beginning of Year | | $ | 5,193 |
| | $ | 5,039 |
| | $ | 420 |
| | $ | 374 |
| |
| Actual Return on Plan Assets | | 903 |
| | 403 |
| | 77 |
| | 32 |
| |
| Employer Contributions | | 11 |
| | 33 |
| | 71 |
| | 71 |
| |
| Gross Benefits Paid | | (295 | ) | | (282 | ) | | (57 | ) | | (57 | ) | |
| Fair Value of Assets at End of Year | | $ | 5,812 |
| | $ | 5,193 |
| | $ | 511 |
| | $ | 420 |
| |
| Funded Status | | | | | | | | | |
| Funded Status (Plan Assets less Benefit Obligation) | | $ | (547 | ) | | $ | (579 | ) | | $ | (1,465 | ) | | $ | (1,334 | ) | |
| Additional Amounts Recognized in the Consolidated Balance Sheets | | | | | | | | | |
| Current Accrued Benefit Cost | | (10 | ) | | (11 | ) | | (10 | ) | | (10 | ) | |
| Noncurrent Accrued Benefit Cost | | (537 | ) | | (568 | ) | | (1,455 | ) | | (1,324 | ) | |
| Amounts Recognized | | $ | (547 | ) | | $ | (579 | ) | | $ | (1,465 | ) | | $ | (1,334 | ) | |
| Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (B) | | | |
| Prior Service Cost | | $ | (46 | ) | | $ | (63 | ) | | $ | (3 | ) | | $ | (14 | ) | |
| Net Actuarial Loss | | 1,721 |
| | 1,763 |
| | 629 |
| | 523 |
| |
| Total | | $ | 1,675 |
| | $ | 1,700 |
| | $ | 626 |
| | $ | 509 |
| |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | Pension Benefits | | Other Benefits | |
| | | 2023 | | 2022 | | 2023 | | 2022 | |
| | | Millions | |
| Change in Benefit Obligation | | | | | | | | | |
| Benefit Obligation at Beginning of Year (A) | | $ | 5,628 | | | $ | 7,240 | | | $ | 851 | | | $ | 1,197 | | |
| Service Cost | | 90 | | | 142 | | | 3 | | | 6 | | |
| Interest Cost | | 259 | | | 167 | | | 41 | | | 26 | | |
| Actuarial (Gain) Loss (B) | | 103 | | | (1,517) | | | (30) | | | (314) | | |
| Gross Benefits Paid | | (352) | | | (382) | | | (68) | | | (61) | | |
| Settlements | | (970) | | | — | | | — | | | — | | |
| Other | | — | | | (22) | | | 5 | | | (3) | | |
| Benefit Obligation at End of Year (A) | | $ | 4,758 | | | $ | 5,628 | | | $ | 802 | | | $ | 851 | | |
| Change in Plan Assets | | | | | | | | | |
| Fair Value of Assets at Beginning of Year | | $ | 4,911 | | | $ | 6,906 | | | $ | 429 | | | $ | 606 | | |
| Actual Return on Plan Assets | | 539 | | | (1,606) | | | 51 | | | (139) | | |
| Employer Contributions | | 12 | | | 11 | | | 28 | | | 23 | | |
| Gross Benefits Paid | | (352) | | | (382) | | | (68) | | | (61) | | |
| Settlements | | (970) | | | — | | | — | | | — | | |
| Other | | — | | | (18) | | | — | | | — | | |
| Fair Value of Assets at End of Year | | $ | 4,140 | | | $ | 4,911 | | | $ | 440 | | | $ | 429 | | |
| Funded Status | | | | | | | | | |
| Funded Status (Plan Assets less Benefit Obligation) | | $ | (618) | | | $ | (717) | | | $ | (362) | | | $ | (422) | | |
| Additional Amounts Recognized in the Consolidated Balance Sheets | | | | | | | | | |
| Current Accrued Benefit Cost | | $ | (12) | | | $ | (12) | | | $ | (13) | | | $ | (12) | | |
| Noncurrent Accrued Benefit Cost | | (606) | | | (705) | | | (349) | | | (410) | | |
| Amounts Recognized | | $ | (618) | | | $ | (717) | | | $ | (362) | | | $ | (422) | | |
| Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (C) | | | |
| Prior Service Cost (Credit) | | $ | — | | | $ | — | | | $ | 6 | | | $ | (52) | | |
| Net Actuarial Loss (Gain) | | 1,656 | | | 2,151 | | | (6) | | | 41 | | |
| Total | | $ | 1,656 | | | $ | 2,151 | | | $ | — | | | $ | (11) | | |
| | | | | | | | | | |
| |
(A) | Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation of retirement. |
| |
(B) | Includes $683 million ($406 million, after-tax) and $679 million ($398 million, after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2017 and 2016, respectively. Also includes Regulatory Assets of $1,485 million and Deferred Assets of $133 million as of December 31, 2017 and Regulatory Assets of $1,396 million and Deferred Assets of $134 million as of December 31, 2016. |
(A)Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation or retirement.
(B)For pension benefits, the net actuarial loss in 2023 was due primarily to a decrease in the discount rate. The net actuarial gain in 2022 was due primarily to an increase in the discount rate. For OPEB, the net actuarial gain in 2023 was due primarily to assumption updates. The net actuarial gain in 2022 was due primarily to an increase in the discount rate and other assumption updates.
(C)Includes $143 million ($102 million, after-tax) and $594 million ($426 million, after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2023 and 2022, respectively. Also includes Regulatory Assets of $1,427 million and Deferred Assets of $141 million as of December 31, 2023 and Regulatory Assets of $1,405 million and Deferred Assets of $141 million as of December 31, 2022. This amount does not include $55 million as a result of modifying the method for calculating pension expense for ratemaking purposes, approved by the BPU effective January 1, 2023.
The pension benefits table above provides information relating to the funded status of the qualified and nonqualified pension and OPEB plans on an aggregate basis. As of December 31, 2017,2023, PSEG had funded approximately 91%87% of its projected pension benefit obligation. This percentage does not include $231$179 million of assets in the Rabbi Trust as of December 31, 20172023, which were used partially to fundprovide funding for the nonqualified pension plans. As of December 31, 2017, theplans and certain deferred compensation. The nonqualified pension plans included in the projected benefit obligation in the above table were $167$140 million. The fair values of the Rabbi Trust assets are included in Other Special Funds on the Consolidated Balance Sheets.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Accumulated Benefit Obligation
The accumulated benefit obligation for all PSEG’s defined benefit pension plans was $6.1$4.7 billion as of December 31, 20172023 and $5.6$5.5 billion as of December 31, 2016.2022.
The following table provides the components of net periodic benefit costrelating to all qualified and nonqualified pension and OPEB plans on an aggregate basis for PSEG, excluding Servco for the years ended December 31, 2017, 20162023, 2022 and 2015.2021. Amounts shown do not reflect the impacts of capitalization, co-owner allocations and the 2023 BPU accounting order. Only the service cost component is eligible for capitalization, when applicable.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | Pension Benefits Years Ended December 31, | | Other Benefits Years Ended December 31, | |
| | | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | |
| | | Millions | |
| Components of Net Periodic Benefit Cost | | | | | | | | | | | | | |
| Service Cost | | $ | 114 |
| | $ | 109 |
| | $ | 123 |
| | $ | 17 |
| | $ | 17 |
| | 22 |
| |
| Interest Cost | | 204 |
| | 202 |
| | 234 |
| | 63 |
| | 59 |
| | 67 |
| |
| Expected Return on Plan Assets | | (394 | ) | | (394 | ) | | (414 | ) | | (34 | ) | | (31 | ) | | (31 | ) | |
| Amortization of Net | | | | | | | | | | | | | |
| Prior Service Credit | | (18 | ) | | (19 | ) | | (19 | ) | | (11 | ) | | (14 | ) | | (14 | ) | |
| Actuarial Loss | | 97 |
| | 158 |
| | 150 |
| | 51 |
| | 40 |
| | 43 |
| |
| Net Periodic Benefit Cost | | $ | 3 |
| | $ | 56 |
| | $ | 74 |
| | $ | 86 |
| | $ | 71 |
| | $ | 87 |
| |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | Pension Benefits Years Ended December 31, | | Other Benefits Years Ended December 31, | |
| | | 2023 | | 2022 | | 2021 | | 2023 | | 2022 | | 2021 | |
| | | Millions | |
| Components of Net Periodic Benefit (Credits) Costs | | | | | | | | | | | |
| Service Cost (included in O&M Expense) | | $ | 90 | | | $ | 142 | | | $ | 151 | | | $ | 3 | | | $ | 6 | | | $ | 9 | | |
| Non-Service Components of Pension and OPEB (Credits) Costs | | | | | | | | | | | | | |
| Interest Cost | | 259 | | | 167 | | | 140 | | | 41 | | | 26 | | | 22 | | |
| Expected Return on Plan Assets | | (361) | | | (484) | | | (476) | | | (33) | | | (42) | | | (42) | | |
| Amortization of Net | | | | | | | | | | | | | |
| Prior Service Credit | | — | | | — | | | — | | | (52) | | | (129) | | | (129) | | |
| Actuarial Loss | | 83 | | | 60 | | | 103 | | | (2) | | | 15 | | | 44 | | |
| Settlement Charge Resulting from Pension Lift-Out | | 338 | | | — | | | — | | | — | | | — | | | — | | |
| Non-Service Components of Pension and OPEB (Credits) Costs | | 319 | | | (257) | | | (233) | | | (46) | | | (130) | | | (105) | | |
| Total Net Benefit (Credits) Costs | | $ | 409 | | | $ | (115) | | | $ | (82) | | | $ | (43) | | | $ | (124) | | | $ | (96) | | |
| | | | | | | | | | | | | | |
Pension costs and OPEB (credits) costs for PSEG and PSE&G and Power are detailed as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | Pension Benefits Years Ended December 31, | | Other Benefits Years Ended December 31, | |
| | | 2023 | | 2022 | | 2021 | | 2023 | | 2022 | | 2021 | |
| | | Millions | |
| PSE&G | | $ | 50 | | | $ | (70) | | | $ | (64) | | | $ | (42) | | | $ | (109) | | | $ | (92) | | |
| PSEG Power & Other | | 359 | | | (45) | | | (18) | | | (1) | | | (15) | | | (4) | | |
| Total Net Benefit (Credits) Costs | | $ | 409 | | | $ | (115) | | | $ | (82) | | | $ | (43) | | | $ | (124) | | | $ | (96) | | |
| | | | | | | | | | | | | | |
PSEG completed the above mentioned “lift-out” transaction in August 2023. As a result of the transaction, PSEG recognized a settlement charge of $332 million ($239 million, net of tax) in the third quarter of 2023 related to the immediate recognition of unamortized net actuarial loss associated with the portion of the pension involved in the transaction. Additionally, a settlement charge of $6 million ($4 million, net of tax) related to lump sum payments to participants was recognized in the fourth quarter of 2023.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | Pension Benefits Years Ended December 31, | | Other Benefits Years Ended December 31, | |
| | | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | |
| | | Millions | |
| PSE&G | | $ | (4 | ) | | $ | 29 |
| | $ | 40 |
| | $ | 54 |
| | $ | 43 |
| | $ | 55 |
| |
| Power | | 1 |
| | 16 |
| | 21 |
| | 27 |
| | 23 |
| | 27 |
| |
| Other | | 6 |
| | 11 |
| | 13 |
| | 5 |
| | 5 |
| | 5 |
| |
| Total Benefit Cost | | $ | 3 |
| | $ | 56 |
| | $ | 74 |
| | $ | 86 |
| | $ | 71 |
| | $ | 87 |
| |
| | | | | | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table provides the pre-tax changes recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Deferred Assets:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | Pension | | Other Benefits | |
| | | 2023 | | 2022 | | 2023 | | 2022 | |
| | | Millions | |
| Net Actuarial (Gain) Loss in Current Period due to Plan Experience and Assumption Changes | | $ | (35) | | | $ | 568 | | | $ | (49) | | | $ | (138) | | |
| Net Actuarial (Gain) Loss due to Settlements/Curtailments | | (39) | | | — | | | — | | | — | | |
| Amortization of Net Actuarial Gain (Loss) | | (83) | | | (60) | | | 2 | | | (14) | | |
| Recognition of Net Actuarial (Gain) Loss due to Settlements/Curtailments | | (338) | | | — | | | — | | | — | | |
| Prior Service Cost (Credit) in Current Period | | — | | | — | | | 6 | | | — | | |
| Amortization of Prior Service Credit | | — | | | — | | | 52 | | | 129 | | |
| Total | | $ | (495) | | | $ | 508 | | | $ | 11 | | | $ | (23) | | |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | Pension | | OPEB | |
| | | 2017 | | 2016 | | 2017 | | 2016 | |
| | | Millions | |
| Net Actuarial (Gain) Loss in Current Period | | $ | 55 |
| | $ | 211 |
| | $ | 156 |
| | $ | 125 |
| |
| Amortization of Net Actuarial Gain (Loss) | | (97 | ) | | (158 | ) | | (50 | ) | | (40 | ) | |
| Prior Service Cost (Credit) in current period | | — |
| | 1 |
| | — |
| | (3 | ) | |
| Amortization of Prior Service Credit | | 18 |
| | 19 |
| | 11 |
| | 14 |
| |
| Total | | $ | (24 | ) | | $ | 73 |
| | $ | 117 |
| | $ | 96 |
| |
| | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Amounts that are expected to be amortized from Accumulated Other Comprehensive Loss, Regulatory Assets and Deferred Assets into Net Periodic Benefit Cost in 2018 are as follows:
|
| | | | | | | | | | |
| | | | | | |
| | | Pension Benefits | | Other Benefits | |
| | | 2018 | | 2018 | |
| | | Millions | |
| Actuarial Loss | | $ | 85 |
| | $ | 64 |
| |
| Prior Service Credit | | $ | (18 | ) | | $ | (1 | ) | |
| | | | | | |
The following assumptions were used to determine the benefit obligations and net periodic benefit costs: |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | Pension Benefits | | Other Benefits | |
| | | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | |
| Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 | | | |
| Discount Rate | | 3.73 | % | | 4.29 | % | | 4.54 | % | | 3.76 | % | | 4.37 | % | | 4.58 | % | |
| Rate of Compensation Increase | | 3.90 | % | | 3.61 | % | | 3.61 | % | | 3.90 | % | | 3.61 | % | | 3.61 | % | |
| Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 | | | |
| Discount Rate | | 4.29 | % | | 4.54 | % | | 4.20 | % | | 4.37 | % | | 4.58 | % | | 4.21 | % | |
| Service Cost Interest Rate | | 4.53 | % | | 4.81 | % | | 4.20 | % | | 4.64 | % | | 4.87 | % | | 4.21 | % | |
| Interest Cost Interest Rate | | 3.63 | % | | 3.75 | % | | 4.20 | % | | 3.69 | % | | 3.76 | % | | 4.21 | % | |
| Expected Return on Plan Assets | | 7.80 | % | | 8.00 | % | | 8.00 | % | | 7.80 | % | | 8.00 | % | | 8.00 | % | |
| Rate of Compensation Increase | | 3.61 | % | | 3.61 | % | | 3.61 | % | | 3.61 | % | | 3.61 | % | | 3.61 | % | |
| Assumed Health Care Cost Trend Rates as of December 31 | | | | | | | | | |
| Health Care Costs | | | | | | | | | | | | | |
| Immediate Rate | | | | | | | | 7.93 | % | | 7.55 | % | | 7.75 | % | |
| Ultimate Rate | | | | | | | | 4.75 | % | | 4.75 | % | | 4.75 | % | |
| Year Ultimate Rate Reached | | | | | | | | 2026 |
| | 2025 |
| | 2025 |
| |
| | | | | | | | | Millions | |
| Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs | | | |
| Total of Service Cost and Interest Cost | | | | | | | | $ | 13 |
| | $ | 11 |
| | $ | 12 |
| |
| Postretirement Benefit Obligation | | | | | | | | $ | 240 |
| | $ | 191 |
| | $ | 194 |
| |
| Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs | | | |
| Total of Service Cost and Interest Cost | | | | | | | | $ | (10 | ) | | $ | (9 | ) | | $ | (10 | ) | |
| Postretirement Benefit Obligation | | | | | | | | $ | (198 | ) | | $ | (160 | ) | | $ | (160 | ) | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | Pension Benefits | | Other Benefits | |
| | | 2023 | | 2022 | | 2021 | | 2023 | | 2022 | | 2021 | |
| | | | | | | | | | | | | | |
| Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 | | | |
| Discount Rate | | 5.02 | % | | 5.20 | % | | 2.94 | % | | 4.96 | % | | 5.16 | % | | 2.82 | % | |
| Rate of Compensation Increase | | 4.60 | % | | 4.40 | % | | 4.40 | % | | 4.60 | % | | 4.40 | % | | 4.40 | % | |
| Cash Balance Interest Crediting Rate | | 6.00 | % | | 6.00 | % | | 6.00 | % | | N/A | | N/A | | N/A | |
| Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 | | | |
| Discount Rate | | 5.20 | % | | 2.94 | % | | 2.61 | % | | 5.16 | % | | 2.82 | % | | 2.46 | % | |
| Service Cost Interest Rate | | 5.31 | % | | 3.19 | % | | 2.94 | % | | 5.23 | % | | 3.06 | % | | 2.76 | % | |
| Interest Cost Interest Rate | | 5.09 | % | | 2.37 | % | | 1.91 | % | | 5.07 | % | | 2.21 | % | | 1.70 | % | |
| Expected Return on Plan Assets | | 8.10 | % | | 7.20 | % | | 7.70 | % | | 8.10 | % | | 7.20 | % | | 7.69 | % | |
| Rate of Compensation Increase | | 4.40 | % | | 4.40 | % | | 4.40 | % | | 4.40 | % | | 4.40 | % | | 4.40 | % | |
| Cash Balance Interest Crediting Rate | | 6.00 | % | | 6.00 | % | | 6.00 | % | | N/A | | N/A | | N/A | |
| Assumed Health Care Cost Trend Rates as of December 31 | | | | | | | | | |
| | | | | | | | | | | | | | |
| Health Care Costs | | | | | | | | | | | | | |
| Immediate Rate | | | | | | | | 8.89 | % | | 6.98 | % | | 6.14 | % | |
| Ultimate Rate | | | | | | | | 4.75 | % | | 4.75 | % | | 4.75 | % | |
| Year Ultimate Rate Reached | | | | | | | | 2033 | | 2032 | | 2029 | |
| | | | | | | | | | | | | | |
Plan Assets
The investments of pension and OPEB plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Master Trust. The investments in the pension and OPEB plans are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 17. Fair Value Measurements for more information on fair value guidance. Use of the Master Trust permits the commingling of pension plan assets and OPEB plan assets for investment and administrative purposes. Although assets of the plans are commingled in the Master Trust, the Trustee maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Trustee to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans. As of December 31, 2017,2023, the pension plan interest and OPEB plan interest in such assets of the Master Trust were approximately 92%90% and 8%10%, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following tables present information about the investments measured at fair value on a recurring basis as of December 31, 20172023 and 2016,2022, including the fair value measurements and the levels of inputs used in determining those fair values.
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | Recurring Fair Value Measurements as of December 31, 2017 | |
| | | | | Quoted Market Prices for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | |
| Description | | Total | | (Level 1) | | (Level 2) | | (Level 3) | |
| | | Millions | |
| Cash Equivalents (A) | | $ | 133 |
| | $ | 117 |
| | $ | 16 |
| | $ | — |
| |
| Equity Securities | |
|
| | | | | | | |
| Common Stock (B) | | 1,275 |
| | 1,275 |
| | — |
| | — |
| |
| Commingled (C) | | 1,401 |
| | 1,218 |
| | 183 |
| | — |
| |
| Preferred Stock (B) | | 6 |
| | 6 |
| | — |
| | — |
| |
| Debt Securities (D) | |
|
| | | | | | | |
| U.S. Treasury | | 571 |
| | — |
| | 571 |
| | — |
| |
| Government—Other | | 272 |
| | — |
| | 272 |
| | — |
| |
| Corporate | | 963 |
| | — |
| | 963 |
| | — |
| |
| Subtotal Fair Value | | $ | 4,621 |
| | $ | 2,616 |
| | $ | 2,005 |
| | $ | — |
| |
| Measured at net asset value practical expedient | | | | | | | | | |
| Commingled—Equities (E) | | 1,675 |
| | | | | | | |
| Private Equity (F) | | 14 |
| | | | | | | |
| Total Fair Value (G) | | $ | 6,310 |
| |
|
| |
|
| |
|
| |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | Recurring Fair Value Measurements as of December 31, 2016 | |
| | | | | Quoted Market Prices for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | |
| Description | | Total | | (Level 1) | | (Level 2) | | (Level 3) | |
| | | Millions | |
| Cash Equivalents (A) | | $ | 107 |
| | $ | 105 |
| | $ | 2 |
| | $ | — |
| |
| Equity Securities | |
|
| | | | | | | |
| Common Stock (B) | | 944 |
| | 944 |
| | — |
| | — |
| |
| Commingled (C) | | 1,387 |
| | 1,247 |
| | 140 |
| | — |
| |
| Preferred Stock (B) | | 1 |
| | 1 |
| | — |
| | — |
| |
| Debt Securities (D) | |
|
| | | | | | | |
| U.S. Treasury | | 441 |
| | — |
| | 441 |
| | — |
| |
| Government—Other | | 263 |
| | — |
| | 263 |
| | — |
| |
| Corporate | | 836 |
| | — |
| | 836 |
| | — |
| |
| Subtotal Fair Value | | $ | 3,979 |
| | $ | 2,297 |
| | $ | 1,682 |
| | $ | — |
| |
| Measured at net asset value practical expedient | | | | | | | | | |
| Commingled—Equities (E) | | 1,604 |
| | | | | | | |
| Private Equity (F) | | 16 |
| | | | | | | |
| Total Fair Value (G) | | $ | 5,599 |
| |
|
| |
|
| |
|
| |
| | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | Recurring Fair Value Measurements as of December 31, 2023 | |
| | | | | Quoted Market Prices for Identical Assets | | Significant Other Observable Inputs | | | |
| Description | | Total | | (Level 1) | | (Level 2) | | | |
| | | Millions | |
| Cash Equivalents (A) | | $ | 39 | | | $ | 39 | | | $ | — | | | | |
| Equity Securities | | | | | | | | | |
| Common Stock (B) | | 748 | | | 748 | | | — | | | | |
| Commingled (C) | | 1,376 | | | — | | | 1,376 | | | | |
| Debt Securities (D) | | | | | | | | | |
| U.S. Treasury | | 1,299 | | | — | | | 1,299 | | | | |
| Commingled | | 4 | | | 4 | | | — | | | | |
| Subtotal Fair Value | | $ | 3,466 | | | $ | 791 | | | $ | 2,675 | | | | |
| Measured at net asset value practical expedient | | | | | | | | | |
| Commingled—Equities (E) | | 745 | | | | | | | | |
| Real Estate Investment (F) | | 365 | | | | | | | | |
| Other | | 2 | | | | | | | | |
| Total Fair Value (G) | | $ | 4,578 | | | | | | | | |
| | | | | | | | | | |
| |
(A) | The Collective Investment Fund publishes a daily net asset value (NAV) which participants may use for daily redemptions without restrictions (Level 1). Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2). |
| |
(B) | Common stocks and preferred stocks are measured using observable data in active markets and considered Level 1. |
| |
(C) | Commingled Funds that allow daily redemption at their daily published NAV without restrictions are classified as Level 1. Commingled Funds that publish daily NAV but with certain near term redemption restrictions which prevent redemption at the published daily NAV are classified as Level 2. |
| |
(D) | Debt securities include mainly investment grade corporate and municipal bonds, US Treasury obligations and Federal Agency asset-backed securities with a wide range of maturities. These investments are valued using an evaluated pricing approach that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads or the most recent quoted for similar securities which are a Level 2 measure. |
| |
(E) | In 2016, as part of the implementation of the accounting guidance on investments measured at fair value using NAV as a practical expedient, certain commingled equity funds have been removed from the fair value hierarchy as they are measured at fair value using the NAV per share (or its equivalent) practical expedient. These funds do not meet the definition of readily determinable fair value due to limitations in published NAV (last business day of the month) and include certain redemption restrictions ranging from five to fifteen days advance notice prior to redemption days and limitations on withdrawals over 25% of the total fund. The objectives of these funds are mainly tracking the S&P Index or achieving long-term growth through investment in foreign equity securities and the MSCI Emerging Markets Index. |
| |
(F) | Private equity investments primarily include various limited partnerships that invest in either operating companies through acquisitions or developing a portfolio of non-US distressed investments to maximize total return on capital. These investments are valued at NAV (or its equivalent) on an annual basis and have significant redemption restrictions preventing redemption until fund liquidation and limited ability to sell these investments. Fund liquidation is not expected to occur for several more years. These investments have been removed from the fair value hierarchy in accordance with the guidance on NAV practical expedient. |
| |
(G) | Excludes net receivable of $13 million and $14 million at December 31, 2017 and 2016, respectively, which consists of interest, dividends and receivables and payables related to pending securities sales and purchases. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Recurring Fair Value Measurements as of December 31, 2022 | | | | | | | Quoted Market Prices for Identical Assets | | Significant Other Observable Inputs | | | | | Description | | Total | | (Level 1) | | (Level 2) | | | | | | | Millions | | | Cash Equivalents (A) | | $ | 36 | | | $ | 36 | | | $ | — | | | | | | Equity Securities | | | | | | | | | | | Common Stock (B) | | 1,231 | | | 1,231 | | | — | | | | | | Commingled (C) | | 1,346 | | | — | | | 1,346 | | | | | | Debt Securities (D) | | | | | | | | | | | U.S. Treasury | | 1,351 | | | — | | | 1,351 | | | | | | Commingled | | 4 | | | 4 | | | — | | | | | | Subtotal Fair Value | | $ | 3,968 | | | $ | 1,271 | | | $ | 2,697 | | | | | | Measured at net asset value practical expedient | | | | | | | | | | | Commingled—Equities (E) | | 965 | | | | | | | | | | Real Estate Investment (F) | | 395 | | | | | | | | | | Other | | 3 | | | | | | | | | | Total Fair Value (G) | | $ | 5,331 | | | | | | | | | | | | | | | | | | | |
(A)The Collective Investment Fund publishes a daily net asset value (NAV) which participants may use for daily redemptions without restrictions (Level 1). (B)Common stocks are measured using observable data in active markets and considered Level 1. (C)Commingled Funds that publish daily NAV but with certain near-term redemption restrictions which prevent redemption at the published daily NAV are classified as Level 2. (D)Debt securities include mainly U.S. Treasury obligations. These investments are valued using an evaluated pricing approach that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads or the most recent quotes for similar securities which are a Level 2 measure. (E)Certain commingled equity funds are not included in the fair value hierarchy as they are measured at fair value using the NAV per share (or its equivalent) practical expedient. These funds do not meet the definition of readily
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS determinable fair value due to the frequency of publishing NAV (monthly). The objectives of these funds are mainly tracking the S&P Index or achieving long-term growth through investment in foreign equity securities and the Morgan Stanley Capital International Index. (F)The unlisted real estate fund invests in office, apartment, industrial and retail space. The fund is valued using the NAV per unit of funds. The investment value of the real estate properties is determined on a quarterly basis by independent market appraisers engaged by the board of directors of the fund. The ability to redeem funds is subject to the availability of cash arising from net investment income, allocations and the sale of investments in the normal course of business. The fund’s NAV is published quarterly. In addition, redemptions require one quarter advance notice prior to redemption and are fulfilled quarterly. The fund, therefore, does not meet the definition of readily determinable fair value. The purpose of the fund is to acquire, own, hold for investment and ultimately dispose of investments in real estate and real estate-related assets with the intention of achieving current income, capital appreciation or both. (G)Excludes net receivables of $2 million and $7 million as of December 31, 2023 and 2022, respectively, which consist of interest, dividends and receivables and payables related to pending securities sales and purchases. In addition, the table excludes cash and foreign currency of $2 million as of December 31, 2022. |
The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans as of the measurement date, December 31:
|
| | | | | | | | |
| | | | | | |
| | | As of December 31, | |
| Investments | | 2017 | | 2016 | |
| Equity Securities | | 69 | % | | 70 | % | |
| Debt Securities | | 29 |
| | 28 |
| |
| Other Investments | | 2 |
| | 2 |
| |
| Total Percentage | | 100 | % | | 100 | % | |
| | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | As of December 31, | |
| Investments | | 2023 | | 2022 | |
| Equity Securities | | 63 | % | | 67 | % | |
| Debt Securities | | 28 | | | 25 | | |
| Other Investments | | 9 | | | 8 | | |
| Total Percentage | | 100 | % | | 100 | % | |
| | | | | | |
PSEG utilizes forecasted returns, risk, and correlation of all asset classes in order to develop a portfolio designed to produce the maximum return opportunity per unit of risk.an efficient portfolio. PSEG’s latest asset/liability study indicates that a long-term target asset allocation of 70%54% equities, 18% real assets and 30%28% fixed income is consistent with the funds’ financial objectives. Certain investments in real assets (13% as of December 31, 2023) are made through investing in equity securities and tracked as equities when reporting fair value; however, they are viewed by their asset class, real assets, in our target asset allocation. Derivative financial instruments are used by the plans’ investment managers primarily to adjust the fixed income duration of the portfolio and hedge the currency risk component of foreign investments. The expected long-term rate of return on plan assets was 7.8%8.1% for 20172023 and will be 7.8%remain at 8.1% for 2018.2024. This expected return was determined based on the study discussed above, includingincludes a premium for active management and considered the plans’ historical annualized rate of return since inception.management.
Plan Contributions
PSEG has no planned contributionsplans to contribute $5 million to its OPEB plan and does not plan to contribute to its pension plans in 2018. PSEG2024. Internal Revenue Service (IRS) minimum funding requirements for pension plans to make discretionary contributionsare determined based on the fund’s assets and liabilities at the end of $14 million into its OPEB plan during 2018.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
a calendar year for the subsequent calendar year.
Estimated Future Benefit Payments
The following pension benefit and postretirement benefit payments are expected to be paid to plan participants.
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| Year | | | Pension Benefits | | Other Benefits | |
| | | | Millions | |
| 2024 | | | $ | 364 | | | $ | 74 | | |
| 2025 | | | 325 | | | 73 | | |
| 2026 | | | 331 | | | 71 | | |
| 2027 | | | 338 | | | 69 | | |
| 2028 | | | 343 | | | 67 | | |
| 2029-2033 | | | 1,758 | | | 288 | | |
| Total | | | $ | 3,459 | | | $ | 642 | | |
| | | | | | | |
|
| | | | | | | | | | | |
| | | | | | | |
| Year | | | Pension Benefits | | Other Benefits | |
| | | | Millions | |
| 2018 | | | $ | 337 |
| | $ | 88 |
| |
| 2019 | | | 331 |
| | 92 |
| |
| 2020 | | | 341 |
| | 96 |
| |
| 2021 | | | 352 |
| | 101 |
| |
| 2022 | | | 364 |
| | 105 |
| |
| 2023-2027 | | | 1,954 |
| | 560 |
| |
| Total | | | $ | 3,679 |
| | $ | 1,042 |
| |
| | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
401(k) Plans
PSEG sponsors two 401(k) plans, which are defined contribution retirement plans subject to the Employee Retirement Income Security Act (ERISA) defined contribution retirement plans.. Eligible represented employees of PSEG’s subsidiaries participate in the PSEG Employee Savings Plan (Savings Plan), while eligible non-represented employees of PSEG’s subsidiaries participate in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). Eligible employees may contribute up to 50% of their annual eligible compensation to these plans, not to exceed the IRS maximums, including any catch-up contributions for those employees age 50 and above. PSEG matches 50% of such employee contributions up to 7% of pay for Savings Plan participants and up to 8% of pay for Thrift Plan participants.
The amountamounts paid for employer matching contributions to the plans for PSEG and PSE&G and Power are detailed as follows:
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | Thrift Plan and Savings Plan | |
| | | Years Ended December 31, | |
| | | 2017 | | 2016 | | 2015 | |
| | | Millions | |
| PSE&G | | $ | 25 |
| | $ | 24 |
| | $ | 22 |
| |
| Power | | 11 |
| | 12 |
| | 12 |
| |
| Other | | 5 |
| | 5 |
| | 5 |
| |
| Total Employer Matching Contributions | | $ | 41 |
| | $ | 41 |
| | $ | 39 |
| |
| | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | Thrift Plan and Savings Plan | |
| | | Years Ended December 31, | |
| | | 2023 | | 2022 | | 2021 | |
| | | Millions | |
| PSE&G | | $ | 29 | | | $ | 28 | | | $ | 28 | | |
| PSEG Power & Other | | 14 | | | 14 | | | 16 | | |
| Total Employer Matching Contributions | | $ | 43 | | | $ | 42 | | | $ | 44 | | |
| | | | | | | | |
Servco Pension and OPEB
At the direction of LIPA, effective January 1, 2014, Servco established benefit plans that provide substantially the same benefits tosponsors a qualified pension plan and OPEB plan covering its employees as those previously provided by National Grid Electric Services LLC (NGES), the predecessor T&D system manager for LIPA. Since the vast majority of Servco’s employees had worked under NGES’ T&D operations services arrangement with LIPA, Servco’s plans providewho meet certain of those employees with pension and OPEB vested credit for prior years’ services earned while working for NGES. The benefit plans cover all employees of Servco for current service.eligibility criteria. Under the OSA, all of these and any future employee benefit costs for these plans are to be funded by LIPA. See Note 4. Variable Interest Entity. These obligations, as well as the offsetting long-term receivable, are separately presented on the Consolidated Balance Sheet of PSEG.
The following table provides a roll-forward of the changes in Servco’s benefit obligation and the fair value of its plan assets during the years ended December 31, 20172023 and 2016.2022. It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | Pension Benefits | | Other Benefits | |
| | | 2023 | | 2022 | | 2023 | | 2022 | |
| | | Millions | |
| Change in Benefit Obligation | | | | | | | | | |
| Benefit Obligation at Beginning of Year (A) | | $ | 452 | | | $ | 596 | | | $ | 455 | | | $ | 640 | | |
| Service Cost | | 24 | | | 38 | | | 12 | | | 21 | | |
| Interest Cost | | 23 | | | 17 | | | 24 | | | 19 | | |
| Actuarial (Gain) Loss (B) | | 31 | | | (189) | | | 35 | | | (215) | | |
| Plan Amendment | | 16 | | | — | | | — | | | — | | |
| Gross Benefits Paid | | (11) | | | (10) | | | (12) | | | (10) | | |
| Benefit Obligation at End of Year (A) | | $ | 535 | | | $ | 452 | | | $ | 514 | | | $ | 455 | | |
| Change in Plan Assets | | | | | | | | | |
| Fair Value of Assets at Beginning of Year | | $ | 370 | | | $ | 422 | | | $ | — | | | $ | — | | |
| Actual Return on Plan Assets | | 56 | | | (72) | | | — | | | — | | |
| Employer Contributions | | 18 | | | 30 | | | 12 | | | 10 | | |
| Gross Benefits Paid | | (11) | | | (10) | | | (12) | | | (10) | | |
| Fair Value of Assets at End of Year | | $ | 433 | | | $ | 370 | | | $ | — | | | $ | — | | |
| Funded Status | | | | | | | | | |
| Funded Status (Plan Assets less Benefit Obligation) | | $ | (102) | | | $ | (82) | | | $ | (514) | | | $ | (455) | | |
| Additional Amounts Recognized in the Consolidated Balance Sheets | | | | | | | | | |
| Accrued Pension Costs of Servco | | $ | (102) | | | $ | (82) | | | N/A | | N/A | |
| OPEB Costs of Servco | | N/A | | N/A | | (514) | | | (455) | | |
| Amounts Recognized (C) | | $ | (102) | | | $ | (82) | | | $ | (514) | | | $ | (455) | | |
| | | | | | | | | | |
(A)Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation or retirement.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | Pension Benefits | | Other Benefits | |
| | | 2017 | | 2016 | | 2017 | | 2016 | |
| | | | | Millions | |
| Change in Benefit Obligation | | | | | | | | | |
| Benefit Obligation at Beginning of Year | | $ | 262 |
| | $ | 211 |
| | $ | 452 |
| | $ | 375 |
| |
| Service Cost | | 27 |
| | 24 |
| | 15 |
| | 12 |
| |
| Interest Cost | | 11 |
| | 9 |
| | 19 |
| | 17 |
| |
| Actuarial (Gain) Loss | | 22 |
| | 14 |
| | 60 |
| | 50 |
| |
| Gross Benefits Paid | | (2 | ) | | (1 | ) | | (4 | ) | | (2 | ) | |
| Plan Amendments | | — |
| | 5 |
| | — |
| | — |
| |
| Benefit Obligation at End of Year (A) | | $ | 320 |
| | $ | 262 |
| | $ | 542 |
| | $ | 452 |
| |
| Change in Plan Assets | | | | | | | | | |
| Fair Value of Assets at Beginning of Year | | $ | 134 |
| | $ | 97 |
| | $ | — |
| | $ | — |
| |
| Actual Return on Plan Assets | | 24 |
| | 10 |
| | — |
| | — |
| |
| Employer Contributions | | 35 |
| | 28 |
| | 4 |
| | 2 |
| |
| Gross Benefits Paid | | (2 | ) | | (1 | ) | | (4 | ) | | (2 | ) | |
| Fair Value of Assets at End of Year | | $ | 191 |
| | $ | 134 |
| | $ | — |
| | $ | — |
| |
| Funded Status | | | | | | | | | |
| Funded Status (Plan Assets less Benefit Obligation) | | $ | (129 | ) | | $ | (128 | ) | | $ | (542 | ) | | $ | (452 | ) | |
| Additional Amounts Recognized in the Consolidated Balance Sheets | | | | | | | | | |
| Accrued Pension Costs of Servco | | $ | (129 | ) | | $ | (128 | ) | | N/A |
| | N/A |
| |
| OPEB Costs of Servco | | N/A |
| | N/A |
| | (542 | ) | | (452 | ) | |
| Amounts Recognized (B) | | $ | (129 | ) | | $ | (128 | ) | | $ | (542 | ) | | $ | (452 | ) | |
| | | | | | | | | | |
(B)For pension and OPEB benefits, the net actuarial losses in 2023 were due primarily to a decrease in the discount rate and other assumption updates. For pension benefits and OPEB, the net actuarial gains in 2022 were due primarily to an increase in the discount rate. | |
(A) | Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation of retirement. |
| |
(B) | Amounts equal to the accrued pension and OPEB costs of Servco are offset in Long-Term Receivable of VIE on PSEG’s Consolidated Balance Sheets. |
(C)Amounts equal to the accrued pension and OPEB costs of Servco are offset in Long-Term Receivable of VIE on PSEG’s Consolidated Balance Sheets.
Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. The pension-related revenues and costs for 2017, 20162023, 2022 and 20152021 were $35$18 million, $28$30 million and $30$37 million, respectively. Servco has contributed its entire planned contribution amount to its pension plan trusts during 2017.2023. The OPEB-related revenues earned and costs incurred were $4$12 million, $10 million and $2$11 million in 20172023, 2022 and 2016, respectively, and immaterial for 2015.2021, respectively.
