obtain community support for such projects to avoid delays in the receipt of permits and approvals from regulatory authorities;
complete such projects within budgets and on commercially reasonable terms and conditions;
obtain any necessary debt financing on acceptable terms and/or necessary governmental financial incentives;
ensure that contracting parties, including suppliers, perform under their contracts in a timely and cost effective manner; and
at PSE&G, recover the related costs through rates.
Any delays, cost escalations or otherwise unsuccessful construction and development could materially affect our financial position, results of operations and cash flows. Further, any unexpected failure of our existing facilities, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures could result in reduced profitability. Modifications to existing facilities may require us to install the best available control technology or to achieve the lowest achievable emission rates required by then-current regulations, which would likely result in substantial additional capital expenditures.
In addition, the successful operation of new or upgraded generation facilities or transmission or distribution projects is subject to risks relating to supply interruptions; work stoppages and labor disputes; weather interferences; unforeseen engineering and environmental problems, including those related to climate change; and the other risks described herein. Any of these risks could cause our return on these investments to be lower than expected or they could cause these facilities to operate below expected capacity or availability levels, which would adversely impact our financial condition and results of operations through lost revenue, increased expenses, higher maintenance costs and penalties.
FERC Order 1000 has generally opened transmission development to competition from independent developers, allowing such developers to compete with incumbent utilities for the construction and operation of transmission facilities in its service territory. While Order 1000 retains limited carve-outs for certain projects that will continue to default to incumbents for construction responsibility, including immediately needed reliability projects, upgrades to existing transmission facilities, projects cost-allocated to a single transmission zone, and projects being built on existing rights-of-way and whose construction would interfere with incumbents’ use of their rights-of-way, increased competition for transmission projects could decrease the value of new investments that would be subject to recovery by PSE&G under its rate base, which could have a material adverse impact on our financial condition and results of operations.
We may be adversely affected by equipment failures, accidents, severe weather events or other incidents that impact our ability to provide safe and reliable service to our customers and remain competitive and could result in substantial financial losses.
The success of our businesses is dependent on our ability to continue providing safe and reliable service to our customers while minimizing service disruptions. We are exposed to the risk of equipment failures, accidents, severe weather events, or other incidents which could result in damage to or destruction of our facilities or damage to persons or property. For instance, equipment failures in our natural gas distribution system could give rise to a variety of hazards and operating risks, such as leaks, accidental explosions and mechanical problems, which could cause substantial financial losses and harm our reputation.
In addition, the physical risks of severe weather events, such as experienced from Hurricane Irene and Superstorm Sandy, and of climate change, changes in sea level, temperature and precipitation patterns and other related phenomena have further exacerbated these risks. Such issues experienced at our facilities, or by others in our industry, could adversely impact our revenues; increase costs to repair and maintain our systems; subject us to potential litigation and/or damage claims, fines/fines or penalties; and increase the level of oversight of our utility and generation operations and infrastructure through investigations or through the imposition of additional regulatory or legislative requirements. Such actions could adversely affect our costs, competitiveness and future investments, which could be material to our financial position, results of operations and cash flow. For our transmission and distributionT&D business, the cost of storm restoration efforts may not be fully recoverable through the regulatory process. In addition, the inability to restore power to our customers on a timely basis could also materially damage our reputation.
We own less than a controlling interest in some of our generating facilities.
limited governance rights. However, we may not always succeed in such negotiations. As a result, we may be dependent on our partners to operate such facilities. The approval of our partners also
may be required for us to transfer our interest in such projects. Reliance on our partners for the management and operation of these facilities could result in a lower return on these facilities than what we believe we could have otherwise achieved.
Any inability to recover the carrying amount of our long-lived assets and leveraged leases could result in future impairment charges which could have a material adverse impact on our financial condition and results of operations.
Energy Holdings 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. 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. Our receipt of payments related to our leveraged lease portfolio in accordance with the lease contracts can be impacted by various factors, including new environmental legislation regarding air quality and other discharges in the process of generating electricity; market prices for fuel and electricity, including the impact of low gas prices on our coal generation investments;electricity; overall financial condition of lease counterparties; and the quality and condition of assets under lease.
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 unitsassets in our leveraged lease portfolio, and such write-downs could be materialmaterial.
Inability to maintain sufficient liquidity in the amounts and at the times needed or access sufficient capital at reasonable rates or on commercially reasonable terms could adversely impact our business.
Funding for our investments in capital improvement and additions, scheduled payments of principal and interest on our existing indebtedness and the extension and refinancing of such indebtedness has been provided primarily by internally-generated cash flow and external financings. We have significant capital requirements and depend on our ability to generate cash in the future from our operations and continued access to capital and credit markets to efficiently fund our cash flow needs. Our ability to generate cash flow is dependent upon, among other things, industry conditions and general economic, financial, competitive, legislative, regulatory and other factors. The ability to arrange financing and the costs of such financing depend on numerous factors including, among other things.
for PSE&G, our ability to obtain necessary regulatory approvals for the incurrence of additional indebtedness;
our current level of indebtedness and compliance with covenants in our debt agreements;
our financial performance and the continued reliable operation of our business; and
maintenance of our investment grade credit ratings.
Market disruptions, such as economic downturns experienced in the U.S. and abroad, in recent years, the bankruptcy of an unrelated energy company or a systemically important financial institution, changes in market prices for electricity and gas, and actual or threatened acts of war or terrorist attacks, may increase our cost of borrowing or adversely affect our ability to access capital. As a result, no assurance can be given that we will be successful in obtaining financing for projects and investments, to extend or refinance maturing debt or for our other cash flow needs on acceptable terms or at all, which could materially adversely impact our financial position, results of operations and future growth.
We may be unable to realize anticipated tax benefits or retain existing tax credits.
Challenges associated with recruitment and/or retention of key executives and a skilled workforce could adversely impact our businesses.
Our operations depend on the recruitment and retention of key executives and a skilled workforce. The loss or retirement of key executives or other employees, including those with the specialized knowledge required to support our generation transmission and distributionT&D operations, could result in various operational challenges. Certain events, such as the potential for early retirement of our nuclear facilities, can make it more difficult to retain these employees. We may incur increased costs for contractors to replace employees, and the loss of institutional and industry knowledge and the increased costs to hire and lengthy time to train new personnel could result in lower productivity, resulting in increased costs, which would negatively impact our results of operations. This has the potential to become more critical as a growing number of employees become eligible to retire.
Covenants in our debt instruments may adversely affect our operations.
Cybersecurity attacks or intrusions could adversely impact our businesses.
Cybersecurity threats to the U.S. energy market infrastructure are increasing in sophistication, magnitude and frequency. We rely on information technology systems that utilize sophisticated digital systems and network infrastructure to operate our generation transmission and distributionT&D systems. We also store sensitive data, intellectual property and proprietary or personally identifiable information regarding our business, employees, shareholders, customers and vendors on our systems and conduct power marketing and hedging activities. In addition, the operation of our business is dependent upon the information technology systems of third parties, including our vendors, regulators, RTOs and Independent System Operators (ISOs),ISOs, among others. Our and third-party information technology systems may be vulnerable to cybersecurity attacks involving fraud or malice on the part of our employees, other insiders or third parties, whether domestic or foreign sources. A cybersecurity attack may also leverage such information technology to cause disruptions at a third party. Cybersecurity impacts to our operations include:
theft of confidential company, employee, shareholder, vendor or customer information, which may cause us to be in breach of certain covenants and contractual obligations,
general business system and process interruption or compromise, including preventing us from servicing our customers, collecting revenues or the ability to record, process and/or report financial information correctly, and
breaches of vendors’ infrastructures where our confidential information is stored.
existing laws and regulations, significant litigation costs, increased costs to finance our businesses, reputational damage to our reputation and loss of confidence from our customers, regulators, investors, vendors and employees. Similarly, a significant cybersecurity event or breach experienced by a competitor, regulatory authority, RTO, ISO, or vendor could also materially impact our business and results of operations via enhanced legal and regulatory requirements. For a discussion of state and federal cybersecurity regulatory requirements and information regarding our cybersecurity program, see Part 1, Item 1. Business—Regulatory Issues.
The market for cybersecurity insurance is relatively new and coverage available for cybersecurity events mayis expected to evolve as the industry matures. While we maintain insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damage we experience.
Acts of war or terrorism could adversely affect our operations.
Our businesses and industry may be impacted by acts and threats of war or terrorism. These actions could result in increased political, economic and financial and insurance market instability and volatility in power and fuel markets, which could materially adversely affect our business and results of operations, including our ability to access capital on terms and conditions acceptable to us. In addition, our infrastructure facilities, such as our generating stations, transmission and distributionT&D facilities and information technology systems, could be direct or indirect targets or be affected by acts of war or terrorist or other criminal activity. Such events could severely disrupt our business operations and prevent us from servicing our customers. New or updated security regulations may require us to make changes to our current measures which could also result in additional expenses.
None.
Our subsidiaries own all of our physical property. We believe that we and our subsidiaries maintain adequate insurance coverage against loss or damage to plants and properties, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost. For a discussion of nuclear insurance, see Item 8. Financial Statements and Supplementary Data—Note 13.15. Commitments and Contingent Liabilities.
PSE&G
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.
Electric Property and Facilities
As of December 31, 20172019, PSE&G’s electric transmission and distributionT&D system included approximately 24,00025,000 circuit miles, and 853,000858,000 poles, of which 65%64% are jointly-owned. In addition, PSE&G owns and operates 5052 switching stations with an aggregate installed capacity of 36,02337,353 megavolt-amperes (MVA) and 244 substations with an aggregate installed capacity of 8,2508,428 MVA. Four of those substations, having an aggregate installed capacity of 109 MVA are operated on leased property. In addition, PSE&G owns four electric distribution headquarters and five electric sub-headquarters.
Gas Property and Facilities
As of December 31, 2017,2019, PSE&G’s gas system included approximately 18,000 miles of gas mains, 12 gas distribution headquarters, two sub-headquarters, and one meter shop serving all of its gas territory in New Jersey. In addition, PSE&G operates 58 natural gas metering and regulating stations, of which 22 are located on land owned by customers or natural gas pipeline suppliers and are operated under lease, easement or other similar arrangement. In some instances, the pipeline companies own portions of the metering and regulating facilities. PSE&G also owns one liquefied natural gas (LNG) and three liquid petroleum air gas (LPG) peaking facilities. The daily gas capacity of these peaking facilities (the maximum daily gas delivery available during the three peak winter months) is approximately 2.82.5 million therms in the aggregate.
Solar
As of December 31, 2017,2019, PSE&G had 123150 MW dc of installed PV solar capacity throughout New Jersey.
ITEM 3. LEGAL PROCEEDINGS
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 13.15. Commitments and Contingent Liabilities.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
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, 2018,21, 2020, there were 60,86855,987 registered holders.
The following graph below shows a comparison of the five-year cumulative return assuming $100 invested on December 31, 20122014 in our common stock and the subsequent reinvestment of quarterly dividends, the S&P Composite Stock Price Index, the Dow Jones Utilities Index and the S&P Electric Utilities Index.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | 2012 | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 | |
| | PSEG | | $ | 100.00 |
| | $ | 109.35 |
| | $ | 146.73 |
| | $ | 142.46 |
| | $ | 167.57 |
| | $ | 204.11 |
| |
| | S&P 500 | | $ | 100.00 |
| | $ | 132.31 |
| | $ | 150.35 |
| | $ | 152.47 |
| | $ | 170.59 |
| | $ | 207.74 |
| |
| | DJ Utilities | | $ | 100.00 |
| | $ | 112.67 |
| | $ | 147.01 |
| | $ | 142.57 |
| | $ | 168.26 |
| | $ | 190.76 |
| |
| | S&P Electrics | | $ | 100.00 |
| | $ | 113.20 |
| | $ | 145.82 |
| | $ | 138.80 |
| | $ | 161.20 |
| | $ | 180.76 |
| |
| | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | 2014 | | 2015 | | 2016 | | 2017 | | 2018 | | 2019 | |
| | PSEG | | $ | 100.00 |
| | $ | 97.22 |
| | $ | 114.50 |
| | $ | 139.43 |
| | $ | 145.94 |
| | $ | 170.87 |
| |
| | S&P 500 | | $ | 100.00 |
| | $ | 101.37 |
| | $ | 113.49 |
| | $ | 138.26 |
| | $ | 132.19 |
| | $ | 173.80 |
| |
| | DJ Utilities | | $ | 100.00 |
| | $ | 96.93 |
| | $ | 114.55 |
| | $ | 129.85 |
| | $ | 132.43 |
| | $ | 168.57 |
| |
| | S&P Electrics | | $ | 100.00 |
| | $ | 95.16 |
| | $ | 110.65 |
| | $ | 124.05 |
| | $ | 129.15 |
| | $ | 163.24 |
| |
| | | | | | | | | | | | | | | |
The following table indicates the high and low sale prices for our common stock and dividends paid for the periods indicated:
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | Common Stock | | High | | Low | | Dividend per Share | |
| | |
| | 2017 | | | | | | | |
| | First Quarter | | $ | 46.14 |
| | $ | 42.77 |
| | $ | 0.43 |
| |
| | Second Quarter | | $ | 45.94 |
| | $ | 42.47 |
| | $ | 0.43 |
| |
| | Third Quarter | | $ | 47.47 |
| | $ | 41.67 |
| | $ | 0.43 |
| |
| | Fourth Quarter | | $ | 53.28 |
| | $ | 46.05 |
| | $ | 0.43 |
| |
| | 2016 | | | | | | | |
| | First Quarter | | $ | 47.22 |
| | $ | 37.85 |
| | $ | 0.41 |
| |
| | Second Quarter | | $ | 47.41 |
| | $ | 42.77 |
| | $ | 0.41 |
| |
| | Third Quarter | | $ | 46.81 |
| | $ | 41.07 |
| | $ | 0.41 |
| |
| | Fourth Quarter | | $ | 44.29 |
| | $ | 39.28 |
| | $ | 0.41 |
| |
| | | | | | | | | |
On February 20, 2018,18, 2020, our Board of Directors approved a $0.45$0.49 per share common stock dividend for the first quarter of 2018.2020. This reflects an indicative annual dividend rate of $1.80$1.96 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.
The following table indicates our common share repurchases in the open market during the fourth quarter of 2017 to satisfy obligations under various equity compensation award grants:
|
| | | | | | | | | |
| | | | | | | |
| | 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 | | — |
| | $ | — |
| |
| | | | | | | |
In December 2017,November 2019, 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 2018.2020. There were no common share repurchases in the open market during the fourth quarter of 2019.
The following table indicates the securities authorized for issuance under equity compensation plans as of December 31, 2017:2019:
|
| | | | | | | | | | | | |
| | | | | | | | | |
| | 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 |
| |
| | | | | | | | | |
|
| | | | | | | | | | | | |
| | | | | | | | |
| 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 | | — |
| | $ | — |
| | 12,492,253 |
| |
| Employee Stock Purchase Plan | | — |
| | — |
| | 2,608,284 |
| |
| Total | | — |
| | $ | — |
| | 15,100,537 |
| |
| | | | | | | | |
For additional discussion of specific plans concerning equity-based compensation, see Item 8. Financial Statements and Supplementary Data—Note 18.20. 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.
PSEG Power
We own all of PSEG Power’s outstanding limited liability company membership interests. For additional information regarding PSEG Power’s ability to pay dividends, see Item 7. MD&A—Liquidity and Capital Resources.
ITEM 6. SELECTED FINANCIAL DATA
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).Statements.
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | 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 |
| |
| | Long-Term Obligations (D) | | $ | 12,071 |
| | $ | 10,897 |
| | $ | 8,837 |
| | $ | 8,218 |
| | $ | 7,830 |
| |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | PSEG | | | | | | | | | | | |
| | Years Ended December 31, | | 2019 | | 2018 | | 2017 | | 2016 | | 2015 | |
| | | | Millions, except Earnings per Share | |
| | Operating Revenues (A) | | $ | 10,076 |
| | $ | 9,696 |
| | $ | 9,094 |
| | $ | 8,966 |
| | $ | 10,415 |
| |
| | Income from Continuing Operations (B)(C)(D)(E) | | $ | 1,693 |
| | $ | 1,438 |
| | $ | 1,574 |
| | $ | 887 |
| | $ | 1,679 |
| |
| | Net Income (B)(C)(D)(E) | | $ | 1,693 |
| | $ | 1,438 |
| | $ | 1,574 |
| | $ | 887 |
| | $ | 1,679 |
| |
| | Earnings per Share: | | | | | | | | | | | |
| | Income from Continuing Operations | | | | | | | | | | | |
| | Basic | | $ | 3.35 |
| | $ | 2.85 |
| | $ | 3.12 |
| | $ | 1.76 |
| | $ | 3.32 |
| |
| | Diluted | | $ | 3.33 |
| | $ | 2.83 |
| | $ | 3.10 |
| | $ | 1.75 |
| | $ | 3.30 |
| |
| | Net Income | | | | | | | | | | | |
| | Basic | | $ | 3.35 |
| | $ | 2.85 |
| | $ | 3.12 |
| | $ | 1.76 |
| | $ | 3.32 |
| |
| | Diluted | | $ | 3.33 |
| | $ | 2.83 |
| | $ | 3.10 |
| | $ | 1.75 |
| | $ | 3.30 |
| |
| | Dividends Declared per Share | | $ | 1.88 |
| | $ | 1.80 |
| | $ | 1.72 |
| | $ | 1.64 |
| | $ | 1.56 |
| |
| | As of December 31, | | | | | | | | | | | |
| | Total Assets | | $ | 47,730 |
| | $ | 45,326 |
| | $ | 42,716 |
| | $ | 40,070 |
| | $ | 37,535 |
| |
| | Long-Term Obligations | | $ | 13,743 |
| | $ | 13,168 |
| | $ | 12,071 |
| | $ | 10,897 |
| | $ | 8,837 |
| |
| | | | | | | | | | | | | |
| |
| (A) | Operating RevenuesAmounts for 2017 and 2016 have been retrospectively adjusted to reflect guidance for Revenue from Contracts with Customers adopted on January 1, 2018. Amounts for 2015 were not required to be adjusted for this guidance 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.are therefore not comparative. |
| |
| (B) | Income from Continuing Operations and Net Income for 2019 include an after-tax loss of $286 million related to the sale of PSEG Power’s ownership interests in the Keystone and Conemaugh fossil generation plants. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions. |
| |
| (C) | Income from Continuing Operations and Net Income for 2019 and 2018 include after-tax net unrealized gains (losses) on equity securities of approximately $118 million and $(125) million, respectively, in accordance with accounting guidance effective January 1, 2018. |
| |
| (D) | Income from Continuing Operations and Net Income include an after-tax gain for 2018 of $39 million from the sale of PSEG Power’s Hudson and Mercer coal/gas generation plants and after-tax expenses 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 andthese plants; after-tax charges for 2019, 2018, 2017 and 2016 totaling $32 million, $5 million, $45 million and $92 million, respectively, related to investments in REMA’scertain leveraged leasesleases; and an after-tax insurance recovery for Superstorm Sandy2015 of $102 million for 2015.Superstorm Sandy. See Item 8. Financial Statements and Supplementary Data—Note 3.4. Early Plant Retirements,Retirements/Asset Dispositions, Note 7.9. Long-Term Investments and Note 8.10. Financing Receivables for additional information for 2017.information. |
| |
(C)(E) | 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 20.22. Income Taxes for additional information for 2017. |
| |
(D) | Includes capital lease obligations. |
PSE&G and PSEG 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), Public Service Electric and Gas Company (PSE&G) and PSEG Power LLC (Power)(PSEG Power). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G and PSEG Power each make representations only as to itself and make no representations whatsoever as to any other company.
PSEG’s business consists of two reportable segments, our principal direct wholly owned subsidiaries, which are:
PSE&G—which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). PSE&G also invests in solar generation projects and energy efficiency and related programs in New Jersey, which are regulated by the BPU, and
Power—which is a multi-regional energy supply company that integrates the operations of its merchant nuclear and fossil generating assets with its power marketing businesses and fuel supply functions through competitive energy sales in well-developed energy markets primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, Power owns and operates solar generation in various states. Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate.
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| • | PSE&G—which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). PSE&G also invests in regulated solar generation projects and energy efficiency and related programs in New Jersey, which are regulated by the BPU, and |
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| • | PSEG Power—which is a multi-regional energy supply company that integrates the operations of its merchant nuclear and fossil generating assets with its power marketing businesses and fuel supply functions through competitive energy sales in well-developed energy markets primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, PSEG Power owns and operates solar generation in various states. PSEG Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission, the Environmental Protection Agency (EPA) and the states in which they operate. |
PSEG’s other direct wholly owned subsidiaries are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) transmission and distribution (T&D) system under an Operations Services Agreement (OSA);Agreement; PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.
Our business discussion in Item 1. Business provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets, focusing on operational excellence, financial strength and making disciplined investments. Our risk factor discussion in Item 1A. Risk Factors provides information about factors that could have a material adverse impact on our businesses. The following discussion provides an overview of the significant events and business developments that have occurred during 20172019 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.
For a discussion of 2017 items and year-over-year comparisons of changes in our financial condition and results of operations as of and for the years ended December 31, 2018 and December 31, 2017, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2018 (2018 Annual Report) as filed with the Securities and Exchange Commission on February 27, 2019.
EXECUTIVE OVERVIEW OF 20172019 AND FUTURE OUTLOOK
2017 Overview
Our business plan is designed to achieve growth while managing the risks associated with regulatory changes, fluctuating commodity prices and changes in customer demand. Over the past few years, our investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G.
PSE&G
At PSE&G, our focus is on enhancing reliability and resiliency of our T&D system, meeting customer expectations and supporting public policy objectives by investing capital in T&D infrastructure and clean energy programs. For the five-year period ending December 31, 2024, PSE&G expects to invest between $11.5 billion to $15 billion, resulting in an expected compound annual rate base growth of 6.5% to 8%. These ranges are driven by certain unapproved investment programs, including the Clean Energy Future (CEF) and incremental reliability and resiliency investments anticipated in the 2024 timeframe that we intend to seek approval for under the third phase of existing infrastructure programs. See below for a description of the CEF program.
In 2019, we commenced our BPU-approved Gas System Modernization Program II (GSMP II), an expanded, five-year program to invest $1.9 billion beginning in 2019 to replace approximately 875 miles of cast iron and unprotected steel mains in addition to other improvements to the gas system. Approximately $1.6 billion will be recovered through periodic rate roll-ins, with the remaining $300 million to be recovered through a future base rate proceeding. As part of the settlement approved by the BPU,
PSE&G agreed to file a base rate proceeding no later than December 2023, to maintain a base level of gas distribution capital expenditures of $155 million per year and to achieve certain leak reduction targets.
Also in 2019, the BPU approved our Energy Strong II Program, an $842 million program to harden, modernize and improve the resiliency of our electric and gas distribution systems. This program began in the fourth quarter of 2019 and is expected to be completed by the end of 2023. Approximately $692 million of the program will be recovered through periodic rate recovery filings, with the balance to be recovered in our next distribution base rate case, which is required to be filed no later than December 2023.
In October 2018, we filed our proposed CEF program with the BPU, a six-year estimated $3.5 billion investment covering four programs; (i) an Energy Efficiency (EE) program totaling $2.5 billion of investment designed to achieve energy efficiency targets required under New Jersey’s Clean Energy law; (ii) an Electric Vehicle (EV) infrastructure program; (iii) an Energy Storage (ES) program and (iv) an Energy Cloud (EC) program which will include installing approximately two million electric smart meters and associated infrastructure. The BPU is reviewing the CEF-EE program concurrently with its efforts to complete a stakeholder process to define key terms and policy parameters regarding returns, amortization and lost revenue recovery related to implementing energy efficiency programs statewide. Additionally, the State released its Energy Master Plan in January 2020, which is supportive of energy efficiency but gives the BPU discretion in implementation between state-and utility-operated programs. In February 2020, PSE&G reached an agreement with parties in the CEF-EE matter which was approved by the BPU to (a) extend several existing EE programs for six months, with an additional $111 million investment over the course of the programs, and (b) extend the timeline for review of the CEF-EE filing through September 2020. In addition, the BPU has circulated to the parties procedural schedules for the proposed $1 billion investment in CEF-EC, CEF-EV and CEF-ES programs.
We also continue to invest in transmission infrastructure in order to (i) maintain and enhance system integrity and grid reliability, grid security and safety, (ii) address an aging transmission infrastructure, (iii) leverage technology to improve the operation of the system, (iv) reduce transmission constraints, (v) meet growing demand and (vi) meet environmental requirements and standards set by various regulatory bodies. Our planned capital spending for transmission in 2020-2022 is $2.8 billion.
PSEG Power
At PSEG Power, we strive to improve performance and reduce costs in order to optimize cash flow generation from our fleet in light of low wholesale power and gas prices, environmental considerations and competitive market forces that reward efficiency and reliability. PSEG Power continues to move its fleet toward improved efficiency and believes that its recently completed investment program enhances its competitive position with the addition of efficient, clean, reliable combined cycle gas turbine capacity. In 2019, our natural gas fleet generated 23 terawatt hours and our nuclear fleet achieved a capacity factor of 88.7%. Our commitments for load, such as basic generation service (BGS) in New Jersey and other bilateral supply contracts, are backed by this generation or may be combined with the use of physical commodity purchases and financial instruments from the market to optimize the economic efficiency of serving our obligations. PSEG 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 70% of PSEG Power’s expected gross margin in 2020 relates to hedging of our energy margin, our expected revenues from the capacity market mechanisms, Zero Emission Certificate (ZEC) revenues that commenced in April 2019 and certain ancillary service payments such as reactive power.
PSEG Power completed its 1,800 MW combined cycle gas turbine construction program with the addition of the Keys Energy Center (Keys) in Maryland and Sewaren 7 in New Jersey in 2018 and Bridgeport Harbor Station Unit 5 (BH5) in Connecticut in 2019. These additions to our fleet both expand our geographic diversity and adjust our fuel mix and enhance the environmental profile and overall efficiency of PSEG Power’s generation fleet.
Operational Excellence
We emphasize operational performance while developing opportunities in both our competitive and regulated businesses. Flexibility in our generating fleet has allowed us to take advantage of opportunities in a rapidly evolving market as we remain diligent in managing costs. In 2019, our
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| • | utility continued its efforts to control costs while maintaining strong operational performance, including being recognized by PA Consulting as the most reliable electric utility in the Mid-Atlantic region for the 18th consecutive year, and |
our efficient combined cycle gas units benefited our capacity factor across the natural gas fleet and were readily available to operate when needed, all while diligently adhering to our cost control programs.
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 2019 as we
maintained sufficient liquidity,
maintained solid investment grade credit ratings, and
increased our annual dividend for 2019 to $1.88 per share.
We expect to be able to fund our planned capital requirements, as described in Liquidity and Capital Resources, and the impacts of the Tax Cuts and Jobs Act of 2017 (Tax Act) without the issuance of new equity. For additional information on the impacts of the Tax Act, see Item 8. Note 7. Regulatory Assets and Liabilities and Note 22. Income Taxes.
Financial Results
As a result of the settlement of PSE&G’s distribution base rate proceeding in 2018, PSE&G’s overall 2019annual revenues were reduced by approximately $13 million, comprised of a $212 million increase in base revenues, including recovery of deferred storm costs, offset by the return of tax benefits of approximately $225 million. The tax benefits include the flowback to customers in 2019 of excess accumulated deferred income taxes resulting from the reduction of the federal income tax rates provided in the Tax Act as well as the flowback of accumulated deferred income taxes from previously realized tax repair deductions and tax benefits from future tax repair deductions as realized.
PSE&G also filed a revised 2019 Transmission Formula Rate Annual Update to include the refund of the approved excess deferred income tax benefits. The revised 2019 Annual Transmission Formula Rate, as filed with FERC in January 2019, decreased overall annual transmission revenues by approximately $54 million, and was offset by estimated true-up adjustments, resulting in a net decrease in 2019 transmission revenues of $19 million. PSE&G will file a final true-up to the 2019 Annual Transmission Formula Rate Update in the second quarter of 2020.
The financial results for PSEG, PSE&G and PSEG Power for the years ended December 31, 2019 and 2018 are presented as follows:
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| | | | Years Ended December 31, | |
| | | | 2019 | | 2018 | |
| | | | Millions, except per share data | |
| | PSE&G | | $ | 1,250 |
| | $ | 1,067 |
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| | PSEG Power | | 468 |
| | 365 |
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| | Other | | (25 | ) | | 6 |
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| | PSEG Net Income | | $ | 1,693 |
| | $ | 1,438 |
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| | PSEG Net Income Per Share (Diluted) | | $ | 3.33 |
| | $ | 2.83 |
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Our 2019 over 2018 increase in Net Income was due primarily to higher earnings from distribution rate relief and transmission and distribution investments at PSE&G, MTM and Nuclear Decommissioning Trust (NDT) Fund gains in 2019 as compared to losses in the prior year and ZEC revenues in 2019 at PSEG Power, and pension credits resulting from retiree medical plan benefit changes in 2019. These increases were partially offset by a loss on the sale in 2019 of PSEG Power’s ownership interests in two fossil plants. For a more detailed discussion of our financial results, see Results of Operations.
The greater emphasis on capital spending in recent years for projects on which we receive contemporaneous returns at PSE&G has yielded strong results, which when combined with the cash flow generated by PSEG Power, has allowed us to meet customer needs, address market conditions and investor expectations, reflecting our long-term approach to managing our company. We continue our focus on operational excellence, financial strength and disciplined investment. These guiding principles have provided the base from which we have been able to execute our strategic initiatives, including:initiatives.
Disciplined Investment
improving utility operations through growthWe utilize rigorous criteria when deploying capital and seek to invest in investmentareas that complement our existing business and provide reasonable risk-adjusted returns. These areas include upgrading our energy infrastructure and improving our environmental footprint to align with public policy objectives. In 2019, we
made additional investments in T&D infrastructure projects on time and on budget,
continued to execute our Energy Efficiency and other infrastructure projects designed to enhance system reliabilityexisting BPU-approved utility programs, and resiliency and to meet customer expectations and public policy objectives, and
maintaining and expanding a reliable generation fleet with the flexibility to utilize a diverse mix of fuels which allows us to respond to market volatility and capitalize on opportunities as they arise.
Financial Results
The results for PSEG, PSE&Gcompleted construction and Power forplaced into service our BH5 generation project, 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 retirementfinal stage of our Hudson and Mercer units. Higher transmission revenuesinvestment program 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 lowcycle gas prices, environmental considerations and competitive market forces that reward efficiency and reliability.
At PSE&G, we continue to invest in transmission projects that focus on reliability improvements and replacement of aging infrastructure. We also continue to make investments to improve the resiliency of our gas and electric distribution system as part of our Energy Strong program that was approved by the BPU in 2014 and to seek recovery on such investments. We are modernizing PSE&G’s gas distribution systems as part of our Gas System Modernization Program (GSMP) that was approved by the BPU in late 2015. In July 2017, we filed a petition with the BPU for a GSMP II program, an extension of GSMP to continue to modernize our gas system, through which PSE&G has proposed investing $2.7 billion over five years beginning in 2019. This matter is pending. We believe the petition is consistent with the Infrastructure Investment Program (IIP) regulations that the BPU approved in December 2017. In August 2017, the BPU approved PSE&G’s petition for an Energy Efficiency 2017 Program (EE 2017) to extend three existing energy efficiency subprograms (multi-family, direct install and hospital efficiency) and establish two new residential energy efficiency offerings. The EE 2017 allows for $69 million of additional investment and $16 million of additional administrative and information technology costs. The EE 2017 was added as the eleventh component of the Green Program Recovery Charges (GPRC) rate effective September 1, 2017. Over the past few years, these types of investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G.
In January 2018, PSE&G filed a distribution base rate case as required by the BPU as a condition of approval of its Energy Strong Program. The filing requests an approximate one percent increase in revenues and seeks to recover investments made to strengthen electric and gas distribution systems. In its filing, PSE&G requested that these rates take into account a reduction in the revenue requirement as a result of the federal corporate income tax rate reduction from 35% to 21% provided in new tax legislation enacted in December 2017 (Tax Act), including a one-time credit for estimated excess income taxes collected between January 1, 2018 and the time new rates go into effect, and the flow-back to customers of certain additional tax benefits. PSE&G anticipates the new base rates will take effect in the fourth quarter of 2018.
Separately, in January 2018, the BPU issued an order commencing a proceeding to ensure that the rate revenue resulting from expenses relating to taxes reflected in rates but no longer owed as the result of the Tax Act shall be passed onto the ratepayers. The BPU directed New Jersey utilities (including PSE&G) to make filings by March 2, 2018 setting forth interim rates to be effective April 1, 2018, reflecting the new federal corporate tax rate, and to subsequently file proposed final rates, effective July 1, 2018, incorporating all other effects of the Tax Act. This proceeding is currently pending.
As a result of the enactment of the Tax Act, various state regulatory authorities, including the BPU, have taken action to ensure that excess federal income taxes previously collected in rates are returned to ratepayers. We have made filings to adjust the revenue requirement in certain of our rate matters as a result of the change in federal income tax rate. We continue to assess whether any further action needs to be taken by the company at this time.