The following assumptions were used to determine the benefit obligations of Servco: |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | Pension Benefits | | Other Benefits | |
| | | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | |
| Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 | | | |
| Discount Rate | | 3.90 | % | | 4.61 | % | | 4.92 | % | | 3.96 | % | | 4.71 | % | | 4.97 | % | |
| Rate of Compensation Increase | | 3.25 | % | | 3.25 | % | | 3.25 | % | | 3.25 | % | | 3.25 | % | | 3.25 | % | |
| Assumed Health Care Cost Trend Rates as of December 31 | | | | | | | | | |
| Health Care Costs | | | | | | | | | | | | | |
| Immediate Rate | | | | | | | | 7.69 | % | | 7.55 | % | | 7.55 | % | |
| Ultimate Rate | | | | | | | | 4.75 | % | | 4.75 | % | | 4.75 | % | |
| Year Ultimate Rate Reached | | | | | | | | 2026 |
| | 2025 |
| | 2025 |
| |
| | | | | | | | | Millions | |
| Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs | | | |
| Postretirement Benefit Obligation | | | | | | | | $ | 131 |
| | $ | 97 |
| | $ | 75 |
| |
| Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs | | | |
| Postretirement Benefit Obligation | | | | | | | | $ | (99 | ) | | $ | (75 | ) | | $ | (60 | ) | |
| | | | | | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | Pension Benefits | | Other Benefits | |
| | | 2023 | | 2022 | | 2021 | | 2023 | | 2022 | | 2021 | |
| Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 | | | |
| Discount Rate | | 5.13 | % | | 5.30 | % | | 3.21 | % | | 5.16 | % | | 5.34 | % | | 3.28 | % | |
| Rate of Compensation Increase | | 5.54 | % | | 3.95 | % | | 3.95 | % | | 5.54 | % | | 3.95 | % | | 3.95 | % | |
| Cash Balance Interest Crediting Rate | | 4.13 | % | | 4.30 | % | | 3.75 | % | | N/A | | N/A | | N/A | |
| Assumed Health Care Cost Trend Rates as of December 31 | | | | | | | | | |
| Health Care Costs | | | | | | | | | | | | | |
| Immediate Rate | | | | | | | | 6.84 | % | | 6.71 | % | | 6.48 | % | |
| Ultimate Rate | | | | | | | | 4.75 | % | | 4.75 | % | | 4.75 | % | |
| Year Ultimate Rate Reached | | | | | | | | 2033 | | 2032 | | 2029 | |
| | | | | | | | | | | | | | |
Plan Assets
All the investments of Servco’s pension plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Servco Master Trust. The investments in the pension are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 17. Fair Value Measurements for more information on fair value guidance. The Actuary maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Actuary to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans.
The following tables present information about Servco’s investments measured at fair value on a recurring basis as of December 31, 20172023 and 2016,2022, including the fair value measurements and the levels of inputs used in determining those fair values.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | Recurring Fair Value Measurements as of December 31, 2023 | | | |
| | | | | Quoted Market Prices for Identical Assets | | Significant Other Observable Inputs | | | |
| Description | | Total | | (Level 1) | | (Level 2) | | | |
| | | Millions | |
| Cash Equivalents | | $ | 2 | | | $ | 2 | | | $ | — | | | | |
| Equity Securities | | | | | | | | | |
| Common Stock (A) | | 32 | | | 32 | | | — | | | | |
| Commingled (B) | | 294 | | | — | | | 294 | | | | |
| Commingled Bonds (B) | | 105 | | | — | | | 105 | | | | |
| Total Fair Value | | $ | 433 | | | $ | 34 | | | $ | 399 | | | | |
| | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | Recurring Fair Value Measurements as of December 31, 2017 | |
| | | | | Quoted Market Prices for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | |
| Description | | Total | | (Level 1) | | (Level 2) | | (Level 3) | |
| | | Millions | |
| Commingled Equities (A) | | $ | 137 |
| | $ | — |
| | $ | 137 |
| | $ | — |
| |
| Commingled Bonds (A) | | 54 |
| | — |
| | 54 |
| | — |
| |
| Total | | $ | 191 |
| | $ | — |
| | $ | 191 |
| | $ | — |
| |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | Recurring Fair Value Measurements as of December 31, 2022 | | | |
| | | | | Quoted Market Prices for Identical Assets | | Significant Other Observable Inputs | | | |
| Description | | Total | | (Level 1) | | (Level 2) | | | |
| | | Millions | |
| Cash Equivalents | | $ | 1 | | | $ | 1 | | | $ | — | | | | |
| Equity Securities | | | | | | | | | |
| Common Stock (A) | | 25 | | | 25 | | | — | | | | |
| Commingled (B)
| | 251 | | | — | | | 251 | | | | |
| Commingled Bonds (B)
| | 93 | | | — | | | 93 | | | | |
| Total Fair Value | | $ | 370 | | | $ | 26 | | | $ | 344 | | | | |
| | | | | | | | | | |
(A)Common stocks are measured using observable data in active markets and considered Level 1. |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | Recurring Fair Value Measurements as of December 31, 2016 | |
| | | | | Quoted Market Prices for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | |
| Description | | Total | | (Level 1) | | (Level 2) | | (Level 3) | |
| | | Millions | |
| Commingled Equities (A)
| | $ | 96 |
| | $ | — |
| | $ | 96 |
| | $ | — |
| |
| Commingled Bonds (A)
| | 38 |
| | — |
| | 38 |
| | — |
| |
| Total | | $ | 134 |
| | $ | — |
| | $ | 134 |
| | $ | — |
| |
| | | | | | | | | | |
(B)Investments in commingled equity and bond funds have a readily determinable fair value as they publish a daily NAV available to investors which is the basis for current transactions and contain certain redemption restrictions requiring advance notice of one to two days for withdrawals (Level 2). | |
(A) | Investments in commingled equity and bond funds have a readily determinable fair value as they publish a daily NAV available to investors which is the basis for current transactions and contain certain redemption restrictions requiring advance notice of one to two days for withdrawals (Level 2). |
The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans of Servco as of the measurement date, December 31:
|
| | | | | | | | |
| | | | | | |
| | | As of December 31, | |
| Investments | | 2017 | | 2016 | |
| Equity Securities | | 72 | % | | 71 | % | |
| Debt Securities | | 28 |
| | 29 |
| |
| Total Percentage | | 100 | % | | 100 | % | |
| | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | As of December 31, | |
| Investments | | 2023 | | 2022 | |
| Equity Securities | | 76 | % | | 75 | % | |
| Debt Securities | | 24 | | | 25 | | |
| Total Percentage | | 100 | % | | 100 | % | |
| | | | | | |
Servco utilizes forecasted returns, risk, and correlation of all asset classes in order to develop a portfolio designed to produce the maximum return opportunity per unit of risk. The results froman efficient portfolio. Servco’s latest asset/liability study indicated that a long-term target asset allocation of 70%60% equities, 15% real assets and 30%25% fixed income is consistent with the funds’ financial objectives. Certain investments in real assets (15% at December 31, 2023) are made through investing in equity securities and tracked as equities when reporting fair value; however, they are viewed by their asset class, real assets, in our target asset allocation. The expected long-term rate of return on plan assets was 7.6%8.0% for 20172023 and will be 7.6%8.0% for 2018.2024. This expected return was determined based on the study discussed above, includingincludes a premium for active management.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Plan Contributions
Servco plans to contribute $40$25 million into its pension plan during 2018.2024.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Estimated Future Benefit Payments
The following pension benefit and postretirement benefit payments are expected to be paid to Servco’s plan participants:
|
| | | | | | | | | | | |
| | | | | | | |
| Year | | | Pension Benefits | | Other Benefits | |
| | | | Millions | |
| 2018 | | | $ | 3 |
| | $ | 4 |
| |
| 2019 | | | 4 |
| | 6 |
| |
| 2020 | | | 5 |
| | 8 |
| |
| 2021 | | | 7 |
| | 9 |
| |
| 2022 | | | 9 |
| | 12 |
| |
| 2023-2027 | | | 78 |
| | 87 |
| |
| Total | | | $ | 106 |
| | $ | 126 |
| |
| | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| Year | | | Pension Benefits | | Other Benefits | |
| | | | Millions | |
| 2024 | | | $ | 15 | | | $ | 12 | | |
| 2025 | | | 17 | | | 14 | | |
| 2026 | | | 20 | | | 16 | | |
| 2027 | | | 23 | | | 18 | | |
| 2028 | | | 25 | | | 20 | | |
| 2029-2033 | | | 167 | | | 125 | | |
| Total | | | $ | 267 | | | $ | 205 | | |
| | | | | | | |
Servco 401(k) Plans
Servco sponsors two 401(k) plans, which are defined contribution retirement plans subject to ERISA. Eligible non-represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan I (Thrift Plan I), and eligible represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan II (Thrift Plan II). Participants in the Plansplans may contribute up to 50% of their eligible compensation to these plans, not to exceed the IRS maximums, including any Catch-Up Contributionscatch-up contributions for those employees age 50 and above. Servco does not provide an employer match or core contribution for employees in Thrift Plan II. For employees in Thrift Plan I, Servco matches 50% of such employee contributions up to 8% of eligible compensation and provides core contributions (based on years of service and age) to employees who do not participate in Servco’s Retirement Income Plan. The amountsamount expensed by Servco for employer matching contributions was $10 million for the year ended December 31, 2023, and $9 million for each of the years ended December 31, 2017, 20162022 and 2015 were $6 million, $5 million and $4 million, respectively, and pursuant2021. Pursuant to the OSA, Servco recognizes Operating Revenues for the reimbursement of these costs.
Note 13. Commitments and Contingent Liabilities
Guaranteed Obligations
PSEG Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees as a form of collateral.
PSEG Power has unconditionally guaranteed payments to counterparties byon behalf of its subsidiaries in commodity-related transactions in order to
•support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and
•obtain credit.
PSEG Power is subject to
•counterparty collateral calls related to commodity contracts of its subsidiaries, and
•certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries.
Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction.
In order for PSEG Power to incur a liability for the face value of the outstanding guarantees,
•its subsidiaries would have to
fully utilize the credit granted to them by every counterparty to whom PSEG Power has provided a guarantee, and
•the net position of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, PSEG Power would owe money to the counterparties).
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSEG Power believes the probability of this result is unlikely. For this reason, PSEG Power believes that the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. Current exposure
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.
Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. PSEG Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules.
In addition to the guarantees discussed above, PSEG Power has also provided payment guarantees to third parties and regulatory authorities on behalf of its affiliated companies. These guarantees support various other non-commodity related contractual obligations.
The following table shows the face value of PSEG Power’s outstanding guarantees, current exposure and margin positions as of December 31, 20172023 and 2016.2022. |
| | | | | | | | | | |
| | | | | | |
| | | As of December 31, 2017 | | As of December 31, 2016 | |
| | | Millions | |
| Face Value of Outstanding Guarantees | | $ | 1,701 |
| | $ | 1,806 |
| |
| Exposure under Current Guarantees | | $ | 153 |
| | $ | 139 |
| |
| | | | | | |
| Letters of Credit Margin Posted | | $ | 103 |
| | $ | 157 |
| |
| Letters of Credit Margin Received | | $ | 32 |
| | $ | 99 |
| |
| | | | | | |
| Cash Deposited and Received | | | | | |
| Counterparty Cash Margin Deposited | | $ | — |
| | $ | — |
| |
| Counterparty Cash Margin Received | | $ | (1 | ) | | $ | (1 | ) | |
| Net Broker Balance Deposited (Received) | | $ | 147 |
| | $ | 57 |
| |
| | | | | | |
| Additional Amounts Posted | | | | | |
| Other Letters of Credit | | $ | 61 |
| | $ | 51 |
| |
| | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | As of December 31, | |
| | | 2023 | | 2022 | |
| | | Millions | |
| Face Value of Outstanding Guarantees | | $ | 1,381 | | | $ | 1,601 | | |
| Exposure under Current Guarantees | | $ | 118 | | | $ | 198 | | |
| | | | | | |
| Letters of Credit Margin Posted | | $ | 10 | | | $ | 87 | | |
| Letters of Credit Margin Received | | $ | 91 | | | $ | 38 | | |
| | | | | | |
| Cash Deposited and Received | | | | | |
| Counterparty Cash Collateral Deposited | | $ | — | | | $ | — | | |
| Counterparty Cash Collateral Received | | $ | (2) | | | $ | (1) | | |
| Net Broker Balance Deposited (Received) | | $ | 115 | | | $ | 1,522 | | |
| | | | | | |
| Additional Amounts Posted | | | | | |
| Other Letters of Credit | | $ | 180 | | | $ | 156 | | |
| | | | | | |
As part of determining credit exposure, PSEG Power nets receivables and payables with the corresponding net fair values of energy contract balances.contracts. See Note 16. Financial Risk Management Activities for further discussion. In accordance with PSEG’s accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Consolidated Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively.
In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and PSEG Power hadhave posted letters of credit to support PSEG Power’s various other non-energy contractual and environmental obligations. See the preceding table. In June 2017, Power sold its minority interest in PennEast and upon disposition, PSEG’s $106 million guarantee that had supported Power’s payment obligations related to PennEast was terminated.
Environmental Matters
Passaic River
Historic operations of PSEG companies and the operations of hundreds of other companies along theLower 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 as discussed as follows.
Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA)River Study Area
The U.S. Environmental Protection Agency (EPA) has determined that a 17-mile stretch of the lower Passaic River from Newark to Clifton,(Lower Passaic River Study Area (LPRSA)) in New Jersey is a “Superfund” site under CERCLAthe Federal Comprehensive Environmental Response, Compensation and a comprehensive studyLiability Act of the entire 17 miles of the lower Passaic River needed to be performed.1980 (CERCLA). PSE&G and certain of its predecessors conducted operations at properties in this area, of the Passaic River. The properties includedincluding at one operating electric generating station (Essex Site), whichsite that was transferred to Power, one former generating stationPSEG Power.
The EPA has announced two separate cleanup plans for the Lower 8.3 miles and four former manufactured gas plant (MGP) sites.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In early 2007, certain Potentially Responsible Parties (PRPs), including PSE&G and Power, formed a Cooperating Parties Group (CPG) and agreed to assume responsibility for conducting a Remedial Investigation and Feasibility Study (RI/FS) of the 17Upper 9 miles of the lower Passaic River.LPRSA. The CPG has agreed to allocate, on an interim basis, the associated costs of the RI/FS among its members on the basis of a mutually agreed upon formula. For the purpose of this interim allocation, which has been revised as parties have exited the CPG, approximately 7.6 percent of the RI/FS costs are currently deemed attributable to PSE&G’s former MGP sites and approximately 1.9 percent is attributable to Power’s generating stations. These interim allocations are not binding on PSE&G or Power in terms of their respective shares of the costs that will be ultimately required to remediate the 17 miles of the lower Passaic River. PSEG has provided notice to insurers concerning this potential claim. Certain PRPs are currently involved in discussions with the EPA regarding cost allocations and related indemnification matters. We cannot predict the outcome of these discussions, or whether individual PRPs will be able to meet their obligations, either of which could have a material impact on PSE&G’s and Power’s allocation of costs.
The CPG’s draft FS set forth various alternatives for remediating the lower Passaic River with an estimated cost to remediate the lower 17 miles of the Passaic River ranging from approximately $518 million to $3.2 billion on an undiscounted basis.
In March 2016, the EPA released its Record of Decision (ROD)EPA’s plan for the EPA’s own Focused Feasibility Study (FFS) which requires the removal of 3.5 million cubic yards of sediment from the Passaic River’s lowerLower 8.3 miles involves dredging and capping sediments at an estimated cost of $2.3 billion, and its plan for the Upper 9 miles involves dredging and capping sediments at an estimated cost of $550 million. Additional cleanup work may be required depending on the results of these initial phases of work.
Occidental Chemical Corporation (Occidental) has voluntarily commenced design of the cleanup plan for the Lower 8.3 miles, and has received an undiscounted basis (ROD Remedy). The EPA estimates the total project length to be about 11 years, including a one year period of negotiation with the PRPs, three to four yearsUnilateral Administrative Order directing it to design the projectcleanup plan for the Upper 9 miles. It has filed two lawsuits against PSE&G and six years for implementation. Occidental Chemical Corporation, oneothers to attempt to recover costs associated with this work and to obtain a declaratory judgement of parties’ shares of any future costs. PSEG cannot predict the outcome of the PRPs,litigation.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The EPA has committedannounced a proposed settlement with 82 parties who have agreed to performpay $150 million to resolve their LPRSA CERCLA liability, in whole or in part. It is uncertain whether the remedial design required bysettlement will be finalized as currently proposed. PSE&G and PSEG Power are not included in the ROD Remedy, reserving its right of cost contribution from all other PRPs.
In September 2017,proposed settlement, but the EPA concluded thatsent PSE&G, Occidental, and several other Potentially Responsible Parties (PRPs) a letter in March 2022 inviting them to submit to the EPA individually or jointly an Agency-commenced allocation process foroffer to fund or participate in the Passaic River’s lower 8.3 miles should include only certain PRPs. The allocation is intended to lead to a consent decree in which certainnext stages of the PRPs agreeremediation. PSEG submitted a good faith offer to perform the remedial action under EPA oversight. Discussions on the matter are ongoing. Conversations between the EPA and the PRPs regarding remediation of the Passaic River’s upper 9 miles are ongoing.
Based upon (i) the estimated cost of the ROD Remedy, (ii) PSEG’s estimatein June 2022 on behalf of PSE&G’s&G and Power’s sharesPSEG Power. PSEG understands that the EPA is evaluating its offer.
As of that cost,December 31, 2023, PSEG has approximately $66 million accrued for this matter. PSE&G has an Environmental Costs Liability of $53 million and (iii) thea corresponding Regulatory Asset based on its continued ability of PSE&G to recover such costs in its rates, as of December 31, 2017,rates. PSEG Power has accrued approximately $57 million. Of this amount $46 million has been accrued by PSE&G as an Environmental Costs Liability and a corresponding Regulatory Asset and $11 million has been accrued by Power as an Other Noncurrent Liability with the corresponding O&M Expense recorded in the periods when the liability was accrued.of $13 million.
The EPA has broad authority to implement its selectedoutcome of this matter is uncertain, and until (i) a final remedy through the ROD and PSEG cannot at this time predict how the implementation of the ROD might impact PSE&G’s and Power’s ultimate liability. Until (i) the RI/FS, which coversfor the entire 17 miles of the lower Passaic River,LPRSA is finalized either in whole or in part, (ii)selected and an agreement is reached by the PRPs to perform either the ROD Remedy as issued, or an amended ROD Remedy determined through negotiation or litigation, and an agreed upon remedy for the remaining 8.7 miles of the river, are reached, (iii)fund it, (ii) PSE&G’s and PSEG Power’s respective shares of the costs both in the aggregate as well as individually, are determined, and (iv)(iii) PSE&G’s continued ability to recover the costs in its rates is determined, it is not possible to predict this matter’s ultimate impact on PSEG’s financial statements. It is possible that PSE&G and PSEG Power will record additional costs beyond what they have accrued, and that such costs could be material, but PSEG cannot at the current time estimate the amount or range of any additional costs.
Natural Resource Damage Claims
In 2003, the New Jersey Department of Environmental Protection (NJDEP) directed PSEG, PSE&G and 56 other PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the New Jersey Spill Compensation and Control Act. The NJDEP alleged that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million. In 2007, agencies of the U.S. Department of Commerce and the U.S. Department of the Interior (the Passaic River federal trustees) sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In 2008, PSEG and a number of other PRPs agreed to share certain immaterial costs the trustees have incurred and will incur going forward, and to work with the trustees to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That effort is continuing. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter.
Newark Bay Study Area
The EPA has established the Newark Bay Study Area, which it defines asis an extension of the LPRSA and includes Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, thesurrounding waterways. The EPA senthas notified PSEG and 1121 other entities notices that it considered eachPRPs of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two operating electric generating
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but PSEG has not consented to fund the third phase.their potential liability. PSE&G and PSEG Power are unable to estimate their respective portions of any loss or possible range of loss related to this matter. In December 2018, PSEG Power completed the sale of the site of the Hudson electric generating station. PSEG Power contractually transferred all land rights and structures on the Hudson site to a third-party purchaser, along with the assumption of the environmental liabilities for the site.
Natural Resource Damage Claims
New Jersey and certain federal regulators have alleged that PSE&G, PSEG Power and 56 other PRPs may be liable for natural resource damages within the LPRSA. In particular, PSE&G, PSEG Power and other PRPs received notice from federal regulators of the regulators’ intent to move forward with a series of studies assessing potential damages to natural resources at the Diamond Alkali Superfund Site, which includes the LPRSA and the Newark Bay Study Area. PSE&G and PSEG Power are unable to estimate their respective portions of any possible loss or range of loss related to this matter.
Hackensack River
In 2022, the EPA announced it had designated approximately 23 river miles of the Lower Hackensack River as a federal Superfund site. PSE&G and certain of its predecessors conducted operations at properties in this area, including at the Hudson, Bergen and Kearny generating stations that were transferred to PSEG Power. PSEG Power subsequently contractually transferred all land rights and structures on the Hudson generating station site to a third-party purchaser, along with the assumption of the environmental liabilities for that site. In 2024, the EPA identified PSE&G and four other parties as PRPs for the site and requested that they voluntarily perform a technical study of a portion of the river designated as “Operable Unit 2.” The EPA estimates that the technical study will cost $55 million to complete. The EPA may take enforcement action against parties that do not cooperate. PSE&G and PSEG Power do not believe participation in the technical study will have a material impact on their results of operations and financial condition based upon EPA’s estimate of the study costs, however, future costs related to this matter could be material.
MGP Remediation Program
PSE&G is working with the NJDEPNew Jersey Department of Environmental Protection (NJDEP) to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined that the estimated cost to remediate all MGP sites to completion could range between $358$199 million and $403$219 million on an undiscounted basis, through 2021, including its $46$53 million share for the Passaic River as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $358$199 million as ofDecember 31, 2017.2023. Of this amount, $79$52 million was recorded in Other Current Liabilities and $279$147 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $358$199 millionRegulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. NJDEP, PSEG and EPA representatives have had discussions regarding to what extentPSE&G completed sampling in the Passaic River is requiredin 2020 to delineate coal tar from certain MGP sites that abut the Passaic River Superfund site. PSEG cannot determine at this time whether this will have anthe magnitude of any impact on the Passaic River Superfund remedy.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Legacy Environmental Obligations at Former Fossil Generating Sites
PSEG Power has retained ownership of certain liabilities excluded from the 2022 sale of its fossil generation portfolio. These liabilities primarily relate to obligations under the New Jersey ISRA and the CTA to investigate and remediate PSEG Power’s two formerly owned generating station sites in Connecticut, and six formerly owned generating station sites in New Jersey. In addition, PSEG Power still owns two former generating station sites in New Jersey that triggered ISRA in 2015.
PSEG Power is in the process of fulfilling its obligations under ISRA and the CTA to investigate these sites. It will require multiple years and comprehensive environmental sampling to understand the extent of and to carry out the required remediation. At this stage in the remediation process, the full remediation costs are not estimable, but given the number and operating history of the facilities in the portfolio, the full remediation costs will likely be material in the aggregate. The costs could potentially include costs for, among other things, excavating soil, implementation of institutional controls, and the construction, operation and maintenance of engineering controls.
Clean Water Act (CWA) Permit RenewalsSection 316(b) Rule
Pursuant to the Federal Water Pollution Control Act (FWPCA), National Pollutant Discharge Elimination System permits expire within five years of their effective date. In order to renew these permits, but allow a plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit. States with delegated federal authority for this program manage these permits. The NJDEP manages the permits under the New Jersey Pollutant Discharge Elimination System (NJPDES) program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs.
In May 2014, the EPA issued a final cooling water intakeEPA’s CWA Section 316(b) rule that establishes requirements for the regulationdesign and operation of cooling water intakesintake structures at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day.
The EPA has structured the rule so that each state Permitting Director will continue to consider renewal permits for existing
power facilities on a case by case basis, based on studies related to impingement mortality and entrainment and submit the results with their permit applications to be conducted by the facilities seeking renewal permits.
Several environmental organizations and certain energy industry groups have filed suit under the Clean Water Act and the Endangered Species Act. The cases have been consolidated at the Second Circuit and a decision remains pending.
In June 2016, the NJDEP issued a final NJPDESNew Jersey Pollutant Discharge Elimination System permit for Salem. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the CWA, it requires additional studies and the selection of technology to address impingement for the service water system. The final permit does not mandate specific service water system modifications but, it requires additional studies and the selection of technology to address impingement for the service water system. In July 2016, the Delaware Riverkeeper Network (Riverkeeper) filed aan administrative hearing request challenging certain conditions of the permit, including the NJDEP’s issuanceapplication of the final NJPDES renewal permit for Salem. NJDEP has granted the hearing request, but it has not yet been scheduled. The Riverkeeper’s filing does not change the effective date of the permit.316(b) rule. If the Riverkeeper’s challenge wereis successful, PSEG Power may be required to incur additional costs to comply with the CWA. Potential cooling water and/or service water system modification costs could be material and could adversely impact the economic competitiveness of this facility.
State permitting decisions at Bridgeport The NJDEP granted the hearing request and possibly New Haven could also havemay schedule a material impact on Power’s ability to renew permits at its existing larger once-through cooled plants without making significant upgrades to existing intakes and cooling systems.
Power is unable to predict the outcome of these permitting decisions and the effect, if any, that they may have on Power’s future capital requirements, financial condition or results of operations.
Power is actively engaged with the Connecticut Department of Energy and Environmental Protection (CTDEEP) regarding renewal of the current permit for the cooling water intake structure at Bridgeport Harbor Station Unit 3 (BH3). To address compliance with the EPA’s CWA Section 316(b) final rule, Power has proposed to continue to operate BH3 without making the capital expenditures for modification to the existing intake structure and retire BH3 in 2021, which is four years earlier than the previously estimated useful life ending in 2025. Power is currently awaiting action by the CTDEEP to issue a draft and then a final permit.
Power has negotiated a Community Environmental Benefit Agreement (CEBA) with the City of Bridgeport, Connecticut and local community organizations. That CEBA provides that Power would retire BH3 early if all of its conditions precedent occur, which include receipt of all final permits to build and operate a proposed new combined cycle generating facility on the same
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
site that BH3 currently operates. Absent those conditions being met, and the permit for the cooling water intake structure referred to above not being issued, Power may seek to operate BH3 through the previously estimated useful life.
In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. The Connecticut Siting Council (CSC) issued an order to approve siting Bridgeport Harbor Station unit 5 (BH5). All major environmental permits have been received; however, secondary approvals are still being obtained to allow operations to begin in mid-2019. Power’s obligations under the CEBA are being monitored regularly and carried out as needed.
Bridgeport Harbor National Pollutant Discharge Elimination System (NPDES) Permit Compliance
In April 2015, Power determined that monitoring and reporting practices related to certain permitted wastewater discharges at its Bridgeport Harbor station may have violated conditions of the station’s NPDES permit and applicable regulations and could subject it to fines and penalties. Power has notified the CTDEEP of the issues and has taken actions to investigate and resolve the potential non-compliance. Power cannot predict the impact of this matter.hearing after considering dispositive motions.
Jersey City, New Jersey Subsurface Feeder Cable Matter
In early October 2016, a discharge of dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City, New Jersey, was identified and reported to the NJDEP. The feeder cables are located within a subsurface easement granted to PSE&G by the property owners, Newport Associates Development Company (NADC) and Newport Associates Phase I Developer Limited Partnership. The feeder cables are subject to agreements between PSE&G and Consolidated Edison Company of New York, Inc. (Con Edison) and are jointly owned by PSE&G and Con Edison, with PSE&G owning the portion of the cables located in New Jersey and Con Edison owning the portion of the cables located in New York. The NJDEP has declared an emergency and an emergency response action has been undertaken to investigate, contain, remediate and stop the fluid discharge; to assess, repair and restore the cables to good working order, if feasible; and to restore the property. The regulatory agencies overseeing the emergency response, including the U.S. Coast Guard, the NJDEP and the Army Corps of Engineers, have issued multiple notices, orders and directives to the various parties related to this matter.Edison. The impacted cable was repaired in late-September 2017; however,September 2017. A federal response was initially led by the U.S. Coast Guard. The U.S. Coast Guard transitioned control of the federal response to the EPA, and the EPA ended the federal response to the matter in 2018. The investigation of small amounts of residual dielectric fluid continuesbelieved to appear onbe contained with the surface and so the investigation and response actions related to the fluid discharge are ongoing. PSE&G may determine that retirementmarina sediment is ongoing as part of the affected facilities would be appropriate. Also ongoing isNJDEP site remediation program. In August 2020, PSE&G finalized a settlement with the processfederal government regarding the reimbursement of costs associated with the federal response to this matter and payment of civil penalties of an immaterial amount.
The lawsuit in federal court to determine ultimate responsibility for the costs to address the leak among PSE&G, Con Edison and NADC including an action filed by PSE&G in New Jersey federal court seeking damages from NADC. In that action, NADC has also pursued counterclaims against PSE&Gbeen resolved and Con Edison seeking damages for its costs to address the leak. In addition, NADC provided notice to the New Jersey Secretary of Transportation of several alleged violations by Con Edisonis now dismissed.
BGS, BGSS and PSE&G of regulations prescribed under the Hazardous Liquids Pipeline Safety Act (HLPSA), a requirement to preserve NADC’s right to pursue injunctive relief under the HLPSA. Based on the information currently available and depending on the outcome of the New Jersey federal action, PSE&G’s portion of the costs to address the leak may be material; however, PSE&G anticipates that it will recover these costs through regulatory proceedings. ZECs
Steam Electric Effluent Guidelines
In September 2015, the EPA issued a new Effluent Limitation Guidelines Rule (ELG Rule) for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater. Power’s Bridgeport Harbor station and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges that are regulated under the ELG Rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the ELG Rule.
Through various orders, the EPA has stayed the compliance dates in the ELG Rule and has announced plans to further revise the requirements and compliance dates of the ELG Rule. Power is unable to determine how this will ultimately impact its compliance requirements or its financial condition and results of operations.
Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS)
Each year, PSE&G obtains its electric supply requirements through the annual New Jersey BGS auctions for two categories of customers whothat choose not to purchase electric supply from third-party suppliers. The first category which represents about 80% of PSE&G’s load requirement, is residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category is larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial Energy Pricing (CIEP)). Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master AgreementAgreements with the winners of these RSCP and CIEP BGS auctions following the BPU’s approval of the auction results. PSE&G has entered into contracts with winning BGS suppliers, including Power, to purchase BGS for PSE&G’s load requirements. The winners of the auction (including Power)RSCP and CIEP auctions are responsible for fulfilling all the requirements of a PJM Load Serving Entityload-serving entity including the provision of capacity, energy, ancillary services transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards.
The BGS-CIEP auction is for a one-year supply period from June 1 to May 31 with the BGS-CIEP auction price measured in dollars per MW-day for capacity. The final price for the BGS-CIEP auction year commencing June 1, 20182024 is $287.76$378.21 per MW-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
day,MW-day, replacing the BGS-CIEP auction year price ending May 31, 20182024 of $276.83$330.72 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period.
PSE&G contracts for its anticipated BGS-RSCP load on a three-year rolling basis, whereby each year one-third of the load is procured for a three-year period. The contract prices in dollars per MWh for the BGS-RSCP supply, as well as the approximate load, are as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | |
| | | | | | | | | | |
| | Auction Year | | |
| | 2015 | | 2016 | | 2017 | | 2018 | | |
| 36-Month Terms Ending | May 2018 |
| | May 2019 |
| | May 2020 |
| | May 2021 |
| (A) | |
| Load (MW) | 2,900 |
| | 2,800 |
| | 2,800 |
| | 2,900 |
| | |
| $ per MWh | $99.54 | | $96.38 | | $90.78 | | $91.77 | | |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | Auction Year | | |
| | 2021 | | 2022 | | 2023 | | 2024 | | |
| 36-Month Terms Ending | May 2024 | | May 2025 | | May 2026 | | May 2027 | (A) | |
| Load (MW) | 2,900 | | | 2,800 | | | 2,800 | | | 2,900 | | | |
| $ per MWh | $64.80 | | $76.30 | | $93.11 | | $80.88 | | |
| | | | | | | | | | |
| |
(A) | (A)Prices set in the 2018 BGS auction will become effective on June 1, 2018 when the 2015 BGS auction agreements expire. |
Power seeks to mitigate volatility in its results by contracting in advance for the sale of most of its anticipated electric output as well as its anticipated fuel needs. As part of its objective, Power has entered into contracts to directly supply PSE&G and other New Jersey electric distribution companies (EDCs) with a portion of their respective BGS requirements through the New Jersey2024 BGS auction process, described above.will become effective on June 1, 2024 when the 2021 BGS auction agreements expire.
PSE&G has a full-requirements contract with PSEG Power to meet the gas supply requirements of PSE&G’s gas customers. PSEG Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. Current plans call for PSEG Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements. For additional information, see Note 24. Related-Party Transactions.
Pursuant to a process established by the BPU, New Jersey EDCs, including PSE&G, are required to purchase ZECs from eligible nuclear plants selected by the BPU. In April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were selected to receive ZEC revenue for approximately three years, through May 2022. In April 2021, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded ZECs for the three-year eligibility period starting June 2022. PSE&G has implemented a tariff to collect a non-bypassable distribution charge in the amount of $0.004 per KWh from its retail distribution customers to be used to purchase the ZECs from these plants. PSE&G will purchase the ZECs on a monthly basis with payment to be made annually following completion of each energy year. The legislation also requires nuclear plants to reapply for any subsequent three-year periods and allows the BPU to adjust prospective ZEC payments.
Minimum Fuel Purchase Requirements
PSEG Power’s nuclear fuel strategy is to maintain certain levels of uranium and to make periodic purchases to support such levels. As such, the commitments referred to in the following table may include estimated quantities to be purchased that deviate from contractual nominal quantities. PSEG Power’s minimum nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 20202026 and a significant portion through 20222027 at Salem, Hope Creek and Peach Bottom.
PSEG Power has various multi-year contracts for natural gas and firm transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess delivery capacity available beyond the needs of PSE&G’s customers, Power can use the gas to supply its fossil generating stations.
Power also has various long-term fuel purchase commitments for coal through 2021 to support its fossil generation stations.
As of December 31, 2017,2023, the total minimum purchase requirements included in these commitments were as follows:
| | | | | | | | | | | | | | |
| | | | |
| Fuel Type | | PSEG Power’s Share of Commitments through 2028 | |
| | | Millions | |
| Nuclear Fuel | | | |
| Uranium | | $ | 392 | | |
| Enrichment | | $ | 344 | | |
| Fabrication | | $ | 185 | | |
| Natural Gas | | $ | 1,329 | | |
| | | | |
|
| | | | | | |
| | | | |
| Fuel Type | | Power's Share of Commitments through 2022 | |
| | | Millions | |
| Nuclear Fuel | | | |
| Uranium | | $ | 240 |
| |
| Enrichment | | $ | 391 |
| |
| Fabrication | | $ | 170 |
| |
| Natural Gas | | $ | 1,042 |
| |
| Coal | | $ | 293 |
| |
| | | | |
Pending FERC Matters
FERC has been conducting a non-public investigation of the Roseland-Pleasant Valley transmission project. In November 2021, FERC staff presented PSE&G with its non-public preliminary findings, alleging that PSE&G violated a FERC regulation. PSE&G disagrees with FERC staff’s allegations and believes it has factual and legal defenses that refute these allegations. PSE&G has the opportunity to respond to these preliminary findings. The matter is pending and the investigation is ongoing. PSE&G is unable to predict the outcome or estimate the range of possible loss related to this matter; however, depending on the success of PSE&G’s factual and legal arguments, the potential financial and other penalties that PSE&G may incur could be material to PSEG’s and PSE&G’s results of operations and financial condition.
BPU Audit of PSE&G
In 2020, the BPU ordered the commencement of a comprehensive affiliate and management audit of PSE&G. It has been more than ten years since the BPU last conducted a management and affiliate audit of this kind of PSE&G, which is initiated
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
periodically as required by New Jersey statutes/regulations. Phase 1 of the audit reviews affiliate relations and cost allocation between PSE&G and its affiliates, including an analysis of the relationship between PSE&G and PSEG Energy Resources & Trade, LLC, a wholly owned subsidiary of PSEG Power over the past ten years, and between PSE&G and PSEG LI. Phase 2 is a comprehensive management audit, which addresses, among other things, executive management, corporate governance, system operations, human resources, cyber security, compliance with customer protection requirements and customer safety. The audit officially began in late May 2021. The BPU Audit Staff submitted the final audit report to the BPU in June 2023. The BPU is currently considering public comments on the audit report and has not yet determined which audit recommendations it will require PSE&G to implement. It is not possible at this time to predict the outcome of this matter.
Regulatory ProceedingsLitigation
FERC Compliance
PJM Bidding MatterSewaren 7 Construction
In the first quarter of 2014, Power discovered that it incorrectly calculated certain components of its cost-based bids for itsJune 2018, a complaint was filed in federal court in Newark, New Jersey fossil generating units in the PJM energy market. Upon discovery of the errors,against PSEG retained outside counsel to assist in the conduct of an investigation into the matter and self-reported the errors. As the internal investigation proceeded, additional pricing errors in the bids were identified. It was further determined that the quantity of energy that Power offered into the energy market for its fossil peaking units differed from the amount forFossil LLC, which Power was compensated in the capacity market for those units. PSEG informed FERC, PJM and the PJM Independent Market Monitor (IMM) of these additional issues, corrected the identified errors, and modified the bid quantities for Power’s peaking units. Power has implemented procedures and continues to review its policies and practices to mitigate the risk of similar issues occurring in the future. During the three month period ended March 31, 2014, based upon its best estimate available at the time was a wholly owned subsidiary of PSEG Power, recordedregarding an ongoing dispute with Durr Mechanical Construction, Inc. (Durr), a pre-tax chargecontractor on the Sewaren 7 project. Among other things, Durr seeks damages of $93 million and alleges that PSEG Power withheld money owed to incomeDurr and that PSEG Power’s intentional conduct led to the inability of Durr to obtain prospective contracts. PSEG Power intends to vigorously defend against these allegations. In January 2021, the court partially granted PSEG Power’s motion to dismiss certain claims, reducing the amount claimed to $68 million. In December 2018, Durr filed for Chapter 11 bankruptcy in the amount of $25 million related to this matter.
Since September 2014, FERC Staff has been conducting a preliminary, non-public staff investigation into these matters. While considerable uncertainty remains as to the final resolution of these matters, based upon developmentsfederal court in the investigation inSouthern District of New York (SDNY). The SDNY bankruptcy court has allowed the first quarter of 2017, Power believes the disgorgement and interest costs relatedNew Jersey litigation to the cost-based bidding matter may range between approximately $35 million and $135 million, depending on the legal interpretation of the principles under the PJM Tariff, plus penalties. Since no point within this range is more likely than any other,proceed. PSEG Power has accrued the low endan amount related to outstanding invoices which does not reflect an assessment of claims and potential counterclaims in this range of $35 million by recording an additional pre-tax chargematter. Due to income of $10 million during the three months ended March 31, 2017. Power is unable to reasonably estimate the range of possible loss, if any, for the quantity of energy offered matter or the penalties that FERC would impose relating to either the cost-based bidding or quantity of energy matter. However, any of these amounts could be individually material toits preliminary nature, PSEG and Power.
Power continues to believe that it has legal defenses that it may assert in a judicial challenge, including the legal defense that its cost-based bidding in a substantial majority of the hours was below the allowed rate under the Tariff and therefore any errors in those hours did not violate the Tariff or were immaterial. Furthermore, it is unclear whether the quantity of energy offered violated any legal requirement. As a result, PSEG and Power cannot predict the final outcome of these matters.this matter.
Other Litigation and Legal Proceedings
PSEG and its subsidiaries are party to various lawsuits in the ordinary course of business. In view of the inherent difficulty in predicting the outcome of such matters, PSEG and PSE&G and Power generally cannot predict the eventual outcome of the pending matters, the timing of the ultimate resolution of these matters, or the eventual loss, fines or penalties related to each pending matter.
In accordance with applicable accounting guidance, a liability is accrued when those matters present loss contingencies that are both probable and reasonably estimable. In such cases, there may be an exposure to loss in excess of any amounts accrued. PSEG will continue to monitor the matter for further developments that could affect the amount of the accrued liability that has been previously established.
Based on current knowledge, management does not believe that loss contingencies arising from pending matters, other than the matters described herein, could have a material adverse effect on PSEG’s or PSE&G’s or Power’s consolidated financial position or liquidity. However, in light of the inherent uncertainties involved in these matters, some of which are beyond PSEG’s control, and the large or indeterminate damages sought in some of these matters, an adverse outcome in one or more of these matters could be material to PSEG’s or PSE&G’s or Power’s results of operations or liquidity for any particular reporting period.
Nuclear Insurance Coverages and Assessments
PSEG Power is a member of the joint underwriting association, American Nuclear Insurers (ANI), which provides nuclear liability insurance coverage at the Salem and Hope Creek site and the Peach Bottom site. The ANI policies are designed to satisfy the financial protection requirements outlined in the Price-Anderson Act, which sets the limit of liability for claims that could arise from an incident involving any licensed nuclear facility in the United States. The limit of liability per incident per site is composed of primary and excess layers. As of December 31, 2017,2023, nuclear sites were required to purchase $450 million of primary liability coverage for each site (through ANI).through ANI. This coverage increased to $500 million effective January 1, 2024. The primary layer is supplemented by an excess layer, which is an industry self-insurance pool. In the event a nuclear site, which is part of the industry self-insurance pool, has a claim that exceeds the primary layer, each licensee would be assessed a prorated share of the excess layer. The excess layer limit is $13.4$15.8 billion. PSEG Power’s maximum aggregate assessment per incident is $401$522 million (basedbased on PSEG Power’s ownership interests in Salem, Hope Creek and Peach Bottom)Bottom and its maximum aggregate annual assessment per incident is $60$78 million. If the damages exceed the limit of liability, Congress could impose further revenue-raising measures on the nuclear industry to pay claims. Further, a decision by the U.S. Supreme Court, not involving PSEG Power, held that the Price-Anderson Act did not preclude punitive damage awards based on state law claims.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSEG Power is also a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides the property, decontamination and decommissioning liability insurance at the Salem and Hope Creek site and the Peach Bottom site. NEIL also provides replacement power coverage through its accidental outage policy. NEIL policies may make retrospective premium assessments in the case of adverse loss experience. The current maximum aggregate annual retrospective premium obligation for PSEG Power is approximately $76$48 million. NEIL requires its members to maintain an
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance. Certain provisions in the NEIL policies provide that the insurer may suspend coverage with respect to all nuclear units on a site without notice if the NRC suspends or revokes the operating license for any unit on that site, issues a shutdown order with respect to such unit or issues a confirmatory order keeping such unit down.
The ANI and NEIL policies all include coverage for claims arising out of acts of terrorism. However, NEIL policies are subject to an industry aggregate limit of $3.2$3.24 billion plus such additional amounts as NEIL recovers for such losses from reinsurance, indemnity and any other source applicable to such losses.
Minimum Lease Payments
The total future minimum payments under various operating leases as of December 31, 2017 are:
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | PSE&G | | Power | | Services | | Other | | Total | |
| | | Millions | | | |
| 2018 | | $ | 16 |
| | $ | 5 |
| | $ | 14 |
| | $ | 1 |
| | $ | 36 |
| |
| 2019 | | 9 |
| | 6 |
| | 15 |
| | 1 |
| | 31 |
| |
| 2020 | | 8 |
| | 3 |
| | 15 |
| | 1 |
| | 27 |
| |
| 2021 | | 8 |
| | 3 |
| | 15 |
| | 1 |
| | 27 |
| |
| 2022 | | 7 |
| | 3 |
| | 15 |
| | 1 |
| | 26 |
| |
| Thereafter | | 65 |
| | 38 |
| | 120 |
| | 1 |
| | 224 |
| |
| Total Minimum Lease Payments | | $ | 113 |
| | $ | 58 |
| | $ | 194 |
| | $ | 6 |
| | $ | 371 |
| |
| | | | | | | | | | | | |
Note 14. Debt and Credit Facilities
Long-Term Debt
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | | | As of December 31, | |
| | | | Maturity | | 2023 | | 2022 | |
| | | | | | Millions | |
| PSEG | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Senior Notes: | | | | | | | |
| 0.84% | | 2023 | | $ | — | | | $ | 750 | | |
| 2.88% | | 2024 | | 750 | | | 750 | | |
| 0.80% | | 2025 | | 550 | | | 550 | | |
| 5.85% | | 2027 | | 700 | | | 700 | | |
| 5.88% | | 2028 | | 600 | | | — | | |
| 1.60% | | 2030 | | 550 | | | 550 | | |
| 8.63% | (A) | | 2031 | | 96 | | | 96 | | |
| 2.45% | | 2031 | | 750 | | | 750 | | |
| 6.13% | | 2033 | | 400 | | | — | | |
| Total Senior Notes | | | | 4,396 | | | 4,146 | | |
| Principal Amount Outstanding | | | | 4,396 | | | 4,146 | | |
| Amounts Due Within One Year | | | | (750) | | | (750) | | |
| Net Unamortized Discount and Debt Issuance Costs | | | | (25) | | | (22) | | |
| Total Long-Term Debt of PSEG | | | | $ | 3,621 | | | $ | 3,374 | | |
| | | | | | | | | |
|
| | | | | | | | | | | | |
| | | | | | | | |
| | | | | As of December 31, | |
| | | Maturity | | 2017 | | 2016 | |
| | | | | Millions | |
| PSEG | | | | | | | |
| Term Loan: | | | | | | | |
| Variable | | 2017 | | $ | — |
| | $ | 500 |
| |
| Variable | | 2019 | | 700 |
| | — |
| |
| Total Term Loan | | | | 700 |
| | 500 |
| |
| Senior Notes: | | | | | | | |
| 1.60% | | 2019 | | 400 |
| | 400 |
| |
| 2.00% | | 2021 | | 300 |
| | 300 |
| |
| 2.65% | | 2022 | | 700 |
| | — |
| |
| Total Senior Notes | | | | 1,400 |
| | 700 |
| |
| Principal Amount Outstanding | | | | 2,100 |
| | 1,200 |
| |
| Amounts Due Within One Year | | | | — |
| | (500 | ) | |
| Net Unamortized Discount and Debt Issuance Costs | | | | (9 | ) | | (5 | ) | |
| Total Long-Term Debt of PSEG | | | | $ | 2,091 |
| | $ | 695 |
| |
| | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | |
| | | | | | | | |
| | | | | As of December 31, | |
| | | Maturity | | 2017 | | 2016 | |
| | | | | Millions | |
| PSE&G | | | | | | | |
| First and Refunding Mortgage Bonds (A): | | | | | | | |
| 9.25% | | 2021 | | $ | 134 |
| | $ | 134 |
| |
| 8.00% | | 2037 | | 7 |
| | 7 |
| |
| 5.00% | | 2037 | | 8 |
| | 8 |
| |
| Total First and Refunding Mortgage Bonds | | | | 149 |
| | 149 |
| |
| Medium-Term Notes (MTNs) (A): | | | | | | | |
| 5.30% | | 2018 | | 400 |
| | 400 |
| |
| 2.30% | | 2018 | | 350 |
| | 350 |
| |
| 1.80% | | 2019 | | 250 |
| | 250 |
| |
| 2.00% | | 2019 | | 250 |
| | 250 |
| |
| 7.04% | | 2020 | | 9 |
| | 9 |
| |
| 3.50% | | 2020 | | 250 |
| | 250 |
| |
| 1.90% | | 2021 | | 300 |
| | 300 |
| |
| 2.38% | | 2023 | | 500 |
| | 500 |
| |
| 3.75% | | 2024 | | 250 |
| | 250 |
| |
| 3.15% | | 2024 | | 250 |
| | 250 |
| |
| 3.05% | | 2024 | | 250 |
| | 250 |
| |
| 3.00% | | 2025 | | 350 |
| | 350 |
| |
| 2.25% | | 2026 | | 425 |
| | 425 |
| |
| 3.00% | | 2027 | | 425 |
| | — |
| |
| 5.25% | | 2035 | | 250 |
| | 250 |
| |
| 5.70% | | 2036 | | 250 |
| | 250 |
| |
| 5.80% | | 2037 | | 350 |
| | 350 |
| |
| 5.38% | | 2039 | | 250 |
| | 250 |
| |
| 5.50% | | 2040 | | 300 |
| | 300 |
| |
| 3.95% | | 2042 | | 450 |
| | 450 |
| |
| 3.65% | | 2042 | | 350 |
| | 350 |
| |
| 3.80% | | 2043 | | 400 |
| | 400 |
| |
| 4.00% | | 2044 | | 250 |
| | 250 |
| |
| 4.05% | | 2045 | | 250 |
| | 250 |
| |
| 4.15% | | 2045 | | 250 |
| | 250 |
| |
| 3.80% | | 2046 | | 550 |
| | 550 |
| |
| 3.60% | | 2047 | | 350 |
| | — |
| |
| Total MTNs | | | | 8,509 |
| | 7,734 |
| |
| Principal Amount Outstanding | | | | 8,658 |
| | 7,883 |
| |
| Amounts Due Within One Year | | | | (750 | ) | | — |
| |
| Net Unamortized Discount and Debt Issuance Costs | | | | (67 | ) | | (65 | ) | |
| Total Long-Term Debt of PSE&G | | | | $ | 7,841 |
| | $ | 7,818 |
| |
| | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | | As of December 31, | |
| | | Maturity | | 2023 | | 2022 | |
| | | | | Millions | |
| PSE&G | | | | | | | |
| First and Refunding Mortgage Bonds (B): | | | | | | | |
| 8.00% | | 2037 | | $ | 7 | | | $ | 7 | | |
| 5.00% | | 2037 | | 8 | | | 8 | | |
| Total First and Refunding Mortgage Bonds | | | | 15 | | | 15 | | |
| Medium-Term Notes (B): | | | | | | | |
| 2.38% | | 2023 | | — | | | 500 | | |
| 3.25% | | 2023 | | — | | | 325 | | |
| 3.75% | | 2024 | | 250 | | | 250 | | |
| 3.15% | | 2024 | | 250 | | | 250 | | |
| 3.05% | | 2024 | | 250 | | | 250 | | |
| 3.00% | | 2025 | | 350 | | | 350 | | |
| 0.95% | | 2026 | | 450 | | | 450 | | |
| 2.25% | | 2026 | | 425 | | | 425 | | |
| 3.00% | | 2027 | | 425 | | | 425 | | |
| 3.70% | | 2028 | | 375 | | | 375 | | |
| 3.65% | | 2028 | | 325 | | | 325 | | |
| 3.20% | | 2029 | | 375 | | | 375 | | |
| 2.45% | | 2030 | | 300 | | | 300 | | |
| 1.90% | | 2031 | | 425 | | | 425 | | |
| 3.10% | | 2032 | | 500 | | | 500 | | |
| 4.90% | | 2032 | | 400 | | | 400 | | |
| 4.65% | | 2033 | | 500 | | | — | | |
| 5.20% | | 2033 | | 500 | | | — | | |
| 5.25% | | 2035 | | 250 | | | 250 | | |
| 5.70% | | 2036 | | 250 | | | 250 | | |
| 5.80% | | 2037 | | 350 | | | 350 | | |
| 5.38% | | 2039 | | 250 | | | 250 | | |
| 5.50% | | 2040 | | 300 | | | 300 | | |
| 3.95% | | 2042 | | 450 | | | 450 | | |
| 3.65% | | 2042 | | 350 | | | 350 | | |
| 3.80% | | 2043 | | 400 | | | 400 | | |
| 4.00% | | 2044 | | 250 | | | 250 | | |
| 4.05% | | 2045 | | 250 | | | 250 | | |
| 4.15% | | 2045 | | 250 | | | 250 | | |
| 3.80% | | 2046 | | 550 | | | 550 | | |
| 3.60% | | 2047 | | 350 | | | 350 | | |
| 4.05% | | 2048 | | 325 | | | 325 | | |
| 3.85% | | 2049 | | 375 | | | 375 | | |
| 3.20% | | 2049 | | 400 | | | 400 | | |
| 3.15% | | 2050 | | 300 | | | 300 | | |
| 2.70% | | 2050 | | 375 | | | 375 | | |
| 2.05% | | 2050 | | 375 | | | 375 | | |
| 3.00% | | 2051 | | 450 | | | 450 | | |
| 5.13% | | 2053 | | 400 | | | — | | |
| 5.45% | | 2053 | | 400 | | | — | | |
| Total MTNs | | | | 13,750 | | | 12,775 | | |
| Principal Amount Outstanding | | | | 13,765 | | | 12,790 | | |
| Amounts Due Within One Year | | | | (750) | | | (825) | | |
| Net Unamortized Discount and Selling Expense | | | | (102) | | | (94) | | |
| Total Long-Term Debt of PSE&G | | | | $ | 12,913 | | | $ | 11,871 | | |
| | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | |
| | | | | | | | |
| | | | | As of December 31, | |
| | | Maturity | | 2017 | | 2016 | |
| | | | | Millions | |
| Power | | | | | | | |
| Senior Notes: | | | | | | | |
| 2.45% | | 2018 | | $ | 250 |
| | $ | 250 |
| |
| 5.13% | | 2020 | | 406 |
| | 406 |
| |
| 4.15% | | 2021 | | 250 |
| | 250 |
| |
| 3.00% | | 2021 | | 700 |
| | 700 |
| |
| 4.30% | | 2023 | | 250 |
| | 250 |
| |
| 8.63% | | 2031 | | 500 |
| | 500 |
| |
| Total Senior Notes | | | | 2,356 |
| | 2,356 |
| |
| Pollution Control Notes: | | | | | | | |
| Floating Rate (B) | | 2019 | | 44 |
| | 44 |
| |
| Total Pollution Control Notes | | | | 44 |
| | 44 |
| |
| Principal Amount Outstanding | | | | 2,400 |
| | 2,400 |
| |
| Amounts Due Within One Year | | | | (250 | ) | | — |
| |
| Net Unamortized Discount and Debt Issuance Costs | | | | (14 | ) | | (18 | ) | |
| Total Long-Term Debt of Power | | | | $ | 2,136 |
| | $ | 2,382 |
| |
| | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | | | As of December 31, | |
| | | | Maturity | | 2023 | | 2022 | |
| | | | | | Millions | |
| PSEG Power | | | | | | | |
| Term Loan: | | | | | | | |
| Variable Rate | | 2025 | | $ | 1,250 | | | $ | 1,250 | | |
| Total Term Loan | | | | 1,250 | | | 1,250 | | |
| | | | | | | | |
| Total Long-Term Debt of PSEG Power | | | | $ | 1,250 | | | $ | 1,250 | | |
| | | | | | | | | |
| |
(A) | Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage. |
| |
(B) | The Pennsylvania Economic Development Authority (PEDFA) bond that is serviced and secured by Power Pollution Control Notes, is a variable rate bond that is in weekly reset mode. |
(A)In December 2020, PSEG issued $96 million principal amount of 8.63% Senior Notes due 2031 to holders of a like principal amount of 8.63% Senior Notes due 2031 originally issued by PSEG Power who validly tendered their notes pursuant to an offer to exchange. Upon consummation of the offer to exchange, the PSEG Power notes accepted in the exchange were cancelled. The transaction resulted in a non-cash financing activity for both PSEG and PSEG Power.
(B)Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage.
Long-Term Debt Maturities
The aggregate principal amounts of maturities for each of the five years following December 31, 20172023 are as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| Year | | PSEG | | PSE&G | | Power | | Total | |
| | | | |
| 2018 | | $ | — |
| | $ | 750 |
| | $ | 250 |
| | $ | 1,000 |
| |
| 2019 | | 1,100 |
| | 500 |
| | 44 |
| | 1,644 |
| |
| 2020 | | — |
| | 259 |
| | 406 |
| | 665 |
| |
| 2021 | | 300 |
| | 434 |
| | 950 |
| | 1,684 |
| |
| 2022 | | 700 |
| | — |
| | — |
| | 700 |
| |
| Thereafter | | — |
| | 6,715 |
| | 750 |
| | 7,465 |
| |
| Total | | $ | 2,100 |
| | $ | 8,658 |
| | $ | 2,400 |
| | $ | 13,158 |
| |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| Year | | PSEG | | PSE&G | | PSEG Power | | Total | |
| | | Millions | |
| 2024 | | $ | 750 | | | $ | 750 | | | $ | — | | | $ | 1,500 | | |
| 2025 | | 550 | | | 350 | | | 1,250 | | | 2,150 | | |
| 2026 | | — | | | 875 | | | — | | | 875 | | |
| 2027 | | 700 | | | 425 | | | — | | | 1,125 | | |
| 2028 | | 600 | | | 700 | | | — | | | 1,300 | | |
| Thereafter | | 1,796 | | | 10,665 | | | — | | | 12,461 | | |
| Total | | $ | 4,396 | | | $ | 13,765 | | | $ | 1,250 | | | $ | 19,411 | | |
| | | | | | | | | | |
Long-Term Debt Financing Transactions
During 2017, PSEG and its subsidiaries had2023, the following Long-Term Debt issuances, maturities and redemptions:long-term debt transactions occurred:
PSEG
entered into an agreement for a new term loan maturing June 2019. The term loan has a balance of $700 million at an interest rate of 1 month LIBOR + 0.80% and can be terminated at any time without penalty,
•issued $700$600 million of 2.65%5.88% Senior Notes due November 2022,October 2028,
•issued $400 million of 6.13% Senior Notes due October 2033, and
redeemed•retired $750 million of 0.84% Senior Notes at maturity a $500 million term loan at an interest rate of 1 month LIBOR + 0.875% due November 2017.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
maturity.
PSE&G
•issued $425$500 million of 3.00%4.65% Secured Medium-Term Notes (Green Bond), Series P, due March 2033,
•issued $400 million of 5.13% Secured Medium-Term Notes (Green Bond), Series P, due March 2053,
•issued $500 million of 5.20% Secured Medium-Term Notes, Series LP, due May 2027, andAugust 2033,
•issued $350$400 million of 3.60%5.45% Secured Medium-Term Notes, Series LP, due December 2047.August 2053,
•retired $500 million of 2.38% Secured Medium-Term Notes, Series I, at maturity, and
•retired $325 million of 3.25% Secured Medium-Term Notes, Series M, at maturity.
Short-Term Liquidity
PSEG meets its short-term liquidity requirements, as well as those of PSEG Power, primarily with cash and through the issuance of commercial paper.paper and, from time to time, short-term loans. PSE&G maintains its own separate commercial paper program to
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facilities.facility.
The commitments under the $4.2$4.0 billion credit facilities are provided by a diverse bank group. As of December 31, 2017,2023, the total available credit capacity was $3.5$3.4 billion.
As of December 31, 2017,2023, no single institution represented more than 8%10% of the total commitments in the credit facilities.
As of December 31, 2017, the total2023, PSEG’s liquidity position, including credit capacityfacilities and access to external financing, was in excess of the anticipated maximum liquidityexpected to be sufficient to meet its projected stressed requirements over PSEG’sa 12-month planning horizon.
Each of the credit facilities is restricted as to availability and use to the specific companies as listed in the following table; however, if necessary, the PSEG facilities can also be used to support ourits subsidiaries’ liquidity needs.
The total credit facilities and available liquidity as of December 31, 20172023 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | As of December 31, 2023 | | | | |
| Company/Facility | | Total Facility | | Usage (B) | | Available Liquidity | | Expiration Date | | Primary Purpose | | |
| | | Millions | | | | | | |
| PSEG | | | | | | | | | | | | |
| Revolving Credit Facility (A) | | $ | 1,500 | | | $ | 27 | | | $ | 1,473 | | | Mar 2027 | | Commercial Paper Support/Funding/Letters of Credit | | |
| Total PSEG | | $ | 1,500 | | | $ | 27 | | | $ | 1,473 | | | | | | | |
| PSE&G | | | | | | | | | | | | |
| Revolving Credit Facility | | $ | 1,000 | | | $ | 445 | | | $ | 555 | | | Mar 2027 | | Commercial Paper Support/Funding/Letters of Credit | | |
| Total PSE&G | | $ | 1,000 | | | $ | 445 | | | $ | 555 | | | | | | | |
| PSEG Power | | | | | | | | | | | | |
| Revolving Credit Facility (A) | | $ | 1,250 | | | $ | 39 | | | $ | 1,211 | | | Mar 2027 | | Funding/Letters of Credit | | |
| Letter of Credit Facility | | 75 | | | 66 | | | 9 | | | Apr 2026 | | Letters of Credit | | |
| Letter of Credit Facility | | 200 | | | 83 | | | 117 | | | Sept 2024 | | Letters of Credit | | |
| Total PSEG Power | | $ | 1,525 | | | $ | 188 | | | $ | 1,337 | | | | | | | |
| Total (C) | | $ | 4,025 | | | $ | 660 | | | $ | 3,365 | | | | | | | |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | As of December 31, 2017 | | | |
| Company/Facility | | Total Facility | | Usage | | Available Liquidity | | Expiration Date | | Primary Purpose | |
| | | Millions | | | | | |
| PSEG | | | | | | | | | | | |
| 5-year Credit Facilities (A) | | $ | 1,500 |
| | $ | 556 |
| | $ | 944 |
| | Mar 2022 | | Commercial Paper Support/Funding/Letters of Credit (LC) | |
| Total PSEG | | $ | 1,500 |
| | $ | 556 |
| | $ | 944 |
| | | | | |
| PSE&G | | | | | | | | | | | |
| 5-year Credit Facility (A) | | $ | 600 |
| | $ | 15 |
| | $ | 585 |
| | Mar 2022 | | Commercial Paper Support/Funding/Letters of Credit | |
| Total PSE&G | | $ | 600 |
| | $ | 15 |
| | $ | 585 |
| | | | | |
| Power | | | | | | | | | | | |
| 3-year LC Facilities | | $ | 200 |
| | $ | 112 |
| | $ | 88 |
| | Mar 2020 | | Letters of Credit | |
| 5-year Credit Facilities | | 1,900 |
| | 39 |
| | 1,861 |
| | Mar 2022 | | Funding/Letters of Credit | |
| Total Power | | $ | 2,100 |
| | $ | 151 |
| | $ | 1,949 |
| | | | | |
| Total | | $ | 4,200 |
| | $ | 722 |
| | $ | 3,478 |
| | | | | |
| | | | | | | | | | | | |
| |
(A) | The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs under which as of December 31, 2017, PSEG had $542 million outstanding at a weighted average interest rate of 1.89%. PSE&G had no amounts outstanding under its Commercial Paper Program as of December 31, 2017. |
(A)Master Credit Facility with sub-limits of $1.5 billion for PSEG and $1.25 billion for PSEG Power; sub-limits can be adjusted pursuant to the terms of the Master Credit Facility agreement. The PSEG sub-limit includes a sustainability linked pricing based mechanism with potential increases or decreases, which are not expected to be material, depending on performance relative to targeted methane emission reductions.
Table(B)The primary use of ContentsPSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs, under which as of December 31, 2023, PSEG had $25 million outstanding at a weighted average interest rate of 5.60%. PSE&G had $425 million Commercial Paper outstanding at a weighted average interest rate of 5.57%.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(C)Amounts do not include uncommitted credit facilities.
PSEG Power has an uncommitted credit facility for $100 million, which can be utilized for letters of credit. A subsidiary of PSEG Power has an uncommitted credit facility for $150 million, which can be utilized for cash collateral postings. As of December 31, 2023, there was an immaterial amount outstanding under these facilities.
Debt Covenants
PSEG Power’s existing credit agreements contain covenants restricting the ability of PSEG Power and its subsidiaries that guarantee its indebtedness from consummating certain mergers, consolidations or asset sales.
Short-Term Loans
In January 2023, PSEG repaid $750 million of the $1.5 billion 364-day variable rate term loan that was issued in April 2022 and in April 2023 the remaining $750 million matured. In April 2023, PSEG entered into a new 364-day variable rate term loan agreement for $750 million. In May 2023, PSEG’s $500 million 364-day variable rate term loan matured. In August 2023, PSEG repaid $250 million of the $750 million 364-day variable rate term loan that was issued in April 2023.
Fair Value of Debt
The estimated fair values, carrying amounts and methods used to determine the fair valuevalues of long-term debt as of
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 20172023 and 20162022 are included in the following table and accompanying notes as of December 31, 20172023 and 2016.2022. See Note 17. Fair Value Measurements for more information on fair value guidance and the hierarchy that prioritizes the inputs to fair value measurements into three levels.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | December 31, 2023 | | December 31, 2022 | |
| | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | |
| | | Millions | |
| Long-Term Debt: | | | | | | | | | |
| PSEG (A) | | $ | 4,371 | | | $ | 4,240 | | | $ | 4,124 | | | $ | 3,808 | | |
| PSE&G (A) | | 13,663 | | | 12,460 | | | 12,696 | | | 11,106 | | |
| PSEG Power (B) | | 1,250 | | | 1,250 | | | 1,250 | | | 1,250 | | |
| Total Long-Term Debt | | $ | 19,284 | | | $ | 17,950 | | | $ | 18,070 | | | $ | 16,164 | | |
| | | | | | | | | | |
(A)Given that these bonds do not trade actively, the fair value amounts of taxable debt securities (primarily Level 2 measurements) are generally determined by a valuation model using market-based measurements that are processed through a rules-based pricing methodology. The fair value amounts above do not represent the price at which the outstanding debt may be called for redemption by each issuer under their respective debt agreements.
(B)Private term loan with book value approximating fair value (Level 2 measurement).
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | December 31, 2017 | | December 31, 2016 | |
| | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | |
| | | Millions | |
| Long-Term Debt: | | | | | | | | | |
| PSEG (A) (B) | | $ | 2,091 |
| | $ | 2,081 |
| | $ | 1,195 |
| | $ | 1,185 |
| |
| PSE&G (B) | | 8,591 |
| | 9,322 |
| | 7,818 |
| | 8,240 |
| |
| Power (B) | | 2,386 |
| | 2,659 |
| | 2,382 |
| | 2,578 |
| |
| | | $ | 13,068 |
| | $ | 14,062 |
| | $ | 11,395 |
| | $ | 12,003 |
| |
| | | | | | | | | | |
| |
(A) | As of December 31, 2017 and 2016, fair value includes floating rate term loans of $700 million and $500 million, respectively. The fair values of the term loan debt (Level 2 measurement) approximate the carrying values because the interest payments are based on LIBOR rates that are reset monthly and the debt is redeemable at face value by PSEG at any time. |
| |
(B) | Given that these bonds do not trade actively, the fair value amounts of taxable debt securities (primarily Level 2 measurements) are generally determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk into the discount rates, pricing is obtained (i.e. U.S. Treasury rate plus credit spread) based on expected new issue pricing across each of the companies’ respective debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. |
Note 15. Schedule of Consolidated Capital Stock
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | As of December 31, | |
| | | Outstanding Shares | | Book Value | |
| | | 2023 | | 2022 | | 2023 | | 2022 | |
| | | Millions | |
| PSEG Common Stock (no par value) (A) | | | | | | | | | |
| Authorized 1,000 shares | | 498 | | | 497 | | | $ | 3,639 | | | $ | 3,688 | | |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | As of December 31, | |
| | | Outstanding Shares | | Book Value | |
| | | 2017 | | 2016 | | 2017 | | 2016 | |
| | | Millions | |
| PSEG Common Stock (no par value) (A) | | | | | | | | | |
| Authorized 1,000 shares | | 505 |
| | 505 |
| | $ | 4,198 |
| | $ | 4,219 |
| |
| | | | | | | | | | |
(A)PSEG did not issue any new shares under the Dividend Reinvestment and Stock Purchase Plan or the Employee Stock Purchase Plan (ESPP) in 2023 or 2022. | |
(A) | PSEG did not issue any new shares under the Dividend Reinvestment and Stock Purchase Plan (DRASPP) or the Employee Stock Purchase Plan (ESPP) in 2017 or 2016. |
As of December 31, 2017,2023, PSE&G had an aggregate of 7.5 million shares of $100$100 par value and 10 million shares of $25$25 par value Cumulative Preferred Stock, which were authorized and unissued and which, upon issuance, may or may not provide for mandatory sinking fund redemption.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 16. Financial Risk Management Activities
Derivative accounting guidance requires that a derivative instrument be recognized as either an asset or a liability at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation provided that the derivative instrument meets specific, restrictive criteria, both at the time of designation and on an ongoing basis. These alternative permissible treatments include NPNS cash flow hedge and fair value hedge accounting. PSEG Power and PSE&G have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements and fuel agreements. PSEG uses interest rate swaps and other derivatives, which are designated and effectivequalifying as cash flow or fair value hedges. PSEG Power and PSE&G enterenters into additional contracts that are derivatives, but are not designated as either cash flow hedges or fair value hedges. These transactions are economic hedges and are recorded at fair market value.value with changes recognized in earnings.
Commodity Prices
Within PSEG and its affiliate companies, PSEG Power has the most exposure to commodity price risk. PSEG Power is exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuelsnatural gas and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. PSEG Power uses a variety of derivative and non-derivative instruments, such as financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity, to manage the exposure to fluctuations in commodity prices and optimize the value of PSEG Power’s
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
expected generation. PSEG Power also uses derivatives to hedge a portion of its anticipated BGSS obligations with PSE&G. For additional information see Note 13. Commitments and Contingent Liabilities. ChangesAdditionally, prospective changes in the fair market value of these derivative contracts are recorded in earnings.
Interest Rates
PSEG, PowerPSE&G and PSE&GPSEG Power are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, they have usedPSEG, PSE&G and PSEG Power may use a mix of fixed and floating rate debt, interest rate swaps and interest rate swaps.
Fair Value Hedges
PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. The changes in fair value of the interest rate swaps are fully offset by changes in the fair value of the underlying forecasted interest payments of the debt. There were no outstanding interest rate swaps as of December 31, 2017 or 2016. The fair value hedges reduced interest expense by $6 million and $19 million for the years ended December 31, 2016 and 2015, respectively.lock agreements.
Cash Flow Hedges
PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. There were no outstanding interest rate hedges as of December 31, 2017.
As of December 31, 2016,2023, PSEG had interest rate hedges outstanding totaling $500 million. These hedges converted$1.4 billion which were executed to convert $900 million of PSEG Power’s $1.25 billion variable rate term loan due March 2025 and PSEG’s $500 million variable rate term loan due November 2017April 2024 into a fixed rate loan. As of December 31, 2016, theloans. The fair value of these hedges was a net $5 million and $1 million as of December 31, 2023 and there2022, respectively.
In the third quarter of 2023, PSEG entered into interest rate treasury locks totaling $800 million to fix the interest rate for a portion of an anticipated $1 billion long-term debt issuance that occurred in October 2023. The settlement payment of $17 million for these treasury locks was no ineffectiveness. recorded in Accumulated Other Comprehensive Income (Loss) and will be amortized into earnings to match the term and timing of the hedged debt.
In the fourth quarter of 2023, PSEG entered into interest rate treasury locks totaling $600 million to fix the interest rate for a portion of an anticipated long-term debt issuance. As of December 31, 2023, these treasury locks had a fair value of $(16) million.
The Accumulated Other Comprehensive Income (Loss) (after tax) related to existingoutstanding and terminated interest rate derivatives designated as cash flow hedges was immaterial as of December 31, 2017$3 million and $2$(3) million as of December 31, 2016.2023 and December 31, 2022, respectively. The after-tax unrealized gains on these hedges expected to be reclassified to earnings during the next 12 months is immaterial.are $3 million.
Fair Values of Derivative Instruments
The following are the fair values of derivative instruments on the Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with PSEG’s accounting policy, these positions are offset on the Consolidated Balance Sheets of Power and PSEG. For additional information see Note 17. Fair Value Measurements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2023 and 2022. The following tabular disclosure does not include the offsetting of trade receivables and payables.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | As of December 31, 2017 | |
| | Power (A) | | PSE&G (A) | | PSEG (A) | | Consolidated | |
| | | Not Designated | | | | | | Not Designated | | Cash Flow Hedges | | | |
| Balance Sheet Location | | Energy- Related Contracts | | Netting (B) | | Total Power | | Energy- Related Contracts | | Interest Rate Swaps | | Total Derivatives | |
| | Millions | |
| Derivative Contracts | | | | | | | | | | | | | |
| Current Assets | | $ | 391 |
| | $ | (362 | ) | | $ | 29 |
| | $ | — |
| | $ | — |
| | $ | 29 |
| |
| Noncurrent Assets | | 78 |
| | (71 | ) | | 7 |
| | — |
| | — |
| | 7 |
| |
| Total Mark-to-Market Derivative Assets | | $ | 469 |
| | $ | (433 | ) | | $ | 36 |
| | $ | — |
| | $ | — |
| | $ | 36 |
| |
| Derivative Contracts | | | | | | | | | | | | | |
| Current Liabilities | | $ | (403 | ) | | $ | 387 |
| | $ | (16 | ) | | $ | — |
| | $ | — |
| | $ | (16 | ) | |
| Noncurrent Liabilities | | (95 | ) | | 90 |
| | (5 | ) | | — |
| | — |
| | (5 | ) | |
| Total Mark-to-Market Derivative (Liabilities) | | $ | (498 | ) | | $ | 477 |
| | $ | (21 | ) | | $ | — |
| | $ | — |
| | $ | (21 | ) | |
| Total Net Mark-to-Market Derivative Assets (Liabilities) | | $ | (29 | ) | | $ | 44 |
| | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | 15 |
| |
| | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | As of December 31, 2016 | |
| | Power (A) | | PSE&G (A) | | PSEG (A) | | Consolidated | |
| | | Not Designated | | | | | | Not Designated | | Fair Value Hedges | | | |
| Balance Sheet Location | | Energy- Related Contracts | | Netting (B) | | Total Power | | Energy- Related Contracts | | Interest Rate Swaps | | Total Derivatives | |
| | Millions | |
| Derivative Contracts | | | | | | | | | | | | | |
| Current Assets | | $ | 435 |
| | $ | (273 | ) | | $ | 162 |
| | $ | — |
| | $ | 1 |
| | $ | 163 |
| |
| Noncurrent Assets | | 122 |
| | (98 | ) | | 24 |
| | — |
| | — |
| | 24 |
| |
| Total Mark-to-Market Derivative Assets | | $ | 557 |
| | $ | (371 | ) | | $ | 186 |
| | $ | — |
| | $ | 1 |
| | $ | 187 |
| |
| Derivative Contracts | | | | | | | | | | | | | |
| Current Liabilities | | $ | (285 | ) | | $ | 277 |
| | $ | (8 | ) | | $ | (5 | ) | | $ | — |
| | $ | (13 | ) | |
| Noncurrent Liabilities | | (98 | ) | | 95 |
| | (3 | ) | | — |
| | — |
| | (3 | ) | |
| Total Mark-to-Market Derivative (Liabilities) | | $ | (383 | ) | | $ | 372 |
| | $ | (11 | ) | | $ | (5 | ) | | $ | — |
| | $ | (16 | ) | |
| Total Net Mark-to-Market Derivative Assets (Liabilities) | | $ | 174 |
| | $ | 1 |
| | $ | 175 |
| | $ | (5 | ) | | $ | 1 |
| | $ | 171 |
| |
| | | | | | | | | | | | | | |
| |
(A) | Substantially all of Power's and PSEG's derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of December 31, 2017 and 2016. PSE&G does not have any derivative contracts subject to master netting or similar agreements. |
| |
(B) | Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset on the Consolidated Balance Sheets. As of December 31, 2017, and 2016, Power had net cash collateral/margin payments to counterparties of $146 million and $56 million, |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | As of December 31, 2023 | |
| | PSEG | | PSEG Power | | Consolidated | |
| | Cash Flow Hedges | | Not Designated | | | | | | | |
| Balance Sheet Location | Interest Rate Derivatives | | Energy- Related Contracts | | Netting (A) | | Total PSEG Power | | Total Derivatives | |
| | Millions | |
| Derivative Contracts | | | | | | | | | | |
| Current Assets | $ | 6 | | | $ | 912 | | | $ | (806) | | | $ | 106 | | | $ | 112 | | |
| Noncurrent Assets | — | | | 440 | | | (411) | | | 29 | | | 29 | | |
| Total Mark-to-Market Derivative Assets | $ | 6 | | | $ | 1,352 | | | $ | (1,217) | | | $ | 135 | | | $ | 141 | | |
| Derivative Contracts | | | | | | | | | | |
| Current Liabilities | $ | (16) | | | $ | (890) | | | $ | 820 | | | $ | (70) | | | $ | (86) | | |
| Noncurrent Liabilities | (1) | | | (424) | | | 419 | | | (5) | | | (6) | | |
| Total Mark-to-Market Derivative (Liabilities) | $ | (17) | | | $ | (1,314) | | | $ | 1,239 | | | $ | (75) | | | $ | (92) | | |
| Total Net Mark-to-Market Derivative Assets (Liabilities) | $ | (11) | | | $ | 38 | | | $ | 22 | | | $ | 60 | | | $ | 49 | | |
| | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | As of December 31, 2022 | |
| | PSEG | | PSEG Power | | | | Consolidated | |
| | Cash Flow Hedges | | Not Designated | | | | | | | |
| Balance Sheet Location | Interest Rate Derivatives | | Energy- Related Contracts | | Netting (A) | | Total PSEG Power | | Total Derivatives | |
| | Millions | |
| Derivative Contracts | | | | | | | | | | |
| Current Assets | $ | 4 | | | $ | 1,721 | | | $ | (1,707) | | | $ | 14 | | | $ | 18 | | |
| Noncurrent Assets | — | | | 629 | | | (614) | | | 15 | | | 15 | | |
| Total Mark-to-Market Derivative Assets | $ | 4 | | | $ | 2,350 | | | $ | (2,321) | | | $ | 29 | | | $ | 33 | | |
| Derivative Contracts | | | | | | | | | | |
| Current Liabilities | $ | — | | | $ | (2,447) | | | $ | 2,323 | | | $ | (124) | | | $ | (124) | | |
| Noncurrent Liabilities | (3) | | | (1,139) | | | 1,109 | | | (30) | | | (33) | | |
| Total Mark-to-Market Derivative (Liabilities) | $ | (3) | | | $ | (3,586) | | | $ | 3,432 | | | $ | (154) | | | $ | (157) | | |
| Total Net Mark-to-Market Derivative Assets (Liabilities) | $ | 1 | | | $ | (1,236) | | | $ | 1,111 | | | $ | (125) | | | $ | (124) | | |
| | | | | | | | | | | |
(A) Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of cash collateral. All cash collateral (received) posted that has been allocated to derivative positions, where the right of offset exists, has been offset on the Consolidated Balance Sheets. As of December 31, 2023 and 2022, PSEG Power had net cash collateral payments to counterparties of $113 million and $1,521 million, respectively. Of these net cash collateral/margincollateral (receipts) payments, $44$22 million as of December 31, 20172023 and $1$1,111 million as of December 31, 20162022 were netted against the corresponding net derivative contract positions. Of the $44$22 million as of December 31, 2017, $(3)2023, $(1) million was netted against current assets, $28$15 million was netted against current liabilities and $19$8 million was netted against noncurrent liabilities. Of the $1$1,111 million as of December 31, 2016, $(3)2022, $616 million was netted against current liabilities and $495 million was netted against noncurrent assets and $4 million was netted against current liabilities.
Certain of PSEG Power’s derivative instruments contain provisions that require PSEG Power to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PSEG Power’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if PSEG Power were to be downgraded to a below investment grade rating by S&P or Moody’s, it would be required to provide additional collateral. A below investment grade credit rating for PSEG
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Power would represent a threetwo level downgrade from its current Moody’s and S&P or Moody’s ratings. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. PSEG Power also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margin requirements.
The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the NYMEX and ICE that are fully collateralized) was $30$77 million and $19$190 million as of December 31, 20172023 and 2016,2022, respectively. As of December 31, 20172023 and 2016,2022, PSEG Power had the contractual right of offset of $13$3 million and $9$41 million, respectively, related to derivative instruments that are assets with the same counterparty under master agreements and net of margin posted. If PSEG Power had been downgraded to a below investment grade rating, it would have had additional collateral obligations of $17$74 million and $10$149 million as of December 31, 20172023 and 2016,2022, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral.