For additional information on our specific filings, see Item 8. Financial Statements and Supplementary Data—Note 6. Regulatory Assets and Liabilities.
Power manages its existing firm pipeline transportation contracts for the benefit of PSE&G’s customers through the basic gas supply service (BGSS) arrangement. The contracts are sized to provide for delivery of a reliable gas supply to PSE&G customers on peak winter days. When pipeline capacity beyond the customers’ needs is available, Power may use it to make third-party sales and supply gas to its generating units in New Jersey. Alternatively, gas supply and pipeline capacity constraints could adversely impact our ability to meet the needs of our utility customers and generating units. Power’s hedging practices and ability to capitalize on market opportunities help it to balance some of the volatility of the merchant power business. More than half of Power’s expected gross margin in 2018 relates to our hedging strategy, our expected revenues from the capacity market mechanisms and certain ancillary service payments such as reactive power.
Our investments in Keys Energy Center (Keys), Sewaren 7 and Bridgeport Harbor Station 5 (BH5) reflect our recognition of the value of opportunistic growth in the Power business. See Item 1. Business—Power for additional information on major growth projects. These additions to our fleet both expand our geographic diversity and adjust our fuel mix and are expected to contribute to the overall efficiency of operations.
Since 2013, several nuclear generating stations in the United States have closed or announced early retirement due to economic reasons, or have announced being at risk for early retirement. Most recently, in February 2018, Exelon, a co-owner of the Salem units, announced its intention to accelerate the closure of its Oyster Creek nuclear plant located in New Jersey, one year earlier than previously planned for economic reasons. These closures and retirements are generally due to the decline in market prices of energy, resulting from low natural gas prices driven by the growth of shale gas production since 2007, the continuing cost of regulatory compliance and enhanced security for nuclear facilities, both federal and state-level policies that provide financial incentives to construct renewable energy such as wind and solar and the failure to adequately compensate nuclear generating stations for the attributes they bring similar to renewable energy production. These trends have significantly reduced the revenues of nuclear generating stations while limiting their ability to reduce the unit cost of production. This may result in the electric generation industry experiencing a further shift from nuclear generation to natural gas-fired generation, creating less diversity of the generation fleet.
If any or all of the Salem and Hope Creek units were shut down, it would significantly alter New Jersey’s energy supply predominately by increasing New Jersey’s reliance on natural gas generation. Such a decrease in fuel diversity could also increase the market’s vulnerability to price fluctuations and power disruptions in times of high demand. The New Jersey Legislature is assessing legislation that would provide a safety net in order to prevent the loss of environmental attributes from nuclear generating stations. We cannot predict whether the legislation will be enacted or, if enacted, whether our nuclear generating stations in New Jersey will be selected or whether the legislation will provide a sufficient safety net for the continued operation of nuclear generating stations in New Jersey.
In the ordinary course, management, and in the case of the Salem units the co-owner, each makes a number of decisions that impact the operation of our nuclear units beyond the current year, including whether and to what extent these units participate in RPM capacity auctions, commitments relating to refueling outages and significant capital expenditures, and decisions regarding our hedging arrangements. When considering whether to make these future commitments, management’s decisions will primarily be influenced by the financial outlook of the units, including the progress, timing and continued outlook for enactment of proposed legislation in the state of New Jersey.
If market prices continue to be depressed and legislation is not enacted that adequately compensates nuclear generating stations for their attributes, Power anticipates it will no longer be covering its costs nor be adequately compensated for its market and operational risks at the Salem and Hope Creek nuclear units and would anticipate retiring these units early. The costs associated with any such retirement, which may include, among other things, accelerated depreciation and amortization or impairment charges, accelerated asset retirement costs, severance costs, environmental remediation costs and additional funding of the Nuclear Decommissioning Trust Fund (NDT) would be material to both PSEG and Power.turbines.
Regulatory, Legislative and Other Developments
In our pursuit of operational excellence, financial strength and disciplined investment, we closely monitor and engage with stakeholders on significant regulatory and legislative developments. Transmission planning rules and wholesale power market design are of particular importance to our results and we continue to advocate for policies and rules that promote fair and efficient electricity markets. For additional information about regulatory, legislative and other developments that may affect the company, see Item 1. Business—Regulatory Issues.
Transmission Planning
There are several mattersIn March 2019, FERC issued a Notice of Inquiry (NOI) seeking comment on improvements to FERC’s electric transmission incentives policy to ensure that it appropriately encourages the development of the infrastructure needed to ensure grid reliability and reduce congestion to lower the cost of power for consumers. The NOI is intended to examine whether existing incentives, such as the 50 basis point adder for membership in the Regional Transmission Organization, should continue to be granted and whether new incentives should be established.
In November 2019, FERC issued an order establishing a new Return on Equity (ROE) policy for reviewing existing transmission ROEs. FERC applied the methodology outlined in the new policy to two complaints filed against the Midcontinent Independent System Operator (MISO) transmission owners and found that the MISO transmission owners’ ROE was unjust and unreasonable and directed that the ROE be lowered. Other ROE complaints have been pending before FERC regarding the ISO New England Inc. Transmission Owners and the U. S. Court of Appeals for the District of Columbia Circuit that concern the allocation of costs associated with transmission projects being constructed by PSE&G. Regardless of howutilities in other jurisdictions. In parallel to these proceedings, are resolved, PSE&G’s ability to recoverand in light of declining interest rates and other market conditions, over the costs of these projects will not be affected. However, the result of these proceedings could ultimately impact the amount of costs borne by ratepayers in New Jersey. In addition, as a basic generation service (BGS) supplier, Power provides servicespast few years, several companies have negotiated settlements that include specified transmission costs. If the allocation of the costs associated with the transmission projects were to increase these BGS-related transmission costs, BGS suppliers may be entitled to recovery, subject to BPU approval. We do not believe that these matters will have a material effect on Power’s business or results of operations.
Several complaints have been filed and several remain pending at FERC against transmission owners around the country, challenging those transmission owners’ base return on equity (ROE). Certain of those complaints have resulted in decisions and others have been settled, resulting in reductions of those transmission owners’ basereduced ROEs. The resultsWe continue to analyze the potential impact 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’ requestmethodologies and cannot predict the outcome of ongoing ROE proceedings. An adverse change to PSE&G’s base transmission ROE or ROE incentives could be material.
Wholesale Power Market Design
In January 2020, New Jersey rejoined the proceeding.Regional Greenhouse Gas Initiative (RGGI). As a result, generating plants operating in New Jersey, including those owned by PSEG Power, that emit carbon dioxide (CO2) emissions will be required to procure credits for each ton they emit. In response to RGGI, PJM initiated a process in 2019 to investigate the development of a carbon pricing mechanism that may mitigate the environmental and financial distortions that could occur when emissions “leak” from non-participating states to the RGGI states. If the process leads to a market solution, it could have a material impact on the value of PSEG Power’s generating fleet.
In June 2017, PJMDecember 2019, FERC issued an order establishing new rules for PJM’s capacity market. In this new order, FERC extended the PJM Minimum Offer Price Rule (MOPR), which currently applies to new natural gas-fired generators, to include both new and existing resources that receive or are entitled to receive certain out-of-market payments, with certain exemptions. PSEG cannot at this time estimate the impact of the MOPR on resources that receive out-of-market payments or the markets generally.
States that have clean energy price formation proposalprograms designed to addressachieve public policy goals are not prevented from pursuing those programs by the expanded MOPR and could choose to utilize the existing Fixed Resource Requirement (FRR) approach authorized under the PJM tariff. Subsidized units that cannot clear in a flawReliability Pricing Model (RPM) capacity auction because of the expanded MOPR could still count as capacity resources to a load serving entity using the FRR approach.
PSEG Power’s New Jersey nuclear plants that receive ZEC payments will be subject to the new MOPR. However, the impact, if any, of the MOPR on theability of the nuclear plants to clear in the energy marketRPM markets will depend on the level of the applicable generic offer floors as well as the offer floor levels that would be derived via a unit specific exception should one or more of the units elect that option. In addition, if one or more electric distribution zones in which energy prices during off-peak periods often do not reflectNew Jersey (or another state) were to become FRR service areas, procurements needed for that area could provide an alternate means for nuclear units whose ability to clear in RPM auctions was affected by the production costs of generators during these periods even though they are serving load. PJM’s proposal would allow large, inflexible unitsMOPR 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. provide capacity within PJM.
We cannot predict what impact those rules will have on the outcomecapacity market or our generating stations. In addition, we cannot predict whether there will be challenges to the FERC order and, if so, the impact of this matter.such challenges on the MOPR and other capacity market rules.
See Item 1. Business—Federal Regulation for additional information.
The BPU has enacted IIP regulations that allow utilities to construct, install, or remediate utility plant and facilities related to reliability, resiliency, and/or safety to support the provision of safe and adequate service. Under these regulations, utilities can seek authority to make specified infrastructure investments in programs extending for up to five years with accelerated cost recovery mechanisms. The BPU characterized the IIP regulations as a regulatory initiative intended to create a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing infrastructure that enhances reliability, resiliency, and/or safety.
Environmental Regulation
We continue to advocate for the development and implementation of fair and reasonable rules by the EPA and state environmental regulators. In particular, section 316(b) of the Federal Water Pollution Control Act requires that cooling water intake structures, which are a significant part of the generation of electricity at steam-electric generating stations, reflect the
best technology available for minimizing adverse environmental impacts. Implementation of Section 316(b) and related state regulations could adversely impact future nuclear and fossil operations and costs.
In March 2017, the President of the United States issued an Executive Order that instructed the EPA to review the New Source Performance Standards that establish emissions standards for CO2 for certain new fossil power plants, and the Clean Power Plan (CPP), a greenhouse gas emissions regulation under the Clean Air Act for existing power plants that establishes state-specific emission rate targets based on implementation of the best system of emission reduction. In October 2017, the EPA Administrator signed a proposed repeal of the CPP. The EPA Administrator concluded that the CPP exceeds the EPA’s statutory authority by considering measures that are beyond the control of the owners of the affected sources (fossil fuel-fired electric generating units). The EPA is considering rulemaking to replace the CPP. PSEG cannot assess the impact of any such rulemaking on its business and future results of operations at this time.
We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we generated. In particular, the historic operations of PSEG companies and the operations of numerous other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of variousstatutes. We are also currently involved in a number of proceedings relating to sites where other hazardous substances may have been discharged and may be subject to additional proceedings in the future, and the costs of any such remediation efforts could be material.
For further information regarding the matters described above, as well as other matters that may impact our financial condition and results of operations, see Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities.
FERC Compliance
Since September 2014, FERC Staff has been conducting a preliminary non-public investigation regarding errors in the calculation of certain components of Power’s cost-based bids for its New Jersey fossil generating units in the PJM energy market and the quantity of energy that Power offered into the energy market for its fossil peaking units compared to the amounts for which Power was compensated in the capacity market for those units. While considerable uncertainty remains as to the final resolution of these matters, based upon developments in the investigation in the first quarter of 2017, Power believes the disgorgement and interest costs related to the cost-based bidding matter may range between approximately $35 million and $135 million, depending on the legal interpretation of the principles under the PJM Tariff, plus penalties. Since no point within this range is more likely than any other, Power has accrued the low end of this range of $35 million by recording an additional pre-tax charge to income of $10 million during the three months ended March 31, 2017. PSEG is unable to reasonably estimate the range of possible loss, if any, for the quantity of energy offered matter or the penalties that FERC would impose relating to either the cost-based bidding or quantity of energy matter. However, any of these amounts could be individually material to PSEG and Power. We cannot predict the final outcome of these matters. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 13.15. Commitments and Contingent Liabilities.
EarlyNuclear
In April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded ZECs by the BPU. 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 $0.004 per kilowatt-hour used (which is equivalent to approximately $10 per megawatt hour generated in payments to selected nuclear plants (ZEC payment)). These nuclear plants are expected to receive ZEC revenue for approximately three years, through May 2022, and will be obligated to maintain operations during that period, subject to exceptions specified in the ZEC legislation. PSEG Power has and will continue to recognize revenue monthly as the nuclear plants generate electricity and satisfy their performance obligations. The ZEC legislation requires nuclear plants to reapply for any subsequent three year periods. The ZEC payment may be adjusted by the BPU (a) at any time to offset environmental or fuel diversity payments that a selected nuclear plant may receive from another source or (b) at certain times specified in the ZEC legislation if the BPU determines that the purposes of the ZEC legislation can be achieved through a reduced charge that will nonetheless be sufficient to achieve the state’s air quality and other environmental objectives by preventing the retirement of nuclear plants. The BPU’s decision awarding ZECs has been appealed by the Division of Rate Counsel. PSEG cannot predict the outcome of this matter. In the event that (i) the ZEC program is overturned or otherwise materially adversely modified through legal process, (ii) the terms and conditions of the subsequent period under the ZEC program, including the amount of ZEC payments that may be awarded, materially differ from those of the current ZEC period, or (iii) any of the Salem 1, Salem 2 and Hope Creek plants is not awarded ZEC payments by the BPU and does not otherwise experience a material financial change, PSEG Power will take all necessary steps to retire all of these plants subsequent to the initial ZEC period at or prior to a scheduled refueling outage. Alternatively, if all of the Salem 1, Salem 2 and Hope Creek plants are selected to continue to receive ZEC payments but the financial condition of the plants is materially adversely impacted by changes in commodity prices, FERC’s changes to the capacity market construct (absent sufficient capacity revenues provided under a program approved by the BPU in accordance with a FERC-authorized capacity mechanism), or, in the case of the Salem nuclear plants, decisions by the EPA and state environmental regulators regarding the implementation of Section 316(b) of the Clean Water Act and related state regulations, or other factors, PSEG Power would still take all necessary steps to retire all of these plants. Retirement of Hudson and Mercer Units
On June 1, 2017, Power completed its previously announced retirement of the generation operations of the existing coal/gas units at the Hudson and Mercer generating stations. The decision to retire the Hudson and Mercer units had a material effect on PSEG’s and Power’s results of operationsthese plants would result in 2016 and continued to adversely impact their results of operations in 2017. As of June 1, 2017, Power completed recognition of the incremental Depreciation and Amortization (D&A) of $938 million ($964 million in total) due to the significant shortening of the expected economic useful lives of Hudson and Mercer. During 2017, Energy Costs of $15 million and Operation and Maintenance (O&M) of $23 million were also incurred. See Item 8. Financial Statements and Supplementary Data—Note 3. Early Plant Retirements for additional information.
Power is exploring various opportunities with these sites, including using the sites for alternative industrial activity or the disposition of one or both of the sites. If Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would trigger obligations under certain environmental regulations, including possible remediation. The amounts for any such remediation are neither currently probable nor estimable but may be material.
In addition, PSEG and Power continue to monitor their other coal assets, including the Keystone and Conemaugh generating stations, to assess their economic viability through the end of their designated useful lives and their continued classification as held for use. The precise timing of a change in useful lives may be dependent upon events out of PSEG’s and Power’s control and may impact their ability to operate or maintain certain assets in the future. These generating stations may be impacted by factors such as environmental legislation, co-owner capital requirements and continued depressed wholesale power prices or capacity factors, among other things. Any early retirement or change in the classification as held for use of our remaining coal units may have a material adverse impact on PSEG’s and PSEG Power’s future financial results.
Fossil
In September 2019, PSEG Power completed the sale of its ownership interests in the Keystone and Conemaugh generation plants and related assets and liabilities. PSEG Power recorded a pre-tax loss on disposition of approximately $400 million in the second quarter of 2019 as the sale price was less than book value. PSEG Power has also announced the early retirement of its 383 MW coal unit in Bridgeport, Connecticut in 2021. Including this planned retirement in 2021, PSEG Power will have retired or exited through sales over 2,400 MW of coal-fired generation since 2017.
California Solar Facilities
As part of its solar production portfolio, PSEG Power owns and operates two California-based solar facilities with an aggregate capacity of approximately 30 MW direct current whose output is sold to Pacific Gas and Electric Company (PG&E) under power purchase agreements (PPAs) with twenty year terms. The net book value of these solar facilities was approximately $55 million as of December 31, 2019. In January 2019, PG&E and its parent company PG&E Corporation filed for Chapter 11 bankruptcy protection. PSEG Power cannot predict the ultimate outcome that this bankruptcy proceeding will have on our ability to collect all of the revenues from these facilities due under the PPAs; however, any adverse changes to the terms of PSEG Power’s PPAs as a result of this bankruptcy proceeding could result in the future impairment of these assets in amounts up to their current net book value.
Offshore Wind
In June 2019, the BPU selected Ørsted US Offshore Wind’s Ocean Wind project as the winning bid in New Jersey’s initial solicitation for 1,100 MW of offshore wind generation. In October 2019, PSEG exercised its option on Ørsted’s Ocean Wind
project, resulting in a period of exclusive negotiation for PSEG to potentially acquire a 25% equity interest in the project, subject to negotiations toward a joint venture agreement, advanced due diligence and any required regulatory approvals.
Leveraged Lease ImpairmentsLeases
GenOn Energy, Inc. (GenOn) and certain ofIn December 2018, NRG REMA, LLC emerged from its subsidiaries filed voluntary petitions for reliefin-court proceeding under Chapter 11 of the United States Bankruptcy Code on June 14, 2017. NRG REMA, LLC (REMA) was not included inCode. As a result of the GenOn bankruptcy filing. GenOn is currently engaged in a balance sheet restructuring, which will take an undetermined time to complete. PSEG cannot predict the outcome of GenOn’s efforts to restructure its balance sheet and improve its liquidity.
During the first quarter of 2017, due to continuing liquidity issues facing REMA, economic challenges facing coal generation in PJM, and based upon an ongoing review of available alternatives as well as discussions with REMA management, Energy Holdings recorded an additional $55 million pre-tax charge for its current best estimate of loss relating to its REMA leveraged lease receivables, which was reflected in Operating Revenues. During the second quarter of 2017, Energy Holdings recorded an additional $22 million pre-tax charge for its current best estimate of lossremaining deferred tax liabilities related to lease receivables due to collectability of payments ($15 million)the Keystone 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’Conemaugh lease investments which could include further write-downswere reclassified to current tax liabilities. PSEG realized the remaining tax liability related to the restructuring of approximately $85 million with the filing 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 unitsconsolidated federal income tax return in our leveraged lease portfolio, and such write-downs could be material.December 2019.
Additional facilities in our leveraged lease portfolio include the Shawville, 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.
During the second quarter of 2019, Energy Holdings completed its annual review of estimated residual values embedded in the leveraged leases. The outcome indicated that the updated residual value estimate of the coal-fired Powerton lease was lower than the recorded residual value and the decline was deemed to be other than temporary as a result of expected future adverse market conditions. As a result, a pre-tax write-down of $58 million was reflected in Operating Revenues in the quarter ended June 30, 2019, calculated by comparing the gross investment in the leases before and after the revised residual estimates.
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 downadditional write-downs of the residual valuevalues of theEnergy Holdings’ leveraged lease receivables associated with these facilities.
Tax Legislation
For non-regulated businesses, the Tax Act enacted rules that set a cap on the amount of interest that can be deducted in a given year. Any amount that is disallowed can be carried forward indefinitely. For 2018 and 2019, a portion of PSEG’s and PSEG Power’s interest was disallowed but is expected to be realized in future periods. However, certain aspects of the law are unclear. Therefore, we recorded taxes in 2018 and 2019 based on our interpretation of the relevant statute. Amounts recorded under the Tax Act, such as depreciation and interest disallowance, are subject to change based on several factors, including but not limited to, the Internal Revenue Service and state taxing authorities issuing additional guidance and/or further clarification. Any further guidance or clarification could impact PSEG’s, PSE&G’s and PSEG Power’s financial statements. For additional information, see Item 8. Note 22. Income Taxes.
In December 2017,July 2018, the U.S. government enacted comprehensive tax legislation (Tax Act), which, among other things, decreased the statutory U.S. corporateState of New Jersey made changes to its income tax rate fromlaws, including imposing a maximumtemporary surtax of 35% to 21%,2.5% effective January 1, 2018 and made certain changes to bonus depreciation rules.
As a result of the enacted reduction2019 and 1.5% in the statutory U.S. corporate income tax rate,2020 and 2021, as well as otherrequiring corporate taxpayers to file in a combined reporting group as defined under New Jersey law starting in 2019. Both provisions include an exemption for public utilities. We believe PSE&G meets the definition of a public utility and, therefore, will not be impacted by the temporary surtax or be included in the combined reporting group. There are certain aspects of the Tax Act, we have recorded a one-time, non-cash earnings benefitlaw that are not clear. We anticipate the State 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 refundsNew Jersey will be madeissuing clarifying guidance regarding combined reporting rules. Any further guidance or clarification could impact PSEG’s and PSEG Power’s financial statements.
Future Outlook
For more than a century, our mission has been to customers in future rates. The amount and timingprovide universal access to an around-the-clock supply of any such refund cannot be determined atreliable, affordable power. Building on this time.
Beginning in 2018, PSEG, on a consolidated basis, will incur lower income tax expense resultingmission, we believe in a decrease in its projected effective income tax rate. Thisfuture where customers universally use less energy, the energy they use 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 casecleaner, and its transmission formula rate filings. The Tax Actdelivery 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 thesemore reliable 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, guidancemore resilient.In July 2019, we announced 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 fundcut carbon emissions at PSEG Power’s generation fleet by 80% by 2046, from 2005 levels. We have also announced our planned capital requirements, as describedvision of attaining net-zero CO2 emissions by 2050, assuming advances in Liquiditytechnology, public policy 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 Outlookcustomer behavior.
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-constrainedan environment with low gas prices, to capitalize on or otherwise address appropriately regulatory and legislative developments that impact our business and to respond to the issues and challenges described below. In order to do this, we must continue to:
focus on controlling costs while maintaining safety, reliability and reliabilitycustomer satisfaction and complying with applicable standards and requirements,
successfully manage our energy obligations and re-contract our open supply positions in response to changes in prices and demand,
obtain approval of and execute our utility capital investment program, including our Energy StrongCEF program GSMP and other investments for growth that yield contemporaneous and reasonable risk-adjusted returns, while enhancing the resiliency of our infrastructure and maintaining the reliability of the service we provide to our customers, and obtain approval for extension
effectively manage construction of our Keys, Sewaren 7, BH5 and other generation projects,
advocate for the continuation of the ZEC program and measures to ensure the implementation by PJM, FERC and FERCstate regulators of market design and transmission planning rules that continue to promote fair and efficient electricity markets, including recognition of the cost of emissions,
engage multiple stakeholders, including regulators, government officials, customers and investors, and
successfully operate the LIPA T&D system and manage LIPA’s fuel supply and generation dispatch obligations.
For 2018In addition to the risks described elsewhere in this Form 10-K for 2020 and beyond, the key issues and challenges we expect our business to confront include:
regulatory and political uncertainty, both with regard to future energy policy, design of energy and capacity markets, transmission policy and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other proceeding, settlement, investigation or claim, applicable to us and/or the energy industry,
fair and timely rate relief from the BPU and FERC for recovery of costs and return on investments, including with respect to our distribution base rate case which was filed with the BPU in January 2018,
continuing discussions regarding the restructuring of GenOn and REMA and its potential impact on the value of our Keystone, Conemaugh and Shawville leveraged leases,proceedings,
the continuing impactimpacts of the Tax Act
uncertainty in the national and regional economic recovery, continuing customer conservation efforts, changes in energy usage patternsstate tax laws, and evolving technologies, which impact customer behaviors and demand,
the potential for continuedimpact of reductions in demand and sustained lower natural gas and electricity prices both at market hubs and the locations where we operate,
the impact of lower natural gas prices and increasing environmental compliance costs on the competitiveness of our nuclear and remaining coal-fired generation plants, and the potential for retirement of such plants earlier than their current useful lives,costs.
delays and other obstacles that might arise in connection with the construction of our T&D, generation and other development projects, including in connection with permitting and regulatory approvals,
maintaining a diverse mix of fuels to mitigate risks associated with fuel price volatility and market demand cycles, and
FERC Staff’s continuing investigation of certain of Power’s New Jersey fossil generating unit bids in the PJM energy market.
Our primary investment opportunities are in two areas: our regulated utility business and our merchant power business. We continually assess a broad range of strategic options to maximize long-term stockholder value. In assessing our options, we consider a wide variety of factors, including the performance and prospects of our businesses; the views of investors, regulators, customers and rating agencies; our existing indebtedness and restrictions it imposes; and tax considerations, among other things. Strategic options available to us include:
the acquisition, construction or disposition of T&D facilities, clean energy investments and/or generation units,projects, including offshore wind opportunities,
the disposition or reorganization of our merchant generation business or other existing businesses or the acquisition or development of new businesses,
the expansion of our geographic footprint,
continued or expanded participation in solar, demand response and energy efficiency programs, and
investments in capital improvements and additions, including the installation of environmental upgrades and retrofits, improvements to system resiliency, modernizing existing infrastructure and participation in transmission projects through FERC’s “open window” solicitation process.
Power is developing a retail energy business to sell energy, which we believe complements our existing wholesale marketing business. Power began these marketing activities in 2017 and has been granted retail energy supplier licenses in New Jersey, Pennsylvania and Maryland.
There can be no assurance, however, that we will successfully develop and execute any of the strategic options noted above, or any additional options we may consider in the future. The execution of any such strategic plan may not have the expected benefits or may have unexpected adverse consequences.
RESULTS OF OPERATIONS
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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 |
| |
| | | | | | | | | |
| | PSEG Net Income Per Share (Diluted) | | $ | 3.10 |
| | $ | 1.75 |
| | $ | 3.30 |
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| | | | | | | | | |
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| | | | | | | | | |
| | | | Years Ended December 31, | |
| | | | 2019 | | 2018 | | 2017 | |
| | Earnings (Losses) | | Millions | |
| | PSE&G | | $ | 1,250 |
| | $ | 1,067 |
| | $ | 973 |
| |
| | PSEG Power (A)(B) | | 468 |
| | 365 |
| | 479 |
| |
| | Other (B)(C) | | (25 | ) | | 6 |
| | 122 |
| |
| | PSEG Net Income | | $ | 1,693 |
| | $ | 1,438 |
| | $ | 1,574 |
| |
| | | | | | | | | |
| | PSEG Net Income Per Share (Diluted) | | $ | 3.33 |
| | $ | 2.83 |
| | $ | 3.10 |
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| | | | | | | | | |
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| (A) | PSEG Power’s results in 2017 and 20162019 include an after-tax expensesloss of $577$286 million and $396 million, respectively, related to the early retirementsale of PSEG Power’s ownership interests in the Keystone and Conemaugh fossil generation plants. PSEG Power’s results in 2018 include an after-tax gain of $39 million from the sale of its Hudson and Mercer coal/gas generation plants and after-tax expenses of $577 million in 2017 related to the early retirement of the Hudson and Mercer generation plants. See Item 8. Financial Statements and Supplementary Data—Note 3.4. Early Plant RetirementsRetirements/Asset Dispositions for additional information. Power’s results in 2015 include an after-tax insurance recovery for Superstorm Sandy of $102 million. |
| |
| (B) | Results in 2017 include the non-cash net income benefit of $745 million, including $588 million related to PSEG Power and $147 million related to Energy Holdings, resulting from the remeasurement of deferred tax liabilities required due to the enactment of the Tax Act in December 2017. |
| |
| (C) | Other includes after-tax activities at the parent company, PSEG LI and Energy Holdings as well as intercompany eliminations. Energy Holdings recorded after-tax charges totaling $45$32 million, $5 million and $92$45 million related to its investments in REMA’scertain leveraged leases in 2019, 2018 and 2017, and 2016.respectively. See Item 8. Financial Statements and Supplementary Data—Note 7.9. Long-Term Investments and Note 8.10. Financing Receivables for further information. |
OurPSEG Power’s results above include the realized gains, losses and earnings on Power’s Nuclear Decommissioning Trust (NDT) Fund and other related NDT activity. Realized gains and losses, interest and dividend income and other costs related to the NDT Fund are recorded in Other Income (Deductions), and impairments on certain NDT securities are recorded as Other-Than-Temporary Impairments. Interest accretion expense on Power’s nuclear Asset Retirement Obligation (ARO) is recorded in O&M Expenseactivity and the depreciation related to the ARO asset is recorded in D&A Expense.
Our results also include the after-tax impacts of non-trading commodity mark-to-market (MTM) activity, which consist of the financial impact from positions with forwardfuture delivery dates.
The combined after-tax impact onvariances in our Net Income for the years ended December 31, 2017, 2016 and 2015 include theattributable to changes related to the NDT Fund and MTM activityare shown in the chart below:following table:
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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 |
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| | | | | | | | | |
| | Years Ended December 31, | | 2019 | | 2018 | | 2017 | |
| | | | Millions, after tax | |
| | NDT Fund and Related Activity (A) (B) | | $ | 152 |
| | $ | (90 | ) | | $ | 62 |
| |
| | Non-Trading MTM Gains (Losses) (C) | | $ | 205 |
| | $ | (84 | ) | | $ | (99 | ) | |
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| (A) | NDT Fund Income (Expense) includes gains and losses on NDT securities which are recorded in Net of tax (expense) benefit of $(72) million, $(5) millionGains (Losses) on Trust Investments. See Item 8. Note 11. Trust Investments for additional information. NDT Fund Income (Expense) also includes interest and $(16) million fordividend income and other costs related to the years ended December 31, 2017, 2016NDT Fund recorded in Other Income (Deductions), interest accretion expense on PSEG Power’s nuclear Asset Retirement Obligation (ARO) recorded in Operation & Maintenance (O&M) Expense and 2015, respectively.the depreciation related to the ARO asset recorded in Depreciation and Amortization (D&A) Expense. |
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| (B) | Net of tax (expense) benefit of $68$(103) million, $68$54 million and $(65)$(72) million for the years ended December 31, 2017, 20162019, 2018 and 2015,2017, respectively. |
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| (C) | Net of tax (expense) benefit of $(80) million, $33 million and $68 million for the years ended December 31, 2019, 2018 and 2017, respectively. |
The 2017Our 2019 $255 million year-over-year increase in our Net Income was driven primarily by:
non-cash net income benefits related to new tax legislation (See Item 8. Financial Statements and Supplementary Data—Note 20. Income Taxes) at Power and Energy Holdings,by
higher transmission revenues,
higher net NDT gains in 2017, and
lower charges relatedearnings due to investments in certain leveraged leasesT&D programs and the favorable impact of new rates effective November 1, 2018 as a result of the BPU’s approval of our distribution base rate proceeding 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),PSE&G,
MTM lossesgains in 20162019 as compared to MTM losses in 2018 at PSEG Power,
net 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 primarily2019 as compared to realized gainslosses on financial transmission rights (FTR) in PJMequity securities in the prior year due to extremely cold weather,NDT Fund at PSEG Power,
lower volumesthe favorable impact of gas soldretiree medical plan benefit changes implemented in 2019, and
revenue from ZECs starting in mid-April 2019 at lower average prices under the BGSS contract,PSEG Power,
insurance recoveries received primarilylargely offset by Power in 2015a loss related to Superstorm Sandy,the sale of PSEG Power’s ownership interests in the Keystone and
an impairment related to investments Conemaugh generation plants 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.
2019.
PSEG
Our results of operations are primarily comprised of the results of operations of our principal operating subsidiaries, 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 24.26. Related-Party Transactions.