The following shows the effect on the Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI)Loss (AOCL) of derivative instruments designated as cash flow hedges for the years ended December 31, 2017, 20162023, 2022 and 2015.2021.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | Amount of Pre-Tax Gain (Loss) Recognized in AOCL on Derivatives | | Location of Pre-Tax Gain (Loss) Reclassified from AOCL into Income | | Amount of Pre-Tax Gain (Loss) Reclassified from AOCL into Income | | | |
| Derivatives in Cash Flow Hedging Relationships | Years Ended December 31, | | | | Years Ended December 31, | | | |
| | | 2023 | | 2022 | | 2021 | | | | 2023 | | 2022 | | 2021 | | | | | | | |
| | | Millions | | | | Millions | | | | | | | |
| Interest Rate Derivatives | | $ | 13 | | | $ | — | | | $ | — | | | Interest Expense | | $ | 5 | | | $ | (5) | | | $ | (4) | | | | | | | | |
| Total | | $ | 13 | | | $ | — | | | $ | — | | | | | $ | 5 | | | $ | (5) | | | $ | (4) | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion) | | Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income | | Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion) | |
| Derivatives in Cash Flow Hedging Relationships | Years Ended December 31, | | | | Years Ended December 31, | |
| | | 2017 | | 2016 | | 2015 | | | | 2017 | | 2016 | | 2015 | |
| | | Millions | | | | Millions | |
| PSEG | | | | | | | | | | | | | | | |
| Energy-Related Contracts | | $ | — |
| | $ | — |
| | $ | 3 |
| | Operating Revenues | | $ | — |
| | $ | — |
| | $ | 20 |
| |
| Interest Rate Swaps | | — |
| | 3 |
| | — |
| | Interest Expense | | 3 |
| | — |
| | — |
| |
| Total PSEG | | $ | — |
| | $ | 3 |
| | $ | 3 |
| | | | $ | 3 |
| | $ | — |
| | $ | 20 |
| |
| Power | | | | | | | | | | | | | | | |
| Energy-Related Contracts | | $ | — |
| | $ | — |
| | $ | 3 |
| | Operating Revenues | | $ | — |
| | $ | — |
| | $ | 20 |
| |
| Total Power | | $ | — |
| | $ | — |
| | $ | 3 |
| | | | $ | — |
| | $ | — |
| | $ | 20 |
| |
| | | | | | | | | | | | | | | | |
There were no pre-taxThe effect of interest rate cash flow hedges is recorded in Interest Expense in PSEG’s Consolidated Statement of Operations. The amount of gain (loss) recognized inon interest rate hedges reclassified from Accumulated Other Comprehensive Income (Loss) into income on derivatives (ineffective portion)was $3 million, $(3) million and $(3) million after tax as of December 31, 2017, 20162023, 2022 and 2015.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2021, respectively.
The following reconciles the AOCIAccumulated Other Comprehensive Income (Loss) for derivative activity included in the Accumulated Other Comprehensive LossAOCL of PSEG on a pre-tax and after-tax basis.
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| Accumulated Other Comprehensive Income (Loss) | | Pre-Tax | | After-Tax | |
| | | Millions | |
| Balance as of December 31, 2021 | | $ | (9) | | | $ | (6) | | |
| Loss Recognized in AOCI | | — | | | — | | |
| Less: Loss Reclassified into Income | | 5 | | | 3 | | |
| Balance as of December 31, 2022 | | $ | (4) | | | $ | (3) | | |
| Gain Recognized in AOCI | | 13 | | | 9 | | |
| Less: Gain Reclassified into Income | | (5) | | | (3) | | |
| Balance as of December 31, 2023 | | $ | 4 | | | $ | 3 | | |
| | | | | | |
|
| | | | | | | | | | |
| | | | | | |
| Accumulated Other Comprehensive Income | | Pre-Tax | | After-Tax | |
| | | Millions | |
| Balance as of December 31, 2015 | | $ | — |
| | $ | — |
| |
| Gain Recognized in AOCI | | 3 |
| | 2 |
| |
| Less: Gain Reclassified into Income | | — |
| | — |
| |
| Balance as of December 31, 2016 | | $ | 3 |
| | $ | 2 |
| |
| Gain Recognized in AOCI | | — |
| | — |
| |
| Less: Gain Reclassified into Income | | (3 | ) | | (2 | ) | |
| Balance as of December 31, 2017 | | $ | — |
| | $ | — |
| |
| | | | | | |
The following shows the effect on the Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the years ended December 31, 2017, 20162023, 2022 and 2015.2021. PSEG Power’s derivative contracts reflected in this table include contracts to hedge the purchase and sale of electricity and natural gas, and the purchase of fuel. The table does not include contracts which Power has designated as NPNS, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| Derivatives Not Designated as Hedges | | Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives | | Pre-Tax Gain (Loss) Recognized in Income on Derivatives | |
| | | | | Years Ended December 31, | |
| | | | | 2017 | | 2016 | | 2015 | |
| | | | | Millions | |
| PSEG and Power | | | | | | | | | |
| Energy-Related Contracts | | Operating Revenues | | $ | 72 |
| | $ | 230 |
| | $ | 412 |
| |
| Energy-Related Contracts | | Energy Costs | | (17 | ) | | (8 | ) | | (8 | ) | |
| Total PSEG and Power | | | | $ | 55 |
| | $ | 222 |
| | $ | 404 |
| |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| Derivatives Not Designated as Hedges | | Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives | | Pre-Tax Gain (Loss) Recognized in Income on Derivatives | |
| | | | | Years Ended December 31, | |
| | | | | 2023 | | 2022 | | 2021 | |
| | | | | Millions | |
| Energy-Related Contracts | | Operating Revenues | | $ | 1,567 | | | $ | (1,748) | | | $ | (993) | | |
| Energy-Related Contracts | | Energy Costs | | — | | | 2 | | | 126 | | |
| Total | | | | $ | 1,567 | | | $ | (1,746) | | | $ | (867) | | |
| | | | | | | | | | |
The following table summarizes the net notional volume purchases/(sales) of open derivative transactions by commodity as of December 31, 20172023 and 2016.2022.
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| Type | | Notional | | Total | | PSEG | | Power | | PSE&G | |
| | | Millions | |
| As of December 31, 2017 | | | | | | | | | | | |
| Natural Gas | | Dth | | 154 |
| | — |
| | 154 |
| | — |
| |
| Electricity | | MWh | | (63 | ) | | — |
| | (63 | ) | | — |
| |
| Financial Transmission Rights (FTRs) | | MWh | | 6 |
| | — |
| | 6 |
| | — |
| |
| As of December 31, 2016 | | | | | | | | | | | |
| Natural Gas | | Dth | | 122 |
| | — |
| | 113 |
| | 9 |
| |
| Electricity | | MWh | | (44 | ) | | — |
| | (44 | ) | | — |
| |
| FTRs | | MWh | | 9 |
| | — |
| | 9 |
| | — |
| |
| Interest Rate Swaps | | U.S. Dollars | | 500 |
| | 500 |
| | — |
| | — |
| |
| | | | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | | As of December 31, | |
| Type | | Notional | | 2023 | | 2022 | |
| | | | | Millions | |
| Natural Gas | | Dekatherm | | 66 | | | 49 | |
| Electricity | | MWh | | (60) | | | (60) | | |
| Financial Transmission Rights | | MWh | | 19 | | | 24 | |
| Interest Rate Derivatives | | U.S. Dollars | | 2,000 | | | 1,050 | | |
| | | | | | | | |
Credit Risk
Credit risk relates to the risk of loss that PSEG Power would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. PSEG has established credit policies that it believes significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s and PSEG’s financial condition, results of operations or net cash flows.
As of December 31, 2017, 99%2023, nearly 100% of the net credit exposure for PSEG Power’s wholesale operations was with investment grade counterparties. Creditcounterparties and there was only one counterparty with credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives, NPNS and non-derivatives).
The following table provides information on Power’s credit risk from others, net of collateral, as of December 31, 2017. It further delineates that exposure by the credit ratingwas greater than 10% of the counterparties, which is determined by the lowest rating from S&P, Moody’s or an internal scoring model. In addition, it provides guidance on the concentration of credit risk to individual counterparties and an indication of the quality of Power’s credit risk by credit rating of the counterparties.
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Rating | | Current Exposure | | Securities held as Collateral | | Net Exposure | | Number of Counterparties >10% | | Net Exposure of Counterparties >10% | | |
| | | Millions | | | | Millions | | |
| Investment Grade | | $ | 329 |
| | $ | 25 |
| | $ | 304 |
| | 1 |
| | $ | 204 |
| (A) | |
| Non-Investment Grade | | 3 |
| | 1 |
| | 2 |
| | — |
| | — |
| | |
| Total | | $ | 332 |
| | $ | 26 |
| | $ | 306 |
| | 1 |
| | $ | 204 |
| | |
| | | | | | | | | | | | | |
| |
(A) | Represents net exposure with PSE&G. |
As of December 31, 2017, collateral held from counterparties where Power hadtotal. This credit exposure included $1 millionwas with PSE&G, which eliminates in cash collateral and $25 million in letters of credit.
As of December 31, 2017, Power had 152 active counterparties.consolidation. See Note 24. Related-Party Transactions for additional information.
PSE&G’s supplier master agreements are approved by the BPU and govern the terms of its electric supply procurement contracts. These agreements define a supplier’s performance assurance requirements and allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s credit ratings from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day the procurement transaction is executed, compared to the forward price curve for energy on the valuation day. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post a parental guarantyguarantee or other security instrument such as a letter of credit or cash, as collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of December 31, 2017, primarily all2023, PSEG held parental guarantees, letters of the posted collateral was in the form of parental guarantees. The unsecured credit used by the suppliers represents PSE&G’s net credit exposure.and cash as security. PSE&G’s BGS suppliers’ credit exposure is calculated each business day. As of December 31, 2017,2023, PSE&G had no netunsecured mark-to-market credit exposure with suppliers, including Power.its suppliers.
PSE&G is permitted to recover its costs of procuring energy through the BPU-approved BGS tariffs. PSE&G’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 17. Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance for fair value measurement emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels:
Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG and PSE&G and Power have the ability to access. These consist primarily of listed equity securities and money market mutual funds, as well as natural gas futures contracts executed on NYMEX.
Level 2—measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as forward contracts or options and most fixed income securities.
Level 3—measurements use unobservable inputs for assets or liabilities, based on the best information available and might include an entity’s own data and assumptions. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. As of December 31, 2017, these consistedThese consist primarily of certain electric load contracts and gas contracts.
Certain derivative transactions may transfer from Level 2 to Level 3 if inputs become unobservable and internal modeling techniques are employed to determine fair value. Conversely, measurements may transfer from Level 3 to Level 2 if the inputs become observable.
The following tables present information about PSEG’s and PSE&G’s and Power’s respective assets and (liabilities) measured at fair value on a recurring basis as of December 31, 20172023 and December 31, 2016,2022, including the fair value measurements and the levels of inputs used in determining those fair values. Amounts shown for PSEG include the amounts shown for PSE&G and Power.
&G.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | Recurring Fair Value Measurements as of December 31, 2017 | |
| Description | | Total | | Netting (E) | | Quoted Market Prices for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | |
| | | Millions | |
| PSEG | | | | | | | | | | | |
| Assets: | | | | | | | | | | | |
| Cash Equivalents (A) | | $ | 223 |
| | $ | — |
| | $ | 223 |
| | $ | — |
| | $ | — |
| |
| Derivative Contracts: | | | | | | | | | | | |
| Energy-Related Contracts (B) | | $ | 36 |
| | $ | (433 | ) | | $ | 15 |
| | $ | 442 |
| | $ | 12 |
| |
| NDT Fund (D) | | | | | | | | | | | |
| Equity Securities | | $ | 1,055 |
| | $ | — |
| | $ | 1,053 |
| | $ | 2 |
| | $ | — |
| |
| Debt Securities—U.S. Treasury | | $ | 314 |
| | $ | — |
| | $ | — |
| | $ | 314 |
| | $ | — |
| |
| Debt Securities—Govt Other | | $ | 270 |
| | $ | — |
| | $ | — |
| | $ | 270 |
| | $ | — |
| |
| Debt Securities—Corporate | | $ | 402 |
| | $ | — |
| | $ | — |
| | $ | 402 |
| | $ | — |
| |
| Other Securities | | $ | 92 |
| | $ | — |
| | $ | 92 |
| | $ | — |
| | $ | — |
| |
| Rabbi Trust (D) | | | | | | | | | | | |
| Equity Securities—Mutual Funds | | $ | 25 |
| | $ | — |
| | $ | 25 |
| | $ | — |
| | $ | — |
| |
| Debt Securities—U.S. Treasury | | $ | 51 |
| | $ | — |
| | $ | — |
| | $ | 51 |
| | $ | — |
| |
| Debt Securities—Govt Other | | $ | 34 |
| | $ | — |
| | $ | — |
| | $ | 34 |
| | $ | — |
| |
| Debt Securities—Corporate | | $ | 119 |
| | $ | — |
| | $ | — |
| | $ | 119 |
| | $ | — |
| |
| Other Securities | | $ | 2 |
| | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| |
| Liabilities: | | | | | | | | | | | |
| Derivative Contracts: | | | | | | | | | | | |
| Energy-Related Contracts (B) | | $ | (21 | ) | | $ | 477 |
| | $ | (8 | ) | | $ | (485 | ) | | $ | (5 | ) | |
| PSE&G | | | | | | | | | | | |
| Assets: | | | | | | | | | | | |
| Cash Equivalents (A) | | $ | 223 |
| | $ | — |
| | $ | 223 |
| | $ | — |
| | $ | — |
| |
| Rabbi Trust (D) | | | | | | | | | | | |
| Equity Securities—Mutual Funds | | $ | 5 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | — |
| |
| Debt Securities—U.S. Treasury | | $ | 10 |
| | $ | — |
| | $ | — |
| | $ | 10 |
| | $ | — |
| |
| Debt Securities—Govt Other | | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | 7 |
| | $ | — |
| |
| Debt Securities—Corporate | | $ | 24 |
| | $ | — |
| | $ | — |
| | $ | 24 |
| | $ | — |
| |
| Other Securities | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| Power | | | | | | | | | | | |
| Assets: | | | | | | | | | | | |
| Derivative Contracts: | | | | | | | | | | | |
| Energy-Related Contracts (B) | | $ | 36 |
| | $ | (433 | ) | | $ | 15 |
| | $ | 442 |
| | $ | 12 |
| |
| NDT Fund (D) | | | | | | | | | | | |
| Equity Securities | | $ | 1,055 |
| | $ | — |
| | $ | 1,053 |
| | $ | 2 |
| | $ | — |
| |
| Debt Securities—U.S. Treasury | | $ | 314 |
| | $ | — |
| | $ | — |
| | $ | 314 |
| | $ | — |
| |
| Debt Securities—Govt Other | | $ | 270 |
| | $ | — |
| | $ | — |
| | $ | 270 |
| | $ | — |
| |
| Debt Securities—Corporate | | $ | 402 |
| | $ | — |
| | $ | — |
| | $ | 402 |
| | $ | — |
| |
| Other Securities | | $ | 92 |
| | $ | — |
| | $ | 92 |
| | $ | — |
| | $ | — |
| |
| Rabbi Trust (D) | | | | | | | | | | | |
| Equity Securities—Mutual Funds | | $ | 6 |
| | $ | — |
| | $ | 6 |
| | $ | — |
| | $ | — |
| |
| Debt Securities—U.S. Treasury | | $ | 13 |
| | $ | — |
| | $ | — |
| | $ | 13 |
| | $ | — |
| |
| Debt Securities—Govt Other | | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | 8 |
| | $ | — |
| |
| Debt Securities—Corporate | | $ | 30 |
| | $ | — |
| | $ | — |
| | $ | 30 |
| | $ | — |
| |
| Other Securities | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| Liabilities: | | | | | | | | | | | |
| Derivative Contracts: | | | | | | | | | | | |
| Energy-Related Contracts (B) | | $ | (21 | ) | | $ | 477 |
| | $ | (8 | ) | | $ | (485 | ) | | $ | (5 | ) | |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | Recurring Fair Value Measurements as of December 31, 2023 | |
| Description | | Total | | Netting (E) | | Quoted Market Prices for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | |
| | | Millions | |
| PSEG | | | | | | | | | | | |
| Assets: | | | | | | | | | | | |
| Cash Equivalents (A) | | $ | 20 | | | $ | — | | | $ | 20 | | | $ | — | | | $ | — | | |
| Derivative Contracts: | | | | | | | | | | | |
| Energy-Related Contracts (B) | | $ | 135 | | | $ | (1,217) | | | $ | 13 | | | $ | 1,339 | | | $ | — | | |
| Interest Rate Derivatives (C) | | $ | 6 | | | $ | — | | | $ | — | | | $ | 6 | | | $ | — | | |
| NDT Fund (D) | | | | | | | | | | | |
| Equity Securities | | $ | 1,310 | | | $ | — | | | $ | 1,310 | | | $ | — | | | $ | — | | |
| Debt Securities—U.S. Treasury | | $ | 293 | | | $ | — | | | $ | — | | | $ | 293 | | | $ | — | | |
| Debt Securities—Govt Other | | $ | 398 | | | $ | — | | | $ | — | | | $ | 398 | | | $ | — | | |
| Debt Securities—Corporate | | $ | 522 | | | $ | — | | | $ | — | | | $ | 522 | | | $ | — | | |
| | | | | | | | | | | | |
| Rabbi Trust (D) | | | | | | | | | | | |
| Equity Securities | | $ | 18 | | | $ | — | | | $ | 18 | | | $ | — | | | $ | — | | |
| Debt Securities—U.S. Treasury | | $ | 59 | | | $ | — | | | $ | — | | | $ | 59 | | | $ | — | | |
| Debt Securities—Govt Other | | $ | 32 | | | $ | — | | | $ | — | | | $ | 32 | | | $ | — | | |
| Debt Securities—Corporate | | $ | 70 | | | $ | — | | | $ | — | | | $ | 70 | | | $ | — | | |
| | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | |
| Derivative Contracts: | | | | | | | | | | | |
| Energy-Related Contracts (B) | | $ | (75) | | | $ | 1,239 | | | $ | (1) | | | $ | (1,311) | | | $ | (2) | | |
| Interest Rate Derivatives (C) | | $ | (17) | | | $ | — | | | $ | — | | | $ | (17) | | | $ | — | | |
| PSE&G | | | | | | | | | | | |
| Assets: | | | | | | | | | | | |
| Cash Equivalents (A) | | $ | 20 | | | $ | — | | | $ | 20 | | | $ | — | | | $ | — | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Rabbi Trust (D) | | | | | | | | | | | |
| Equity Securities | | $ | 3 | | | $ | — | | | $ | 3 | | | $ | — | | | $ | — | | |
| Debt Securities—U.S. Treasury | | $ | 11 | | | $ | — | | | $ | — | | | $ | 11 | | | $ | — | | |
| Debt Securities—Govt Other | | $ | 6 | | | $ | — | | | $ | — | | | $ | 6 | | | $ | — | | |
| Debt Securities—Corporate | | $ | 12 | | | $ | — | | | $ | — | | | $ | 12 | | | $ | — | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | Recurring Fair Value Measurements as of December 31, 2016 | |
| Description | | Total | | Netting (E) | | Quoted Market Prices for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | |
| | | Millions | |
| PSEG | | | | | | | | | | | |
| Assets: | | | | | | | | | | | |
| Cash Equivalents (A) | | $ | 365 |
| | $ | — |
| | $ | 365 |
| | $ | — |
| | $ | — |
| |
| Derivative Contracts: | | | | | | | | | | | |
| Energy-Related Contracts (B) | | $ | 186 |
| | $ | (371 | ) | | $ | 17 |
| | $ | 533 |
| | $ | 7 |
| |
| Interest Rate Swaps (C) | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | — |
| |
| NDT Fund (D) | | | | | | | | | | | |
| Equity Securities | | $ | 957 |
| | $ | — |
| | $ | 954 |
| | $ | 3 |
| | $ | — |
| |
| Debt Securities—U.S. Treasury | | $ | 227 |
| | $ | — |
| | $ | — |
| | $ | 227 |
| | $ | — |
| |
| Debt Securities—Govt Other | | $ | 293 |
| | $ | — |
| | $ | — |
| | $ | 293 |
| | $ | — |
| |
| Debt Securities—Corporate | | $ | 337 |
| | $ | — |
| �� | $ | — |
| | $ | 337 |
| | $ | — |
| |
| Other Securities | | $ | 44 |
| | $ | — |
| | $ | 44 |
| | $ | — |
| | $ | — |
| |
| Rabbi Trust (D) | | | | | | | | | | | |
| Equity Securities—Mutual Funds | | $ | 22 |
| | $ | — |
| | $ | 22 |
| | $ | — |
| | $ | — |
| |
| Debt Securities—U.S. Treasury | | $ | 37 |
| | $ | — |
| | $ | — |
| | $ | 37 |
| | $ | — |
| |
| Debt Securities—Govt Other | | $ | 66 |
| | $ | — |
| | $ | — |
| | $ | 66 |
| | $ | — |
| |
| Debt Securities—Corporate | | $ | 91 |
| | $ | — |
| | $ | — |
| | $ | 91 |
| | $ | — |
| |
| Other Securities | | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| |
| Liabilities: | | | | | | | | | | | |
| Derivative Contracts: | | | | | | | | | | | |
| Energy-Related Contracts (B) | | $ | (16 | ) | | $ | 372 |
| | $ | (18 | ) | | $ | (364 | ) | | $ | (6 | ) | |
| PSE&G | | | | | | | | | | | |
| Assets: | | | | | | | | | | | |
| Cash Equivalents (A) | | $ | 365 |
| | $ | — |
| | $ | 365 |
| | $ | — |
| | $ | — |
| |
| Derivative Contracts: | | | | | | | | | | | |
| Energy Related Contracts (B) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| Rabbi Trust (D) | | | | | | | | | | | |
| Equity Securities—Mutual Funds | | $ | 5 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | — |
| |
| Debt Securities—U.S. Treasury | | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | 7 |
| | $ | — |
| |
| Debt Securities—Govt Other | | $ | 13 |
| | $ | — |
| | $ | — |
| | $ | 13 |
| | $ | — |
| |
| Debt Securities—Corporate | | $ | 18 |
| | $ | — |
| | $ | — |
| | $ | 18 |
| | $ | — |
| |
| Other Securities | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| Liabilities: | | | | | | | | | | | |
| Derivative Contracts: | | | | | | | | | | | |
| Energy-Related Contracts (B) | | $ | (5 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (5 | ) | |
| Power | | | | | | | | | | | |
| Assets: | | | | | | | | | | | |
| Derivative Contracts: | | | | | | | | | | | |
| Energy-Related Contracts (B) | | $ | 186 |
| | $ | (371 | ) | | $ | 17 |
| | $ | 533 |
| | $ | 7 |
| |
| NDT Fund (D) | | | | | | | | | | | |
| Equity Securities | | $ | 957 |
| | $ | — |
| | $ | 954 |
| | $ | 3 |
| | $ | — |
| |
| Debt Securities—U.S. Treasury | | $ | 227 |
| | $ | — |
| | $ | — |
| | $ | 227 |
| | $ | — |
| |
| Debt Securities—Govt Other | | $ | 293 |
| | $ | — |
| | $ | — |
| | $ | 293 |
| | $ | — |
| |
| Debt Securities—Corporate | | $ | 337 |
| | $ | — |
| | $ | — |
| | $ | 337 |
| | $ | — |
| |
| Other Securities | | $ | 44 |
| | $ | — |
| | $ | 44 |
| | $ | — |
| | $ | — |
| |
| Rabbi Trust (D) | | | | | | | | | | | |
| Equity Securities—Mutual Funds | | $ | 5 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | — |
| |
| Debt Securities—U.S. Treasury | | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | 9 |
| | $ | — |
| |
| Debt Securities—Govt Other | | $ | 16 |
| | $ | — |
| | $ | — |
| | $ | 16 |
| | $ | — |
| |
| Debt Securities—Corporate | | $ | 23 |
| | $ | — |
| | $ | — |
| | $ | 23 |
| | $ | — |
| |
| Other Securities | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| Liabilities: | | | | | | | | | | | |
| Derivative Contracts: | | | | | | | | | | | |
| Energy-Related Contracts (B) | | $ | (11 | ) | | $ | 372 |
| | $ | (18 | ) | | $ | (364 | ) | | $ | (1 | ) | |
| | | | | | | | | | | | |
| |
(A) | Represents money market mutual funds. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | Recurring Fair Value Measurements as of December 31, 2022 | |
| Description | | Total | | Netting (E) | | Quoted Market Prices for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | |
| | | Millions | |
| PSEG | | | | | | | | | | | |
| Assets: | | | | | | | | | | | |
| Cash Equivalents (A) | | $ | 385 | | | $ | — | | | $ | 385 | | | $ | — | | | $ | — | | |
| Derivative Contracts: | | | | | | | | | | | |
| Energy-Related Contracts (B) | | $ | 29 | | | $ | (2,321) | | | $ | 42 | | | $ | 2,307 | | | $ | 1 | | |
| Interest Rate Derivatives (C) | | $ | 4 | | | $ | — | | | $ | — | | | $ | 4 | | | $ | — | | |
| NDT Fund (D) | | | | | | | | | | | |
| Equity Securities | | $ | 1,072 | | | $ | — | | | $ | 1,072 | | | $ | — | | | $ | — | | |
| Debt Securities—U.S. Treasury | | $ | 288 | | | $ | — | | | $ | — | | | $ | 288 | | | $ | — | | |
| Debt Securities—Govt Other | | $ | 339 | | | $ | — | | | $ | — | | | $ | 339 | | | $ | — | | |
| Debt Securities—Corporate | | $ | 529 | | | $ | — | | | $ | — | | | $ | 529 | | | $ | — | | |
| | | | | | | | | | | | |
| Rabbi Trust (D) | | | | | | | | | | | |
| Equity Securities | | $ | 20 | | | $ | — | | | $ | 20 | | | $ | — | | | $ | — | | |
| Debt Securities—U.S. Treasury | | $ | 57 | | | $ | — | | | $ | — | | | $ | 57 | | | $ | — | | |
| Debt Securities—Govt Other | | $ | 32 | | | $ | — | | | $ | — | | | $ | 32 | | | $ | — | | |
| Debt Securities—Corporate | | $ | 74 | | | $ | — | | | $ | — | | | $ | 74 | | | $ | — | | |
| | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | |
| Derivative Contracts: | | | | | | | | | | | |
| Energy-Related Contracts (B) | | $ | (154) | | | $ | 3,432 | | | $ | (3) | | | $ | (3,537) | | | $ | (46) | | |
| Interest Rate Derivatives | | $ | (3) | | | $ | — | | | $ | — | | | $ | (3) | | | $ | — | | |
| PSE&G | | | | | | | | | | | |
| Assets: | | | | | | | | | | | |
| Cash Equivalents (A) | | $ | 165 | | | $ | — | | | $ | 165 | | | $ | — | | | $ | — | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Rabbi Trust (D) | | | | | | | | | | | |
| Equity Securities | | $ | 3 | | | $ | — | | | $ | 3 | | | $ | — | | | $ | — | | |
| Debt Securities—U.S. Treasury | | $ | 10 | | | $ | — | | | $ | — | | | $ | 10 | | | $ | — | | |
| Debt Securities—Govt Other | | $ | 6 | | | $ | — | | | $ | — | | | $ | 6 | | | $ | — | | |
| Debt Securities—Corporate | | $ | 13 | | | $ | — | | | $ | — | | | $ | 13 | | | $ | — | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| |
(B) | Level 1—During 2016 a net fair value of $1 million relating to energy-related contracts was transferred from Level 2 into Level 1. These contracts represent natural gas futures contracts executed on NYMEX, and are being valued solely on settled pricing inputs which come directly from the exchange. |
(A)Represents money market mutual funds.
(B)Level 1—These contracts represent natural gas futures contracts executed on NYMEX, and are being valued solely on settled pricing inputs which come directly from the exchange.
Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using settled prices from similar assets and liabilities from an exchange, such as NYMEX, ICE and Nodal Exchange, or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs.
Level 3—Unobservable inputs are used for the valuation of certain contracts. See “Additional Information Regarding Level 3 Measurements” below for more information on the utilization of unobservable inputs.
| |
(C) | Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment. |
| |
(D) | As of December 31, 2016, the fair value measurement table excludes cash of $1 million, which is part of the NDT Fund. The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in a Russell 3000 index fund and various fixed income securities classified as “available for sale” as of December 31, 2017. The Rabbi Trust maintained investments in an S&P 500 index fund and various securities classified as “available for sale” as of December 31, 2016. These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities). |
(C)Interest rate derivatives are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgement.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(D)As of December 31, 2023 and 2022, the fair value measurement table excludes cash and foreign currency of $1 million and $2 million, respectively, in the NDT Fund. The NDT Fund maintains investments in various equity and fixed income securities. The Rabbi Trust maintains investments in a Russell 3000 index fund and various fixed income securities. These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).
Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Other SecuritiesCertain other equity securities in the NDT and Rabbi Trust Funds consist primarily of investments in Dreyfus money market funds which seek a high level of current income as is consistent with the preservation of capital and the maintenance of liquidity. To pursue its goals, the fundfunds normally investsinvest in a diversified portfolioportfolios of high quality, short-term, dollar-denominated debt securities and government securities. The funds’ Net Asset Valuenet asset value is priced and published daily. The Rabbi Trust equityTrust’s Russell 3000 index fund is valued based on quoted prices in an active market.market and can be redeemed daily without restriction.
Level 2—NDT and Rabbi Trust fixed income securities include investment grade corporate bonds, collateralized mortgage obligations, asset-backed securities and certain government and U.S. Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield.
| |
(E) | Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Consolidated Balance Sheets. As of December 31, 2017 and 2016, Power had net cash collateral/margin payments to counterparties of $146 million and $56 million, respectively. Of these net cash collateral/margin payments $44 million as of December 31, 2017 and $1 million as of December 31, 2016 were netted against the corresponding net derivative contract positions. Of the $44 million of cash collateral as of December 31, 2017, $(3) million was netted against assets, and $47 million was netted against liabilities. Of the $1 million of cash collateral as of December 31, 2016, $(3) million was netted against assets and $4 million was netted against liabilities. |
(E)Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. See Note 16. Financial Risk Management Activities for additional detail.
Additional Information Regarding Level 3 Measurements
For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee (RMC) approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The RMC reports to the Corporate Governance and Audit Committees of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by Power to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group and used for financial reporting purposes. PSEG considers credit and nonperformancenon-performance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformancenon-performance risk by counterparty. The impacts of credit and nonperformancenon-performance risk were not material to the financial statements.
For PSE&G, the natural gas supply contract is measured at fair value using modeling techniques taking into account the current price of natural gas adjusted for appropriate risk factors, as applicable, and internal assumptions about transportation costs, and accordingly, the fair value measurements are classified in Level 3. The fair value of Power’s electric load contracts in which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. The fair value of Power’s gas physical contracts at certain illiquid delivery locations are measured using average historical basis and, accordingly, are categorized as Level 3. While these gas physical contracts have an unobservable component in their respective forward price curves, the fluctuations in fair value have been driven primarily by changes in the observable inputs. The following tables provide details surrounding significant Level 3 valuations as of December 31, 2017 and 2016.
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | Quantitative Information About Level 3 Fair Value Measurements | | | |
| Commodity | | Level 3 Position | | Fair Value as of December 31, 2017 | | Valuation Technique(s) | | Significant Unobservable Input | | Range | |
| | | | | | |
| | | | | Assets | | (Liabilities) | | | | | | | |
| | | | | Millions | | | | | | | |
| Power | | | | | | | | | | | | | |
| Electricity | | Electric Load Contracts | | $ | 1 |
| | $ | (3 | ) | | Discounted Cash flow | | Historic Load Variability | | 0% to +10% | |
| Gas | | Gas Physical Contracts | | 11 |
| | (2 | ) | | Discounted Cash flow | | Average Historical Basis | | -40% to -10% | |
| Total Power | | | | $ | 12 |
| | $ | (5 | ) | | | | | | | |
| Total PSEG | | | | $ | 12 |
| | $ | (5 | ) | | | | | | | |
| | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | Quantitative Information About Level 3 Fair Value Measurements | | | |
| Commodity | | Level 3 Position | | Fair Value as of December 31, 2016 | | Valuation Technique(s) | | Significant Unobservable Input | | Range | |
| | | | | | |
| | | | | Assets | | (Liabilities) | | | | | | | |
| | | | | Millions | | | | | | | |
| PSE&G | | | | | | | | | | | | | |
| Gas | | Natural Gas Supply Contract | | $ | — |
| | $ | (5 | ) | | Discounted Cash Flow | | Transportation Costs | | $0.60 to $0.80/Dth | |
| Total PSE&G | | | | $ | — |
| | $ | (5 | ) | | | | | | | |
| Power | | | | | | | | | | | | | |
| Electricity | | Electric Load Contracts | | $ | 7 |
| | $ | (1 | ) | | Discounted Cash Flow | | Historic Load Variability | | 0% to +10% | |
| Gas (A) | | Other | | — |
| | — |
| | | | | | | |
| Total Power | | | | $ | 7 |
| | $ | (1 | ) | | | | | | | |
| Total PSEG | | | | $ | 7 |
| | $ | (6 | ) | | | | | | | |
| | | | | | | | | | | | | | |
| |
(A) | Includes gas positions which were immaterial. |
Significant unobservable inputs listed above would have a direct impact on the fair values of the above Level 3 instruments if they were adjusted. For energy-related contracts in cases where Power is a seller, an increase in the load variability would
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
decrease the fair value. For gas-related contracts in cases where Power is a buyer, an increase in the average historical basis would increase the fair value.
A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the years ended December 31, 2017 and 2016, respectively, follows:
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Year Ended December 31, 2017 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | Total Gains or (Losses) Realized/Unrealized | | | | | | | | | |
| Description | | Balance as of January 1, 2017 | | Included in Income (A) | | Included in Regulatory Assets/ Liabilities (B) | | Purchases, (Sales) | | Issuances/ Settlements (C) | | Transfers In/Out (D) | | Balance as of December 31, 2017 | |
| | | Millions | |
| PSEG | | | | | | | | | | | | | | | |
| Net Derivative Assets (Liabilities) | | $ | 1 |
| | $ | 26 |
| | $ | 5 |
| | $ | — |
| | $ | (24 | ) | | $ | (1 | ) | | $ | 7 |
| |
| PSE&G | | | | | | | | | | | | | | | |
| Net Derivative Assets (Liabilities) | | $ | (5 | ) | | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| Power | | | | | | | | | | | | | | | |
| Net Derivative Assets (Liabilities) | | $ | 6 |
| | $ | 26 |
| | $ | — |
| | $ | — |
| | $ | (24 | ) | | $ | (1 | ) | | $ | 7 |
| |
| | | | | | | | | | | | | | | | |
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Year Ended December 31, 2016 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | Total Gains or (Losses) Realized/Unrealized | | | | | | | | | |
| Description | | Balance as of January 1, 2016 | | Included in Income (A) | | Included in Regulatory Assets/ Liabilities (B) | | Purchases, (Sales) | | Issuances/ Settlements (C) | | Transfers In/Out | | Balance as of December 31, 2016 | |
| | | Millions | |
| PSEG | | | | | | | | | | | | | | | |
| Net Derivative Assets (Liabilities) | | $ | 13 |
| | $ | 13 |
| | $ | (7 | ) | | $ | 3 |
| | $ | (21 | ) | | $ | — |
| | $ | 1 |
| |
| PSE&G | | | | | | | | | | | | | | | |
| Net Derivative Assets (Liabilities) | | $ | 2 |
| | $ | — |
| | $ | (7 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (5 | ) | |
| Power | | | | | | | | | | | | | | | |
| Net Derivative Assets (Liabilities) | | $ | 11 |
| | $ | 13 |
| | $ | — |
| | $ | 3 |
| | $ | (21 | ) | | $ | — |
| | $ | 6 |
| |
| | | | | | | | | | | | | | | | |
| |
(A) | PSEG’s and Power’s gains(losses) attributable to changes in net derivative assets and liabilities for 2017 include $14 million in Operating Revenues, of which $(9) million is unrealized and $12 million in Energy Costs, all of which is unrealized. For 2016, $25 million is included in Operating Revenues, of which $(5) million is unrealized, and $(12) |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
million is in Energy Costs, all of which is realized.
| |
(B) | Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Accumulated Other Comprehensive Income, as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers. |
| |
(C) | Represents $(24) million and $(21) million in settlements for derivative contracts in 2017 and 2016, respectively. |
| |
(D) | During the year ended December 31, 2017, $(1) million of net derivatives assets/liabilities were transferred from Level 2 to Level 3.
|
As of December 31, 2017,2023, PSEG carried $2.6$2.8 billion of net assets that arewere measured at fair value on a recurring basis, of which $7$2 million of net assetsliabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.hierarchy and are considered immaterial.
As of December 31, 2016,2022, PSEG carried $2.6$2.7 billion of net assets that arewere measured at fair value on a recurring basis, of which $1$45 million of net assetsliabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.hierarchy and are considered immaterial.
There were no transfers in 2023 and 2022 to or from Level 3. Note 18. Stock Based Compensation
PSEG’s 2021 Long-Term Incentive Plan (2021 LTIP), approved by shareholders on April 20, 2021 and the Amended and Restated 2004 Long-Term Incentive Plan (LTIP) is a((2004 LTIP) under which no new grants have been made effective April 20, 2021), are broad-based equity compensation programprograms that providesprovide for grants of various long-term incentive compensation awards, such as stock options, stock appreciation rights, performance share units (PSUs), restricted stock, restricted stock units (RSUs), cash awards or any combination thereof. The types of long-term incentive awards that have been granted and remain outstanding under the LTIP are non-qualified options to purchase shares of PSEG’s common stock, restricted stock unit awards and performance share unit awards. The type of equity award that is granted and the details of that award may vary from time to time and is subject to the approval of the Organization and Compensation Committee of PSEG’s Board of Directors (O&CC), the LTIP’s administrative committee.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The 2021 LTIP currently provides for the issuance of equity awards with respect to approximately 168 million shares of common stock. As of December 31, 2017, there were2023, approximately 147 million shares were available for future awards under the 2021 LTIP.
In addition, on April 20, 2021 shareholders approved the PSEG 2021 Equity Compensation Plan for Outside Directors (2021 BOD Plan) and the PSEG 2007 Equity Compensation Plan for Outside Directors (2007 BOD Plan) was closed to new awards.
Under the 2021 BOD Plan, the only equity instrument which may be granted are RSUs and the Board member must defer the award until they have achieved their stock ownership requirement.
Stock Options
Under the 2021 LTIP, non-qualified options to acquire shares of PSEG common stock may be granted to officers and other key employees selected by the O&CC. Option awards are granted with an exercise price equal to the market price of PSEG’s common stock at the grant date. The options generally vest over four years of continuous service. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change-in-control (unless substituted with an equity award of equal value), retirement, death or disability. Options are exercisable over a period of time designated by the O&CC (but not prior to one year or longer than ten years from the date of grant) and are subject to such other terms and conditions as the O&CC determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the O&CC, by delivering previously acquired shares of PSEG common stock. No options have been issuedgranted since 2009.
Restricted Stock UnitsRSUs
Under both the 2021 LTIP and 2004 LTIP (LTIPs), PSEG has granted restricted stock unitRSU awards to officers and other key employees. These awards, which are bookkeeping entries only, are subject to risk of forfeiture until vested by continued employment. Until distributed, the units are credited with dividend equivalentsequivalent units (DEUs) proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. The restricted stock unitRSU grants for 20172023 and 20162022 generally vest at the end of three years. Vesting may be accelerated (pro-rated basis or full vesting) upon certain events such as change-in-control, retirement, disability change-in-control or death.