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| | | | | | | | | | Increase / (Decrease) | | Increase / (Decrease) | |
| | | | Years Ended December 31, | | |
| | | | 2019 | | 2018 | | 2017 | | 2019 vs. 2018 | 2018 vs. 2017 | |
| | | | Millions | | Millions | | % |
| | Millions | | % |
| |
| | Operating Revenues | | $ | 10,076 |
| | $ | 9,696 |
| | $ | 9,094 |
| | $ | 380 |
| | 4 |
| | $ | 602 |
| | 7 |
| |
| | Energy Costs | | 3,372 |
| | 3,225 |
| | 2,778 |
| | 147 |
| | 5 |
| | 447 |
| | 16 |
| |
| | Operation and Maintenance | | 3,111 |
| | 3,069 |
| | 2,901 |
| | 42 |
| | 1 |
| | 168 |
| | 6 |
| |
| | Depreciation and Amortization | | 1,248 |
| | 1,158 |
| | 1,986 |
| | 90 |
| | 8 |
| | (828 | ) | | (42 | ) | |
| | (Gain) Loss on Asset Dispositions | | 402 |
| | (54 | ) | | — |
| | 456 |
| | N/A |
| | (54 | ) | | N/A |
| |
| | Income from Equity Method Investments | | 14 |
| | 15 |
| | 14 |
| | (1 | ) | | (7 | ) | | 1 |
| | 7 |
| |
| | Net Gains (Losses) on Trust Investments | | 260 |
| | (143 | ) | | 134 |
| | 403 |
| | N/A |
| | (277 | ) | | N/A |
| |
| | Other Income (Deductions) | | 125 |
| | 85 |
| | 82 |
| | 40 |
| | 47 |
| | 3 |
| | 4 |
| |
| | Non-Operating Pension and OPEB Credits (Costs) | | 177 |
| | 76 |
| | — |
| | 101 |
| | N/A |
| | 76 |
| | N/A |
| |
| | Interest Expense | | 569 |
| | 476 |
| | 391 |
| | 93 |
| | 20 |
| | 85 |
| | 22 |
| |
| | Income Tax (Benefit) Expense | | 257 |
| | 417 |
| | (306 | ) | | (160 | ) | | (38 | ) | | 723 |
| | N/A |
| |
| | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | Increase / (Decrease) | | Increase / (Decrease) | |
| | | | Years Ended December 31, | | |
| | | | 2017 | | 2016 | | 2015 | | 2017 vs. 2016 | 2016 vs. 2015 | |
| | | | Millions | | Millions | | % |
| | Millions | | % |
| |
| | Operating Revenues | | $ | 9,084 |
| | $ | 9,061 |
| | $ | 10,415 |
| | $ | 23 |
| | — |
| | $ | (1,354 | ) | | (13 | ) | |
| | Energy Costs | | 2,800 |
| | 3,001 |
| | 3,261 |
| | (201 | ) | | (7 | ) | | (260 | ) | | (8 | ) | |
| | Operation and Maintenance | | 2,869 |
| | 3,008 |
| | 2,978 |
| | (139 | ) | | (5 | ) | | 30 |
| | 1 |
| |
| | Depreciation and Amortization | | 1,986 |
| | 1,476 |
| | 1,214 |
| | 510 |
| | 35 |
| | 262 |
| | 22 |
| |
| | Income from Equity Method Investments | | 14 |
| | 11 |
| | 12 |
| | 3 |
| | 27 |
| | (1 | ) | | (8 | ) | |
| | Other Income (Deductions) | | 228 |
| | 124 |
| | 152 |
| | 104 |
| | 84 |
| | (28 | ) | | (18 | ) | |
| | Other-Than-Temporary Impairments | | 12 |
| | 28 |
| | 53 |
| | (16 | ) | | (57 | ) | | (25 | ) | | (47 | ) | |
| | Interest Expense | | 391 |
| | 385 |
| | 393 |
| | 6 |
| | 2 |
| | (8 | ) | | (2 | ) | |
| | Income Tax (Benefit) Expense | | (306 | ) | | 411 |
| | 1,001 |
| | (717 | ) | | (174 | ) | | (590 | ) | | (59 | ) | |
| | | | | | | | | | | | | | | | | |
The 2017, 20162019, 2018 and 20152017 amounts in the preceding table for Operating Revenues and O&M costs each include $438$490 million, $410$458 million and $375$438 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 4.5. Variable Interest Entity for further explanation. The Income Tax Benefit in 2017 includes the non-cash benefit resulting from the remeasurement of deferred tax liabilities required due to the enactment of the Tax Act in December 2017. The following discussions for PSE&G and PSEG Power provide a detailed explanation of their respective variances.
PSE&G
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | Years Ended December 31, | | Increase / (Decrease) | | Increase / (Decrease) | |
| | | | 2017 | | 2016 | | 2015 | | 2017 vs. 2016 | 2016 vs. 2015 | |
| | | | Millions | | Millions | | % |
| | Millions | | % |
| |
| | Operating Revenues | | $ | 6,234 |
| | $ | 6,221 |
| | $ | 6,636 |
| | $ | 13 |
| | — |
| | $ | (415 | ) | | (6 | ) | |
| | Energy Costs | | 2,363 |
| | 2,567 |
| | 2,722 |
| | (204 | ) | | (8 | ) | | (155 | ) | | (6 | ) | |
| | Operation and Maintenance | | 1,434 |
| | 1,475 |
| | 1,560 |
| | (41 | ) | | (3 | ) | | (85 | ) | | (5 | ) | |
| | Depreciation and Amortization | | 685 |
| | 565 |
| | 892 |
| | 120 |
| | 21 |
| | (327 | ) | | (37 | ) | |
| | Other Income (Deductions) | | 87 |
| | 79 |
| | 75 |
| | 8 |
| | 10 |
| | 4 |
| | 5 |
| |
| | Interest Expense | | 303 |
| | 289 |
| | 280 |
| | 14 |
| | 5 |
| | 9 |
| | 3 |
| |
| | Income Tax Expense | | 563 |
| | 515 |
| | 470 |
| | 48 |
| | 9 |
| | 45 |
| | 10 |
| |
| | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | Years Ended December 31, | | Increase / (Decrease) | | Increase / (Decrease) | |
| | | | 2019 | | 2018 | | 2017 | | 2019 vs. 2018 | 2018 vs. 2017 | |
| | | | Millions | | Millions | | % |
| | Millions | | % |
| |
| | Operating Revenues | | $ | 6,625 |
| | $ | 6,471 |
| | $ | 6,324 |
| | $ | 154 |
| | 2 |
| | $ | 147 |
| | 2 |
| |
| | Energy Costs | | 2,738 |
| | 2,520 |
| | 2,421 |
| | 218 |
| | 9 |
| | 99 |
| | 4 |
| |
| | Operation and Maintenance | | 1,581 |
| | 1,575 |
| | 1,458 |
| | 6 |
| | — |
| | 117 |
| | 8 |
| |
| | Depreciation and Amortization | | 837 |
| | 770 |
| | 685 |
| | 67 |
| | 9 |
| | 85 |
| | 12 |
| |
| | Net Gains (Losses) on Trust Investments | | 2 |
| | (1 | ) | | 2 |
| | 3 |
| | N/A |
| | (3 | ) | | N/A |
| |
| | Other Income (Deductions) | | 83 |
| | 80 |
| | 85 |
| | 3 |
| | 4 |
| | (5 | ) | | (6 | ) | |
| | Non-Operating Pension and OPEB Credits (Costs) | | 150 |
| | 59 |
| | (8 | ) | | 91 |
| | N/A |
| | 67 |
| | N/A |
| |
| | Interest Expense | | 361 |
| | 333 |
| | 303 |
| | 28 |
| | 8 |
| | 30 |
| | 10 |
| |
| | Income Tax Expense | | 93 |
| | 344 |
| | 563 |
| | (251 | ) | | (73 | ) | | (219 | ) | | (39 | ) | |
| | | | | | | | | | | | | | | | | |
Year Ended December 31, 20172019 as compared to 20162018
Operating Revenuesincreased$13 $154 million due to changes in delivery, clause, commodity and other operating revenues.
Delivery Revenuesincreaseddecreased$16667 million due primarily to an increase in transmission revenues..
Transmission revenues were $152increased $97 millionhigher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.
Gas distribution revenues increased $30$107 million due to a $16 million increase due to Energy Strong, $10$98 million from inclusionan increase in the distribution tariff rates effective November 1, 2018, $25 million from collection of the Gas System Modernization Program (GSMP) and GSMP II in base rates $4 million in higher collections of GPRC and an increase of $2 million due to higher sales volumes. These increases were partially offset by lowerin Weather Normalization ClauseCharge (WNC) revenues of $2 million.
Electric distribution revenues decreased $16 million due primarily to a $28 million decrease in sales volume and $14 million in lower collections of GPRC, partially offset by a $26 million increase in Energy Strong revenues.
Clause Revenues increased $47 million due to the absence of the return in 2016 to customers of overcollections of Securitization Transition Charge (STC) revenues of $59 million and higher Margin Adjustment Clause (MAC) revenues of $4$1 million. These increases were partially offset by a $12 million decrease from lower sales volumes and $5 million in lower collections of Green Program Recovery Charges (GPRC).
Electric distribution revenues increased $67 million due primarily to $75 million from an increase in the distribution tariff rates effective November 1, 2018 and $16 million in higher collections of GPRC. These increases were partially offset by a $24 million decrease in sales volumes.
Transmission, electric distribution and gas distribution revenue requirements were $338 million lower as a result of rate reductions due to the flowback of excess deferred income tax liabilities and tax repair related accumulated deferred income taxes. This decrease is offset in Income Tax Expense.
Clause Revenues decreased $2 million due to $11 million in Tax Adjustment Credits (TAC) and GPRC deferrals. These decreases were partially offset by $6 million in Margin Adjustment Clause (MAC) revenues, $2 million in higher Solar Pilot Recovery Charge (SPRC) collections and higher Societal Benefit Charges (SBC) of $17$1 million. The changes in STC,TAC and GPRC Deferrals, MAC, SPRC and SBC amountscollections were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, D&A and Interest Expense.and Tax Expenses. PSE&G does not earn margin on STC,TAC or GPRC deferrals or on MAC, SPRC or SBC Solar Pilot Recovery Charges (SPRC) or MAC collections.
Commodity Revenues decreased $204 increased $98 million due to lower Electrichigher Gas revenues partially offset by higher Gaslower Electric revenues. This decrease isThe changes in Commodity Revenues for both gas and electric are entirely offset with decreasedby changes in Energy Costs. PSE&G earns no margin on the provision of BGSbasic gas supply service (BGSS) and BGSSBGS to retail customers.
Electric revenues decreased $274 million due to $199 million in lower BGS revenues reflecting $109 million from lower sales volumes and $90 million from lower prices, $61 million in lower collections of Non-Utility Generation Charges (NGC) due primarily to lower prices and $14 million in lower revenues from the decreased sales volume of Non-Utility Generation (NUG) energy.
Gas revenues increased $70$102 million due to higher BGSS prices of $68$83 million and $2 million from higher BGSS sales volumes of $19 million.
| |
• | Electric revenues decreased $4 million due to lower BGS sales volumes. |
Other Operating Revenues increased $125 million due primarily to ZEC revenues billed after the ZEC program was approved by the BPU in April 2019. See Item 8. Note 15. Commitments and Contingent Liabilities. The ZEC revenues are entirely offset by changes to Energy Costs.
Operating Expenses
Energy Costs decreased $204 increased $218 million. This is entirely offset by changes in Commodity Revenues and Other Operating Revenues.
Operation and Maintenance decreased $41 increased $6 million due primarily to
a $28$42 million net reduction related toincrease for various clause mechanisms and GPRC expenditures
and a $15$4 million decreaseincrease in appliance service costs,injuries and
a $7 million net decrease in pension and OPEB expenses, net of amounts capitalized,
damages. These increases were partially offset by a $9$19 million net increasedecrease in other operating expenses.electric distribution maintenance expenditures, a $14 million decrease in transmission maintenance expenditures and a $6 million decrease in storm-related costs.
Depreciation and Amortizationincreased$12067 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$52 million due to additional plant placed into service, in 2017.an $8 million increase due to new depreciation rates resulting from the distribution base rate settlement applied to assets held as of November 1, 2018 and a net $7 million increase from other factors.
Other Income (Deductions)Non-Operating Pension and OPEB Credits (Costs) increased $8$91 million due primarily to a $7$103 million increase in Allowance for Funds Used During Construction (AFUDC).the amortization of prior service credit mainly related to the December 2018 OPEB plan amendment and a $6 million decrease in interest cost, partially offset by a $17 million reduction in the expected return on plan assets.
Interest Expense increased $14$28 million due primarily due to
$11 increases of $18 million due to net long-term debt issuances in 20162019 and $9$12 million due to net long-term debt issuances in 2017, partially offset by2018.
a decrease of $6 million due to clause-related interest for BGSS in 2016.
Income Tax Expense increased $48 decreased $251 million due primarily to higher pre-tax income.the flowback of excess deferred income tax liabilities and tax repair-related accumulated deferred income taxes to ratepayers.
Year Ended December 31, 20162018 as compared to 20152017
Operating Revenues decreased $415 million due to changesSee Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in delivery, clause, commodity and other operating revenues.
Delivery Revenues increased $191 million due primarily to an increase in transmission revenues.
Transmission revenues were $223 million higher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.2018 Annual Report.
Electric distribution revenues decreased $27 million due primarily to $47 million in lower collections of GPRC, partially offset by an $18 million increase in Energy Strong revenues.
Gas distribution revenues decreased $5 million due to a decrease of $43 million due to lower sales volumes and $7 million in lower collections of GPRC. These decreases were partially offset by higher WNC revenues of $25 million due to warmer weather in 2016 compared to 2015 and $20 million due to the inclusion of Energy Strong in base rates.
Clause Revenues decreased $445 million due to lower STC revenues of $419 million, lower SBC of $33 million and lower SPRC of $8 million. These decreases were partially offset by higher MAC revenues of $15 million. The changes in STC, SBC, SPRC and MAC amounts were entirely offset by changes in the amortization of related costs (Regulatory Assets) in O&M, D&A and Interest Expense. PSE&G does not earn margin on STC, SBC, SPRC or MAC collections.
Commodity Revenues decreased $155 million due to lower Electric and Gas revenues. This is entirely offset with decreased Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.
Electric revenues decreased $136 million due to $73 million in lower collections of NGC due primarily to lower prices, $42 million in lower revenues from the sale of NUG energy and $21 million in lower prices BGS revenues primarily due to lower sales volumes.
Gas revenues decreased $19 million due to $80 million from lower sales volumes, partially offset by higher BGSS prices of $61 million.
Operating Expenses
Energy Costs decreased $155 million. This is entirely offset by Commodity Revenues.
Operation and Maintenance decreased $85 million due to
a $98 million net reduction related to various clause mechanisms and GPRC, and
a $13 million decrease in pension and OPEB expenses, net of amounts capitalized,
partially offset by $10 million of insurance recovery proceeds in 2015,
a $10 million increase in vegetation management costs, and
a $6 million net increase due primarily to T&D corrective maintenance and appliance service costs.
Depreciation and Amortization decreased $327 million due primarily to a $396 million net decrease in amortization of Regulatory Assets, partially offset by an increase in depreciation of $65 million due to additional plant in service in 2016.
Interest Expense increased $9 million due to increases of
$14 million due to net debt issuances in 2015, and
$13 million due to net debt issuances in 2016,
partially offset by a decrease of $11 million due to the redemption of securitization debt in 2015, and
$7 million of higher interest related to BGSS in 2015.
Income Tax Expense increased $45 million due primarily to higher pre-tax income partially offset by changes in the reserve for uncertain tax positions and flow through items.
PSEG Power
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | Years Ended December 31, | | Increase / (Decrease) | | Increase / (Decrease) | |
| | | | 2017 | | 2016 | | 2015 | | 2017 vs. 2016 | 2016 vs. 2015 | |
| | | | Millions | | Millions | | % |
| | Millions | | % |
| |
| | Operating Revenues | | $ | 3,930 |
| | $ | 4,023 |
| | $ | 4,928 |
| | $ | (93 | ) | | (2 | ) | | $ | (905 | ) | | (18 | ) | |
| | Energy Costs | | 1,983 |
| | 1,986 |
| | 2,150 |
| | (3 | ) | | N/A |
| | (164 | ) | | (8 | ) | |
| | Operation and Maintenance | | 1,038 |
| | 1,143 |
| | 1,057 |
| | (105 | ) | | (9 | ) | | 86 |
| | 8 |
| |
| | Depreciation and Amortization | | 1,268 |
| | 881 |
| | 291 |
| | 387 |
| | 44 |
| | 590 |
| | N/A |
| |
| | Income from Equity Method Investments | | 14 |
| | 11 |
| | 14 |
| | 3 |
| | 27 |
| | (3 | ) | | (21 | ) | |
| | Other Income (Deductions) | | 157 |
| | 45 |
| | 97 |
| | 112 |
| | N/A |
| | (52 | ) | | (54 | ) | |
| | Other-Than-Temporary Impairments | | 12 |
| | 28 |
| | 53 |
| | (16 | ) | | (57 | ) | | (25 | ) | | (47 | ) | |
| | Interest Expense | | 50 |
| | 84 |
| | 121 |
| | (34 | ) | | (40 | ) | | (37 | ) | | (31 | ) | |
| | Income Tax Expense (Benefit) | | (729 | ) | | (61 | ) | | 511 |
| | (668 | ) | | N/A |
| | (572 | ) | | N/A |
| |
| | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | Years Ended December 31, | | Increase / (Decrease) | | Increase / (Decrease) | |
| | | | 2019 | | 2018 | | 2017 | | 2019 vs. 2018 | 2018 vs. 2017 | |
| | | | Millions | | Millions | | % |
| | Millions | | % |
| |
| | Operating Revenues | | $ | 4,385 |
| | $ | 4,146 |
| | $ | 3,860 |
| | $ | 239 |
| | 6 |
| | $ | 286 |
| | 7 |
| |
| | Energy Costs | | 2,118 |
| | 2,197 |
| | 1,913 |
| | (79 | ) | | (4 | ) | | 284 |
| | 15 |
| |
| | Operation and Maintenance | | 1,040 |
| | 1,053 |
| | 1,046 |
| | (13 | ) | | (1 | ) | | 7 |
| | 1 |
| |
| | Depreciation and Amortization | | 377 |
| | 354 |
| | 1,268 |
| | 23 |
| | 6 |
| | (914 | ) | | (72 | ) | |
| | (Gain) Loss on Asset Dispositions | | 402 |
| | (54 | ) | | — |
| | 456 |
| | N/A |
| | (54 | ) | | N/A |
| |
| | Income from Equity Method Investments | | 14 |
| | 15 |
| | 14 |
| | (1 | ) | | (7 | ) | | 1 |
| | 7 |
| |
| | Net Gains (Losses) on Trust Investments | | 253 |
| | (140 | ) | | 125 |
| | 393 |
| | N/A |
| | (265 | ) | | N/A |
| |
| | Other Income (Deductions) | | 54 |
| | 21 |
| | 20 |
| | 33 |
| | N/A |
| | 1 |
| | 5 |
| |
| | Non-Operating Pension and OPEB Credits (Costs) | | 21 |
| | 15 |
| | 8 |
| | 6 |
| | 40 |
| | 7 |
| | 88 |
| |
| | Interest Expense | | 119 |
| | 76 |
| | 50 |
| | 43 |
| | 57 |
| | 26 |
| | 52 |
| |
| | Income Tax Expense (Benefit) | | 203 |
| | 66 |
| | (729 | ) | | 137 |
| | N/A |
| | 795 |
| | N/A |
| |
| | | | | | | | | | | | | | | | | |
Year Ended December 31, 20172019 as compared to 20162018
Operating Revenuesdecreasedincreased$93239 million due to changes in generation, gas supply and other operating revenues.
Generation Revenuesdecreased$204increased $312 million due primarily to
a net increase of $374 million due to MTM gains in 2019 as compared to MTM losses in 2018. Of this amount, there was a $340 million increase from changes in forward prices in 2019 as compared to 2018, coupled with a $34 million increase due to more gains on positions reclassified to realized upon settlement, and
an increase of $129 million due to ZEC revenues earned since mid-April 2019,
partially offset by a decrease of $126 million in energy sales in the PJM and New England (NE) regions due primarily to lower average realized prices,
a decrease of $100$112 million in electricity sold under our BGS contracts due primarily to lower volumes coupled withand lower prices,
a net decrease of $24$63 million in revenue expecteddue primarily 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 reserveslower average realized prices in the PJM, region,
a charge of $10 million due to an increaseNew England (NE), and New York (NY) regions coupled with lower volumes sold in the FERC accrual related to the PJM bidding matter,
a decrease of $7 million due to higher MTM losses in 2017 as compared to 2016. Of this amount, $120 million was due to increased forward prices,NY region, partially offset by a decrease of $113 million due to lower gains on positions reclassified to realized upon settlement in 2017 as compared to 2016,
partially offset by a net increase of $53 million due primarily to higher volumes of electricity sold under wholesale load contracts in the PJM and NE regions,
a net increase of $18 million in capacity revenues in the PJM and NE regions, and
a net decrease of $16 million in capacity revenues due primarily to increasesdecreases in cleared capacity and capacity auction prices in the PJM region, partially offset by the commencement of commercial operations of Keys and Sewaren 7 in mid-2018 and BH5 in June 2019.
an increase of $11 million due to higher sales related to new solar projects.
Gas Supply Revenuesincreased $110decreased $75 million due primarily to
a decrease of $107 million related to sales to third parties, primarily due to lower volumes sold and lower average sales prices,
partially offset by an increase of $67$27 million in sales under the BGSS contract, of which $40 million wasprimarily due to higher average sales prices coupled with a $27 million increase in salesand higher volumes due to periods of colder weather in the heating season,
a net increase of $24 million due to higher MTM gains in 2017 as compared to 2016, and
an increase of $19 million related to sales to third parties, of which $48 million was due to higher average sales prices, partially offset by $29 million of lower volumes sold.
Operating Expenses
Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet PSEG Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $3$79 million due to
GenerationGas costsdecreased $69$52 million due primarily to
a net decrease of $83 million primarily due to lower congestion costs in PJM due to lower rates coupled with less volumes, partially offset by higher transmission charges due to higher rates,
a net decrease of $50 million due to charges associated with the announced early retirement of the Mercer and Hudson units in 2016, primarily related to lower coal inventory write-downs in 2017, partially offset by additional retirement costs incurred in 2017,
partially offset by higher fuel costs of $31 million reflecting higher average realized prices for natural gas coupled with the utilization of higher volumes of coal, partially offset by the utilization of lower volumes of gas,
an increase of $17 million due to MTM losses in 2017 as compared to MTM gains in 2016, and
a net increase of $16 million primarily due to an increase in the volume of energy purchases in the NE region to serve load obligations.
Gas costs increased $66 million due to
an increase of $50 million related to sales under the BGSS contract, of which $31 million was due to higher average gas costs, coupled with a $19 million increase in volumes sold due to periods of colder weather in the heating season, and
an increase of $16 million related to sales to third parties, of which $44 million was due to higher average gas costs, partially offset by a $28 million decrease in volumes sold.
Operation and Maintenance decreased $105 million due to
a $72 million decrease at our fossil plants, due primarily to the retirement of the Hudson and Mercer units and higher planned outage costs in 2016,
a $35 million net decrease related to our nuclear plants due primarily to lower labor-related expenses and outage costs,
an $8 million net decrease due to lower pension and OPEB costs,
partially offset by $5 million of costs related to new solar plants placed into service in 2017.
Depreciation and Amortization increased $387 million due primarily to
$346 million of higher depreciation for Hudson and Mercer, primarily due to the accelerated expense related to the early retirement of those units,
a $15 million increase due to the accelerated retirement date for the Bridgeport Harbor unit 3,
an $11 million increase due primarily to a higher nuclear asset base, and
$11 million of higher depreciation due to new solar projects.
Other Income (Deductions) increased $112 million due primarily to higher net realized gains from the NDT Fund in 2017.
Other-Than-Temporary Impairments decreased $16 million due to lower impairments of equity securities in the NDT Fund in 2017.
Interest Expense decreased $34 million due primarily to
a $24 million decrease due to higher interest capitalized for the construction of three new fossil stations: BH5, Sewaren 7 and Keys, and
a net $7 million decrease due to debt maturities in September 2016, partially offset by a debt issuance in June 2016.
Income Tax Expense decreased $668 million due primarily to the one-time benefit recorded as a result of the remeasurement of deferred tax balances required due to the enactment of the Tax Act in December 2017.
Year Ended December 31, 2016 as compared to 2015
Operating Revenues decreased $905 million due to changes in generation, gas supply and other operating revenues.
Generation Revenues decreased $714 million due primarily to
a decrease of $317 million due to MTM losses in 2016 as compared to MTM gains in 2015. Of this amount, $199 million was due to changes in forward power prices resulting in lower MTM gains in 2016 compared to 2015. Also contributing to the decrease was $118 million of higher gains on positions reclassified to realized upon settlement in 2016 compared to 2015,
a decrease of $298 million in energy sales volumes in the PJM, NE and NY regions due primarily to milder weather in 2016 and lower average realized prices,
a decrease of $80 million in capacity revenue primarily in the PJM region due to the retirement of older peaking units in June 2015, and
a decrease of $49 million due to lower operating reserve revenues in the PJM region due to less congestion and lower prices,
partially offset by a net increase of $19 million due primarily to higher volumes of electricity sold under wholesale load contract in the PJM and NE regions, partially offset by lower average prices, and
a net increase of $8 million due to new solar projects beginning commercial operations.
Gas Supply Revenues decreased $191 million due primarily to
a decrease of $183 million in sales under the BGSS contract due primarily to lower average sales prices and a decrease in sales volumes due to warmer average temperatures in the 2016 heating season, and
a decrease of $9 million due to MTM losses in 2016 due to changes in forward prices.
Operating Expenses
Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $164 million due to
Generation costs decreased $95 million due primarily to
lower fuel costs of $288 million reflecting lower average realized prices for natural gas and the utilization of lower volumes of fuel,
partially offset by a net increase of $143 million primarily due to realized gains on FTRs in PJM in 2015 due to extremely cold weather, and
a $62 million charge associated with the announced early retirement of the Mercer and Hudson units, primarily related to a coal inventory write-down.
Gas costs decreased $69 million due to
a decrease of $101 million related to sales under the BGSS contract due primarily to lower average gas costs and a decrease in volumes sold due to warmer average temperatures during the 2016 winter heating season,
partially offset by an increase of $32$90 million related to sales to third parties due primarily to higherlower volumes sold and lower average gas costs, and an increase in volumes sold.
Operation and Maintenance increased $86 million due to
$145 million of insurance recoveries received in 2015 related to Superstorm Sandy, and
$53 million of charges related to the early retirement of the Hudson and Mercer units,
partially offset by a net decreaseincrease of $73$40 million related to sales under the BGSS contract, primarily due to an increase in the average cost of gas.
Generation costs decreased $27 million due primarily
a net decrease of $21 million due to lower MTM losses in 2019 as compared to 2018, and
a net decrease of $15 million due primarily to decreases in energy purchased in the NE region due to BH5 beginning commercial operations in June 2019,
partially offset by a net increase of $13 million in higher fuel costs reflecting utilization of higher volumes of gas at Keys, Sewaren 7 and BH5, coupled with higher prices of gas in the PJM region, partially offset by utilization of lower volumes and lower prices of gas in the NY region, lower prices of gas in the NE region, utilization of lower volumes of oil in the PJM region, and lower usage of coal at lower prices in the PJM and NE regions.
Operation and Maintenance decreased $13 million due primarily to a decrease at our fossil plants, largely due to higherlower outage costs, incurreddecreased support costs and the sale of PSEG Power’s ownership interests in 2015the Keystone and Conemaugh generation plants in September 2019. The decrease was partially offset by a goodwill impairment charge of $16 million for our planned major outages at the Bethlehem Energy Centerwrite down of PSEG Power’s carrying value to fair value (see Note 12. Goodwill and Bergen generating plants,
a net decrease of $31 millionOther Intangibles), increased costs related to our nuclear plantsthe Keys and Sewaren 7 being placed into service in mid-2018 and increased property taxes.
Depreciation and Amortization increased $23 million due primarily to lower planned outage costs at our 100%-owned Hope Creek plantKeys, Sewaren 7 and our 57%-owned Salem Unit 1 plant,BH5 being placed into service, partially offset by the sale of PSEG Power’s ownership interests in the Keystone and Conemaugh generation plants.
an $8(Gain) Loss on Asset Dispositions reflects a$402 million decrease due to lower pension and OPEB costs.
Depreciation and Amortization increased $590 million due primarily to
$555 million of accelerated depreciation dueloss in 2019 related to the early retirementsale of PSEG Power’s ownership interests in the Keystone and Conemaugh generation plants and a gain of $54 million in 2018 related to the sale of the Hudson and Mercer units,plants.
a $24Net Gains (Losses) on Trust Investments increased $393 million increase due primarily to a higher nuclear asset base, and$405 million increase resulting from net unrealized gains in 2019 as compared to net unrealized losses in 2018 on equity investments in the NDT Fund, partially offset by a $16 million decrease in net realized gains on NDT Fund investments.
$5 million of higher depreciation due to new solar projects
Other Income (Deductions) decreased $52increased$33 million primarily due to $26 million in less purchased net operating losses and higher interest and dividend income on NDT Fund investments.
Non-Operating Pension and OPEB Credits (Costs)increased $6 million due to a $19 million increase in the amortization of prior service credit mainly related to the December 2018 OPEB plan amendment, a $5 million decrease in interest cost and a $3
million decrease in the amortization of the net unrecognized loss, largely offset by a $20 million decrease in the expected return on plan assets.
Interest Expense increased $43 million due primarily to $28lower capitalized interest as a result of Keys and Sewaren 7 being placed into service in mid-2018 and BH5 being place into service in June 2019.
Income Tax Expense increased $137 million of insurance recoveries received in 2015 relateddue primarily to Superstorm Sandy and $38 million of lower net realized gainshigher pre-tax income, including higher pre-tax income from the NDT Fundqualified fund which is subject to an additional trust tax, and the favorable impact that resulted in 2016, partially offset by $10 million2018 from the remeasurement of lower purchasedthe reserve for uncertain tax credits in 2016.positions.
Other-Than-Temporary Impairments decreased $25 million due to lower impairments of equity securities in the NDT Fund in 2016.
Interest Expense decreased $37 million due to
$27 million of interest capitalized for the construction of three new fossil stations: Bridgeport Harbor 5, Sewaren 7 and Keys Energy Center, and
a $15 million decrease due to the maturity of 5.50% of Senior Notes inYear Ended December 2015,
partially offset by an increase of $5 million due to net debt issuances in 2016.
Income Tax Expense decreased $572 million in 2016 due primarily to a pre-tax loss in 201631, 2018 as compared to pre-tax income2017
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in 2015.our 2018 Annual Report.
LIQUIDITY AND CAPITAL RESOURCES
The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions, where material, of our two direct major operating subsidiaries.
Financing Methodology
We expect our capital requirements to be met through internally generated cash flows and external financings, consisting of short-term debt for working capital needs and long-term debt for capital investments.
PSE&G’s sources of external liquidity include a $600 million multi-year revolving credit facility. PSE&G uses internally generated cash flow and its commercial paper program to meet seasonal, intra-month and temporary working capital needs. PSE&G does not engage in any intercompany borrowing or lending arrangements. PSE&G maintains back-up facilities in an amount sufficient to cover the commercial paper and letters of credit outstanding. PSE&G’s dividend payments to/capital contributions from PSEG are consistent with its capital structure objectives which have been established to maintain investment grade credit ratings. PSE&G’s long-term financing plan is designed to replace maturities, fund a portion of its capital program and manage short-term debt balances. Generally, PSE&G uses either secured medium-term notes or first mortgage bonds to raise long-term capital.
PSEG, PSEG Power, Energy Holdings, PSEG LI and Services participate in a corporate money pool, an aggregation of daily cash balances designed to efficiently manage their respective short-term liquidity needs. PSEG LI’s subsidiary, Long Island Electric Utility Servco LLC (Servco), does not participate in the corporate money pool. Servco’s short-term liquidity needs are met through an account funded and owned by LIPA.
PSEG’s available sources of external liquidity may include the issuance of long-term debt securities and the incurrence of additional indebtedness under credit facilities. Our current sources of external liquidity include multi-year revolving credit facilities totaling $1.5 billion. These facilities are available to back-stop PSEG’s commercial paper program, issue letters of credit and for general corporate purposes. These facilities may also be used to provide support to PSEG’s subsidiaries. PSEG’s credit facilities and the commercial paper program are available to support PSEG working capital needs or to temporarily fund growth opportunities in advance of obtaining permanent financing. PSEGPSEG’s credit facilities are also has a $700 million term loan credit agreement that is scheduledavailable to expire in June 2019. From time to time, PSEG may make equity contributions or provide creditliquidity support to its subsidiaries.
PSEG Power’s sources of external liquidity include $2.1 billion of multi-year revolving credit facilities. Additionally, from time to time, PSEG Power maintains bilateral credit agreements designed to enhance its liquidity position. 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, PSEG Power issues senior unsecured debt to raise long-term capital.
Operating Cash Flows
We expect our operating cash flows combined with cash on hand and financing activities to be sufficient to fund capital expenditures and shareholder dividend payments.
For the year ended December 31, 20172019, our operating cash flow decreasedincreased by $50466 million. For the year ended December 31, 2016, our operating cash flow decreased by $608 million. The net changes were primarily due to net tax payments at PSEG and its other subsidiaries in 2017 offset by net changes from our subsidiaries as discussed below.
PSE&G
PSE&G’s operating cash flow decreased $55increased $182 million from $1,894$1,853 million to $1,839$2,035 million for the year ended December 31, 2017,2019, as compared to 2016,2018, due primarily to loweran increase of $178 million from recoveries of regulatory deferrals and tax refunds and a decrease of $50 million relatedin 2019 as compared to a changetax payments in regulatory deferrals. These amounts were2018, partially offset by higher earnings and $30$123 million in decreasedincreased vendor payments.
PSE&G’sPSEG Power
PSEG Power’s operating cash flow decreased $231increased $395 million from $2,125$1,084 million to $1,894$1,479 million for the year ended December 31, 2016,2019, as compared to 2015,2018, 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 decreasecollateral requirements of $90$596 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 $74an $83 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 milliondecrease 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 higherlower tax payments and an increaserefunds 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, 2016,2019 as compared to 2015, primarily resulting from lower earnings, an increase in margin deposit requirements of $198 million, and a $134 million decrease from net collection of counterparty receivables, partially offset by a reduction in tax payments.2018.
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. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facilities.
We continually monitor our liquidity and seek to add capacity as needed to meet our liquidity requirements. Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs.