Performance Share UnitsPSUs
Under the LTIP,LTIPs, PSEG has granted performance share unitsPSUs to officers and other key employees. These provide for paymentdistribution in shares of PSEG common stock based on achievement of certain financial goals over a three-year performance period.period of three years. Following the end of the performance period, the payout varies from 0% to 200% of the number of performance unitsPSUs granted depending on PSEG’s performance with respect to certain financial targets, including targets related to comparative performance against other companies in a peer group of energy companies.those goals. The performance share unitsPSUs are credited with dividend equivalentsDEUs proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. Vesting may be accelerated on a pro-rated basis for the period of the employee’s service during the performance period as a result of certain events, such as change-in-control, (unless substituted with an equity award of equal value), retirement, death or disability.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Stock-Based Compensation
PSEG recognizes compensation expense for stock options based on their grant date fair values, which are determined using the Black-Scholes option-pricing model. Stock option awards are expensed on a tranche-specific basis over the requisite service period of the award. Ultimately, compensation expense for stock options is recognized for awards that vest.
PSEG recognizes compensation expense for restricted stock unitsRSUs over the vesting period based on the grant date fair value of the shares, which is equal to the closing market price of PSEG’s common stock on the date of the grant.
PSEG recognizes compensation expense for the total shareholder return (TSR) target for its performance share unitPSU awards based on the grant date fair values of the award, which are determined using the Monte Carlo model. The following table provides the assumptions used to calculate the grant date fair value of the TSR portion of the PSU awards for 2023, 2022 and 2021:
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| Grant Date | | Risk-Free Interest Rate | | Volatility | |
| | | | | | |
| February 14, 2023 | | 4.24% | | 25.09% | |
| February 15, 2022 | | 1.76% | | 27.34% | |
| February 16, 2021 | | 0.22% | | 27.31% | |
| | | | | | |
The accrual of compensation cost is based on the probable achievement of the performance conditions, which result in a payout from 0% to 200% of the initial grant. PSEG recognizes compensation expense for the return on invested capital target forall other components of its performance share unitsPSUs based on the grant date fair value of the awards, which is equal to the market price of PSEG’s common stock on the date of the grant. The accrual during the year of grant is estimated at 100% of the original grant. Such accrual may be adjusted to reflect the actual outcome.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | 2023 | | 2022 | | 2021 | |
| | | Millions | |
| Compensation Cost included in O&M Expense | | $ | 18 | | | $ | 29 | | | $ | 28 | | |
| Income Tax Benefit Recognized in Consolidated Statement of Operations | | $ | 5 | | | $ | 8 | | | $ | 8 | | |
| | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | 2017 | | 2016 | | 2015 | |
| | | Millions | |
| Compensation Cost included in Operation and Maintenance Expense | | $ | 31 |
| | $ | 29 |
| | $ | 34 |
| |
| Income Tax Benefit Recognized in Consolidated Statement of Operations | | $ | 13 |
| | $ | 12 |
| | $ | 14 |
| |
| | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For 2017, 2016each of the years 2023, 2022 and 2015 the2021, PSEG also recorded excess tax benefitbenefits of $4$22 million, $4$2 million and $3$2 million, respectively was included as financing cash flows on the Consolidated Statements of Cash Flow.respectively.
PSEG recognizes compensation cost of awards issued over the shorter of the original vesting period or the period beginning on the date of grant and ending on the date an individual is eligible for retirement and the award vests.
Stock OptionsRSUs
Changes in stock options for 2017 are summarized as follows:
|
| | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | Options | | Weighted Average Exercise Price | | Weighted Average Remaining Years Contractual Term | | Aggregate Intrinsic Value | |
| Outstanding as of January 1, 2017 | | 1,029,900 |
| | $ | 37.93 |
| | | | | |
| Exercised | | 654,200 |
| | $ | 40.02 |
| | | | | |
| Canceled/Forfeited | | 27,800 |
| | $ | 44.44 |
| | | | | |
| Outstanding as of December 31, 2017 | | 347,900 |
| | $ | 33.49 |
| | 1.9 | | $ | 6,265,679 |
| |
| Exercisable at December 31, 2017 | | 347,900 |
| | $ | 33.49 |
| | 1.9 | | $ | 6,265,679 |
| |
| | | | | | | | | | |
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model. There were no option grants in 2017, 2016 and 2015.
Activity for options exercised for the years ended December 31, 2017, 2016 and 2015 is shown below:
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | 2017 | | 2016 | | 2015 | |
| | | Millions | |
| Total Intrinsic Value of Options Exercised | | $ | 5 |
| | $ | 7 |
| | $ | 3 |
| |
| Cash Received from Options Exercised | | $ | 26 |
| | $ | 22 |
| | $ | 12 |
| |
| Tax Benefit Realized from Options Exercised | | $ | — |
| | $ | 1 |
| | $ | — |
| |
| | | | | | | | |
No options were vested during the years ended December 31, 2017, 2016 and 2015.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Restricted Stock Units
Changes in restricted stock unitsRSUs for the year ended December 31, 20172023 are summarized as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | Shares | | Weighted Average Grant Date Fair Value | | Weighted Average Remaining Years Contractual Term | | Aggregate Intrinsic Value | |
| Non-vested as of January 1, 2023 | | 216,240 | | | $ | 61.02 | | | | | | |
| Granted | | 286,059 | | | $ | 61.44 | | | | | | |
| Vested | | 213,504 | | | $ | 60.61 | | | | | | |
| Canceled/Forfeited | | 25,614 | | | $ | 61.21 | | | | | | |
| Non-vested as of December 31, 2023 | | 263,181 | | | $ | 61.79 | | | 1.2 | | $ | 16,093,498 | | |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | Shares | | Weighted Average Grant Date Fair Value | | Weighted Average Remaining Years Contractual Term | | Aggregate Intrinsic Value | |
| Non-vested as of January 1, 2017 | | 322,196 |
| | $ | 38.75 |
| | | | | |
| Granted | | 212,158 |
| | $ | 44.33 |
| | | | | |
| Vested | | 303,092 |
| | $ | 39.96 |
| | | | | |
| Canceled/Forfeited | | 17,363 |
| | $ | 41.76 |
| | | | | |
| Non-vested as of December 31, 2017 | | 213,899 |
| | $ | 42.32 |
| | 1.0 | | $ | 11,015,850 |
| |
| | |
|
| | | | | | | |
The weighted average grant date fair value per share for restricted stockRSUs during the years ended December 31, 2017, 20162023, 2022 and 20152021 was $44.33, $42.28$61.44, $64.44 and $39.65$58.02 per share, respectively.
The total intrinsic value of restricted stock unitsRSUs distributed during the years ended December 31, 2017, 20162023, 2022 and 20152021 was
$13 $54 million, $17$19 million and $11$17 million, respectively.
As of December 31, 2017,2023, there was approximately $3$7 million of unrecognized compensation cost related to the restricted stock units,RSUs, which is expected to be recognized over a weighted average period of ten months. Dividend equivalents units1.2 years. DEUs of 30,06629,174 accrued on the restricted stock unitsRSUs during the year.
Performance Share UnitsPSUs
Changes in performance share unitsPSUs for the year ended December 31, 20172023 are summarized as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | Shares | | Weighted Average Grant Date Fair Value | | Weighted Average Remaining Years Contractual Term | | Aggregate Intrinsic Value | |
| Non-vested as of January 1, 2023 | | 397,010 | | | $ | 67.65 | | | | | | |
| Granted | | 388,658 | | | $ | 67.99 | | | | | | |
| Vested | | 253,289 | | | $ | 66.81 | | | | | | |
| Canceled/Forfeited | | 49,963 | | | $ | 68.20 | | | | | | |
| Non-vested as of December 31, 2023 | | 482,416 | | | $ | 68.31 | | | 1.6 | | $ | 29,499,703 | | |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | Shares | | Weighted Average Grant Date Fair Value | | Weighted Average Remaining Years Contractual Term | | Aggregate Intrinsic Value | |
| Non-vested as of January 1, 2017 | | 393,812 |
| | $ | 44.20 |
| | | | | |
| Granted | | 382,830 |
| | $ | 45.02 |
| | | | | |
| Vested | | 402,451 |
| | $ | 44.03 |
| | | | | |
| Canceled/Forfeited | | 41,730 |
| | $ | 44.69 |
| | | | | |
| Non-vested as of December 31, 2017 | | 332,461 |
| | $ | 45.29 |
| | 1.7 | | $ | 17,121,742 |
| |
| | | | | | | | | | |
The weighted average grant date fair value per share for performance share unitsPSUs during the years ended December 31, 2017, 20162023, 2022 and 20152021 was $45.02, $45.97$67.99, $68.90 and $41.32$65.57 per share, respectively.
The total intrinsic value of performance share unitsPSUs distributed during the years ended December 31, 2017, 20162023, 2022 and 20152021 was
$18 $95 million, $17$18 million and $13$28 million, respectively.
As of December 31, 2017,2023, there was approximately $16$25 million of unrecognized compensation cost related to the performance share units,PSUs, which is expected to be recognized over a weighted average period of one year. Dividend equivalents units1.6 years. DEUs of 38,42540,329 accrued on the performance share unitsPSUs during the year.
Outside Directors
Under the Directors Equityclosed 2007 BOD Plan and the new 2021 BOD Plan, annually, on the first business day of May, each non-employee member of the Board of Directors is awarded stock units based on the amount of annual compensation to be paid at the closing price of PSEG common stock on that date. Dividend equivalentsDEUs are credited quarterly and distributions will commence upon the director leaving the Boardoccur as specified by him/hertheir election in accordance with the provisions of the Directors EquityBOD Plan.
The fair value of these awards is recorded as compensation expense in the Consolidated Statements of Operations. Compensation expense for the plan was immaterial$2 million for each of the years ended December 31, 2017, 20162023 and 2015.2022, and immaterial for the year ended December 31, 2021.
Employee Stock Purchase Plan (ESPP)ESPP
PSEG maintains an ESPP for all eligible employees of PSEG and its subsidiaries. Under the ESPP, shares of PSEG common stock may be purchased at 95% of the fair market value for represented employees and 90% for non-represented employees
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
through payroll deductions. Dividends willare to be reinvested for all employees at 95% of the fair market pricepaid out in cash unless the participant elects the dividends to receive a cash dividend.be reinvested at fair market price. All employees are required to hold the shares purchased under the ESPP for at least three
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
months from the purchase date. In any year, employees may purchase shares having a value not exceeding 10% of their base pay. Compensation expense recognized under this program was immaterial$2 million for each of the years ended December 31, 2017, 20162023, 2022 and 2015.2021.
During the years ended December 31, 2017, 20162023, 2022 and 2015,2021, employees purchased 288,527339,807 shares, 262,763321,429 shares and 250,499326,634 shares, respectively, at an average price of $42.07, $40.70$55.84, $57.72 and $36.66$56.87 per share, respectively. As of December 31, 2017, 3.22023, 1.2 million shares were available for future issuance under this plan.
Note 19. Net Other Income (Deductions)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | PSE&G | | PSEG Power & Other (A) | | Consolidated | |
| | | Millions | |
| Year Ended December 31, 2023 | | | | | | | |
| NDT Fund Interest and Dividends | | $ | — | | | $ | 68 | | | $ | 68 | | |
| AFUDC | | 60 | | | — | | | 60 | | |
| Solar Loan Interest | | 7 | | | — | | | 7 | | |
| Other Interest | | 12 | | | 34 | | | 46 | | |
| Donations | | (1) | | | — | | | (1) | | |
| | | | | | | | |
| Other | | 2 | | | (10) | | | (8) | | |
| Total Net Other Income (Deductions) | | $ | 80 | | | $ | 92 | | | $ | 172 | | |
| Year Ended December 31, 2022 | | | | | | | |
| NDT Fund Interest and Dividends | | $ | — | | | $ | 62 | | | $ | 62 | | |
| AFUDC | | 65 | | | — | | | 65 | | |
| Solar Loan Interest | | 10 | | | — | | | 10 | | |
| Other Interest | | 9 | | | 12 | | | 21 | | |
| Donations | | — | | | (1) | | | (1) | | |
| Purchases of Tax Losses under New Jersey Technology Tax Benefit Transfer Program | | — | | | (27) | | | (27) | | |
| Other | | 4 | | | (10) | | | (6) | | |
| Total Net Other Income (Deductions) | | $ | 88 | | | $ | 36 | | | $ | 124 | | |
| Year Ended December 31, 2021 | | | | | | | |
| NDT Fund Interest and Dividends | | $ | — | | | $ | 59 | | | $ | 59 | | |
| AFUDC | | 71 | | | — | | | 71 | | |
| Solar Loan Interest | | 13 | | | — | | | 13 | | |
| Other Interest | | 1 | | | 6 | | | 7 | | |
| Donations | | (1) | | | (21) | | | (22) | | |
| Purchases of Tax Losses under New Jersey Technology Tax Benefit Transfer Program | | — | | | (19) | | | (19) | | |
| Other | | 4 | | | (15) | | | (11) | | |
| Total Net Other Income (Deductions) | | $ | 88 | | | $ | 10 | | | $ | 98 | | |
| | | | | | | | |
(A)PSEG Power & Other consists of activity at PSEG Power, Energy Holdings, PSEG LI, Services, PSEG (parent company) and Deductionsintercompany eliminations.
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| Other Income | | PSE&G | | Power | | Other (A) | | Consolidated Total | |
| | | Millions | |
| Year Ended December 31, 2017 | | | | | | | | | |
| NDT Fund Gains, Interest, Dividend and Other Income | | $ | — |
| | $ | 202 |
| | $ | — |
| | $ | 202 |
| |
| Allowance for Funds Used During Construction | | 56 |
| | — |
| | — |
| | 56 |
| |
| Rabbi Trust Realized Gains, Interest and Dividends | | 5 |
| | 6 |
| | 13 |
| | 24 |
| |
| Solar Loan Interest | | 21 |
| | — |
| | — |
| | 21 |
| |
| Other | | 10 |
| | 5 |
| | 1 |
| | 16 |
| |
| Total Other Income | | $ | 92 |
| | $ | 213 |
| | $ | 14 |
| | $ | 319 |
| |
| Year Ended December 31, 2016 | | | | | | | | | |
| NDT Fund Gains, Interest, Dividend and Other Income | | $ | — |
| | $ | 96 |
| | $ | — |
| | $ | 96 |
| |
| Allowance for Funds Used During Construction | | 49 |
| | — |
| | — |
| | 49 |
| |
| Rabbi Trust Realized Gains, Interest and Dividends | | 3 |
| | 3 |
| | 6 |
| | 12 |
| |
| Solar Loan Interest | | 22 |
| | — |
| | — |
| | 22 |
| |
| Other | | 9 |
| | 3 |
| | — |
| | 12 |
| |
| Total Other Income | | $ | 83 |
| | $ | 102 |
| | $ | 6 |
| | $ | 191 |
| |
| Year Ended December 31, 2015 | | | | | | | | | |
| NDT Fund Gains, Interest, Dividend and Other Income | | $ | — |
| | $ | 138 |
| | $ | — |
| | $ | 138 |
| |
| Allowance for Funds Used During Construction | | 48 |
| | — |
| | — |
| | 48 |
| |
| Rabbi Trust Realized Gains, Interest and Dividends | | 2 |
| | 2 |
| | 6 |
| | 10 |
| |
| Solar Loan Interest | | 23 |
| | — |
| | — |
| | 23 |
| |
| Gain on Insurance Recovery | | — |
| | 28 |
| | — |
| | 28 |
| |
| Other | | 6 |
| | 1 |
| | — |
| | 7 |
| |
| Total Other Income | | $ | 79 |
| | $ | 169 |
| | $ | 6 |
| | $ | 254 |
| |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| Other Deductions | | PSE&G | | Power | | Other (A) | | Consolidated Total | |
| | | Millions | |
| Year Ended December 31, 2017 | | | | | | | | | |
| NDT Fund Realized Losses and Expenses | | $ | — |
| | $ | 32 |
| | $ | — |
| | $ | 32 |
| |
| Other | | 5 |
| | 24 |
| | 30 |
| | 59 |
| |
| Total Other Deductions | | $ | 5 |
| | $ | 56 |
| | $ | 30 |
| | $ | 91 |
| |
| Year Ended December 31, 2016 | | | | | | | | | |
| NDT Fund Realized Losses and Expenses | | $ | — |
| | $ | 40 |
| | $ | — |
| | $ | 40 |
| |
| Other | | 4 |
| | 17 |
| | 6 |
| | 27 |
| |
| Total Other Deductions | | $ | 4 |
| | $ | 57 |
| | $ | 6 |
| | $ | 67 |
| |
| Year Ended December 31, 2015 | | | | | | | | | |
| NDT Fund Realized Losses and Expenses | | $ | — |
| | $ | 45 |
| | $ | — |
| | $ | 45 |
| |
| Other | | 4 |
| | 27 |
| | 26 |
| | 57 |
| |
| Total Other Deductions | | $ | 4 |
| | $ | 72 |
| | $ | 26 |
| | $ | 102 |
| |
| | | | | | | | | | |
| |
(A) | Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations.
|
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 20. Income Taxes
A reconciliation of reported income tax expense for PSEG with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35%21% is as follows: |
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| PSEG | | 2017 | | 2016 | | 2015 | |
| | | Millions | |
| Net Income | | $ | 1,574 |
| | $ | 887 |
| | $ | 1,679 |
| |
| Income Taxes: | | | | | | | |
| Operating Income: | | | | | | | |
| Current Expense (Benefit): | | | | | | | |
| Federal | | $ | 86 |
| | $ | (74 | ) | | $ | 243 |
| |
| State | | (31 | ) | | 61 |
| | 85 |
| |
| Total Current | | 55 |
| | (13 | ) | | 328 |
| |
| Deferred (Benefit) Expense: | | | | | | | |
| Federal | | (482 | ) | | 311 |
| | 540 |
| |
| State | | 92 |
| | 28 |
| | 104 |
| |
| Total Deferred | | (390 | ) | | 339 |
| | 644 |
| |
| Investment Tax Credit (ITC) | | 29 |
| | 85 |
| | 29 |
| |
| Total Income Tax (Benefit) Expense | | $ | (306 | ) | | $ | 411 |
| | $ | 1,001 |
| |
| Pre-Tax Income | | $ | 1,268 |
| | $ | 1,298 |
| | $ | 2,680 |
| |
| Tax Computed at Statutory Rate @ 35% | | $ | 444 |
| | $ | 454 |
| | $ | 938 |
| |
| Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: | | | | | | | |
| State Income Taxes (net of federal income tax) | | 36 |
| | 56 |
| | 129 |
| |
| Uncertain Tax Positions | | (3 | ) | | (31 | ) | | 7 |
| |
| Manufacturing Deduction | | (13 | ) | | (17 | ) | | (10 | ) | |
| NDT Fund | | 19 |
| | 3 |
| | 7 |
| |
| Plant-Related Items | | (23 | ) | | (20 | ) | | (20 | ) | |
| Tax Credits | | (22 | ) | | (25 | ) | | (13 | ) | |
| Audit Settlement | | 6 |
| | — |
| | — |
| |
| Nuclear Decommissioning Tax Carryback | | — |
| | — |
| | (33 | ) | |
| Provisional Deferred Tax Benefit - Tax Act | | (755 | ) | | — |
| | — |
| |
| Other | | 5 |
| | (9 | ) | | (4 | ) | |
| Sub-Total | | (750 | ) | | (43 | ) | | 63 |
| |
| Total Income Tax (Benefit) Expense | | $ | (306 | ) | | $ | 411 |
| | $ | 1,001 |
| |
| Effective Income Tax Rate | | (24.1 | )% | | 31.7 | % | | 37.4 | % | |
| | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| PSEG | | 2023 | | 2022 | | 2021 | |
| | | Millions | |
| Net Income (Loss) | | $ | 2,563 | | | $ | 1,031 | | | $ | (648) | | |
| Income Taxes: | | | | | | | |
| Operating Income: | | | | | | | |
| Current Expense (Benefit): | | | | | | | |
| Federal | | $ | 144 | | | $ | 262 | | | $ | 407 | | |
| State | | 19 | | | (30) | | | (3) | | |
| Total Current | | 163 | | | 232 | | | 404 | | |
| Deferred Expense (Benefit): | | | | | | | |
| Federal | | 109 | | | (335) | | | (700) | | |
| State | | 253 | | | 80 | | | (136) | | |
| Total Deferred | | 362 | | | (255) | | | (836) | | |
| ITC | | (7) | | | (6) | | | (9) | | |
| Total Income Tax Expense (Benefit) | | $ | 518 | | | $ | (29) | | | $ | (441) | | |
| Pre-Tax Income (Loss) | | $ | 3,081 | | | $ | 1,002 | | | $ | (1,089) | | |
| Tax Computed at Statutory Rate @ 21% | | $ | 647 | | | $ | 210 | | | $ | (229) | | |
| Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: | | | | | | | |
| State Income Taxes (net of federal income tax) | | 215 | | | 41 | | | (109) | | |
| Uncertain Tax Positions | | (14) | | | (22) | | | 19 | | |
| NDT Fund | | 26 | | | (22) | | | 23 | | |
| Plant-Related Items | | (7) | | | (6) | | | (7) | | |
| Tax Credits | | (10) | | | (10) | | | 29 | | |
| Audit Settlement | | (7) | | | — | | | (8) | | |
| Leasing Activities | | (22) | | | — | | | (1) | | |
| GPRC-CEF-EE | | (52) | | | (37) | | | (13) | | |
| TAC | | (232) | | | (193) | | | (171) | | |
| Bad Debt Flow-Through | | (9) | | | (1) | | | 27 | | |
| Other | | (17) | | | 11 | | | (1) | | |
| Subtotal | | (129) | | | (239) | | | (212) | | |
| Total Income Tax Expense (Benefit) | | $ | 518 | | | $ | (29) | | | $ | (441) | | |
| Effective Income Tax Rate | | 16.8 | % | | (2.9) | % | | 40.5 | % | |
| | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following is an analysis of deferred income taxes for PSEG:
|
| | | | | | | | | | |
| | | | | | |
| | | As of December 31, | |
| PSEG | | 2017 | | 2016 | |
| | | Millions | |
| Deferred Income Taxes | | | | | |
| Assets: | | | | | |
| Noncurrent | | | | | |
| Regulatory Liability Excess Deferred Tax | | $ | 602 |
| | $ | — |
| |
| OPEB | | 217 |
| | 283 |
| |
| Related to Uncertain Tax Position | | 142 |
| | 155 |
| |
| Total Noncurrent Assets | | $ | 961 |
| | $ | 438 |
| |
| | | | | | |
| Liabilities: | | | | | |
| Noncurrent: | | | | | |
| Plant-Related Items | | $ | 4,257 |
| | $ | 6,593 |
| |
| New Jersey Corporate Business Tax | | 674 |
| | 674 |
| |
| Leasing Activities | | 384 |
| | 565 |
| |
| AROs and NDT Fund | | 233 |
| | 398 |
| |
| Pension Costs | | 123 |
| | 197 |
| |
| Taxes Recoverable Through Future Rates (net) | | 80 |
| | 208 |
| |
| Other | | 171 |
| | 212 |
| |
| Total Noncurrent Liabilities | | $ | 5,922 |
| | $ | 8,847 |
| |
| Summary of Accumulated Deferred Income Taxes: | | | | | |
| Net Noncurrent Deferred Income Tax Liabilities | | $ | 4,961 |
| | $ | 8,409 |
| |
| ITC | | 279 |
| | 249 |
| |
| Net Total Noncurrent Deferred Income Taxes and ITC | | $ | 5,240 |
| | $ | 8,658 |
| |
| | | | | | |
The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals. Also, the deferred tax effect of AROs is presented net of the deferred tax effect of the associated funding of those obligations.
In December 2017, new tax legislation was enacted, reducing the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018. PSEG is subject to ASC 740, which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate was enacted. The impact of the reduced tax rate is the primary reason for the decrease in the deferred tax liabilities.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A reconciliation of reported income tax expense for PSE&G with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows:
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| PSE&G | | 2017 | | 2016 | | 2015 | |
| | | Millions | |
| Net Income | | $ | 973 |
| | $ | 889 |
| | $ | 787 |
| |
| Income Taxes: | | | | | | | |
| Operating Income: | | | | | | | |
| Current (Benefit) Expense: | | | | | | | |
| Federal | | $ | (52 | ) | | $ | (153 | ) | | $ | 32 |
| |
| State | | (1 | ) | | 10 |
| | 52 |
| |
| Total Current | | (53 | ) | | (143 | ) | | 84 |
| |
| Deferred Expense: | | | | | | | |
| Federal | | 492 |
| | 551 |
| | 325 |
| |
| State | | 129 |
| | 102 |
| | 52 |
| |
| Total Deferred | | 621 |
| | 653 |
| | 377 |
| |
| ITC | | (5 | ) | | 5 |
| | 9 |
| |
| Total Income Tax Expense | | $ | 563 |
| | $ | 515 |
| | $ | 470 |
| |
| Pre-Tax Income | | $ | 1,536 |
| | $ | 1,404 |
| | $ | 1,257 |
| |
| Tax Computed at Statutory Rate @ 35% | | $ | 538 |
| | $ | 491 |
| | $ | 440 |
| |
| Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: | | | | | | | |
| State Income Taxes (net of federal income tax) | | 83 |
| | 72 |
| | 67 |
| |
| Uncertain Tax Positions | | (9 | ) | | (18 | ) | | (14 | ) | |
| Plant-Related Items | | (23 | ) | | (20 | ) | | (20 | ) | |
| Tax Credits | | (9 | ) | | (7 | ) | | (6 | ) | |
| Provisional Deferred Tax Benefit - Tax Act | | (10 | ) | | — |
| | — |
| |
| Other | | (7 | ) | | (3 | ) | | 3 |
| |
| Sub-Total | | 25 |
| | 24 |
| | 30 |
| |
| Total Income Tax Expense | | $ | 563 |
| | $ | 515 |
| | $ | 470 |
| |
| Effective Income Tax Rate | | 36.7 | % | | 36.7 | % | | 37.4 | % | |
| | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following is an analysis of deferred income taxes for PSE&G:
|
| | | | | | | | | | |
| | | | | | |
| | | As of December 31, | |
| PSE&G | | 2017 | | 2016 | |
| | | Millions | |
| Deferred Income Taxes | | | | | |
| Assets: | | | | | |
| Noncurrent: | | | | | |
| Regulatory Liability Excess Deferred Tax | | $ | 602 |
| | $ | — |
| |
| OPEB | | 116 |
| | 189 |
| |
| Total Noncurrent Assets | | $ | 718 |
| | $ | 189 |
| |
| Liabilities: | | | | | |
| Noncurrent: | | | | | |
| Plant-Related Items | | $ | 3,311 |
| | $ | 4,983 |
| |
| New Jersey Corporate Business Tax | | 378 |
| | 385 |
| |
| Pension Costs | | 152 |
| | 252 |
| |
| Conservation Costs | | 24 |
| | 33 |
| |
| Taxes Recoverable Through Future Rates (net) | | 80 |
| | 208 |
| |
| Other | | 86 |
| | 118 |
| |
| Total Noncurrent Liabilities | | $ | 4,031 |
| | $ | 5,979 |
| |
| Summary of Accumulated Deferred Income Taxes: | | | | | |
| Net Noncurrent Deferred Income Tax Liabilities | | $ | 3,313 |
| | $ | 5,790 |
| |
| ITC | | 78 |
| | 83 |
| |
| Net Total Noncurrent Deferred Income Taxes and ITC | | $ | 3,391 |
| | $ | 5,873 |
| |
| | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | As of December 31, | |
| PSEG | | 2023 | | 2022 | |
| | | Millions | |
| Deferred Income Taxes | | | | | |
| Assets: | | | | | |
| Regulatory Liability Excess Deferred Tax | | $ | 339 | | | $ | 390 | | |
| OPEB | | 58 | | | 74 | | |
| Bad Debt | | 57 | | | 66 | | |
| Corporate Alternative Minimum Tax (CAMT) Credit Carryforward | | 44 | | | — | | |
| Operating Leases | | 42 | | | 42 | | |
| Other | | 129 | | | 379 | | |
| Total Assets | | $ | 669 | | | $ | 951 | | |
| | | | | | |
| Liabilities: | | | | | |
| Plant-Related Items | | $ | 4,850 | | | $ | 4,663 | | |
| New Jersey Corporate Business Tax | | 1,284 | | | 1,009 | | |
| Leasing Activities | | 35 | | | 99 | | |
| AROs and NDT Fund | | 250 | | | 161 | | |
| Taxes Recoverable Through Future Rates (net) | | 201 | | | 149 | | |
| Pension Costs | | 189 | | | 164 | | |
| Operating Leases | | 38 | | | 37 | | |
| Other | | 430 | | | 324 | | |
| Total Liabilities | | $ | 7,277 | | | $ | 6,606 | | |
| Summary of Accumulated Deferred Income Taxes: | | | | | |
| Net Deferred Income Tax Liabilities | | $ | 6,608 | | | $ | 5,655 | | |
| ITC | | 63 | | | 70 | | |
| Net Total Deferred Income Taxes and ITC | | $ | 6,671 | | | $ | 5,725 | | |
| | | | | | |
The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals.
In December 2017, new tax legislation was enacted, reducing the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018. PSE&G is subject to ASC 740, which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate was enacted. The impact of the reduced tax rate is the primary reason for the decrease in the deferred tax liabilities.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A reconciliation of reported income tax expense for PowerPSE&G with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35%21% is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| PSE&G | | 2023 | | 2022 | | 2021 | |
| | | Millions | |
| Net Income | | $ | 1,515 | | | $ | 1,565 | | | $ | 1,446 | | |
| Income Taxes: | | | | | | | |
| Operating Income: | | | | | | | |
| Current Expense (Benefit): | | | | | | | |
| Federal | | $ | 127 | | | $ | 130 | | | $ | 208 | | |
| State | | 4 | | | — | | | 1 | | |
| Total Current | | 131 | | | 130 | | | 209 | | |
| Deferred Expense (Benefit): | | | | | | | |
| Federal | | (113) | | | (17) | | | (33) | | |
| State | | 149 | | | 159 | | | 153 | | |
| Total Deferred | | 36 | | | 142 | | | 120 | | |
| ITC | | (7) | | | (5) | | | (5) | | |
| Total Income Tax Expense | | $ | 160 | | | $ | 267 | | | $ | 324 | | |
| Pre-Tax Income | | $ | 1,675 | | | $ | 1,832 | | | $ | 1,770 | | |
| Tax Computed at Statutory Rate @ 21% | | $ | 352 | | | $ | 385 | | | $ | 372 | | |
| Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: | | | | | | | |
| State Income Taxes (net of federal income tax) | | 121 | | | 126 | | | 122 | | |
| Uncertain Tax Positions | | (9) | | | 2 | | | 2 | | |
| Plant-Related Items | | (7) | | | (6) | | | (7) | | |
| Tax Credits | | (9) | | | (9) | | | (8) | | |
| GPRC-CEF-EE | | (52) | | | (37) | | | (13) | | |
| TAC | | (232) | | | (193) | | | (171) | | |
| Bad Debt Flow-Through | | (9) | | | (1) | | | 27 | | |
| Other | | 5 | | | — | | | — | | |
| Subtotal | | (192) | | | (118) | | | (48) | | |
| Total Income Tax Expense | | $ | 160 | | | $ | 267 | | | $ | 324 | | |
| Effective Income Tax Rate | | 9.6 | % | | 14.6 | % | | 18.3 | % | |
| | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| Power | | 2017 | | 2016 | | 2015 | |
| | | Millions | |
| Net Income | | $ | 479 |
| | $ | 18 |
| | $ | 856 |
| |
| Income Taxes: | | | | | | | |
| Operating Income: | | | | | | | |
| Current Expense (Benefit): | | | | | | | |
| Federal | | $ | 95 |
| | $ | 107 |
| | $ | 220 |
| |
| State | | (17 | ) | | 40 |
| | 30 |
| |
| Total Current | | 78 |
| | 147 |
| | 250 |
| |
| Deferred (Benefit) Expense: | | | | | | | |
| Federal | | (804 | ) | | (222 | ) | | 189 |
| |
| State | | (37 | ) | | (68 | ) | | 52 |
| |
| Total Deferred | | (841 | ) | | (290 | ) | | 241 |
| |
| ITC | | 34 |
| | 82 |
| | 20 |
| |
| Total Income Tax (Benefit) Expense | | $ | (729 | ) | | $ | (61 | ) | | $ | 511 |
| |
| Pre-Tax (Loss) Income | | $ | (250 | ) | | $ | (43 | ) | | $ | 1,367 |
| |
| Tax Computed at Statutory Rate @ 35% | | $ | (88 | ) | | $ | (15 | ) | | $ | 478 |
| |
| Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: | | | | | | | |
| State Income Taxes (net of federal income tax) | | (36 | ) | | (18 | ) | | 59 |
| |
| Manufacturing Deduction | | (13 | ) | | (17 | ) | | (10 | ) | |
| NDT Fund | | 19 |
| | 3 |
| | 7 |
| |
| Tax Credits | | (12 | ) | | (18 | ) | | (7 | ) | |
| Uncertain Tax Positions | | 7 |
| | 9 |
| | 22 |
| |
| Audit Settlement | | 1 |
| | — |
| | — |
| |
| Nuclear Decommissioning Tax Carryback | | — |
| | — |
| | (33 | ) | |
| Provisional Deferred Tax Benefit - Tax Act | | (610 | ) | | — |
| | — |
| |
| Other | | 3 |
| | (5 | ) | | (5 | ) | |
| Sub-Total | | (641 | ) | | (46 | ) | | 33 |
| |
| Total Income Tax (Benefit) Expense | | $ | (729 | ) | | $ | (61 | ) | | $ | 511 |
| |
| Effective Income Tax Rate | | 291.6 | % | | 141.9 | % | | 37.4 | % | |
| | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following is an analysis of deferred income taxes for Power:PSE&G:
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | As of December 31, | |
| PSE&G | | 2023 | | 2022 | |
| | | Millions | |
| Deferred Income Taxes | | | | | |
| Assets: | | | | | |
| Regulatory Liability Excess Deferred Tax | | $ | 339 | | | $ | 390 | | |
| OPEB | | 28 | | | 42 | | |
| CAMT Credit Carryforward | | 106 | | | — | | |
| Bad Debt | | 57 | | | 66 | | |
| Operating Leases | | 22 | | | 19 | | |
| Other | | 60 | | | 56 | | |
| Total Assets | | $ | 612 | | | $ | 573 | | |
| Liabilities: | | | | | |
| Plant-Related Items | | $ | 4,396 | | | $ | 4,174 | | |
| New Jersey Corporate Business Tax | | 1,160 | | | 1,011 | | |
| Pension Costs | | 198 | | | 195 | | |
| Taxes Recoverable Through Future Rates (net) | | 201 | | | 149 | | |
| Conservation Costs | | 88 | | | 81 | | |
| Operating Leases | | 21 | | | 18 | | |
| Other | | 297 | | | 223 | | |
| Total Liabilities | | $ | 6,361 | | | $ | 5,851 | | |
| Summary of Accumulated Deferred Income Taxes: | | | | | |
| Net Deferred Income Tax Liabilities | | $ | 5,749 | | | $ | 5,278 | | |
| ITC | | 64 | | | 70 | | |
| Net Total Deferred Income Taxes and ITC | | $ | 5,813 | | | $ | 5,348 | | |
| | | | | | |
|
| | | | | | | | | | |
| | | | | | |
| | | As of December 31, | |
| Power | | 2017 | | 2016 | |
| | | Millions | |
| Deferred Income Taxes | | | | | |
| Assets: | | | | | |
| Noncurrent: | | | | | |
| Related to Uncertain Tax Positions | | $ | 45 |
| | $ | 53 |
| |
| Pension Costs | | 40 |
| | 68 |
| |
| Contractual Liabilities & Environmental Costs | | 12 |
| | 18 |
| |
| Other | | 93 |
| | 76 |
| |
| Total Noncurrent Assets | | $ | 190 |
| | $ | 215 |
| |
| Liabilities: | | | | | |
| Noncurrent: | | | | | |
| Plant-Related Items | | $ | 935 |
| | $ | 1,605 |
| |
| AROs and NDT Fund | | 235 |
| | 400 |
| |
| New Jersey Corporate Business Tax | | 225 |
| | 214 |
| |
| Total Noncurrent Liabilities | | $ | 1,395 |
| | $ | 2,219 |
| |
| Summary of Accumulated Deferred Income Taxes: | | | | | |
| Net Noncurrent Deferred Income Tax Liabilities | | $ | 1,205 |
| | $ | 2,004 |
| |
| ITC | | 201 |
| | 166 |
| |
| Net Total Noncurrent Deferred Income Taxes and ITC | | $ | 1,406 |
| | $ | 2,170 |
| |
| | | | | | |
In the above table, theThe deferred tax effect of asset retirement obligationscertain assets and liabilities is presented in the table above net of the deferred tax effect ofassociated with the associated funding of those obligations.respective regulatory deferrals.
PSEG and PSE&G and Power each provide deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities irrespective of the treatment for rate-making purposes. Management believes that it is probable that the accumulated tax benefits that previously have been treated as a flow-through item to PSE&G customers will be recovered from or refunded to PSE&G’s customers in the future. See Note 6. Regulatory Assets and Liabilities.
The 2018 decrease in the federal tax rate resulted in PSE&G recording excess deferred income taxes. As of December 31, 2023, the balance was approximately $1.3 billion with a Regulatory Liability of approximately $1.8 billion. In December 2017, the U.S. government enacted comprehensive2023, PSE&G returned approximately $323 million of excess deferred income taxes and previously realized and current period deferred income taxes related to tax legislation.repair deductions to its customers with a reduction to tax expense of approximately $232 million. The Tax Act establishes new tax laws that will take effect in 2018, including, but not limitedflowback to (1) reductioncustomers of the U.S.excess deferred income taxes and previously realized tax repair deductions resulted in a decrease of approximately $243 million in the Regulatory Liability. The current period tax repair deduction reduces tax expense and revenue and recognizes a Regulatory Asset as PSE&G believes it is probable that the current period tax repair deductions flowed through to the customers will be recovered from customers in the future. See Note 6. Regulatory Assets and Liabilities for additional information.
In March 2020, the federal corporate tax rate fromCoronavirus Aid, Relief, and Economic Security Act (CARES Act) was enacted. Among other provisions, the CARES Act allows a maximumfive-year carryback of 35% to 21%; (2) elimination of the corporate alternative minimum tax (AMT); (3) a new limitation on deductible interest expense; (4) the repeal of the domestic production activity deduction; (5) limitations on the deductibility of certain executive compensation; and (6) limitations onany net operating losses (NOLs)loss (NOL) generated in a taxable year beginning after December 31, 2017, and before January 1, 2021.
In April 2020, the IRS issued a private letter ruling to 80% of taxable income. In addition,PSE&G concluding that certain changes were madeexcess deferred taxes previously classified as protected should be classified as unprotected. Unprotected excess deferred income taxes are not subject to the bonus depreciationnormalization rules that will impact 2017.
The SEC staff issued Staff Accounting Bulletin 118 (SAB 118), which provides guidance on accounting for the tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act enactment date for companies to complete the accounting under ASC 740. In accordance with SAB 118, a company must reflect the income tax effects of those aspects of the Tax Act for which the accounting under ASC 740 is complete. To the extent that a company’s accounting for certain income tax effects of the Tax Act is incomplete but it is able to determine a reasonable estimate, it must record a provisional estimate in the financial statements. If a company cannot determine a provisional estimateallowing them to be included inrefunded to customers sooner as agreed to with FERC and the financial statements, it should continueBPU. In July 2020, FERC and the BPU approved PSE&G’s requests to apply ASC 740 on the basis of the provisions of the tax laws that were in effect immediately before the enactment of the Tax Act.
PSEG, PSE&G and Power are subjectrefund these unprotected excess deferred income taxes to ASC 740, which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate change is enacted.
The majority of the current period activity was determined using the federal income tax rate of 35% and state income tax rate of 9%. As required under ASC 740, the ending 2017 deferred tax balances were adjusted to reflect the enacted lower tax rate, which resulted in a one-time, provisional deferred tax benefit of $755 million, including $610 million related to Power and $149 million related to Energy Holdings (including other impacts related to the new tax legislation, PSEG’s net non-cash provisional earnings benefit was $745 million, including $588 million related to Power and $147 million related to Energy
customers. FERC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
approved the refund of these unprotected excess deferred income taxes within the 2019 true-up filing. The BPU approved the refund of these unprotected excess deferred income taxes beginning in July 2020 through December 31, 2024.