Our total credit facilities and available liquidity as of December 31, 20172019 were as follows:
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | Company/Facility | | As of December 31, 2017 | |
| | Total Facility | | Usage | | Available Liquidity | |
| | | | Millions | |
| | PSEG | | $ | 1,500 |
| | $ | 556 |
| | $ | 944 |
| |
| | PSE&G | | 600 |
| | 15 |
| | 585 |
| |
| | Power | | 2,100 |
| | 151 |
| | 1,949 |
| |
| | Total | | $ | 4,200 |
| | $ | 722 |
| | $ | 3,478 |
| |
| | | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | Company/Facility | | As of December 31, 2019 | |
| | Total Facility | | Usage | | Available Liquidity | |
| | | | Millions | |
| | PSEG | | $ | 1,500 |
| | $ | 796 |
| | $ | 704 |
| |
| | PSE&G | | 600 |
| | 379 |
| | 221 |
| |
| | PSEG Power | | 2,100 |
| | 161 |
| | 1,939 |
| |
| | Total | | $ | 4,200 |
| | $ | 1,336 |
| | $ | 2,864 |
| |
| | | | | | | | | |
As of December 31, 2017,2019, our credit facility capacity was in excess of our projected maximum liquidity requirements over our 12-month12 month planning horizon. Our maximum liquidity requirements are based on stress scenarios that incorporate changes in commodity prices and the potential impact of PSEG Power losing its investment grade credit rating from S&P or Moody’s, which would represent a three level downgrade from its current S&P or Moody’s ratings. In the event of a deterioration of 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$974 million and $783$857 million as of December 31, 20172019 and 2016,2018, respectively. The early retirement of Power’s Hudson and Mercer coal/gas generation units did not have a material impact on Power’s debt covenant ratios or its ability to obtain credit facilities. See Item 8. Financial Statements and Supplementary Data—Note 3. Early Plant Retirements.
For additional information, see Item 8.Financial Statements and Supplementary Data—8. Note 14.16. Debt and Credit Facilities.
Long-Term Debt Financing
PSE&GDuring the next twelve months,
PSEG has $400a $700 million of 5.30% Medium Term Notes floating rate term loan maturing in May 2018 and $350 million of 2.30% Medium Term Notes maturing in September 2018.November 2020,
PowerPSE&G has $250 million of 2.45%3.50% Medium Term Notes (MTN) maturing in August 2020 and $9 million of 7.04% MTN maturing in November 2020, and
PSEG Power has $406 million of 5.13% Senior Notes maturing in November 2018.April 2020.
For a discussion of our long-term debt transactions during 2017 and into 2018,2019, see Item 8. Financial Statements and Supplementary Data—Note 14.16. Debt and Credit Facilities.
Debt Covenants
Our credit agreements contain maximum debt to equity ratios and other restrictive covenants and conditions to borrowing. We are currently in compliance with all of our debt covenants. Continued compliance with applicable financial covenants will depend upon our future financial position, level of earnings and cash flows, as to which no assurances can be given.
In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements, provided that its ratio of earnings to fixed charges calculated in accordance with
its Mortgage is at least 2 to 1, and/or against retired Mortgage Bonds. As of December 31, 20172019, PSE&G’s Mortgage coverage ratio was 5.24.5 to 1 and the Mortgage would permit up to approximately $6.9$7.6 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. PSEG Power’s bank credit agreements and outstanding notes also contain limitations on the incurrence of subsidiary debt and liens and certain of PSEG Power’s outstanding notes require PSEG Power to repurchase such notes upon certain change of control events.
There are no cross accelerationcross-acceleration provisions in PSEG’s or PSE&G’s indentures. However, PSEG’s existing notes include a cross acceleration provision that may be triggered upon the acceleration of more than $75 million of indebtedness incurred by PSEG. Such provision does not extend to an acceleration of indebtedness by any of PSEG’s subsidiaries. PSEG Power’s indenture includes a cross acceleration provision similar to that described above for PSEG’s existing notes except that such provision may be triggered upon the acceleration of more than $50 million of indebtedness incurred by PSEG Power or any of its subsidiaries. Such provision does not cross accelerate to PSEG, any of PSEG’s subsidiaries (other than PSEG Power and its subsidiaries), PSE&G or any of PSE&G’s subsidiaries.
Ratings Triggers
Our debt indentures and credit agreements do not contain any material ‘ratings triggers’“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
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | 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 | | 2019 | | 2018 | | 2017 | |
| | Per Share | | $ | 1.88 |
| | $ | 1.80 |
| | $ | 1.72 |
| |
| | in Millions | | $ | 950 |
| | $ | 910 |
| | $ | 870 |
| |
| | | | | | | | | |
On February 20, 2018,18, 2020, our Board of Directors approved a $0.45$0.49 per share of common stock dividend for the first quarter of 2018.2020. This reflects an indicative annual dividend rate of $1.801.96 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 24. 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 Issuer Credit Ratings (Moody’s) and Corporate Credit Ratings (S&P) and Issuer Credit Ratings (Moody’s) and can be Stable, Negative, or Positive. There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security.
In April 2017, S&P published updated research and affirmed the ratings and outlooks on PSEG and PSE&G. In June 2017, S&P published updated research on Power and the rating and outlook remained unchanged. In July 2017, Moody’s upgraded PSEG’s senior unsecured rating to Baa1 from Baa2 and revised its outlook to Stable from Positive. Also in July, Moody’s affirmed the ratings at PSE&G and Power.
|
| | | | | |
| | | | | | |
| | | Moody’s (A) | | S&P (B) | |
| | PSEG | | | | |
| | Outlook | Stable | | Stable | |
| | Senior Notes | Baa1 | | BBB | |
| | Commercial Paper | P2 | | A2 | |
| | PSE&G | | | | |
| | Outlook | Stable | | Stable | |
| | Mortgage Bonds | Aa3 | | A | |
| | Commercial Paper | P1 | | A2 | |
| | PSEG Power | | | | |
| | Outlook | Stable | | Stable | |
| | Senior Notes | Baa1 | | BBB+ | |
| | | | | | |
| |
| (A) | Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities. |
| |
| (B) | S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities. |
Other Comprehensive Income
For the year ended December 31, 2017,2019, we had Other Comprehensive IncomeLoss of $34$31 million on a consolidated basis. Other Comprehensive IncomeLoss was due primarily to a $44decrease of $58 million increase in net unrealized gains related to Available-for-Sale Securities, partially offset by a decrease of $8 million in our consolidated liability for pension and other postretirement benefits, and $2$14 million of unrealized losses on derivative contracts accounted for as hedges.hedges, partially offset by $41 million of net unrealized gains related to Available-for-Sale Securities. See Item 8. Financial Statements and Supplementary Data—Note 21.23. Accumulated Other Comprehensive Income (Loss), Net of Tax for additional information.
CAPITAL REQUIREMENTS
We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. Projected capital construction and investment expenditures, excluding nuclear fuel purchases, for the next three years are presented in the table below. These projections include Allowance for Funds Used During Construction and Interest Capitalized During Construction for PSE&G and PSEG Power, respectively. These amounts are subject to change, based on various factors. Amounts shown below for Gas System Modernization, Energy Strong GSMP and Solar/Clean Energy Efficiency programs are for currently approved programs. We intend to continue to invest in infrastructure modernization and will seek to extend these and related programs as appropriate. We will also continue to approach potential growth investments for PSEG 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 |
| |
| | | |
|
| | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | | 2020 | | 2021 | | 2022 | |
| | | | | | Millions | | | |
| | PSE&G: | | | | | | | |
| | Transmission | | $ | 1,200 |
| | $ | 950 |
| | $ | 660 |
| |
| | Distribution | | 855 |
| | 800 |
| | 920 |
| |
| | Gas System Modernization | | 455 |
| | 435 |
| | 405 |
| |
| | Energy Strong | | 110 |
| | 275 |
| | 270 |
| |
| | Clean Energy | | 55 |
| | 55 |
| | 50 |
| |
| | Total PSE&G | | $ | 2,675 |
| | $ | 2,515 |
| | $ | 2,305 |
| |
| | PSEG Power: | | | | | | | |
| | Baseline | | $ | 125 |
| | $ | 105 |
| | $ | 145 |
| |
| | Other | | 35 |
| | 10 |
| | 10 |
| |
| | Total PSEG Power | | $ | 160 |
| | $ | 115 |
| | $ | 155 |
| |
| | Other | | $ | 25 |
| | $ | 25 |
| | $ | 25 |
| |
| | Total PSEG | | $ | 2,860 |
| | $ | 2,655 |
| | $ | 2,485 |
| |
| | | |
|
| | | | | |
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.
Distribution—investments for new business, reliability improvements, 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 DistributionModernization—gas distribution investment program to replace aging infrastructure.
Solar/Energy Efficiency—Strong—electric and gas distribution investment program focused on electric flood mitigation and replacing aging infrastructure.
Clean Energy—investments associated with grid-connected solar, solar loan programs and customer energy efficiency programs.
In November 2017, the BPU issued an order approving PSE&G’s net investment of $100 million to rebuild New Jersey Transit’s Mason electric distribution substation and related facilities in Kearny, New Jersey. This project is expected to be completed in December 2021.
In July 2017, PSE&GOctober 2018, we filed a petitionour proposed CEF program with the BPU, requesting approvala six-year estimated $3.5 billion investment program focused on achieving New Jersey’s energy efficiency targets, supporting electric vehicle infrastructure, deploying energy storage, and implementing an EC program which will include installing approximately two million electric smart meters and associated infrastructure. The size and duration of the $2.7 billion next phaseCEF program, as well as certain other elements of the Gas System Modernization Program (GSMP II) and associated cost recovery mechanism. program, are subject to BPU approval.
The GSMP IICEF 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 the above table.
In 2017,2019, PSE&G made $2,919$2,542 million of capital expenditures, primarily for transmission and distributionT&D system reliability. This does not include expenditures for cost of removal, net of salvage, of $107$108 million, which are included in operating cash flows.
PSEG Power
PSEG Power’s projected expenditures for the various items listed above are primarily comprised of the following:
Baseline—investments to replace major parts and enhance operational performance.
Fossil Growth Opportunities—investments associated with new construction, including Keys, Sewaren 7 and BH5, and with upgrades to increase efficiency and output at combined cycle plants.
Other—includes investments made in response to environmental, regulatory and legal mandates and other capital projects.
In 2017,2019, PSEG Power made $1,040482 million of capital expenditures, excluding $191125 million for nuclear fuel, primarily related to various projects at Fossil Solar and Nuclear.
Disclosures about Contractual Obligations
The following table reflects our contractual cash obligations in the respective periods in which they are due. In addition, the table summarizes anticipated debt maturities for the years shown. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 14.16. Debt and Credit Facilities.
The table below does not reflect any anticipated cash payments for pension obligations due to uncertain timing of payments or liabilities for uncertain tax positions since we are unable to reasonably estimate the timing of liability payments in individual years beyond 12 months due to uncertainties in the timing of the effective settlement of tax positions. See Item 8. Financial Statements and Supplementary Data—Note 20.22. Income Taxes for additional information.
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | Total Amount Committed | | Less Than 1 Year | | 2 - 3 Years | | 4- 5 Years | | Over 5 Years | |
| | | | Millions | |
| | Contractual Cash Obligations | | | | | | | | | | | |
| | Long-Term Recourse Debt Maturities | | | | | | | | | | | |
| | PSEG | | $ | 2,100 |
| | $ | — |
| | $ | 1,100 |
| | $ | 1,000 |
| | $ | — |
| |
| | PSE&G | | 8,658 |
| | 750 |
| | 759 |
| | 434 |
| | 6,715 |
| |
| | Power | | 2,400 |
| | 250 |
| | 450 |
| | 950 |
| | 750 |
| |
| | Interest on Recourse Debt | | | | | | | | | | | |
| | PSEG | | 157 |
| | 49 |
| | 65 |
| | 43 |
| | — |
| |
| | PSE&G | | 5,186 |
| | 313 |
| | 578 |
| | 525 |
| | 3,770 |
| |
| | Power | | 821 |
| | 113 |
| | 202 |
| | 129 |
| | 377 |
| |
| | Capital Lease Obligations | | | | | | | | | | | |
| | Power | | 2 |
| | 1 |
| | 1 |
| | — |
| | — |
| |
| | Operating Leases | | | | | | | | | | | |
| | PSE&G | | 113 |
| | 16 |
| | 17 |
| | 15 |
| | 65 |
| |
| | Power | | 58 |
| | 5 |
| | 9 |
| | 6 |
| | 38 |
| |
| | Services | | 194 |
| | 14 |
| | 30 |
| | 30 |
| | 120 |
| |
| | Other | | 6 |
| | 1 |
| | 2 |
| | 2 |
| | 1 |
| |
| | Energy-Related Purchase Commitments | | | | | | | | | | | |
| | Power | | 2,670 |
| | 730 |
| | 938 |
| | 468 |
| | 534 |
| |
| | Total Contractual Cash Obligations | | $ | 22,365 |
| | $ | 2,242 |
| | $ | 4,151 |
| | $ | 3,602 |
| | $ | 12,370 |
| |
| | | | | | | | | | | | | |
| | Liability Payments for Uncertain Tax Positions | | | | | | | | | | | |
| | PSEG | | $ | 69 |
| | $ | 69 |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| | PSE&G | | 35 |
| | 35 |
| | — |
| | — |
| | — |
| |
| | Power | | 30 |
| | 30 |
| | — |
| | — |
| | — |
| |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | 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 | | $ | 2,450 |
| | $ | 700 |
| | $ | 1,000 |
| | $ | 750 |
| | $ | — |
| |
| | PSE&G | | 9,908 |
| | 259 |
| | 434 |
| | 1,575 |
| | 7,640 |
| |
| | PSEG Power | | 2,850 |
| | 406 |
| | 994 |
| | 950 |
| | 500 |
| |
| | Interest on Recourse Debt | | | | | | | | | | | |
| | PSEG | | 185 |
| | 67 |
| | 86 |
| | 32 |
| | — |
| |
| | PSE&G | | 6,146 |
| | 374 |
| | 702 |
| | 660 |
| | 4,410 |
| |
| | PSEG Power | | 697 |
| | 123 |
| | 183 |
| | 110 |
| | 281 |
| |
| | Operating Leases | | | | | | | | | | | |
| | PSE&G | | 126 |
| | 15 |
| | 23 |
| | 17 |
| | 71 |
| |
| | PSEG Power | | 100 |
| | 13 |
| | 28 |
| | 11 |
| | 48 |
| |
| | Services | | 165 |
| | 15 |
| | 30 |
| | 30 |
| | 90 |
| |
| | Other | | 3 |
| | 1 |
| | 2 |
| | — |
| | — |
| |
| | Energy-Related Purchase Commitments | | | | | | | | | | | |
| | PSEG Power | | 2,468 |
| | 761 |
| | 854 |
| | 456 |
| | 397 |
| |
| | Total Contractual Cash Obligations | | $ | 25,098 |
| | $ | 2,734 |
| | $ | 4,336 |
| | $ | 4,591 |
| | $ | 13,437 |
| |
| | | | | | | | | | | | | |
| | Liability Payments for Uncertain Tax Positions | | | | | | | | | | | |
| | PSEG | | $ | 190 |
| | $ | 190 |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| | PSE&G | | 107 |
| | 107 |
| | — |
| | — |
| | — |
| |
| | PSEG Power | | 77 |
| | 77 |
| | — |
| | — |
| | — |
| |
| | | | | | | | | | | | | |
OFF-BALANCE SHEET ARRANGEMENTS
PSEG and PSEG Power issue guarantees, primarily in conjunction with certain of PSEG Power’s energy contracts. See Item 8. Financial Statements and Supplementary Data—Note 13.15. Commitments and Contingent Liabilities for further discussion.
Through Energy Holdings, we have investments in leveraged leases that are accounted for in accordance with GAAP Accountingaccounting principles generally accepted in the United States (GAAP) for Leases.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 7.9. Long-Term Investments and Note 8.10. Financing Receivables.
In the event that collection of the minimum lease payments to be received by Energy Holdings is no longer reasonably assured, Energy Holdings may deem that a lessee has a high probability of defaulting on the lease obligation and would consider the need to record an impairment of its investment. In the event the lease is ultimately rejected by the lessee in a Bankruptcy Court proceeding, the fair value of the underlying asset and the associated debt would be recorded on the Consolidated Balance Sheets instead of the net equity investment in the lease.
CRITICAL ACCOUNTING ESTIMATES
Under GAAP, many accounting standards require the use of estimates, variable inputs and assumptions (collectively referred to as estimates) that are subjective in nature. Because of this, differences between the actual measure realized versus the estimate can have a material impact on results of operations, financial position and cash flows. We have determined that the following estimates are considered critical to the application of rules that relate to the respective businesses.