Holdings). In addition,July 2020, the IRS issued final and proposed regulations addressing the limitation on deductible business interest expense contained in the Tax Act. These regulations retroactively allow depreciation to be added back in computing the 30% adjusted taxable income (ATI) cap, increasing the amount of interest that can be deducted by unregulated businesses in years before 2022. For 2022 and after, the regulations continue to disallow the addback of depreciation in the computation of ATI, effectively lowering the cap on the amount of deductible business interest and contain special rules in allocating interest between regulated and non-regulated businesses. The portion of PSEG’s and PSEG Power’s business interest expense that was disallowed in 2018 and 2019 under the previously issued proposed regulations will now be deductible in those respective years.
In March 2021, PSEG amended its 2018 federal income tax return to deduct the previously disallowed business interest expense in accordance with the final and proposed regulations issued in July 2020. The 2018 amended return generated a NOL that was carried back to 2013 as provided by the CARES Act. In December 2022, the carryback claim was approved by the IRS, which resulted in a $28 million income statement benefit and the closure of PSEG’s federal tax years through 2018.
In August 2022, the IRA was signed into law. The IRA made certain changes to existing energy tax credit laws and enacted a new 15% CAMT, effective in 2023. For 2023, PSEG and PSE&G had excess deferred taxeshave recorded its best estimate of approximately $2.1 billion as of December 31, 2017 and recorded a $2.9 billion revenuethe impact of thesethe CAMT. To the extent the CAMT exceeds the regular tax liability, the difference can be indefinitely carried forward to reduce regular tax liability in years that it exceeds the CAMT. PSEG and PSE&G anticipate the excess deferred taxes as Regulatory Liabilities where it is probable that refundsCAMT will be madeused in the future and will not result in an impact to customers in future rates.PSEG’s or PSE&G’s income statement. Changes to the energy tax credit laws include: effective 2024 through 2032 a new PTC for existing nuclear generation facilities, effective 2025 a new technology neutral energy tax credit, which includes new nuclear units and increases to nuclear generation capacity, and effective 2023 the transferability of the energy tax credits. The PTC is designed to phase down as the nuclear facilities’ gross receipts increase. The PTC can be increased by five times if the prevailing wages rules are met. The PTC rate and phase down amount are subject to the IRS’ determination of annual inflation.
Despite the issuance of proposed regulations and timingvarious Notices that provide interim guidance on several provisions of any such refund cannot be determined at this time.
For certainthe IRA many aspects of the Tax Act, whichIRA, including the PTC for existing nuclear generation facilities and the CAMT, remain unclear and are discussed below, PSEG, PSE&G and Power made reasonable, good faith estimates for which provisional amounts were recorded.
PSEG’s accounting forin need of further guidance; therefore, the following elementsimpact of several provisions of the Tax ActIRA will have on PSEG's and PSE&G's financial statements is incomplete. However, PSEG was ablesubject to make reasonable, good faith estimatescontinued evaluation.
The enactment of certain effects and, therefore, recorded provisional adjustments for the following: the tax rules regarding the appropriate bonus deprecation rate that should be applied to assets placed in service after September 27, 2017 for Power and PSE&G, including the information required to compute the applicable depreciable tax basis, and the impact on PSEG’s, PSE&G’s and Power’s deferred taxes associated with FIN 48 reserves.
Further, the Tax Act is unclear in certain respects and will require interpretations and implementing regulations by the Internal Revenue Service (IRS), as well asadditional federal or state tax authorities. The Tax Act could also be subject to potential amendmentslegislation and technical corrections whichclarification of previously enacted tax laws could impact PSEG,PSEG’s and PSE&G and Power’s&G’s financial statements.
In December 2015,April 2023, the U.S. government enactedTreasury issued Revenue Procedure 2023-15 that provides a safe harbor method of accounting to determine the Protecting Americans from Tax Hikes Actannual repair tax deduction for gas T&D property. The impact, if any, this may have on PSEG and PSE&G’s financial statements is subject to continued evaluation and has not yet been determined.
As of 2015 (2015 Tax Act). Among other provisions, the 2015 Tax Act included an extension of the bonus depreciation rules and the 30% ITC for qualified property placed into service after 2016. Qualified property that is placed in service from January 1, 2015 through December 31, 2017 is eligible for 50% bonus depreciation. The provisions2023, PSEG had a $33 million state NOL and PSE&G had a $71 million New Jersey Corporate Business Tax NOL that are both expected to be fully realized in the future.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the period beginning September 28, 2017, subject to the transition rules, the Tax Act has modified the bonus depreciation rules of the 2015 Tax Act. Subject to further guidance, it is expected that Power will be entitled to 100% expensing and bonus depreciation will no longer apply to PSE&G.
PSEG recorded the following amounts related to its unrecognized tax benefits, which were primarily comprised of amounts recorded for PSE&G Power and Energy Holdings:PSEG’s other subsidiaries:
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| 2023 | | PSEG | | PSE&G | |
| | | Millions | |
| Total Amount of Unrecognized Tax Benefits as of January 1, 2023 | | $ | 130 | | | $ | 29 | | |
| Increases as a Result of Positions Taken in a Prior Period | | 16 | | | 2 | | |
| Decreases as a Result of Positions Taken in a Prior Period | | (25) | | | (12) | | |
| Increases as a Result of Positions Taken during the Current Period | | — | | | — | | |
| Decreases as a Result of Positions Taken during the Current Period | | — | | | — | | |
| Decreases as a Result of Settlements with Taxing Authorities | | (10) | | | (7) | | |
| Decreases due to Lapses of Applicable Statute of Limitations | | (1) | | | (1) | | |
| Total Amount of Unrecognized Tax Benefits as of December 31, 2023 | | $ | 110 | | | $ | 11 | | |
| Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits | | (29) | | | (7) | | |
| Regulatory Asset—Unrecognized Tax Benefits | | (2) | | | (2) | | |
| Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) | | $ | 79 | | | $ | 2 | | |
| | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| 2022 | | PSEG | | PSE&G | |
| | | Millions | |
| Total Amount of Unrecognized Tax Benefits as of January 1, 2022 | | $ | 192 | | | $ | 27 | | |
| Increases as a Result of Positions Taken in a Prior Period | | 9 | | | 2 | | |
| Decreases as a Result of Positions Taken in a Prior Period | | (40) | | | (2) | | |
| Increases as a Result of Positions Taken during the Current Period | | 1 | | | 1 | | |
| Decreases as a Result of Positions Taken during the Current Period | | — | | | — | | |
| Decreases as a Result of Settlements with Taxing Authorities | | (28) | | | — | | |
| Decreases due to Lapses of Applicable Statute of Limitations | | (4) | | | 1 | | |
| Total Amount of Unrecognized Tax Benefits as of December 31, 2022 | | $ | 130 | | | $ | 29 | | |
| Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits | | (37) | | | (15) | | |
| Regulatory Asset—Unrecognized Tax Benefits | | (8) | | | (8) | | |
| Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) | | $ | 85 | | | $ | 6 | | |
| | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| 2017 | | PSEG | | PSE&G | | Power | | Energy Holdings | |
| | | Millions | |
| Total Amount of Unrecognized Tax Benefits as of January 1, 2017 | | $ | 328 |
| | $ | 140 |
| | $ | 128 |
| | $ | 57 |
| |
| Increases as a Result of Positions Taken in a Prior Period | | 40 |
| | 15 |
| | 18 |
| | 8 |
| |
| Decreases as a Result of Positions Taken in a Prior Period | | (32 | ) | | (11 | ) | | (10 | ) | | (13 | ) | |
| Increases as a Result of Positions Taken during the Current Period | | 12 |
| | 5 |
| | 6 |
| | 1 |
| |
| Decreases as a Result of Positions Taken during the Current Period | | (1 | ) | | (1 | ) | | — |
| | — |
| |
| Decreases as a Result of Settlements with Taxing Authorities | | — |
| | — |
| | — |
| | — |
| |
| Decreases due to Lapses of Applicable Statute of Limitations | | (13 | ) | | (13 | ) | | — |
| | — |
| |
| Total Amount of Unrecognized Tax Benefits as of December 31, 2017 | | $ | 334 |
| | $ | 135 |
| | $ | 142 |
| | $ | 53 |
| |
| Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits | | (157 | ) | | (73 | ) | | (72 | ) | | (12 | ) | |
| Regulatory Asset—Unrecognized Tax Benefits | | (56 | ) | | (56 | ) | | — |
| | — |
| |
| Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) | | $ | 121 |
| | $ | 6 |
| | $ | 70 |
| | $ | 41 |
| |
| | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| 2016 | | PSEG | | PSE&G | | Power | | Energy Holdings | |
| | | Millions | |
| Total Amount of Unrecognized Tax Benefits as of January 1, 2016 | | $ | 386 |
| | $ | 181 |
| | $ | 111 |
| | $ | 93 |
| |
| Increases as a Result of Positions Taken in a Prior Period | | 12 |
| | 3 |
| | 6 |
| | 2 |
| |
| Decreases as a Result of Positions Taken in a Prior Period | | (62 | ) | | (23 | ) | | (1 | ) | | (38 | ) | |
| Increases as a Result of Positions Taken during the Current Period | | 19 |
| | 6 |
| | 12 |
| | — |
| |
| Decreases as a Result of Positions Taken during the Current Period | | — |
| | — |
| | — |
| | — |
| |
| Decreases as a Result of Settlements with Taxing Authorities | | — |
| | — |
| | — |
| | — |
| |
| Decreases due to Lapses of Applicable Statute of Limitations | | (27 | ) | | (27 | ) | | — |
| | — |
| |
| Total Amount of Unrecognized Tax Benefits as of December 31, 2016 | | $ | 328 |
| | $ | 140 |
| | $ | 128 |
| | $ | 57 |
| |
| Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits | | (200 | ) | | (106 | ) | | (74 | ) | | (20 | ) | |
| Regulatory Asset—Unrecognized Tax Benefits | | (31 | ) | | (31 | ) | | — |
| | — |
| |
| Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) | | $ | 97 |
| | $ | 3 |
| | $ | 54 |
| | $ | 37 |
| |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| 2021 | | PSEG | | PSE&G | |
| | | Millions | |
| Total Amount of Unrecognized Tax Benefits as of January 1, 2021 | | $ | 147 | | | $ | 30 | | |
| Increases as a Result of Positions Taken in a Prior Period | | 58 | | | 8 | | |
| Decreases as a Result of Positions Taken in a Prior Period | | (19) | | | (12) | | |
| Increases as a Result of Positions Taken during the Current Period | | 6 | | | 1 | | |
| Decreases as a Result of Positions Taken during the Current Period | | — | | | — | | |
| Decreases as a Result of Settlements with Taxing Authorities | | — | | | — | | |
| Decreases due to Lapses of Applicable Statute of Limitations | | — | | | — | | |
| Total Amount of Unrecognized Tax Benefits as of December 31, 2021 | | $ | 192 | | | $ | 27 | | |
| Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits | | (76) | | | (15) | | |
| Regulatory Asset—Unrecognized Tax Benefits | | (7) | | | (7) | | |
| Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) | | $ | 109 | | | $ | 5 | | |
| | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| 2015 | | PSEG | | PSE&G | | Power | | Energy Holdings | |
| | | Millions | |
| Total Amount of Unrecognized Tax Benefits as of January 1, 2015 | | $ | 332 |
| | $ | 165 |
| | $ | 70 |
| | $ | 95 |
| |
| Increases as a Result of Positions Taken in a Prior Period | | 87 |
| | 55 |
| | 28 |
| | 4 |
| |
| Decreases as a Result of Positions Taken in a Prior Period | | (50 | ) | | (43 | ) | | (6 | ) | | (1 | ) | |
| Increases as a Result of Positions Taken during the Current Period | | 28 |
| | 5 |
| | 23 |
| | — |
| |
| Decreases as a Result of Positions Taken during the Current Period | | (1 | ) | | (1 | ) | | — |
| | — |
| |
| Decreases as a Result of Settlements with Taxing Authorities | | (10 | ) | | — |
| | (4 | ) | | (5 | ) | |
| Decreases due to Lapses of Applicable Statute of Limitations | | — |
| | — |
| | — |
| | — |
| |
| Total Amount of Unrecognized Tax Benefits as of December 31, 2015 | | $ | 386 |
| | $ | 181 |
| | $ | 111 |
| | $ | 93 |
| |
| Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits | | (264 | ) | | (162 | ) | | (68 | ) | | (34 | ) | |
| Regulatory Asset—Unrecognized Tax Benefits | | (27 | ) | | (27 | ) | | — |
| | — |
| |
| Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) | | $ | 95 |
| | $ | (8 | ) | | $ | 43 |
| | $ | 59 |
| |
| | | | | | | | | | |
In 2022, the IRS approved PSEG’s 2018 carryback claim, which resulted in the closure of PSEG’s federal tax years through 2018.PSEG and its subsidiaries include accrued interest and penalties related to uncertain tax positions required to be recorded as Income Tax Expense in the Consolidated Statements of Operations. Accumulated interest and penalties that are recorded on the Consolidated Balance Sheets on uncertain tax positions were as follows:
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | Accumulated Interest and Penalties on Uncertain Tax Positions as of December 31, | |
| | | 2017 | | 2016 | | 2015 | |
| | | Millions | |
| PSE&G | | $ | 25 |
| | $ | 22 |
| | $ | 20 |
| |
| Power | | 24 |
| | 17 |
| | 6 |
| |
| Energy Holdings | | 21 |
| | 20 |
| | 40 |
| |
| Total | | $ | 70 |
| | $ | 59 |
| | $ | 66 |
| |
| | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | Accumulated Interest and Penalties on Uncertain Tax Positions as of December 31, | |
| | | 2023 | | 2022 | | 2021 | |
| | | Millions | |
| PSEG | | $ | 25 | | | $ | 38 | | | $ | 31 | | |
| PSE&G | | $ | 1 | | | $ | 8 | | | $ | 9 | | |
| | | | | | | | |
It is reasonably possible that total unrecognized tax benefits will significantly increase or decrease within the next twelve months due to either agreements with various taxing authorities upon audit, the expiration of the Statute of Limitations, or other pending tax matters. These potential increases or decreases are as follows:
|
| | | | | | |
| | | | |
| Possible (Increase)/Decrease in Total Unrecognized Tax Benefits | | Over the next 12 Months | |
| | | Millions | |
| PSEG | | $ | 69 |
| |
| PSE&G | | $ | 35 |
| |
| Power | | $ | 30 |
| |
| | | | |
| | | | | | | | | | | | | | |
| | | | |
| Possible Decrease in Total Unrecognized Tax Benefits | | Over the next 12 Months | |
| | | Millions | |
| PSEG | | $ | 17 | | |
| PSE&G | | $ | 2 | | |
| | | | |
A description of income tax years that remain subject to examination by material jurisdictions, where an examination has not already concluded are:
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | PSEG | | PSE&G | |
| United States | | | | | | | | |
| Federal | | 2020-2022 | | N/A | | | | | | |
| New Jersey | | 2011-2022 | | 2015-2022 | | PSEG | PSE&G | | Power | |
| Pennsylvania | | United States2017-2022 | | 2019-2022 | | | | | | |
| Connecticut | | Federal2019-2022 | | N/A | | 2011-2016 | N/A | | N/A | |
| Maryland | | New Jersey2020-2022 | | N/A | | 2006-2016 | 2011-2016 | | N/A | |
| New York | | Pennsylvania2017-2022 | | N/A | | 2014-2016 | 2014-2016 | | N/A | |
| | Connecticut | | 2016 | | N/A | N/A | |
| Texas | | 2008-2016 | | N/A | | N/A | |
| California | | 2006-2016 | | N/A | | N/A | |
| New York | | 2014-2016 | | N/A | | 2014-2016 | |
| | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 21. Accumulated Other Comprehensive Income (Loss), Net of Tax
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| PSEG | | Other Comprehensive Income (Loss) | |
| Accumulated Other Comprehensive Income (Loss) | | Cash Flow Hedges | | Pension and OPEB Plans | | Available-for -Sale Securities | | Total | |
| | | Millions | |
| Balance as of December 31, 2014 | | $ | 10 |
| | $ | (411 | ) | | $ | 118 |
| | $ | (283 | ) | |
| Other Comprehensive Income before Reclassifications | | 2 |
| | (7 | ) | | (25 | ) | | (30 | ) | |
| Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | (12 | ) | | 32 |
| | (2 | ) | | 18 |
| |
| Net Current Period Other Comprehensive Income (Loss) | | (10 | ) | | 25 |
| | (27 | ) | | (12 | ) | |
| Balance as of December 31, 2015 | | $ | — |
| | $ | (386 | ) | | $ | 91 |
| | $ | (295 | ) | |
| Other Comprehensive Income before Reclassifications | | 2 |
| | (45 | ) | | 40 |
| | (3 | ) | |
| Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | — |
| | 33 |
| | 2 |
| | 35 |
| |
| Net Current Period Other Comprehensive Income (Loss) | | 2 |
| | (12 | ) | | 42 |
| | 32 |
| |
| Balance as of December 31, 2016 | | $ | 2 |
| | $ | (398 | ) | | $ | 133 |
| | $ | (263 | ) | |
| Other Comprehensive Income before Reclassifications | | — |
| | (32 | ) | | 109 |
| | 77 |
| |
| Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | (2 | ) | | 24 |
| | (65 | ) | | (43 | ) | |
| Net Current Period Other Comprehensive Income (Loss) | | (2 | ) | | (8 | ) | | 44 |
| | 34 |
| |
| Balance as of December 31, 2017 | | $ | — |
| | $ | (406 | ) | | $ | 177 |
| | $ | (229 | ) | |
| | | | | | | | | | |
| Power | | Other Comprehensive Income (Loss) | |
| Accumulated Other Comprehensive Income (Loss) | | Cash Flow Hedges | | Pension and OPEB Plans | | Available-for -Sale Securities | | Total | |
| | | Millions | |
| Balance as of December 31, 2014 | | $ | 11 |
| | $ | (351 | ) | | $ | 112 |
| | $ | (228 | ) | |
| Other Comprehensive Income before Reclassifications | | 1 |
| | (4 | ) | | (24 | ) | | (27 | ) | |
| Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | (12 | ) | | 28 |
| | (1 | ) | | 15 |
| |
| Net Current Period Other Comprehensive Income (Loss) | | (11 | ) | | 24 |
| | (25 | ) | | (12 | ) | |
| Balance as of December 31, 2015 | | $ | — |
| | $ | (327 | ) | | $ | 87 |
| | $ | (240 | ) | |
| Other Comprehensive Income before Reclassifications | | — |
| | (42 | ) | | 39 |
| | (3 | ) | |
| Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | — |
| | 29 |
| | 3 |
| | 32 |
| |
| Net Current Period Other Comprehensive Income (Loss) | | — |
| | (13 | ) | | 42 |
| | 29 |
| |
| Balance as of December 31, 2016 | | $ | — |
| | $ | (340 | ) | | $ | 129 |
| | $ | (211 | ) | |
| Other Comprehensive Income before Reclassifications | | — |
| | (28 | ) | | 106 |
| | 78 |
| |
| Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | — |
| | 21 |
| | (60 | ) | | (39 | ) | |
| Net Current Period Other Comprehensive Income (Loss) | | — |
| | (7 | ) | | 46 |
| | 39 |
| |
| Balance as of December 31, 2017 | | $ | — |
| | $ | (347 | ) | | $ | 175 |
| | $ | (172 | ) | |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| PSEG | | Other Comprehensive Income (Loss) | |
| Accumulated Other Comprehensive Income (Loss) | | Cash Flow Hedges | | Pension and OPEB Plans | | Available-for -Sale Securities | | Total | |
| | | Millions | |
| Balance as of December 31, 2020 | | $ | (9) | | | $ | (545) | | | $ | 50 | | | $ | (504) | | |
| Current Period Other Comprehensive Income (Loss) | | | | | | | | | |
| Other Comprehensive Income (Loss) before Reclassifications | | — | | | 176 | | | (33) | | | 143 | | |
| Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | 3 | | | 14 | | | (6) | | | 11 | | |
| Net Current Period Other Comprehensive Income (Loss) | | 3 | | | 190 | | | (39) | | | 154 | | |
| Balance as of December 31, 2021 | | $ | (6) | | | $ | (355) | | | $ | 11 | | | $ | (350) | | |
| Other Comprehensive Income (Loss) before Reclassifications | | — | | | (72) | | | (158) | | | (230) | | |
| Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | 3 | | | 1 | | | 26 | | | 30 | | |
| Net Current Period Other Comprehensive Income (Loss) | | 3 | | | (71) | | | (132) | | | (200) | | |
| Balance as of December 31, 2022 | | $ | (3) | | | $ | (426) | | | $ | (121) | | | $ | (550) | | |
| Other Comprehensive Income (Loss) before Reclassifications | | 9 | | | 76 | | | 61 | | | 146 | | |
| Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | (3) | | | 248 | | | (20) | | | 225 | | |
| Net Current Period Other Comprehensive Income (Loss) | | 6 | | | 324 | | | 41 | | | 371 | | |
| Balance as of December 31, 2023 | | $ | 3 | | | $ | (102) | | | $ | (80) | | | $ | (179) | | |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| PSEG | | | | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Statement of Operations | |
| | | | | Year Ended December 31, 2021 | |
| Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | Location of Pre-Tax Amount in Statement of Operations | | Pre-Tax Amount | | Tax (Expense) Benefit | | After-Tax Amount | |
| | | | | Millions | |
| Cash Flow Hedges | | | | | | | | | |
| Interest Rate Derivatives | | Interest Expense | | $ | (4) | | | $ | 1 | | | $ | (3) | | |
| Total Cash Flow Hedges | | | | (4) | | | 1 | | | (3) | | |
| Pension and OPEB Plans | | | | | | | | | |
| Amortization of Prior Service (Cost) Credit | | Net Non-Operating Pension and OPEB Credits (Costs) | | 21 | | | (6) | | | 15 | | |
| Amortization of Actuarial Loss | | Net Non-Operating Pension and OPEB Credits (Costs) | | (41) | | | 12 | | | (29) | | |
| Total Pension and OPEB Plans | | | | (20) | | | 6 | | | (14) | | |
| Available-for-Sale Securities | | | | | | | | | |
| Realized Gains (Losses) | | Net Gains (Losses) on Trust Investments | | 9 | | | (3) | | | 6 | | |
| Total Available-for-Sale Securities | | | | 9 | | | (3) | | | 6 | | |
| Total | | | | $ | (15) | | | $ | 4 | | | $ | (11) | | |
| | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| PSEG | | | | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement | |
| | | | | Year Ended December 31, 2015 | |
| Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | Location of Pre-Tax Amount In Statement of Operations | | Pre-Tax Amount | | Tax (Expense) Benefit | | After-Tax Amount | |
| | | | | Millions | |
| Cash Flow Hedges | | | | | | | | | |
| Energy-Related Contracts | | Operating Revenues | | $ | 20 |
| | $ | (8 | ) | | $ | 12 |
| |
| Total Cash Flow Hedges | | | | 20 |
| | (8 | ) | | 12 |
| |
| Pension and OPEB Plans | | | | | | | | | |
| Amortization of Prior Service (Cost) Credit | | O&M Expense | | 12 |
| | (3 | ) | | 9 |
| |
| Amortization of Actuarial Loss | | O&M Expense | | (68 | ) | | 27 |
| | (41 | ) | |
| Total Pension and OPEB Plans | | | | (56 | ) | | 24 |
| | (32 | ) | |
| Available-for-Sale Securities | | | | | | | | | |
| Realized Gains | | Other Income | | 100 |
| | (52 | ) | | 48 |
| |
| Realized Losses | | Other Deductions | | (39 | ) | | 20 |
| | (19 | ) | |
| Other-Than-Temporary Impairments (OTTI) | | OTTI | | (53 | ) | | 26 |
| | (27 | ) | |
| Total Available-for-Sale Securities | | | | 8 |
| | (6 | ) | | 2 |
| |
| Total | | | | $ | (28 | ) | | $ | 10 |
| | $ | (18 | ) | |
| | | | | | | | | | |
| Power | | | | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement | |
| | | | | Year Ended December 31, 2015 | |
| Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | Location of Pre-Tax Amount In Statement of Operations | | Pre-Tax Amount | | Tax (Expense) Benefit | | After-Tax Amount | |
| | | | | Millions | |
| Cash Flow Hedges | | | | | | | | | |
| Energy-Related Contracts | | Operating Revenues | | $ | 20 |
| | $ | (8 | ) | | $ | 12 |
| |
| Total Cash Flow Hedges | | | | 20 |
| | (8 | ) | | 12 |
| |
| Pension and OPEB Plans | | | | | | | | | |
| Amortization of Prior Service (Cost) Credit | | O&M Expense | | 11 |
| | (3 | ) | | 8 |
| |
| Amortization of Actuarial Loss | | O&M Expense | | (60 | ) | | 24 |
| | (36 | ) | |
| Total Pension and OPEB Plans | | | | (49 | ) | | 21 |
| | (28 | ) | |
| Available-for-Sale Securities | | | | | | | | | |
| Realized Gains | | Other Income | | 98 |
| | (51 | ) | | 47 |
| |
| Realized Losses | | Other Deductions | | (38 | ) | | 19 |
| | (19 | ) | |
| OTTI | | OTTI | | (53 | ) | | 26 |
| | (27 | ) | |
| Total Available-for-Sale Securities | | | | 7 |
| | (6 | ) | | 1 |
| |
| Total | | | | $ | (22 | ) | | $ | 7 |
| | $ | (15 | ) | |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| PSEG | | | | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Statement of Operations | |
| | | | | Year Ended December 31, 2022 | |
| Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | Location of Pre-Tax Amount in Statement of Operations | | Pre-Tax Amount | | Tax (Expense) Benefit | | After-Tax Amount | |
| | | | | Millions | |
| Cash Flow Hedges | | | | | | | | | |
| Interest Rate Derivatives | | Interest Expense | | $ | (5) | | | $ | 2 | | | $ | (3) | | |
| Total Cash Flow Hedges | | | | (5) | | | 2 | | | (3) | | |
| Pension and OPEB Plans | | | | | | | | | |
| Amortization of Prior Service (Cost) Credit | | Net Non-Operating Pension and OPEB Credits (Costs) | | 21 | | | (6) | | | 15 | | |
| Amortization of Actuarial Loss | | Net Non-Operating Pension and OPEB Credits (Costs) | | (22) | | | 6 | | | (16) | | |
| Total Pension and OPEB Plans | | | | (1) | | | — | | | (1) | | |
| Available-for-Sale Securities | | | | | | | | | |
| Realized Gains (Losses) | | Net Gains (Losses) on Trust Investments | | (43) | | | 17 | | | (26) | | |
| Total Available-for-Sale Securities | | | | (43) | | | 17 | | | (26) | | |
| Total | | | | $ | (49) | | | $ | 19 | | | $ | (30) | | |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| PSEG | | | | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Statement of Operations | |
| | | | | Year Ended December 31, 2023 | |
| Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | Location of Pre-Tax Amount in Statement of Operations | | Pre-Tax Amount | | Tax (Expense) Benefit | | After-Tax Amount | |
| | | | | Millions | |
| Cash Flow Hedges | | | | | | | | | |
| | | | | | | | | | |
| Interest Rate Derivatives | | Interest Expense | | $ | 5 | | | $ | (2) | | | $ | 3 | | |
| Total Cash Flow Hedges | | | | 5 | | | (2) | | | 3 | | |
| Pension and OPEB Plans | | | | | | | | | |
| Amortization of Prior Service (Cost) Credit | | Net Non-Operating Pension and OPEB Credits (Costs) | | 8 | | | (2) | | | 6 | | |
| Amortization of Actuarial Loss | | Net Non-Operating Pension and OPEB Credits (Costs) | | (20) | | | 6 | | | (14) | | |
| Pension Settlement Charge | | Net Non-Operating Pension and OPEB Credits (Costs) | | (334) | | | 94 | | | (240) | | |
| Total Pension and OPEB Plans | | | | (346) | | | 98 | | | (248) | | |
| Available-for-Sale Securities | | | | | | | | | |
| Realized Gains (Losses) | | Net Gains (Losses) on Trust Investments | | 34 | | | (14) | | | 20 | | |
| Total Available-for-Sale Securities | | | | 34 | | | (14) | | | 20 | | |
| Total | | | | $ | (307) | | | $ | 82 | | | $ | (225) | | |
| | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| PSEG | | | | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement | |
| | | | | Year Ended December 31, 2016 | |
| Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | Location of Pre-Tax Amount In Statement of Operations | | Pre-Tax Amount | | Tax (Expense) Benefit | | After-Tax Amount | |
| | | | | Millions | |
| Pension and OPEB Plans | | | | | | | | | |
| Amortization of Prior Service (Cost) Credit | | O&M Expense | | $ | 12 |
| | $ | (5 | ) | | $ | 7 |
| |
| Amortization of Actuarial Loss | | O&M Expense | | (68 | ) | | 28 |
| | (40 | ) | |
| Total Pension and OPEB Plans | | | | (56 | ) | | 23 |
| | (33 | ) | |
| Available-for-Sale Securities | | | | | | | | | |
| Realized Gains | | Other Income | | 59 |
| | (29 | ) | | 30 |
| |
| Realized Losses | | Other Deductions | | (37 | ) | | 19 |
| | (18 | ) | |
| OTTI | | OTTI | | (28 | ) | | 14 |
| | (14 | ) | |
| Total Available-for-Sale Securities | | | | (6 | ) | | 4 |
| | (2 | ) | |
| Total | | | | $ | (62 | ) | | $ | 27 |
| | $ | (35 | ) | |
| | | | | | | | | | |
| Power | | | | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement | |
| | | | | Year Ended December 31, 2016 | |
| Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | Location of Pre-Tax Amount In Statement of Operations | | Pre-Tax Amount | | Tax (Expense) Benefit | | After-Tax Amount | |
| | | | | Millions | |
| Pension and OPEB Plans | | | | | | | | | |
| Amortization of Prior Service (Cost) Credit | | O&M Expense | | $ | 11 |
| | $ | (5 | ) | | $ | 6 |
| |
| Amortization of Actuarial Loss | | O&M Expense | | (59 | ) | | 24 |
| | (35 | ) | |
| Total Pension and OPEB Plans | | | | (48 | ) | | 19 |
| | (29 | ) | |
| Available-for-Sale Securities | | | | | | | | | |
| Realized Gains | | Other Income | | 55 |
| | (28 | ) | | 27 |
| |
| Realized Losses | | Other Deductions | | (33 | ) | | 17 |
| | (16 | ) | |
| OTTI | | OTTI | | (28 | ) | | 14 |
| | (14 | ) | |
| Total Available-for-Sale Securities | | | | (6 | ) | | 3 |
| | (3 | ) | |
| Total | | | | $ | (54 | ) | | $ | 22 |
| | $ | (32 | ) | |
| | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| PSEG | | | | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement | |
| | | | | Year Ended December 31, 2017 | |
| Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | Location of Pre-Tax Amount In Statement of Operations | | Pre-Tax Amount | | Tax (Expense) Benefit | | After-Tax Amount | |
| | | | | Millions | |
| Cash Flow Hedges | | | | | | | | | |
| Interest Rate Swaps | | Interest Expense | | 3 |
| | (1 | ) | | 2 |
| |
| Total Cash Flow Hedges | | | | 3 |
| | (1 | ) | | 2 |
| |
| Pension and OPEB Plans | | | | | | | | | |
| Amortization of Prior Service (Cost) Credit | | O&M Expense | | $ | 10 |
| | $ | (4 | ) | | $ | 6 |
| |
| Amortization of Actuarial Loss | | O&M Expense | | (51 | ) | | 21 |
| | (30 | ) | |
| Total Pension and OPEB Plans | | | | (41 | ) | | 17 |
| | (24 | ) | |
| Available-for-Sale Securities | | | | | | | | | |
| Realized Gains | | Other Income | | 174 |
| | (89 | ) | | 85 |
| |
| Realized Losses | | Other Deductions | | (28 | ) | | 14 |
| | (14 | ) | |
| OTTI | | OTTI | | (12 | ) | | 6 |
| | (6 | ) | |
| Total Available-for-Sale Securities | | | | 134 |
| | (69 | ) | | 65 |
| |
| Total | | | | $ | 96 |
| | $ | (53 | ) | | $ | 43 |
| |
| | | | | | | | | | |
| Power | | | | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement | |
| | | | | Year Ended December 31, 2017 | |
| Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | Location of Pre-Tax Amount In Statement of Operations | | Pre-Tax Amount | | Tax (Expense) Benefit | | After-Tax Amount | |
| | | | | Millions | |
| Pension and OPEB Plans | | | | | | | | | |
| Amortization of Prior Service (Cost) Credit | | O&M Expense | | $ | 9 |
| | $ | (4 | ) | | $ | 5 |
| |
| Amortization of Actuarial Loss | | O&M Expense | | (44 | ) | | 18 |
| | (26 | ) | |
| Total Pension and OPEB Plans | | | | (35 | ) | | 14 |
| | (21 | ) | |
| Available-for-Sale Securities | | | | | | | | | |
| Realized Gains | | Other Income | | 161 |
| | (83 | ) | | 78 |
| |
| Realized Losses | | Other Deductions | | (24 | ) | | 12 |
| | (12 | ) | |
| OTTI | | OTTI | | (12 | ) | | 6 |
| | (6 | ) | |
| Total Available-for-Sale Securities | | | | 125 |
| | (65 | ) | | 60 |
| |
| Total | | | | $ | 90 |
| | $ | (51 | ) | | $ | 39 |
| |
| | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 22. Earnings Per Share (EPS) and Dividends
EPS
Basic EPS is calculated by dividing Net Income (Loss) by the weighted average number of shares of common stock outstanding. Diluted EPS is calculated by dividing Net Income (Loss) by the weighted average number of shares of common stock outstanding, includingplus dilutive potential shares issuable upon exercise of stock options outstanding or vesting of restricted stock awards granted underrelated to PSEG’s stock compensation plans and upon payment of performance units or restricted stock units.based compensation. For additional information on PSEG’s stock compensation plans see Note 18. Stock Based Compensation. The following table shows the effect of these stock options, performance units and restricted stock unitsdilutive potential shares on the weighted average number of shares outstanding used in calculating diluted EPS:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2023 | | 2022 | | 2021 | |
| | | Basic | | Diluted | | Basic | | Diluted | | Basic | | Diluted | |
| EPS Numerator: | | | | | | | | | | | | | |
| (Millions) | | | | | | | | | | | | | |
| Net Income (Loss) | | $ | 2,563 | | | $ | 2,563 | | | $ | 1,031 | | | $ | 1,031 | | | $ | (648) | | | $ | (648) | | |
| EPS Denominator: | | | | | | | | | | | | | |
| (Millions) | | | | | | | | | | | | | |
| Weighted Average Common Shares Outstanding | | 498 | | | 498 | | | 498 | | | 498 | | | 504 | | | 504 | | |
| Effect of Stock Based Compensation Awards | | — | | | 2 | | | — | | | 3 | | | — | | | — | | |
| Total Shares | | 498 | | | 500 | | | 498 | | | 501 | | | 504 | | | 504 | | |
| EPS: | | | | | | | | | | | | | |
| Net Income (Loss) | | $ | 5.15 | | | $ | 5.13 | | | $ | 2.07 | | | $ | 2.06 | | | $ | (1.29) | | | $ | (1.29) | | |
| | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2017 | | 2016 | | 2015 | |
| | | Basic | | Diluted | | Basic | | Diluted | | Basic | | Diluted | |
| EPS Numerator: | | | | | | | | | | | | | |
| (Millions) | | | | | | | | | | | | | |
| Net Income | | $ | 1,574 |
| | $ | 1,574 |
| | $ | 887 |
| | $ | 887 |
| | $ | 1,679 |
| | $ | 1,679 |
| |
| EPS Denominator: | | | | | | | | | | | | | |
| (Millions) | | | | | | | | | | | | | |
| Weighted Average Common Shares Outstanding | | 505 |
| | 505 |
| | 505 |
| | 505 |
| | 505 |
| | 505 |
| |
| Effect of Stock Based Compensation Awards | | — |
| | 2 |
| | — |
| | 3 |
| | — |
| | 3 |
| |
| Total Shares | | 505 |
| | 507 |
| | 505 |
| | 508 |
| | 505 |
| | 508 |
| |
| EPS: | | | | | | | | | | | | | |
| Net Income | | $ | 3.12 |
| | $ | 3.10 |
| | $ | 1.76 |
| | $ | 1.75 |
| | $ | 3.32 |
| | $ | 3.30 |
| |
| | | | | | | | | | | | | | |
ThereApproximately 3 million potentially dilutive shares were approximately 0.4 million and 0.5 million stock options excluded from the weighted average commontotal shares used forto calculate the diluted EPS due to their antidilutive effectloss per share for the yearsyear ended December 31, 20162021, as their impact was antidilutive.
Fromtime to time, PSEG may repurchase shares to satisfy obligations under equity compensation awards and 2015, respectively.repurchase shares to satisfy purchases by employees under the ESPP.
For additional information on all the types of long-term incentive awards, see Note 18. Stock Based Compensation.
During 2022, PSEG completed a $500 million share repurchase program authorized by the Board of Directors in September 2021 resulting in an aggregate repurchase of approximately 7.4 million shares.
Common Stock Dividends
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| Dividend Payments on Common Stock | | 2017 | | 2016 | | 2015 | |
| Per Share | | $ | 1.72 |
| | $ | 1.64 |
| | $ | 1.56 |
| |
| in Millions | | $ | 870 |
| | $ | 830 |
| | $ | 789 |
| |
| | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| Dividend Payments on Common Stock | | 2023 | | 2022 | | 2021 | |
| Per Share | | $ | 2.28 | | | $ | 2.16 | | | $ | 2.04 | | |
| in Millions | | $ | 1,137 | | | $ | 1,079 | | | $ | 1,031 | | |
| | | | | | | | |
On February 20, 2018,13, 2024, PSEG’s Board of Directors approved a $0.45$0.60 per share common stock dividend for the first quarter of 2018.2024.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 23. Financial Information by Business Segment
Basis of Organization
PSEG’s and PSE&G’s and Power’s operating segments were determined by management in accordance with GAAP. These segments were determined based on how managementthe Chief Operating Decision Maker (CODM) (the Chief Executive Officer (CEO) for PSEG and PSE&G), measures performance based on segment Net Income as illustrated in the following table, and how resources are allocated to each business. PSEG’s
Following completion of the sale of the PSEG Power Fossil portfolio in February 2022 and as a result of the transition to a new CEO, our designated CODM, effective September 1, 2022, various changes have been made to the content and manner in
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
which the new CEO reviews financial information for purposes of assessing business performance and allocating resources. Based on management’s analysis, PSE&G and PSEG Power were determined to remain operating segments of PSEG. However, PSEG revised its reportable segments areto PSE&G and Power.PSEG Power & Other. PSE&G andcontinues to be PSEG’s principal reportable segment. The PSEG Power each represent a single& Other reportable segment includes amounts related to the PSEG Power operating segment as well as amounts applicable to Energy Holdings, PSEG LI, PSEG (parent corporation) and therefore no separateServices, which do not meet the definition of operating segments individually or in the aggregate and are immaterial to PSEG’s consolidated assets and results. All periods presented in the following tables reflect the change in segment information is provided for these Registrants.presentation.
PSE&G
PSE&G earns revenues from its tariffs, under which it provides electric transmission and electric and gas distribution services to residential, commercial and industrial customers in New Jersey. The rates charged for electric transmission are regulated by FERC while the rates charged for electric and gas distribution are regulated by the BPU. Revenues are also earned from several other activities such as investments in EE equipment on customers’ premises, solar investments, sundry sales, the appliance service business wholesale transmission services and other miscellaneous services.
PSEG Power & Other
This reportable segment is comprised primarily of PSEG Power which earns revenues primarily by selling energy, capacity and ancillary services on a wholesale basis under contract to power marketers and to load serving entities and by bidding energy, capacity and ancillary services into the markets for these products. A significant portion of Power’s revenue is obtained from the various ISOs in which Power operates. The ISOs act similarly to a clearing house for all of its members in that all revenues paid out are collected from market participants based on their consumption of energy and energy-related products.PSEG Power also enters into bilateral contracts for energy, capacity, FTRs, gas emission allowances and other energy-related contracts to optimize the value of its portfolio of generating assets and its electric and gas supply obligations.
Other In addition, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants receive ZEC revenue from the EDCs in New Jersey including PSE&G.
This categoryreportable segment also includes amounts applicable to Energy Holdings and PSEG LI, which are belowgenerates revenues under its contract with LIPA, primarily for the quantitative thresholdrecovery of costs when Servco is a principal in the transaction (see Note 4. Variable Interest Entity for separate disclosureadditional information) as reportable segments.well as fixed and variable fee components under the contract, and Energy Holdings which holds an immaterial portfolio of remaining lease investments. Other also includes amounts applicable to PSEG (parent corporation) and Services.
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | PSE&G | | Power | | Other (A) | | Eliminations (B) | | Consolidated Total | |
| | | Millions | |
| Year Ended December 31, 2017 | | | | | | | | | | | |
| Operating Revenues | | $ | 6,234 |
| | $ | 3,930 |
| | $ | 466 |
| | $ | (1,546 | ) | | $ | 9,084 |
| |
| Depreciation and Amortization | | 685 |
| | 1,268 |
| | 33 |
| | — |
| | 1,986 |
| |
| Operating Income (Loss) | | 1,752 |
| | (359 | ) | | 36 |
| | — |
| | 1,429 |
| |
| Income from Equity Method Investments | | — |
| | 14 |
| | — |
| | — |
| | 14 |
| |
| Interest Income | | 24 |
| | 3 |
| | 5 |
| | (2 | ) | | 30 |
| |
| Interest Expense | | 303 |
| | 50 |
| | 40 |
| | (2 | ) | | 391 |
| |
| Income (Loss) before Income Taxes | | 1,536 |
| | (250 | ) | | (18 | ) | | — |
| | 1,268 |
| |
| Income Tax Expense (Benefit) | | 563 |
| | (729 | ) | | (140 | ) | | — |
| | (306 | ) | |
| Net Income (Loss) | | 973 |
| | 479 |
| | 122 |
| | — |
| | 1,574 |
| |
| Gross Additions to Long-Lived Assets | | $ | 2,919 |
| | $ | 1,231 |
| | $ | 40 |
| | $ | — |
| | $ | 4,190 |
| |
| As of December 31, 2017 | | | | | | | | | | | |
| Total Assets | | $ | 28,554 |
| | $ | 12,418 |
| | $ | 2,666 |
| | $ | (922 | ) | | $ | 42,716 |
| |
| Investments in Equity Method Subsidiaries | | $ | — |
| | $ | 87 |
| | $ | — |
| | $ | — |
| | $ | 87 |
| |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | PSE&G | | PSEG Power & Other | | | | Eliminations (A) | | Consolidated Total | |
| | | Millions | |
| Year Ended December 31, 2023 | | | | | | | | | | | |
| Operating Revenues | | $ | 7,807 | | | $ | 4,533 | | | | | $ | (1,103) | | | $ | 11,237 | | |
| Depreciation and Amortization | | 980 | | | 155 | | | | | — | | | 1,135 | | |
| Operating Income (Loss) | | 1,974 | | | 1,711 | | | | | — | | | 3,685 | | |
| Income from Equity Method Investments | | — | | | 1 | | | | | — | | | 1 | | |
| Interest Income | | 19 | | | 38 | | | | | (4) | | | 53 | | |
| Interest Expense | | 493 | | | 259 | | | | | (4) | | | 748 | | |
| Income (Loss) before Income Taxes | | 1,675 | | | 1,406 | | | | | — | | | 3,081 | | |
| Income Tax Expense (Benefit) | | 160 | | | 358 | | | | | — | | | 518 | | |
| Net Income (Loss) (B) (C) | | $ | 1,515 | | | $ | 1,048 | | | | | $ | — | | | $ | 2,563 | | |
| Gross Additions to Long-Lived Assets | | $ | 2,998 | | | $ | 327 | | | | | $ | — | | | $ | 3,325 | | |
| As of December 31, 2023 | | | | | | | | | | | |
| Total Assets | | $ | 42,873 | | | $ | 8,407 | | | | | $ | (539) | | | $ | 50,741 | | |
| Investments in Equity Method Subsidiaries | | $ | — | | | $ | 17 | | | | | $ | — | | | $ | 17 | | |
| | | | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | PSE&G | | Power | | Other (A) | | Eliminations (B) | | Consolidated Total | |
| | | Millions | |
| Year Ended December 31, 2016 | | | | | | | | | | | |
| Operating Revenues | | $ | 6,221 |
| | $ | 4,023 |
| | $ | 370 |
| | $ | (1,553 | ) | | $ | 9,061 |
| |
| Depreciation and Amortization | | 565 |
| | 881 |
| | 30 |
| | — |
| | 1,476 |
| |
| Operating Income (Loss) | | 1,614 |
| | 13 |
| | (51 | ) | | — |
| | 1,576 |
| |
| Income from Equity Method Investments | | — |
| | 11 |
| | — |
| | — |
| | 11 |
| |
| Interest Income | | 24 |
| | 4 |
| | 4 |
| | (2 | ) | | 30 |
| |
| Interest Expense | | 289 |
| | 84 |
| | 14 |
| | (2 | ) | | 385 |
| |
| Income (Loss) before Income Taxes | | 1,404 |
| | (43 | ) | | (63 | ) | | — |
| | 1,298 |
| |
| Income Tax Expense (Benefit) | | 515 |
| | (61 | ) | | (43 | ) | | — |
| | 411 |
| |
| Net Income (Loss) | | 889 |
| | 18 |
| | (20 | ) | | — |
| | 887 |
| |
| Gross Additions to Long-Lived Assets | | $ | 2,816 |
| | $ | 1,343 |
| | $ | 40 |
| | $ | — |
| | $ | 4,199 |
| |
| As of December 31, 2016 | | | | | | | | | | | |
| Total Assets | | $ | 26,288 |
| | $ | 12,193 |
| | $ | 2,373 |
| | $ | (784 | ) | | $ | 40,070 |
| |
| Investments in Equity Method Subsidiaries | | $ | — |
| | $ | 102 |
| | $ | — |
| | $ | — |
| | $ | 102 |
| |
| | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | PSE&G | | Power | | Other (A) | | Eliminations (B) | | Consolidated Total | |
| | | Millions | |
| Year Ended December 31, 2015 | | | | | | | | | | | |
| Operating Revenues | | $ | 6,636 |
| | $ | 4,928 |
| | $ | 462 |
| | $ | (1,611 | ) | | $ | 10,415 |
| |
| Depreciation and Amortization | | 892 |
| | 291 |
| | 31 |
| | — |
| | 1,214 |
| |
| Operating Income (Loss) | | 1,462 |
| | 1,430 |
| | 70 |
| | — |
| | 2,962 |
| |
| Income from Equity Method Investments | | — |
| | 14 |
| | (2 | ) | | — |
| | 12 |
| |
| Interest Income | | 25 |
| | 2 |
| | 33 |
| | (29 | ) | | 31 |
| |
| Interest Expense | | 280 |
| | 121 |
| | 21 |
| | (29 | ) | | 393 |
| |
| Income (Loss) before Income Taxes | | 1,257 |
| | 1,367 |
| | 56 |
| | — |
| | 2,680 |
| |
| Income Tax Expense (Benefit) | | 470 |
| | 511 |
| | 20 |
| | — |
| | 1,001 |
| |
| Net Income (Loss) | | 787 |
| | 856 |
| | 36 |
| | — |
| | 1,679 |
| |
| Gross Additions to Long-Lived Assets | | $ | 2,692 |
| | $ | 1,117 |
| | $ | 54 |
| | $ | — |
| | $ | 3,863 |
| |
| As of December 31, 2015 | | | | | | | | | | | |
| Total Assets | | $ | 23,677 |
| | $ | 12,250 |
| | $ | 2,810 |
| | $ | (1,202 | ) | | $ | 37,535 |
| |
| Investments in Equity Method Subsidiaries | | $ | — |
| | $ | 119 |
| | $ | — |
| | $ | — |
| | $ | 119 |
| |
| | | | | | | | | | | | |
| |
(A) | Includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services. |
| |
(B) | Intercompany eliminations primarily relate to intercompany transactions between PSE&G and Power. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 24. Related-Party Transactions. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | PSE&G | | PSEG Power & Other | | | | Eliminations (A) | | Consolidated Total | |
| | | Millions | |
| Year Ended December 31, 2022 | | | | | | | | | | | |
| Operating Revenues | | $ | 7,935 | | | $ | 3,266 | | | | | $ | (1,401) | | | $ | 9,800 | | |
| Depreciation and Amortization | | 935 | | | 165 | | | | | — | | | 1,100 | | |
| Operating Income (Loss) | | 1,892 | | | (511) | | | | | — | | | 1,381 | | |
| Income from Equity Method Investments | | — | | | 14 | | | | | — | | | 14 | | |
| Interest Income | | 19 | | | 13 | | | | | (1) | | | 31 | | |
| Interest Expense | | 427 | | | 202 | | | | | (1) | | | 628 | | |
| Income (Loss) before Income Taxes | | 1,832 | | | (830) | | | | | — | | | 1,002 | | |
| Income Tax Expense (Benefit) | | 267 | | | (296) | | | | | — | | | (29) | | |
| Net Income (Loss) (B) (C) | | $ | 1,565 | | | $ | (534) | | | | | $ | — | | | $ | 1,031 | | |
| Gross Additions to Long-Lived Assets | | $ | 2,590 | | | $ | 298 | | | | | $ | — | | | $ | 2,888 | | |
| As of December 31, 2022 | | | | | | | | | | | |
| Total Assets | | $ | 39,960 | | | $ | 9,285 | | | | | $ | (527) | | | $ | 48,718 | | |
| Investments in Equity Method Subsidiaries | | $ | — | | | $ | 306 | | | | | $ | — | | | $ | 306 | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | PSE&G | | PSEG Power & Other | | | | Eliminations (A) | | Consolidated Total | |
| | | Millions | |
| Year Ended December 31, 2021 | | | | | | | | | | | |
| Operating Revenues | | $ | 7,122 | | | $ | 3,767 | | | | | $ | (1,167) | | | $ | 9,722 | | |
| Depreciation and Amortization | | 928 | | | 288 | | | | | — | | | 1,216 | | |
| Operating Income (Loss) | | 1,818 | | | (2,674) | | | | | — | | | (856) | | |
| Income from Equity Method Investments | | — | | | 16 | | | | | — | | | 16 | | |
| Interest Income | | 14 | | | 6 | | | | | — | | | 20 | | |
| Interest Expense | | 402 | | | 169 | | | | | — | | | 571 | | |
| Income (Loss) before Income Taxes | | 1,770 | | | (2,859) | | | | | — | | | (1,089) | | |
| Income Tax Expense (Benefit) | | 324 | | | (765) | | | | | — | | | (441) | | |
| Net Income (Loss) (B) (C) | | $ | 1,446 | | | $ | (2,094) | | | | | $ | — | | | $ | (648) | | |
| Gross Additions to Long-Lived Assets | | $ | 2,447 | | | $ | 272 | | | | | $ | — | | | $ | 2,719 | | |
| As of December 31, 2021 | | | | | | | | | | | |
| Total Assets | | $ | 37,198 | | | $ | 12,258 | | | | | $ | (457) | | | $ | 48,999 | | |
| Investments in Equity Method Subsidiaries | | $ | — | | | $ | 173 | | | | | $ | — | | | $ | 173 | | |
| | | | | | | | | | | | |
(A)Intercompany eliminations primarily relate to intercompany transactions between PSE&G and PSEG Power. For a further discussion of the intercompany transactions between PSE&G and PSEG Power, see Note 24. Related-Party Transactions.
(B)Includes a $239 million after-tax pension charge due to the remeasurement of the qualified pension plans as a result of the pension settlement transaction in the third quarter of 2023. Includes after-tax impairments of $92 million related to certain Energy Holdings investments and additional adjustments related to the sale of PSEG Power’s fossil generation assets in the year ended December 31, 2022. Includes after-tax impairment losses and other charges, including debt extinguishment costs, related to the sale of the fossil generating assets at PSEG Power of $2,158 million in the year ended December 31, 2021. See Note 3. Asset Dispositions and Impairments for additional information.
(C)Includes net after-tax gain (loss) of $959 million, $(457) million and $(446) million in the years ended December 31, 2023, 2022 and 2021, respectively at PSEG Power related to the impacts of non-trading commodity mark-to-market activity, which consists of the financial impact from positions with future delivery dates.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 24. Related-Party Transactions
The following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP.
PSE&G
The financial statements for PSE&G include transactions with related parties presented as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| Related Party Transactions | | 2023 | | 2022 | | 2021 | |
| | | Millions | |
| Billings from Affiliates: | | | | | | | |
| Net Billings from PSEG Power (A) | | $ | 1,065 | | | $ | 1,388 | | | $ | 1,144 | | |
| Administrative Billings from Services (B) | | 443 | | | $ | 445 | | | 394 | | |
| Total Billings from Affiliates | | $ | 1,508 | | | $ | 1,833 | | | $ | 1,538 | | |
| | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | Years Ended December 31, | |
| Related Party Transactions | | 2023 | | 2022 | |
| | | Millions | |
| | | | | | |
| Payable to PSEG Power (A) | | $ | 264 | | | $ | 313 | | |
| Payable to Services (B) | | 121 | | | 98 | | |
| Payable to PSEG (C) | | 119 | | | 74 | | |
| Accounts Payable—Affiliated Companies | | $ | 504 | | | $ | 485 | | |
| Working Capital Advances to Services (D) | | $ | 33 | | | $ | 33 | | |
| Long-Term Accrued Taxes Payable | | $ | 2 | | | $ | 9 | | |
| | | | | | |
(A)PSE&G has entered into a requirements contract with PSEG Power under which PSEG Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. Since June 1, 2022, PSEG Power had no contracts to supply electric energy, capacity and ancillary services to PSE&G through the BGS auction process. In addition, PSEG Power sells ZECs to PSE&G from its nuclear units under the ZEC program as approved by the BPU. The rates in the BGS and BGSS contracts and for the ZEC sales are prescribed by the BPU. BGS and BGSS sales are billed and settled on a monthly basis. ZEC sales are billed on a monthly basis and settled annually following completion of each energy year. In addition, PSEG Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules.
(B)Services provides and bills administrative services to PSE&G at cost. In addition, PSE&G has other payables to Services, including amounts related to certain common costs, which Services pays on behalf of PSE&G.
(C)PSEG pays all payroll taxes and receives reimbursement from its affiliated companies for their respective portions. In addition, PSEG files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are NOLs and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits.
(D)PSE&G has advanced working capital to Services. The amount is included in Other Noncurrent Assets on PSE&G’s Consolidated Balance Sheets.
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| Related Party Transactions | | 2017 | | 2016 | | 2015 | |
| | | Millions | |
| Billings from Affiliates: | | | | | | | |
| Net Billings from Power primarily through BGS and BGSS (A) | | $ | 1,580 |
| | $ | 1,587 |
| | $ | 1,630 |
| |
| Administrative Billings from Services (B) | | 331 |
| | 312 |
| | 274 |
| |
| Total Billings from Affiliates | | $ | 1,911 |
| | $ | 1,899 |
| | $ | 1,904 |
| |
| | | | | | | | |
|
| | | | | | | | | | |
| | | | | | |
| | | Years Ended December 31, | |
| Related Party Transactions | | 2017 | | 2016 | |
| | | Millions | |
| Receivables from PSEG (C) | | $ | — |
| | $ | 76 |
| |
| Payable to Power (A) | | $ | 221 |
| | $ | 193 |
| |
| Payable to Services (B) | | 78 |
| | 67 |
| |
| Payable to PSEG (C) | | $ | 41 |
| | $ | — |
| |
| Accounts Payable—Affiliated Companies | | $ | 340 |
| | $ | 260 |
| |
| Working Capital Advances to Services (D) | | $ | 33 |
| | $ | 33 |
| |
| Long-Term Accrued Taxes Payable | | $ | 91 |
| | $ | 130 |
| |
| | | | | | |
Power
The financial statements for Power include transactions with related parties presented as follows:
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | Years Ended December 31, | |
| Related Party Transactions | | 2017 | | 2016 | | 2015 | |
| | | Millions | |
| Billings to Affiliates: | | | | | | | |
| Net Billings to PSE&G primarily through BGS and BGSS (A) | | $ | 1,580 |
| | $ | 1,587 |
| | $ | 1,630 |
| |
| Billings from Affiliates: | | | | | | | |
| Administrative Billings from Services (B) | | $ | 168 |
| | $ | 179 |
| | $ | 187 |
| |
| | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | |
| | | | | | |
| | | Years Ended December 31, | |
| Related Party Transactions | | 2017 | | 2016 | |
| | | Millions | |
| Receivable from PSE&G (A) | | $ | 221 |
| | $ | 193 |
| |
| Receivable from PSEG (C) | | — |
| | 12 |
| |
| Accounts Receivable—Affiliated Companies | | $ | 221 |
| | $ | 205 |
| |
| Payable to Services (B) | | $ | 28 |
| | $ | 25 |
| |
| Payable to PSEG (C) | | 29 |
| | — |
| |
| Accounts Payable—Affiliated Companies | | $ | 57 |
| | $ | 25 |
| |
| Short-Term Loan due (to) from Affiliate (E) | | $ | (281 | ) | | $ | 87 |
| |
| Working Capital Advances to Services (D) | | $ | 17 |
| | $ | 17 |
| |
| Long-Term Accrued Taxes Payable | | $ | 52 |
| | $ | 77 |
| |
| | | | | | |
| |
(A) | PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. The rates in the BGS and BGSS contracts are prescribed by the BPU. In addition, Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules. |
| |
(B) | Services provides and bills administrative services to PSE&G and Power at cost. In addition, PSE&G and Power have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies. |
| |
(C) | PSEG files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits. |
| |
(D) | PSE&G and Power have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on PSE&G’s and Power’s Consolidated Balance Sheets. |
| |
(E) | Power’s short-term loans with PSEG are for working capital and other short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 25. Selected Quarterly Data (Unaudited)
The information shown in the following tables, in the opinion of PSEG, PSE&G and Power includes all adjustments, consisting only of normal recurring accruals, necessary to fairly present such amounts.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | Quarter Ended | |
| | | March 31, | | June 30, | | September 30, | | December 31, (A) | |
| | | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 | |
| PSEG Consolidated: | | Millions, except per share data | |
| Operating Revenues | | $ | 2,592 |
| | $ | 2,616 |
| | $ | 2,133 |
| | $ | 1,905 |
| | $ | 2,263 |
| | $ | 2,450 |
| | $ | 2,096 |
| | $ | 2,090 |
| |
| Operating Income (Loss) | | $ | 178 |
| | $ | 827 |
| | $ | 196 |
| | $ | 347 |
| | $ | 693 |
| | $ | 577 |
| | $ | 362 |
| | $ | (175 | ) | |
| Net Income (Loss) | | $ | 114 |
| | $ | 471 |
| | $ | 109 |
| | $ | 187 |
| | $ | 395 |
| | $ | 327 |
| | $ | 956 |
| | $ | (98 | ) | |
| Earnings Per Share: | | | | | | | | | | | | | | | | | |
| Basic: | | | | | | | | | | | | | | | | | |
| Net Income (Loss) | | $ | 0.23 |
| | $ | 0.93 |
| | $ | 0.22 |
| | $ | 0.37 |
| | $ | 0.78 |
| | $ | 0.65 |
| | $ | 1.89 |
| | $ | (0.19 | ) | |
| Diluted: | | | | | | | | | | | | | | | | | |
| Net Income (Loss) | | $ | 0.22 |
| | $ | 0.93 |
| | $ | 0.22 |
| | $ | 0.37 |
| | $ | 0.78 |
| | $ | 0.64 |
| | $ | 1.88 |
| | $ | (0.19 | ) | |
| Weighted Average Common Shares Outstanding: | | | | | | | | | | | | | | | | | |
| Basic | | 505 |
| | 505 |
| | 505 |
| | 505 |
| | 505 |
| | 505 |
| | 505 |
| | 505 |
| |
| Diluted | | 508 |
| | 508 |
| | 507 |
| | 508 |
| | 507 |
| | 508 |
| | 508 |
| | 508 |
| |
| | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | Quarter Ended | |
| | | March 31, | | June 30, | | September 30, | | December 31, | |
| | | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 | |
| PSE&G: | | Millions | |
| Operating Revenues | | $ | 1,812 |
| | $ | 1,712 |
| | $ | 1,368 |
| | $ | 1,350 |
| | $ | 1,509 |
| | $ | 1,684 |
| | $ | 1,545 |
| | $ | 1,475 |
| |
| Operating Income | | $ | 521 |
| | $ | 462 |
| | $ | 379 |
| | $ | 333 |
| | $ | 459 |
| | $ | 450 |
| | $ | 393 |
| | $ | 369 |
| |
| Net Income | | $ | 299 |
| | $ | 262 |
| | $ | 208 |
| | $ | 179 |
| | $ | 246 |
| | $ | 255 |
| | $ | 220 |
| | $ | 193 |
| |
| | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | Quarter Ended | |
| | | March 31, | | June 30, | | September 30, | | December 31, (A) | |
| | | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 | |
| Power: | | Millions | |
| Operating Revenues | | $ | 1,284 |
| | $ | 1,313 |
| | $ | 929 |
| | $ | 714 |
| | $ | 873 |
| | $ | 1,075 |
| | $ | 844 |
| | $ | 921 |
| |
| Operating Income (Loss) | | $ | (303 | ) | | $ | 343 |
| | $ | (187 | ) | | $ | (12 | ) | | $ | 213 |
| | $ | 238 |
| | $ | (82 | ) | | $ | (556 | ) | |
| Net Income (Loss) | | $ | (170 | ) | | $ | 192 |
| | $ | (97 | ) | | $ | (11 | ) | | $ | 136 |
| | $ | 139 |
| | $ | 610 |
| | $ | (302 | ) | |
| | | | | | | | | | | | | | | | | | |
| |
(A) | The increases in Operating Income at PSEG consolidated and Power in the fourth quarter 2017 as compared to the same quarter in 2016 were primarily due to higher costs in 2016 related to closing the coal/gas Hudson and Mercer units, which were fully depreciated as of June 1, 2017. The increases in Net Income at PSEG consolidated and Power in the fourth quarter 2017 as compared to the same quarter in 2016 also includes the impact of the remeasurement of deferred tax balances resulting from the enactment of new tax legislation in December 2017. See Note 20. Income Taxes for additional information. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 26. Guarantees of Debt
Power’s Senior Notes are fully and unconditionally and jointly and severally guaranteed by its subsidiaries, PSEG Fossil LLC, PSEG Nuclear LLC and PSEG Energy Resources & Trade LLC. The following tables present condensed financial information for the guarantor subsidiaries, as well as Power’s non-guarantor subsidiaries, as of December 31, 2017 and 2016 and for the years ended December 31, 2017, 2016 and 2015.
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | Power | | Guarantor Subsidiaries | | Other Subsidiaries | | Consolidating Adjustments | | Total | |
| | | Millions | |
| Year Ended December 31, 2017 | | | | | | | | | | | |
| Operating Revenues | | $ | — |
| | $ | 3,891 |
| | $ | 174 |
| | $ | (135 | ) | | $ | 3,930 |
| |
| Operating Expenses | | 8 |
| | 4,221 |
| | 195 |
| | (135 | ) | | 4,289 |
| |
| Operating Income (Loss) | | (8 | ) | | (330 | ) | | (21 | ) | | — |
| | (359 | ) | |
| Equity Earnings (Losses) of Subsidiaries | | 567 |
| | 60 |
| | 14 |
| | (627 | ) | | 14 |
| |
| Other Income | | 98 |
| | 257 |
| | 2 |
| | (144 | ) | | 213 |
| |
| Other Deductions | | (24 | ) | | (32 | ) | | — |
| | — |
| | (56 | ) | |
| Other-Than-Temporary Impairments | | — |
| | (12 | ) | | — |
| | — |
| | (12 | ) | |
| Interest Expense | | (128 | ) | | (49 | ) | | (17 | ) | | 144 |
| | (50 | ) | |
| Income Tax Benefit (Expense) | | (26 | ) | | 588 |
| | 167 |
| | — |
| | 729 |
| |
| Net Income (Loss) | | $ | 479 |
| | $ | 482 |
| | $ | 145 |
| | $ | (627 | ) | | $ | 479 |
| |
| Comprehensive Income (Loss) | | $ | 518 |
| | $ | 529 |
| | $ | 145 |
| | $ | (674 | ) | | $ | 518 |
| |
| As of December 31, 2017 | | | | | | | | | | | |
| Current Assets | | $ | 4,327 |
| | $ | 1,500 |
| | $ | 200 |
| | $ | (4,686 | ) | | $ | 1,341 |
| |
| Property, Plant and Equipment, net | | 54 |
| | 5,778 |
| | 2,764 |
| | — |
| | 8,596 |
| |
| Investment in Subsidiaries | | 4,844 |
| | 404 |
| | — |
| | (5,248 | ) | | — |
| |
| Noncurrent Assets | | 100 |
| | 2,349 |
| | 110 |
| | (78 | ) | | 2,481 |
| |
| Total Assets | | $ | 9,325 |
| | $ | 10,031 |
| | $ | 3,074 |
| | $ | (10,012 | ) | | $ | 12,418 |
| |
| Current Liabilities | | $ | 689 |
| | $ | 3,586 |
| | $ | 1,846 |
| | $ | (4,686 | ) | | $ | 1,435 |
| |
| Noncurrent Liabilities | | 533 |
| | 1,966 |
| | 459 |
| | (78 | ) | | 2,880 |
| |
| Long-Term Debt | | 2,136 |
| | — |
| | — |
| | — |
| | 2,136 |
| |
| Member’s Equity | | 5,967 |
| | 4,479 |
| | 769 |
| | (5,248 | ) | | 5,967 |
| |
| Total Liabilities and Member’s Equity | | $ | 9,325 |
| | $ | 10,031 |
| | $ | 3,074 |
| | $ | (10,012 | ) | | $ | 12,418 |
| |
| Year Ended December 31, 2017 | | | | | | | | | | | |
| Net Cash Provided By (Used In) Operating Activities | | $ | (42 | ) | | $ | 1,185 |
| | $ | 238 |
| | $ | (55 | ) | | $ | 1,326 |
| |
| Net Cash Provided By (Used In) Investing Activities | | $ | 506 |
| | $ | (448 | ) | | $ | (525 | ) | | $ | (765 | ) | | $ | (1,232 | ) | |
| Net Cash Provided By (Used In) Financing Activities | | $ | (464 | ) | | $ | (736 | ) | | $ | 307 |
| | $ | 820 |
| | $ | (73 | ) | |
| | | | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | Power | | Guarantor Subsidiaries | | Other Subsidiaries | | Consolidating Adjustments | | Total | |
| | | Millions | |
| Year Ended December 31, 2016 | | | | | | | | | | | |
| Operating Revenues | | $ | — |
| | $ | 3,971 |
| | $ | 173 |
| | $ | (121 | ) | | $ | 4,023 |
| |
| Operating Expenses | | 8 |
| | 3,962 |
| | 161 |
| | (121 | ) | | 4,010 |
| |
| Operating Income (Loss) | | (8 | ) | | 9 |
| | 12 |
| | — |
| | 13 |
| |
| Equity Earnings (Losses) of Subsidiaries | | 36 |
| | (3 | ) | | 11 |
| | (33 | ) | | 11 |
| |
| Other Income | | 71 |
| | 120 |
| | — |
| | (89 | ) | | 102 |
| |
| Other Deductions | | (18 | ) | | (39 | ) | | — |
| | — |
| | (57 | ) | |
| Other-Than-Temporary Impairments | | — |
| | (28 | ) | | — |
| | — |
| | (28 | ) | |
| Interest Expense | | (115 | ) | | (40 | ) | | (18 | ) | | 89 |
| | (84 | ) | |
| Income Tax Benefit (Expense) | | 52 |
| | (11 | ) | | 20 |
| | — |
| | 61 |
| |
| Net Income (Loss) | | $ | 18 |
| | $ | 8 |
| | $ | 25 |
| | $ | (33 | ) | | $ | 18 |
| |
| Comprehensive Income (Loss) | | $ | 47 |
| | $ | 50 |
| | $ | 25 |
| | $ | (75 | ) | | $ | 47 |
| |
| As of December 31, 2016 | | | | | | | | | | | |
| Current Assets | | $ | 4,412 |
| | $ | 1,593 |
| | $ | 152 |
| | $ | (4,697 | ) | | $ | 1,460 |
| |
| Property, Plant and Equipment, net | | 55 |
| | 6,145 |
| | 2,320 |
| | — |
| | 8,520 |
| |
| Investment in Subsidiaries | | 4,249 |
| | 344 |
| | — |
| | (4,593 | ) | | — |
| |
| Noncurrent Assets | | 168 |
| | 2,016 |
| | 129 |
| | (100 | ) | | 2,213 |
| |
| Total Assets | | $ | 8,884 |
| | $ | 10,098 |
| | $ | 2,601 |
| | $ | (9,390 | ) | | $ | 12,193 |
| |
| Current Liabilities | | $ | 171 |
| | $ | 3,752 |
| | $ | 1,454 |
| | $ | (4,697 | ) | | $ | 680 |
| |
| Noncurrent Liabilities | | 532 |
| | 2,398 |
| | 502 |
| | (100 | ) | | 3,332 |
| |
| Long-Term Debt | | 2,382 |
| | — |
| | — |
| | — |
| | 2,382 |
| |
| Member’s Equity | | 5,799 |
| | 3,948 |
| | 645 |
| | (4,593 | ) | | 5,799 |
| |
| Total Liabilities and Member’s Equity | | $ | 8,884 |
| | $ | 10,098 |
| | $ | 2,601 |
| | $ | (9,390 | ) | | $ | 12,193 |
| |
| Year Ended December 31, 2016 | | | | | | | | | | | |
| Net Cash Provided By (Used In) Operating Activities | | $ | 97 |
| | $ | 1,442 |
| | $ | 323 |
| | $ | (607 | ) | | $ | 1,255 |
| |
| Net Cash Provided By (Used In) Investing Activities | | $ | 60 |
| | $ | (707 | ) | | $ | (789 | ) | | $ | 289 |
| | $ | (1,147 | ) | |
| Net Cash Provided By (Used In) Financing Activities | | $ | (157 | ) | | $ | (736 | ) | | $ | 466 |
| | $ | 318 |
| | $ | (109 | ) | |
| | | | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | Power | | Guarantor Subsidiaries | | Other Subsidiaries | | Consolidating Adjustments | | Total | |
| | | Millions | |
| Year Ended December 31, 2015 | | | | | | | | | | | |
| Operating Revenues | | $ | — |
| | $ | 4,883 |
| | $ | 179 |
| | $ | (134 | ) | | $ | 4,928 |
| |
| Operating Expenses | | 12 |
| | 3,451 |
| | 169 |
| | (134 | ) | | 3,498 |
| |
| Operating Income (Loss) | | (12 | ) | | 1,432 |
| | 10 |
| | — |
| | 1,430 |
| |
| Equity Earnings (Losses) of Subsidiaries | | 906 |
| | (4 | ) | | 14 |
| | (902 | ) | | 14 |
| |
| Other Income | | 48 |
| | 174 |
| | — |
| | (53 | ) | | 169 |
| |
| Other Deductions | | (27 | ) | | (45 | ) | | — |
| | — |
| | (72 | ) | |
| Other-Than-Temporary Impairments | | — |
| | (53 | ) | | — |
| | — |
| | (53 | ) | |
| Interest Expense | | (116 | ) | | (39 | ) | | (19 | ) | | 53 |
| | (121 | ) | |
| Income Tax Benefit (Expense) | | 57 |
| | (574 | ) | | 6 |
| | — |
| | (511 | ) | |
| Net Income (Loss) | | $ | 856 |
| | $ | 891 |
| | $ | 11 |
| | $ | (902 | ) | | $ | 856 |
| |
| Comprehensive Income (Loss) | | $ | 844 |
| | $ | 855 |
| | $ | 11 |
| | $ | (866 | ) | | $ | 844 |
| |
| Year Ended December 31, 2015 | | | | | | | | | | | |
| Net Cash Provided By (Used In) Operating Activities | | $ | 571 |
| | $ | 2,089 |
| | $ | 80 |
| | $ | (1,034 | ) | | $ | 1,706 |
| |
| Net Cash Provided By (Used In) Investing Activities | | $ | (366 | ) | | $ | (1,519 | ) | | $ | (430 | ) | | $ | 1,314 |
| | $ | (1,001 | ) | |
| Net Cash Provided By (Used In) Financing Activities | | $ | (205 | ) | | $ | (571 | ) | | $ | 354 |
| | $ | (280 | ) | | $ | (702 | ) | |
| | | | | | | | | | | | |
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
PSEG and PSE&G and Power
We have established and maintain disclosure controls and procedures as defined under Rule 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) that are designed to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported and is accumulated and communicated to the Chief Executive Officer (CEO) and Chief Financial Officer (CFO) of each respective company, as appropriate, by others within the entities to allow timely decisions regarding required disclosure. We have established a disclosure committee which includes several key management employees and which reports directly to the CFO and CEO of each of PSEG PSE&G and Power.PSE&G. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The CFO and CEO of each of PSEG and PSE&G and Power have evaluated the effectiveness of the disclosure controls and procedures and, based on this evaluation, have concluded that disclosure controls and procedures at each respective company were effective at a reasonable assurance level as of the end of the period covered by the report.
Internal Controls
PSEG and PSE&G and Power
We have conducted assessments of our internal control over financial reporting as of December 31, 2017,2023, as required by Section 404 of the Sarbanes-Oxley Act, using the framework promulgated by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO.” Managements’ reports on PSEG’s and PSE&G’s and Power’s internal control over financial reporting are included on pages 181, 182147 and 183,148, respectively. The Independent Registered Public Accounting Firm’s report with respect to the effectiveness of PSEG’s internal control over financial reporting is included on page 184.149. Management has concluded that internal control over financial reporting is effective as of December 31, 2017.2023.
We continually review our disclosure controls and procedures and make changes, as necessary, to ensure the quality of our financial reporting. There have been no changes in internal control over financial reporting that occurred during the fourth quarter of 20172023 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.Director and Officer Rule 10b5-1 and non-Rule 10b5-1 Trading Plans
During the three months ended December 31, 2023, none of PSEG’s directors or officers adopted, terminated or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K of the Securities Act of 1933).
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
MANAGEMENT REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING—PSEG
Management of Public Service Enterprise Group Incorporated (PSEG) is responsible for establishing and maintaining effective internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the SEC in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and implemented by the company’s management and other personnel, with oversight by the Audit Committee of the Board of Directors to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles).
PSEG’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of PSEG’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of PSEG are being made only in accordance with authorizations of PSEG’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of PSEG’s assets that could have a material effect on the financial statements.
In connection with the preparation of PSEG’s annual financial statements, management of PSEG has undertaken an assessment, which includes the design and operational effectiveness of PSEG’s internal control over financial reporting based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. The COSO framework is based upon five integrated components of control: control environment, risk assessment, control activities, information and communications and ongoing monitoring.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Based on the assessment performed, management has concluded that PSEG’s internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of PSEG’s financial reporting and the preparation of its financial statements as of December 31, 20172023 in accordance with generally accepted accounting principles. Further, management has not identified any material weaknesses in internal control over financial reporting as of December 31, 2017.2023.
PSEG’s external auditors, Deloitte & Touche LLP, have audited PSEG’s financial statements for the year ended December 31, 20172023 included in this annual report on Form 10-K and, as part of that audit, have issued a report on the effectiveness of PSEG’s internal control over financial reporting, a copy of which is included in this annual report on Form 10-K.
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/s/ RALPH IZZO A. LAROSSA | |
Chief Executive Officer | |
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/s/ DANIEL J. CREGG | |
Chief Financial Officer | |
February 26, 20182024 | |
MANAGEMENT REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING—PSE&G
Management of Public Service Electric and Gas Company (PSE&G) is responsible for establishing and maintaining effective internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the SEC in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and implemented by the company’s management and other personnel, with oversight by the Audit Committee of the Board of Directors of its parent, Public Service Enterprise Group Incorporated, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles).
PSE&G’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of PSE&G’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of PSE&G are being made only in accordance with authorizations of PSE&G’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of PSE&G’s assets that could have a material effect on the financial statements.
In connection with the preparation of PSE&G’s annual financial statements, management of PSE&G has undertaken an assessment, which includes the design and operational effectiveness of PSE&G’s internal control over financial reporting based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. The COSO framework is based upon five integrated components of control: control environment, risk assessment, control activities, information and communications and ongoing monitoring.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Based on the assessment performed, management has concluded that PSE&G’s internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of PSE&G’s financial reporting and the preparation of its financial statements as of December 31, 20172023 in accordance with generally accepted accounting principles. Further, management has not identified any material weaknesses in internal control over financial reporting as of December 31, 2017.
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/s/ RALPH IZZO A. LAROSSA | |
Chief Executive Officer | |
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/s/ DANIEL J. CREGG | |
Chief Financial Officer | |
February 26, 20182024 | |
MANAGEMENT REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING—Power
Management of PSEG Power LLC (Power) is responsible for establishing and maintaining effective internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the SEC in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and implemented by the company’s management and other personnel, with oversight by the Audit Committee of the Board of Directors of its parent, Public Service Enterprise Group Incorporated, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles).
Power’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of Power’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of Power are being made only in accordance with authorizations of Power’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of Power’s assets that could have a material effect on the financial statements.
In connection with the preparation of Power’s annual financial statements, management of Power has undertaken an assessment, which includes the design and operational effectiveness of Power’s internal control over financial reporting based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. The COSO framework is based upon five integrated components of control: control environment, risk assessment, control activities, information and communications and ongoing monitoring.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Based on the assessment performed, management has concluded that Power’s internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of Power’s financial reporting and the preparation of its financial statements as of December 31, 2017 in accordance with generally accepted accounting principles. Further, management has not identified any material weaknesses in internal control over financial reporting as of December 31, 2017.
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/s/ RALPH IZZO
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Chief Executive Officer | |
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/s/ DANIEL J. CREGG
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Chief Financial Officer | |
February 26, 2018 | |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Public Service Enterprise Group Incorporated
Newark, New Jersey
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Public Service Enterprise Group Incorporated and subsidiaries (the “Company”) or PSEG) as of December 31, 2017,2023, based on criteria established in Internal Control -— Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”)(COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2023, based on criteria established in Internal Control -— Integrated Framework (2013) issued by COSO.
We have also audited,in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”)(PCAOB), the consolidated financial statements and the consolidated financial statement schedule listed in the Index at Item 15(B)(a) as of and for the year ended December 31, 20172023, of the Company and our report dated February 26, 2018,2024, expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control Over Financial Reporting - PSEG. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.PCAOB
We conducted our audit in accordance with the standards of the PCAOB.Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
Parsippany,Morristown, New Jersey
February 26, 2018
2024
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE
Executive Officers
PSEG
The information required by Item 10 of Form 10-K with respect to executive officers is set forth in Part I. Information About Our Executive Officers of the Registrant (PSEG).
PSE&G and Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
Directors
PSEG
The information required by Item 10 of Form 10-K with respect to (i) present directors of PSEG who are nominees for election as directors at PSEG’s 20182024 Annual Meeting of Stockholders, (ii) the director nomination process, and (iii) the composition of the Audit Committee of the Board, is set forth under the headings “Nominees For Director-Biographical Information,” “Overview of Board Nominees-Board Refreshment and Election-Board CompositionTenure,” and Individual Qualifications,” “Nominees and Election-Nomination Process,“-Board Membership Selection,” and “Corporate Governance-Board Committee Responsibilities-Audit Committee,Committees,” respectively, in PSEG’s definitive Proxy Statement for such Annual Meeting of Stockholders, which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about March 12, 20187, 2024 and which information set forth under said heading is incorporated herein by this reference thereto.
PSE&G and Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
Standards of Conduct
Our Standards of Conduct (Standards) is a code of ethics applicable to us and our subsidiaries. The Standards are an integral part of our business conduct compliance program and embody our commitment to conduct operations in accordance with the highest legal and ethical standards. The Standards apply to all of our directors and employees (including PSE&G’s, PSEG Power’s, Energy Holdings’ and Services’ respective principal executive officer, principal financial officer, principal accounting officer or Controller and persons performing similar functions). Each such person is responsible for understanding and complying with the Standards. The Standards are posted on our website, www.pseg.com/info/investors/governance/document.jsp. We will send youhttps://corporate.pseg.com/aboutpseg/leadershipandgovernance/standardsofconduct You can get a free copy on request.of the Standards by making an oral or written request directed to:
Vice President, Investor Relations
PSEG Services Corporation
80 Park Plaza, 4th Floor
Newark, NJ 07102
Telephone (973) 430-6565
The Standards establish a set of common expectations for behavior to which each employee must adhere in dealings with investors, customers, fellow employees, competitors, vendors, government officials, the media and all others who may associate their words and actions with us. The Standards have been developed to provide reasonable assurance that, in conducting our business, employees behave ethically and in accordance with the law and do not take advantage of investors, regulators or customers through manipulation, abuse of confidential information or misrepresentation of material facts.
We will post on our website, www.pseg.com/info/investors/governance/document.jsp:https://corporate.pseg.com/aboutpseg/leadershipandgovernance/standardsofconduct:
•Any amendment (other than one that is technical, administrative or non-substantive) that we adopt to our Standards; and
•Any grant by us of a waiver from the Standards that applies to any director or executive officer and that relates to any element enumerated by the SEC.
In 2017,2023, we did not grant any waivers to the Standards.
Section 16(a) Beneficial Ownership Reporting Compliance
PSEG
The information required by Item 10 of Form 10-K with respect to compliance with Section 16(a) of the Securities Exchange Act of 1934, as amended, is set forth under the heading “Section 16(a) Beneficial Ownership Reporting Compliance,” in
PSEG’s definitive Proxy Statement for the 2018 Annual Meeting of Stockholders, which definitive Proxy Statement is expected to be filed with the SEC on or about March 12, 2018 and which information set forth under said heading is incorporated herein by this reference thereto.
Power and PSE&G
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
PSEG
The information required by Item 11 of Form 10-K is set forth in PSEG’s definitive Proxy Statement for the 20182024 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 12, 20187, 2024 and such information that is responsive to this Item 11, except for information set forth under suchthe heading “Pay Versus Performance,” is incorporated herein by this reference thereto.
Power and PSE&G
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
AND MANAGEMENT AND RELATED STOCKHOLDERSSTOCKHOLDER MATTERS
PSEG
The information required by Item 12 of Form 10-K with respect to directors, executive officers and certain beneficial owners is set forth under the heading “Security Ownership of Directors, Management and Certain Beneficial Owners” in PSEG’s definitive Proxy Statement for the 20182024 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 12, 20187, 2024 and such information set forth under such heading is incorporated herein by this reference thereto.
For information relating to securities authorized for issuance under equity compensation plans, see Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Power and PSE&G
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
DIRECTOR INDEPENDENCE
PSEG
The information required by Item 13 of Form 10-K is set forth under the heading “Corporate Governance—Transactions withGovernance-Certain Relationships and Related Persons”Person Transactions” in PSEG’s definitive Proxy Statement for the 20182024 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 12, 20187, 2024 and such information set forth under such heading is incorporated herein by this reference thereto.
Power and PSE&G
Omitted pursuant to conditions set forth in General Instruction I of Form 10K.10-K.
ITEM 14. PRINCIPAL ACCOUNTINGACCOUNTANT FEES AND SERVICES
The information required by Item 14 of Form 10-K is set forth under the heading “Fees“Oversight of the Independent Auditor-Fees Billed by Deloitte & Touche LLP for 20172023 and 2016”2022” in PSEG’s definitive Proxy Statement for the 20182024 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 12, 2018.7, 2024. Such information set forth under such heading is incorporated herein by this reference hereto.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(A) The following Financial Statements are filed as a part of this report:
a.Public Service Enterprise Group Incorporated’s Consolidated Balance Sheets as of December 31, 2023 and 2022 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Stockholders’ Equity for the three years ended December 31, 2023 on pages 60 through 65.
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a. | Public Service Enterprise Group Incorporated’s Consolidated Balance Sheets as of December 31, 2017 and 2016 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Stockholders’ Equity for the three years ended December 31, 2017 on pages 77 through 82. |
b.Public Service Electric and Gas Company’s Consolidated Balance Sheets as of December 31, 2023 and 2022 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Common Stockholder’s Equity for the three years ended December 31, 2023 on pages 66 through 71.
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b. | Public Service Electric and Gas Company’s Consolidated Balance Sheets as of December 31, 2017 and 2016 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Common Stockholder’s Equity for the three years ended December 31, 2017 on pages 83 through 88. |
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c. | PSEG Power LLC’s Consolidated Balance Sheets as of December 31, 2017 and 2016 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Capitalization and Member’s Equity for the three years ended December 31, 2017 on pages 89 through 94. |
(B) The following documents are filed as a part of this report:
a.PSEG’s Financial Statement Schedules:
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a. | PSEG’s Financial Statement Schedules: |
Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 20172023 (page 193)157).
b.PSE&G’s Financial Statement Schedules:
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b. | PSE&G’s Financial Statement Schedules: |
Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 20172023 (page 193)157).
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c. | Power’s Financial Statement Schedules: |
Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2017 (page 193).
Schedules other than those listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.
(C) The following documents are filed as part of this report:
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101.INS | | |
101.INS | | Inline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. |
101.SCH | | Inline XBRL Taxonomy Extension Schema |
101.CAL | | Inline XBRL Taxonomy Calculation Linkbase |
101.LAB | | Inline XBRL Taxonomy Extension Labels Linkbase |
101.PRE | | Inline XBRL Taxonomy Extension Presentation Linkbase |
101.DEF | | Inline XBRL Taxonomy Extension Definition Document |
104 | | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
b. | | PSE&G |
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4a(1) | | Indenture between PSE&G and Fidelity Union Trust Company (now, Wachovia Bank, National Association), as Trustee, dated August 1, 1924(30)(32), securing First and Refunding Mortgage Bond and Supplemental Indentures between PSE&G and U.S. Bank National Association, successor, as Trustee, supplemental to Exhibit 4a(1), dated as follows: |
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4a(2) | | June 1, 1937(33) |
4a(2)4a(3) | | JuneJuly 1, 1937(31)(34)
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4a(3)4a(4) | | July 1, 1937(32)
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4a(4) | | March 1, 1942(33)
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4a(5) | | June 1, 1991 (No. 1)(34) |
4a(6) | | July 1, 1993(35)
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4c | | Indenture of Trust between PSE&G and Chase Manhattan Bank (National Association) (The Bank of New York Mellon, successor), as Trustee, providing for Secured Medium-Term Notes dated July 1, 1993(44)(48) |
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101.INS | | Inline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document |
101.SCH | | Inline XBRL Taxonomy Extension Schema |
101.CAL | | Inline XBRL Taxonomy Calculation Linkbase |
101.LAB | | Inline XBRL Taxonomy Extension Labels Linkbase |
101.PRE | | Inline XBRL Taxonomy Extension Presentation Linkbase |
101.DEF | | Inline XBRL Taxonomy Extension Definition Document |
c.104 | | Power: |
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101.INS | | XBRL Instance Document |
101.SCH | | XBRL Taxonomy Extension Schema |
101.CAL | | XBRL Taxonomy Calculation Linkbase |
101.LAB | | XBRL Taxonomy Extension Labels Linkbase |
101.PRE | | XBRL Taxonomy Extension Presentation Linkbase |
101.DEF | | XBRL Taxonomy Extension Definition Document101) |
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(1) | Filed as Exhibit 3.1a with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120, on May 4, 2007 and incorporated herein by this reference. |
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(2) | Filed as Exhibit 3.1b with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120, on May 4, 2007 and incorporated herein by this reference. |
(1)Filed as Exhibit 3.1a with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120, on May 4, 2007 and incorporated herein by this reference.
(2)Filed as Exhibit 3.1b with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120, on May 4, 2007 and incorporated herein by this reference.
(3)Filed as Exhibit 3.1c with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120, on May 4, 2007 and incorporated herein by this reference.
(4)Filed as Exhibit 3.1 with Current Report on Form 8-K, File No. 001-09120, on February 17, 2023 and incorporated herein by this reference.
(5)Filed as Exhibit 4(f) with Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, File No. 001-09120, on May 13, 1998 and incorporated herein by this reference.
(6)Filed as Exhibit 4(f) with Annual Report on Form 10-K for the year ended December 31, 1998, File No. 001-09120, on February 23, 1999 and incorporated herein by this reference
(7)Filed as Exhibit 4c for PSEG with Annual Report on Form 10-K for the year ended December 31, 2019. File No. 001-09120, on February 26, 2020 and incorporated herein by this reference.
(8)Filed as Exhibit 10.1 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, File No. 001-09120, on October 31, 2019 and incorporated herein by this reference.
(9)Filed as Exhibit 10.2 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, File No. 001-09120, on October 31, 2019 and incorporated herein by this reference.
(10)Filed as Exhibit 10a(3) with Annual Report on Form 10-K for the year ended December 31, 2020, File No. 001-09120, on March 1, 2021 and incorporated herein by this reference.
(11)Filed as Exhibit 10a(4) with Annual Report on Form 10-K for the year ended December 31, 2018, File No. 001-09120 on February 27, 2019 and incorporated herein by this reference.
(12)Filed as Exhibit 10.1 with Current Report on Form 8-K, File No. 001-09120, on July 22, 2022 and incorporated herein by this reference.
(13)Filed as Exhibit 10a(17) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120, on February 26, 2003 and incorporated herein by this reference.
(14)Filed as Exhibit 10a(20) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120, on February 26, 2003 and incorporated herein by this reference.
(15)Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, File No. 001-09120, on May 1, 2013 and incorporated herein by this reference.
(16)Filed as Exhibit 10.1 with Current Report on Form 8-K, File No. 001-09120, on February 19, 2009 and incorporated herein by this reference.
(17)Filed as Exhibit 10a with Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-09120, on February 26, 2015, and incorporated herein by this reference.
(18)Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, File No. 001-09120, on October 30, 2015, and incorporated herein by this reference.
(19)Filed as Exhibit 10a(20) with Annual Report on Form 10-K for the year ended December 31, 2017, File No. 001-09120 on February 26, 2018 and incorporated herein by this reference.
(20)Filed as Exhibit 10.2 with Current Report on Form 8-K, File No. 001-09120, on April 19, 2022 and incorporated herein by this reference.
(21)Filed as Exhibit 99.1 with Current Report on Form 8-K, File No. 001-09120, on April 22, 2021 and incorporated herein by this reference.
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(3) | Filed as Exhibit 3.1c with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120, on May 4, 2007 and incorporated herein by this reference. |
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(4) | Filed as Exhibit 99.1 with Current Report on Form 8-K, File No. 001-09120, on December 16, 2015 and incorporated herein by this reference. |
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(5) | Filed as Exhibit 4(f) with Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, File No. 001-09120, on May 13, 1998 and incorporated herein by this reference. |
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(6) | Filed as Exhibit 4(f) to the Annual Report on Form 10-K for the year ended December 31, 1998, File No. 001-09120, on February 23, 1999 and incorporated herein by this reference |
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(7) | Filed as Exhibit 10.1 with Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, File No. 001-09120, on July 28, 2017 and incorporated herein by this reference. |
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(8) | Filed as Exhibit 10.2 with Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, File No. 001-09120, on July 28, 2017 and incorporated herein by this reference. |
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(9) | Filed as Exhibit 10a(4) with Annual Report on Form 10-K for the year ended December 31, 2007, File Nos. 001-09120 on February 28, 2008 and 000-49614, and incorporated herein by reference. |
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(10) | Filed as Exhibit 10.5 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, File No. 001-09120, on November 1, 2011 and incorporated herein by this reference. |
| |
(11) | Filed as Exhibit 10a(7) with Annual Report on Form 10-K for the year ended December 31, 2011, File No. 001-09120, on February 27, 2012 and incorporated herein by this reference. |
| |
(12) | Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, File No. 001-09120, on November 4, 2002 and incorporated herein by this reference. |
| |
(13) | Filed as Exhibit 10a(7) with Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-09120, on March 6, 2001 and incorporated herein by this reference. |
| |
(14) | Filed as Exhibit 10a(11) with Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-09120, on February 26, 2009 and incorporated herein by this reference. |
| |
(15) | Filed as Exhibit 99 with Current Report on Form 8-K, File Nos. 001-09120, 000-49614 and 001-00973, on December 22, 2008 and incorporated herein by this reference. |
| |
(16) | Filed as Exhibit 10a(17) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120, on February 26, 2003 and incorporated herein by this reference. |
| |
(17) | Filed as Exhibit 10a(20) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120, on February 26, 2003 and incorporated herein by this reference. |
| |
(18) | Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, File No. 001-09120, on May 1, 2013 and incorporated herein by reference. |
| |
(19) | Filed as Exhibit 10.1 with Current Report on Form 8-K, File No. 001-09120, on February 19, 2009 and incorporated herein by this reference. |
| |
(20) | Filed as Exhibit 10a(19) with Annual Report on Form 10-K for the year ended December 31, 2011, File No. 001-09120, on February 27, 2012. |
| |
(21) | Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, File No. 001-09120, on November 1, 2011 and incorporated herein by reference. |
| |
(22) | Filed as Exhibit 10a with Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-09120, on February 26, 2015. |
| |
(23) | Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, File No. 001-09120, on October 30, 2015. |
| |
(24) | Filed as Exhibit 3(a) with Quarterly Report on Form 10-Q for the quarter ended June 30, 1986, File No. 001-00973, on August 28, 1986 and incorporated herein by this reference. |
| |
(25) | Filed as Exhibit 3a(2) with Annual Report on Form 10-K for the year ended December 31, 1987, File No. 001-00973, on March 28, 1988 and incorporated herein by this reference. |
| |
(26) | Filed as Exhibit 3a(3) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference. |
| |
(27) | Filed as Exhibit 3a(4) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference. |
| |
(28) | Filed as Exhibit 3a(5) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference. |
| |
(29) | Filed as Exhibit 3.3 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-00973, on May 4, 2007 and incorporated herein by this reference. |
| |
(30) | Filed as Exhibit 4b(1) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference. |
| |
(31) | Filed as Exhibit 4b(3) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference. |
(22)Filed as Exhibit 4.6 to Registration Statement on Form S-8, File No. 001-09120, on April 23, 2021 and incorporated herein by this reference.
(23)Filed as Exhibit 10(4) with Quarterly Report on Form 10-Q for the quarter ended June 30, 2021, File No. 001-09120, on August 9, 2021 and incorporated herein by this reference.
(24)Filed as Exhibit 10.1 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2023, File No. 001-09120, and incorporated herein by reference.
(25)Filed as Exhibit 10.3 with Quarterly Report on Form 10-Q for the quarter ended June 30, 2023, File No. 001-09120, and incorporated herein by reference.
(26)Filed as Exhibit 3a(1) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.
(27)Filed as Exhibit 3a(2) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.
(28)Filed as Exhibit 3a(3) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.
(29)Filed as Exhibit 3a(4) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.
(30)Filed as Exhibit 3a(5) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.
(31)Filed as Exhibit 3.3 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-00973, on May 4, 2007 and incorporated herein by this reference.
(32)Filed as Exhibit 4b(1) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference.
(33)Filed as Exhibit 4b(3) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference.
(34)Filed as Exhibit 4b(4) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference.
(35)Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973, on June 1, 1991 and incorporated herein by this reference.
(36)Filed as Exhibit 4a(28) with Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-00973, on March 1, 2005 and incorporated herein by this reference.
(37)Filed as Exhibit 4a(28) with Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-00973, on February 28, 2008 and incorporated herein by this reference.
(38)Filed as Exhibit 4a(30) with Annual Report on Form 10-K for the year ended December 31, 2009, File No. 001-00973, on February 25, 2010 and incorporated herein by this reference.
(39)Filed as Exhibit 4a(32) with Annual Report on Form 10-K for the year ended December 31, 2012, File No. 001-00973, on February 26, 2013, and incorporated herein by this reference.
(40)Filed as Exhibit 4 with Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, File No. 001-00973, on July 30, 2013, and incorporated herein by this reference.
(41)Filed as Exhibit 4a(22) with Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 001-09120, on October 30, 2014 and incorporated herein by this reference.
(42)Filed as Exhibit 4a(23) with Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 001-09120, on July 31, 2015 and incorporated herein by this reference.
(43)Filed as Exhibit 4a(14) with Annual Report on Form 10-K for the year ended December 31, 2016, File No. 001-00973, on February 27, 2017 and incorporated herein by this reference.
(44)Filed as Exhibit 4a(15) with Quarterly Report on Form 10-Q for the quarter ended March 31, 2018, File No. 001-00973, on April 30, 2018 and incorporated herein by this reference.
(45)Filed as Exhibit 4a(15) with Annual Report on Form 10-K for the year ended December 31, 2019, File No. 001-09120, on February 26, 2020 and incorporated herein by this reference.
(46)Filed as Exhibit 4a(15) with Quarterly Report on Form 10-Q for the quarter ended March 31, 2022, File No. 001-09120, on May 3, 2022 and incorporated herein by reference.
(47)Filed as Exhibit 4b with Annual Report on Form 10-K for the year ended December 31, 2019, File No. 001-09120, on February 26, 2020 and incorporated herein by the reference.
(48)Filed as Exhibit 4 with Current Report on Form 8-K, File No. 001-00973, on December 1, 1993 and incorporated herein by this reference.
(49)Filed as Exhibit 4-6 to Registration Statement on Form S-3, File No. 333-76020, filed on December 27, 2001 and incorporated herein by this reference.
(50)Filed as Exhibit 10.2 with Current Report on Form 8-K, File No. 001-00973, on February 19, 2009 and incorporated herein by this reference.
| |
(32) | Filed as Exhibit 4b(4) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference. |
| |
(33) | Filed as Exhibit 4b(6) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference. |
| |
(34) | Filed as Exhibit 4 on Form 8-A, File No. 001-00973, on June 1, 1991 and incorporated herein by this reference. |
| |
(35) | Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973, on December 1, 1993 and incorporated herein by this reference. |
| |
(36) | Filed as Exhibit 4a(28) with Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-00973, on March 1, 2005 and incorporated herein by this reference. |
| |
(37) | Filed as Exhibit 4a(28) with Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-00973, on February 28, 2008 and incorporated herein by this reference. |
| |
(38) | Filed as Exhibit 4a(32) with Annual Report on Form 10-K for the year ended December 31, 2012, File No. 001-00973, on February 26, 2013. |
| |
(39) | Filed as Exhibit 4a(33) with Annual Report on Form 10-K for the year ended December 31, 2012, File No. 001-00973, on February 26, 2013. |
| |
(40) | Filed as Exhibit 4 with Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, File No. 001-00973, on July 30, 2013. |
| |
(41) | Filed as Exhibit 4a(22) with Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 001-09120, on October 30, 2014 and incorporated herein by reference. |
| |
(42) | Filed as Exhibit 4a(23) with Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 001-09120, on July 31, 2015 and incorporated herein by reference. |
| |
(43) | Filed as Exhibit 4(a)(14) with Annual Report on Form 10-K for the year ended December 31, 2016, File No. 001-00973, on February 27, 2017 and incorporated herein by reference. |
| |
(44) | Filed as Exhibit 4 with Current Report on Form 8-K, File No. 001-00973, on December 1, 1993 and incorporated herein by reference. |
| |
(45) | Filed as Exhibit 4.6 to Registration Statement on Form S-3, File No. 333-76020, filed on December 27, 2001 and incorporated herein by reference. |
| |
(46) | Filed as Exhibit 10.2 with Current Report on Form 8-K, File No. 001-00973, on February 19, 2009 and incorporated herein by reference. |
| |
(47) | Filed as Exhibit 3.1 to Registration Statement on Form S-4, No. 333-69228, filed on September 10, 2001 and incorporated herein by this reference. |
| |
(48) | Filed as Exhibit 3.2 to Registration Statement on Form S-4, No. 333-69228, filed on September 10, 2001 and incorporated herein by this reference. |
| |
(49) | Filed as Exhibit 4.1 to Registration Statement on Form S-4, No. 333-69228, filed on September 10, 2001 and incorporated herein by this reference. |
| |
(50) | Filed as Exhibit 4.7 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, File No. 000-49614, on May 15, 2002 and incorporated herein by this reference. |
Schedule II—Valuation and Qualifying Accounts Years Ended December 31, 2017—2023—December 31, 20152021
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Column A | | Column B | | Column C Additions | | | Column D | | | | Column E | |
| Description | | Balance at Beginning of Period | | Charged to cost and expenses | | Charged to other accounts- describe | | | Deductions- describe | | | | Balance at End of Period | |
| | | Millions | |
| 2023 | | | | | | | | | | | | | | |
| Allowance for Credit Losses | | $ | 339 | | | $ | 100 | | (A) | $ | — | | | | $ | 156 | | | (B) | | $ | 283 | | |
| Materials and Supplies Valuation Reserve | | 10 | | | 4 | | | — | | | | — | | | | | 14 | | |
| 2022 | | | | | | | | | | | | | | |
| Allowance for Credit Losses | | $ | 337 | | | $ | 114 | | (A) | $ | — | | | | $ | 112 | | | (B) | | $ | 339 | | |
| Materials and Supplies Valuation Reserve | | 12 | | | 1 | | | — | | | | 3 | | | (C) | | 10 | | |
| 2021 | | | | | | | | | | | | | | |
| Allowance for Credit Losses | | $ | 206 | | | $ | 195 | | (A) | $ | — | | | | $ | 64 | | | (B) | | $ | 337 | | |
| Materials and Supplies Valuation Reserve | | 10 | | | 3 | | | — | | | | 1 | | | (C) | | 12 | | |
| | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| Column A | | Column B | | Column C Additions | | Column D | | | | Column E | |
| Description | | Balance at Beginning of Period | | Charged to cost and expenses | | Charged to other accounts- describe | | Deductions- describe | | | | Balance at End of Period | |
| | | Millions | |
| 2017 | | | | | | | | | | | | | |
| Allowance for Doubtful Accounts | | $ | 68 |
| | $ | 76 |
| | $ | — |
| | $ | 85 |
| | (A) | | $ | 59 |
| |
| Materials and Supplies Valuation Reserve | | 37 |
| | 2 |
| | — |
| | 32 |
| | (C) | | 7 |
| |
| 2016 | | | | | | | | | | | | | |
| Allowance for Doubtful Accounts | | $ | 67 |
| | $ | 85 |
| | $ | — |
| | $ | 84 |
| | (A) | | $ | 68 |
| |
| Materials and Supplies Valuation Reserve | | 11 |
| | 32 |
| | — |
| | 6 |
| | (B) | | 37 |
| |
| 2015 | | | | | | | | | | | | | |
| Allowance for Doubtful Accounts | | $ | 52 |
| | $ | 101 |
| | $ | — |
| | $ | 86 |
| | (A) | | $ | 67 |
| |
| Materials and Supplies Valuation Reserve | | 15 |
| | 2 |
| | — |
| | 6 |
| | (B) | | 11 |
| |
| | | | | | | | | | | | | | |
(A)For a discussion of bad debt recoveries, see Item 8. Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies. | |
(A) | Accounts Receivable written off. |
| |
(B) | Reduce reserve to appropriate level and to remove obsolete inventory. |
| |
(C) | Hudson and Mercer inventory written off. |
(B)Accounts Receivable written off.
(C)Reserve reduced to appropriate level as a result of asset dispositions and to remove obsolete inventory.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Column A | | Column B | | Column C Additions | | | Column D | | | | Column E | |
| Description | | Balance at Beginning of Period | | Charged to cost and expenses | | Charged to other accounts- describe | | | Deductions- describe | | | | Balance at End of Period | |
| | | Millions | |
| 2023 | | | | | | | | | | | | | | |
| Allowance for Credit Losses | | $ | 339 | | | $ | 100 | | (A) | $ | — | | | | $ | 156 | | | (B) | | $ | 283 | | |
| Materials and Supplies Valuation Reserve | | 4 | | | 3 | | | — | | | | — | | | | | 7 | | |
| 2022 | | | | | | | | | | | | | | |
| Allowance for Credit Losses | | $ | 337 | | | $ | 114 | | (A) | $ | — | | | | $ | 112 | | | (B) | | $ | 339 | | |
| Materials and Supplies Valuation Reserve | | 3 | | | 1 | | | — | | | | — | | | | | 4 | | |
| 2021 | | | | | | | | | | | | | | |
| Allowance for Credit Losses | | $ | 206 | | | $ | 195 | | (A) | $ | — | | | | $ | 64 | | | (B) | | $ | 337 | | |
| Materials and Supplies Valuation Reserve | | 2 | | | 2 | | | — | | | | 1 | | | (C) | | 3 | | |
| | | | | | | | | | | | | | | |
(A)For a discussion of bad debt recoveries, see Item 8. Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies.
(B)Accounts Receivable written off.
(C)Reserve reduced to appropriate level and to remove obsolete inventory.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| Column A | | Column B | | Column C Additions | | Column D | | | | Column E | |
| Description | | Balance at Beginning of Period | | Charged to cost and expenses | | Charged to other accounts- describe | | Deductions- describe | | | | Balance at End of Period | |
| | | Millions | |
| 2017 | | | | | | | | | | | | | |
| Allowance for Doubtful Accounts | | $ | 68 |
| | $ | 76 |
| | $ | — |
| | $ | 85 |
| | (A) | | $ | 59 |
| |
| Materials and Supplies Valuation Reserve | | — |
| | — |
| | — |
| | — |
| | | | — |
| |
| 2016 | | | | | | | | | | | | | |
| Allowance for Doubtful Accounts | | $ | 67 |
| | $ | 85 |
| | $ | — |
| | $ | 84 |
| | (A) | | $ | 68 |
| |
| Materials and Supplies Valuation Reserve | | 1 |
| | — |
| | — |
| | 1 |
| | (B) | | — |
| |
| 2015 | | | | | | | | | | | | | |
| Allowance for Doubtful Accounts | | $ | 52 |
| | $ | 101 |
| | $ | — |
| | $ | 86 |
| | (A) | | $ | 67 |
| |
| Materials and Supplies Valuation Reserve | | 2 |
| | — |
| | — |
| | 1 |
| | (B) | | 1 |
| |
| | | | | | | | | | | | | | |
| |
(A) | Accounts Receivable written off. |
| |
(B) | Reduce reserve to appropriate level and to remove obsolete inventory. |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| Column A | | Column B | | Column C Additions | | Column D | | | | Column E | |
| Description | | Balance at Beginning of Period | | Charged to cost and expenses | | Charged to other accounts- describe | | Deductions- describe | | | | Balance at End of Period | |
| | | | | | | Millions | | | | | | | |
| 2017 | | | | | | | | | | | | | |
| Materials and Supplies Valuation Reserve | | $ | 37 |
| | $ | 2 |
| | $ | — |
| | $ | 32 |
| | (A) | | $ | 7 |
| |
| 2016 | | | | | | | | | | | | | |
| Materials and Supplies Valuation Reserve | | $ | 10 |
| | $ | 32 |
| | $ | — |
| | $ | 5 |
| | (B) | | $ | 37 |
| |
| 2015 | | | | | | | | | | | | | |
| Materials and Supplies Valuation Reserve | | $ | 13 |
| | $ | 2 |
| | $ | — |
| | $ | 5 |
| | (B) | | $ | 10 |
| |
| | | | | | | | | | | | | | |
| |
(A) | Hudson and Mercer inventory written off. |
| |
(B) | Reduce reserve to appropriate level and to remove obsolete inventory. |
GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
Term Phrase/Description |
| | |
Base load | | Minimum amount of electric power delivered or required over a given period of time at a constant rate, this is the level of demand that is seen as a minimum during a 24-hour day |
BGS | | Basic Generation Service |
| | PSE&G is required to provide BGS for all customers in New Jersey who are not supplied by a third-party supplier. |
BGS-RSCP | | Basic Generation Service-Residential Small Commercial Product |
| | Seasonally adjusted fixed prices charged for a three-year term for electric supply service to smaller industrial and commercial customers and residential customers who are not supplied by a TPS |
BGSS | | Basic Gas Supply Service |
| | Mechanism approved by the BPU for NJ utilities to recover all commodity costs related to supplying gas to residential customers |
BPU | | New Jersey Board of Public Utilities |
| | Agency responsible for regulating public utilities doing business in New Jersey |
Capacity | | Amount of electricity that can be produced by a specific generating facility |
Combined Cycle | | A method of generation whereby electricity and process steam are produced from otherwise lost waste heat exiting from one or more combustion turbines. The exiting heat is routed to a conventional boiler or to a heat recovery steam generator for use by a steam turbine in the production of electricity |
Congestion | | Condition when the available capacity of a transmission line is being closely approached (or exceeded) by the electric power trying to go through it; at such times, alternative power line pathways (or local generators near the load) must be used instead |
Distribution | | The delivery of electricity to the retail customer’s home, business or industrial facility through low voltage distribution lines |
EPA | | U.S. Environmental Protection Agency |
FASB | | Financial Accounting Standards Board |
| | A private, not-for-profit organization whose primary purpose, as designated by the SEC, is to develop accounting standards for public companies in the U.S. |
FERC | | U.S. Federal Energy Regulatory Commission |
Forward contracts | | A customized, non-exchange traded contract in which the buyer is obligated to deliver a specified amount of a commodity with a predetermined price formula on a specified future date, at which time payment is due in full |
GAAP | | Generally Accepted Accounting Principles |
| | Standard framework of guidelines issued by the FASB for financial accounting used in the U.S. |
GHG | | Greenhouse gas emissions (including carbon dioxide, methane, nitrous oxide, ozone, and chlorofluorocarbon) that trap the heat of the sun in the Earth’s atmosphere, increasing the mean global surface temperature of the earth |
Hedging | | Entering into a contract or transaction designed to reduce exposure to various risks, such as changes in market prices |
ISO | | Independent System Operator |
| | An independent, regulated entity established to manage a regional electric transmission system in a non-discriminatory manner and to help ensure the safety and reliability of the bulk of the power system |
Load | | Amount of electric power delivered or required at any specific point or points on a system. The requirement originates at the energy-consuming equipment of consumers. |
Term Phrase/Description |
| | |
MBR | | Market Based Rates |
| | Electric service prices determined in an open market system of supply and demand under which the price is set solely by agreement as to what a buyer will pay and a seller will accept |
MGP | | Manufactured Gas Plant |
ISO-NE | | New England Power Pool |
| | An ISO comprised of an alliance of approximately 100 utility companies who manage and direct all major energy production and transmission in the New England states |
NJDEP | | New Jersey Department of Environmental Protection |
NRC | | U.S. Nuclear Regulatory Commission |
NUG | | Non-Utility Generation |
| | Power produced by independent power producers, exempt wholesale generators and other companies that have been exempted from traditional utility regulation |
OPEB | | Other Postretirement Benefits |
| | Benefits other than pensions payable to former employees |
Outage | | The period during which a generating unit, transmission line, or other facility is out of service due to scheduled (planned) or unscheduled maintenance |
PJM | | PJM Interconnection, L.L.C. |
| | A regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 13 northeastern states and the District of Columbia |
Power | | PSEG Power LLC |
Power Pool | | An association of two or more interconnected electric systems having an agreement to coordinate operations and planning for improved reliability and efficiencies |
PSE&G | | Public Service Electric and Gas Company |
PSEG | | Public Service Enterprise Group Incorporated |
Renewable Energy | | Energy derived from resources that are regenerative or that cannot be depleted (i.e. moving water (hydro, tidal and wave power), thermal gradients in ocean water, biomass, geothermal energy, solar energy, and wind energy) |
Regulatory Asset | | Costs deferred by a regulated utility company in accordance with Accounting Standards Codification Topic 980: Regulated operations (ASC 980) |
Regulatory Liability | | Costs recognized by a regulated utility company in accordance with ASC 980 |
RPM | | Reliability Pricing Model (PJM market) |
| | A process for pricing generation capacity based on overall system reliability requirements; using multi-year forward auctions, participants could bid capacity in the form of generation, demand response, or transmission to meet reliability needs by location and/or an ISO market |
SBC | | Societal Benefits Charge |
SEC | | U.S. Securities and Exchange Commission |
Tax Act | | Comprehensive tax legislation, Public Law 115-97, enacted by the U.S. government in December 2017, which, among other things, decreased the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018, and made certain changes to bonus depreciation rules. |
Transmission | | The high-voltage wires and networks that move electricity through states and regions in large quantities - from power plants where it is produced, to the distribution networks that deliver it to homes and businesses |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| | | | | | | | | | | |
| | | |
| | | |
| | | PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED |
| | | |
| | | By: | /s/ RALPH IZZO A. LAROSSA |
| | | | Ralph IzzoA. LaRossa |
| | | | ChairmanChair of the Board, President and |
| | | | Chief Executive Officer |
Date: February 26, 20182024
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| | | | | | | | | | | | | | |
| | | | |
Signature | | Title | | Date |
| | | | |
| | | | |
Signature | | Title | | Date |
| | |
/s/ RALPH IZZO A. LAROSSA | | ChairmanChair of the Board, President, Chief Executive Officer and | | February 26, 20182024 |
Ralph IzzoA. LaRossa | | Director (Principal Executive Officer) | | |
| | |
/s/ DANIEL J. CREGG | | Executive Vice President and Chief Financial Officer | | February 26, 20182024 |
Daniel J. Cregg | | (Principal Financial Officer) | | |
| | |
/s/ STUART J. BLACKROSE M. CHERNICK | | Vice President and Controller | | February 26, 20182024 |
Stuart J. BlackRose M. Chernick | | (Principal Accounting Officer) | | |
| | |
/s/ WILLIE A. DEESE | | Director | | February 26, 2024 |
| | |
/s/ WILLIE A. DEESE
| | Director | | February 26, 2018 |
Willie A. Deese | | | | |
| | | | |
/s/ JAMIE M. GENTOSO | | Director | | February 26, 2024 |
Jamie M. Gentoso | | | | |
| | | | |
/s/ BARRY H. OSTROWSKY | | Director | | February 26, 2024 |
/s/ ALBERT R. GAMPER, JR.
| | Director | | February 26, 2018 |
Albert R. Gamper, Jr. | | | | |
| | |
/s/ WILLIAM V. HICKEY
| | Director | | February 26, 2018 |
William V. Hickey | | | | |
| | |
/s/ SHIRLEY ANN JACKSON
| | Director | | February 26, 2018 |
Shirley Ann Jackson | | | | |
| | |
/s/ DAVID LILLEY
| | Director | | February 26, 2018 |
David Lilley | | | | |
| | | | |
/s/ BARRY H. OSTROWSKY
| | Director | | February 26, 2018 |
Barry H. Ostrowsky | | | | |
| | |
/s/ RICARDO G. PÉREZ | | Director | | February 26, 2024 |
Ricardo G. Pérez | | | | |
| | | | |
/s/ VALERIE A. SMITH | | Director | | February 26, 2024 |
Valerie A. Smith | | | | |
| | | | |
/s/ THOMAS A. RENYISCOTT G. STEPHENSON | | Director | | Director | February 26, 20182024 |
ThomasScott G. Stephenson | | | | |
| | | | |
/s/ LAURA A. RenyiSUGG | | Director | | | February 26, 2024 |
Laura A. Sugg | | | | |
| | | | |
/s/ JOHN P. SURMA | | Director | | February 26, 2024 |
John P. Surma | | | | |
| | | | |
/s/ HAK CHEOL SHINKENNETH Y. TANJI | | Director | | Director | February 26, 20182024 |
Hak Cheol ShinKenneth Y. Tanji | | | | |
| | | | |
/s/ SUSAN TOMASKY | | Director | | February 26, 2024 |
Susan Tomasky | | | | |
| /s/ RICHARD J. SWIFT
| | Director | | February 26, 2018
Richard J. Swift | | | | |
| | | | |
/s/ SUSAN TOMASKY
| | Director | | February 26, 2018 |
Susan Tomasky | | | | |
| | | | |
/s/ ALFRED W. ZOLLAR
| | Director | | February 26, 2018 |
Alfred W. Zollar | | | | |
| | | | |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| | | | | | | | | | | |
| | | |
| | | |
| | | PUBLIC SERVICE ELECTRICAND GAS COMPANY |
| | | |
| | By: | | /s/ KIM C. HANEMANN |
| | | By: | /s/ DAVID M. DALYKim C. Hanemann |
| | | | David M. Daly |
| | | President and Chief Operating Officer |
Date: February 26, 20182024
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| | | | | | | | | | | | | | |
| | | | |
Signature | | Title | | Date |
| | | | |
| | | | |
Signature | | Title | | Date |
| | |
/s/ RALPH IZZO A. LAROSSA | | ChairmanChair of the Board and Chief Executive Officer and | | February 26, 20182024 |
Ralph IzzoA. LaRossa | | Director (Principal Executive Officer) | | |
| | |
/s/ DANIEL J. CREGG | | Executive Vice President and Chief Financial Officer | | February 26, 20182024 |
Daniel J. Cregg | | (Principal Financial Officer) | | |
| | |
/s/ STUART J. BLACKROSE M. CHERNICK | | Vice President and Controller | | February 26, 20182024 |
Stuart J. BlackRose M. Chernick | | (Principal Accounting Officer) | | |
| | | | |
/s/ WILLIE A. DEESE | | Director | | February 26, 2024 |
Willie A. Deese | | | | |
| | | | |
/s/ BARRY H. OSTROWSKY | | Director | | February 26, 2024 |
Barry H. Ostrowsky | | | | |
| | | | |
/s/ ALBERT R. GAMPER, JR.SUSAN TOMASKY | | Director | | Director | February 26, 20182024 |
Albert R. Gamper Jr.Susan Tomasky | | | | |
| | |
| /s/ SHIRLEY ANN JACKSON
| Director | | February 26, 2018 |
Shirley Ann Jackson | | | | |
| | | | |
/s/ RICHARD J. SWIFT
| | Director | | February 26, 2018 |
Richard J. Swift | | | | |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
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| | | |
| | | |
| | | PSEG POWER LLC
|
| | | |
| | By: | /s/ RALPH LAROSSA
|
| | | Ralph LaRossa |
| | | President and Chief Operating Officer |
| | | |
Date: February 26, 2018
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
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| | | | |
| | | | |
Signature | | Title | | Date |
| | |
/s/ RALPH IZZO
| | Chairman of the Board and Chief Executive Officer and | | February 26, 2018 |
Ralph Izzo | | Director (Principal Executive Officer) | | |
| | |
/s/ DANIEL J. CREGG
| | Executive Vice President and Chief Financial Officer and | | February 26, 2018 |
Daniel J. Cregg | | Director (Principal Financial Officer) | | |
�� | | |
/s/ STUART J. BLACK
| | Vice President and Controller | | February 26, 2018 |
Stuart J. Black | | (Principal Accounting Officer) | | |
| | |
/s/ DEREK M. DIRISIO
| | Director | | February 26, 2018 |
Derek M. DiRisio | | | | |
| | |
/s/ RALPH LAROSSA
| | Director | | February 26, 2018 |
Ralph LaRossa | | | | |
| | | | |
/s/ TAMARA L. LINDE
| | Director | | February 26, 2018 |
Tamara L. Linde | | | | |
| | | | |
/s/ MARGARET M. PEGO
| | Director | | February 26, 2018 |
Margaret M. Pego | | | | |