Accounting for Pensions and OPEB
PSEG sponsors qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. In late June 2019, PSEG approved a plan amendment to its qualified pension plan, effective July 1, 2019. The amendment involved the spin-off of predominantly active participants from the existing qualified pension plan (Pension Plan) into a new qualified pension plan (Pension Plan II). See Item 8. Note 14. Pension, Other Postretirement Benefits (OPEB) and Savings Plans for additional information. The market-related value of plan assets held for the 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-term rate of return on trust 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 | | 2019 | | 2018 | | 2017 | |
| | Pension | | | | | | | |
| | Discount Rate | | 3.30 | % | | 4.41 | % | | 3.73 | % | |
| | Expected Rate of Return on Plan Assets | | 7.80 | % | | 7.80 | % | | 7.80 | % | |
| | OPEB | | | | | | | |
| | Discount Rate | | 3.20 | % | | 4.31 | % | | 3.76 | % | |
| | Expected Rate of Return on Plan Assets | | 7.79 | % | | 7.80 | % | | 7.80 | % | |
| | | | | | | | | |
The discount rate used to calculate 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 the Pension Plan, the excess would be amortized over the average remaining expected life of inactive participants, which is
approximately twenty years. For Pension Plan II, the excess would be amortized over the average remaining service period of the active employees, which is approximately thirteenfourteen years.
Effect if Different Assumptions Used: As part of the business planning process, we have modeled future costs assuming a 7.80%7.70% expected rate of return and a 3.73%3.30% discount rate for 2018.2020 pension costs/credits and a 3.20% discount rate for 2020 OPEB costs/credits. Based upon these assumptions, we have estimated a net periodic pension credit in 2020 of approximately $28 million, or $84 million, net of amounts capitalized, and a net periodic OPEB credit in 2020 of approximately $77 million, or $81 million, net of amounts capitalized. 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 below solely reflect the impact of that specific assumption.
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | % Change | | Impact on Pension Benefit Obligation as of December 31, 2017 | | Increase to Pension Expense in 2018 | | Increase to Pension Expense, net of Amounts Capitalized in 2018 | |
| | Assumption | | | | Millions | |
| | Discount Rate | | (1)% | | $ | 866 |
| | $ | 46 |
| | $ | 36 |
| |
| | Expected Rate of Return on Plan Assets | | (1)% | | N/A |
| | $ | 57 |
| | $ | 57 |
| |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | % Change | | Impact on Benefit Obligation as of December 31, 2019 | | Increase to Costs in 2020 | | Increase to Costs, net of Amounts Capitalized in 2020 | |
| | Assumption | | | | Millions | |
| | Pension | | | | | | | | | |
| | Discount Rate | | (1)% | | $ | 923 |
| | $ | 33 |
| | $ | 22 |
| |
| | Expected Rate of Return on Plan Assets | | (1)% | | N/A |
| | $ | 57 |
| | $ | 57 |
| |
| | OPEB | | | | | | | | | |
| | Discount Rate | | (1)% | | $ | 145 |
| | $ | 14 |
| | $ | 13 |
| |
| | Expected Rate of Return on Plan Assets | | (1)% | | N/A |
| | $ | 5 |
| | $ | 5 |
| |
| | | | | | | | | | | |
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 16.18. Financial Risk Management Activities and Note 17.19. 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 will be sold or retired before its estimated useful life, an asset group’s carrying amount may not be recoverable. recoverable or an asset’s probability of operating through its estimated remaining useful life changes.
Assumptions and Approach Used: In the event certain triggers exist indicating an asset/asset group may not be recoverable, an undiscounted cash flow test is performed to determine if an impairment exists. When the carrying value of a long-lived asset/asset group exceeds the undiscounted estimate of future cash flows associated with the asset/asset group, an impairment may exist to the extent that the fair value of the asset/asset group is less than its carrying amount. 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 generation units are generally evaluated at a regional portfolio level (PJM, NYISO, ISO-NE) along with cash flows generated from the customer supply and risk management activities, inclusive of cash flows from contracts, including those that are accounted for as derivatives and meet the normal purchases and normal sales scope exception. In certain cases, generation assets are evaluated on an individual basis where those assets are individually contracted on a long-term basis with a third party and operations are independent of other generation assets (typically PSEG Power’s solar plants and Kalaeloa). These tests require significant estimates and judgment when developing expected future cash flows. Significant inputs include forward power prices, fuel costs, dispatch rates, other operating and capital expenditures and the cost of borrowing.
In addition, long-lived assets are depreciated under the straight-line method based on estimated useful lives. An asset’s operating useful life is generally based upon operational experience with similar asset types and other non-operational factors. In the ordinary course, management, together with an asset’s co-owners in the case of certain of our jointly-owned assets, makes a number of decisions that impact the operation of our generation assets beyond the current year. These decisions may have a direct impact on the estimated remaining useful lives of our assets and will be influenced by the financial outlook of the assets, including future market conditions such as forward energy and capacity prices, operating and capital investment costs and any state or federal legislation and regulations, among other items.
Table of ContentsThe assumptions used by management incorporate inherent uncertainties that are at times difficult to predict and could result in impairment charges or accelerated depreciation in future periods if actual results materially differ from the estimated assumptions utilized in our forecasts.
Effect if Different Assumptions Used: The above cash flow tests, and fair value estimates and estimated remaining useful lives may be impacted by a change in the assumptions noted above and could significantly impact the outcome, triggering additional impairment tests, write-offs or write-offs.accelerated depreciation. For additional information on the potential impacts on our future financial statements that may be caused by a change in useful lives of certain of our generating assets. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Note 6. Property, Plant and Equipment and Jointly-Owned Facilities.
Lease Investments
Our Investments in Leases, included in Long-Term Investments on our Consolidated Balance Sheets, are comprised of Lease Receivables (net of non-recourse debt), the estimated residual value of leased assets, and unearned and deferred income. A significant portion of the estimated residual value of leased assets is related to merchant power plants leased to other energy companies. See Item 8. Financial Statements and Supplementary Data – Note 7.9. Long-Term Investments and Note 8.10. 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 maintenanceO&M expenses,
discount rates, and
the current estimated economic viability of the plants after the end of the base lease term.
In addition, the residual values could be impacted by the intent to sell or terminate the leases. 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$49 million.
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 cost studies triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2015.2018. When we revise any assumptions used to calculate fair values of existing AROs, we adjust the ARO
balance and corresponding long-lived asset which generally impacts the amount of accretion and depreciation expense recognized in future periods.
Nuclear Decommissioning AROs
AROs related to the future decommissioning of PSEG Power’s nuclear facilities comprised 93%95% or $740 million of PSEG Power’s total AROs as of December 31, 2017.2019. 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:
financial feasibility and impacts on potential early shutdown,
license renewals,
safe storage forSAFSTOR alternative, which assumes the nuclear facility can be safely stored and subsequently decommissioned in a period of timewithin 60 years after retirement,operations,
DECON alternative, which assumes decommissioning activities begin after operations, and
recovery from the federal government of costs incurred for spent nuclear fuel.
Effect if Different Assumptions Used: Changes in the assumptions could result in a material change in the ARO balance sheet obligation and the period over which we accrete to the ultimate liability. For example, aHad the following assumptions been applied, our estimates of the approximate impacts on the Nuclear ARO as of December 31, 2019 are as follows:
A decrease of 1% in the discount rate would result in a $120$33 million increase in the Nuclear ARO as of December 31, 2017. ARO.
An increase of 1% in the inflation rate would result in a $324$275 million increase in the Nuclear ARO asARO.
If we didwere not assume that we would recover fromreimbursed by the federal government the costs incurred for spent nuclear fuel costs as prescribed under the Nuclear Waste Policy Act, the Nuclear ARO would increase by $550 million at December 31, 2017. $379 million.
| |
| • | If we would elect or be required to decommission under a DECON alternative at Salem and Hope Creek, the Nuclear ARO would increase by $675 million. |
If PSEG Power were to increase its early shutdown probability to 100% and retire Salem and Hope Creek and Salem starting in 2021 (when the current capacity obligations for Salem and Hope Creek expire),2022, which is significantly earlier than the end of their current license periods, the Nuclear ARO would increase by $428$203 million. For additional information, see Item 8. Note 4. Early Plant Retirements/Asset Dispositions.
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 6.7. 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 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 | |
| | | | Millions | |
| | Years Ended December 31, | | 2019 | | 2018 | |
| | | | | |
| | 95% Confidence Level, Loss could exceed VaR one day in 20 days | | | | | |
| | Period End | | $ | 9 |
| | $ | 21 |
| |
| | Average for the Period | | $ | 12 |
| | $ | 14 |
| |
| | High | | $ | 35 |
| | $ | 46 |
| |
| | Low | | $ | 5 |
| | $ | 6 |
| |
| | | | | | | |
| | 99.5% Confidence Level, Loss could exceed VaR one day in 200 days | | | | | |
| | Period End | | $ | 14 |
| | $ | 32 |
| |
| | Average for the Period | | $ | 19 |
| | $ | 22 |
| |
| | High | | $ | 54 |
| | $ | 72 |
| |
| | Low | | $ | 8 |
| | $ | 9 |
| |
| | | | | | | |
See Item 8. Financial Statements and Supplementary Data—Note 16.18. 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, 2017,2019, a hypothetical 10% increase in market interest rates would result in
$1 million of additionalno material impact on annual interest costs related to botheither the current andor the long-term portion of long-term debt, and
a $370$401 million decrease in the fair value of debt, including a $16$14 million decrease at PSEG, a $309$353 million decrease at PSE&G and a $45$34 million decrease at PSEG Power.
Debt and Equity Securities
We have $6.3$6.5 billion of 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, 2017,2019, the portfolio included $1.1$1.2 billion of equity securities and $986 million$1.1 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, 2017,2019, a hypothetical 10% change in the equity market would impact the value of the equity securities in the NDT Fund by approximately $106$115 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 5.985.87 years and a yield of 2.72%2.32%. The portfolio’s value will appreciate or depreciate by the duration with a 1% change in interest rates. As of December 31, 2017,2019, a hypothetical 1% increase in interest rates would result in a decline in the market value for the fixed income portfolio of approximately $59$62 million.
Credit Risk
See Item 8. Financial Statements and Supplementary Data—Note 16.18. Financial Risk Management Activities for a discussion of credit risk and a discussion about PSEG Power’s and PSE&G’s credit risk.
Energy Holdings has credit risk related to its investments in leases, which totaled $85169 million, net of deferred taxes of $480328 million, as of December 31, 2017.2019. These leveraged leases are concentrated in the U.S. energy industry. See Item 8. Financial Statements and Supplementary Data—Note 8.10. 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 transactionsCredit enhancements include covenants that restrict the flow of dividends from the lessee to its parent, over-collateralizationaffiliate guarantees and partial 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 generated by Energy Holdings’ portfolio of investments 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 PSEG Power. Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G and PSEG Power each make representations only as to itself and make 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, 20172019 and 2016,2018, the related consolidated statements of operations, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2017,2019, 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 consolidated financial position of the Company as of December 31, 20172019 and 2016,2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2019, 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, 2017,2019, 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, 2018,2020, 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 auditaudits 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 Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Early Plant Retirements/Asset Dispositions - Nuclear - Refer to Notes 4 and 13 to the financial statements
Critical Audit Matter Description
PSEG’s wholly-owned subsidiary PSEG Power LLC (PSEG Power) owns and operates nuclear plants in New Jersey and has recorded associated asset retirement obligations (ARO) for their eventual decommissioning. In April 2019, the New Jersey Board of Public Utilities (BPU) awarded Zero Emission Certificates (ZEC) to PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants for an initial period of approximately three years through May 2022. As described in Note 4, there are certain legal, regulatory, and economic matters in the markets in which these nuclear plants operate, which, if not favorably resolved, would result in PSEG taking all necessary steps to retire all of these nuclear plants subsequent to the initial ZEC period at or prior to a scheduled refueling outage, which is significantly in advance of their currently estimated remaining
useful lives. This would result in material charges associated with accelerated depreciation and amortization, impairment charges, and accelerated asset retirement costs, among other costs.
We identified the potential early retirement of the nuclear plants as a critical audit matter because of the significant estimates and assumptions management made in determining the nuclear plants’ useful lives and in evaluating the recorded investments in the nuclear plants for potential impairment. Further, management’s estimates used in recording the ARO included a number of assumptions, including the timing of cash flows associated with the eventual decommissioning of the nuclear plants following the retirement of the assets. Auditing each of these assumptions required a high degree of auditor judgment.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the potential early retirement of the nuclear plants and the related impact on the recorded investments in the nuclear plants and the related ARO included the following, among others:
We tested the effectiveness of controls over the evaluation of potential impairment indicators.
We tested the effectiveness of controls over the evaluation of legal matters related to the appeal of the initial awarding of the ZECs and the potential impact on PSEG’s evaluation of impairment indicators.
We tested the effectiveness of controls over the evaluation of retirement date assumptions used in the calculation of the ARO, including the probability weighting of the various cash flow scenarios.
We evaluated management’s judgments over the probability of early retirement of the nuclear plants and impairment triggers.
We evaluated management’s assumptions over the weighted-probability of early retirement of the nuclear plants used in calculating the recorded nuclear ARO balance.
We evaluated the related disclosures for consistency with our understanding.
Commitments and Contingent Liabilities - Passaic River Environmental Liability - Refer to Note 15 to the financial statements
Critical Audit Matter Description
As described in Note 15, the U.S. Environmental Protection Agency (EPA) has designated a 17-mile stretch of the lower Passaic River (Lower Passaic River Study Area (LPRSA)) in New Jersey as a superfund site requiring environmental remediation and has identified certain potentially responsible parties (PRPs), including PSEG’s subsidiaries Public Service Electric and Gas Company (PSE&G) and PSEG Power. The EPA has released a Record of Decision (ROD) for the LPRSA’s lower 8.3 miles that requires the removal of sediments at an estimated cost of $2.3 billion (ROD Remedy). An EPA-commenced process to allocate the associated costs to the PRPs is underway, and PSEG cannot predict the outcome. Additionally, one of the PRPs has filed suit against PSE&G and others seeking cost recovery and contribution under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, but has not quantified alleged damages. The litigation is ongoing and PSEG cannot predict the outcome. As of December 31, 2019, PSEG recorded an environmental liability for its estimated share of the remediation of the environmental contamination, a portion of which has been deferred as a regulatory asset based on PSE&G’s assessment that it will recover such costs in future rates.
The outcome of this matter is uncertain, and PSEG cannot predict this matter’s ultimate impact on its financial statements. It is possible that PSEG will record additional costs beyond what it has accrued, and that such costs could be material, but PSEG cannot at the current time estimate the amount or range of any additional costs.
We identified the accounting for the Passaic River environmental liability as a critical audit matter due to the uncertainties inherent in estimating PSEG’s liability. Auditing PSEG’s allocable share of the remediation cost, the environmental liability recorded, and the evaluation of future recovery of the regulatory asset recorded by PSE&G required a high degree of auditor judgment and the involvement of our environmental specialists.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the Passaic River environmental liability included the following, among others:
We tested the effectiveness of controls over the Passaic River environmental liability, including those over the evaluation of recent events and changes in circumstances that have or may give rise to a change in the allocable share of the estimated total remediation costs.
We tested the effectiveness of controls over the Passaic River regulatory asset, including controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering the Passaic River regulatory asset in future rates.
With the assistance of our environmental specialists, we evaluated management’s judgments and estimates associated with the planned remediation techniques and associated estimated costs used in estimating the environmental liability.
We evaluated the assumptions used by management to estimate the allocable share of the environmental obligation, including consideration of publicly available information.
We requested and received a written response from internal counsel and external legal firms representing PSEG and evaluated the legal conclusions for consistency with those used in management’s accounting judgments and disclosures.
We evaluated management’s analysis over the assertion that the Passaic River regulatory asset is probable of recovery.
We evaluated the related disclosures for consistency with our understanding.
Regulatory Assets and Liabilities - Income Taxes - Refer to Notes 7 and 22 to the financial statements
Critical Audit Matter Description
PSEG’s subsidiary, PSE&G, is an electric and gas transmission and distribution utility regulated by the BPU and the Federal Energy Regulatory Commission (FERC). 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 cost-based rate regulation. PSE&G defers the recognition of costs (regulatory assets) or records the recognition of obligations (regulatory liabilities) 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 regulatory liability is charged or credited to income.
Through the rate-making process, PSE&G’s rates to customers also include the recovery of income tax expense associated with PSE&G’s electric and gas distribution and electric transmission operations. As a result of the 2017 Tax Cuts and Jobs Act, which reduced the federal corporate income tax rate from 35% to 21%, PSE&G recorded regulatory liabilities for excess accumulated deferred income taxes (ADIT). These regulatory liabilities will be refunded to customers in future periods. PSE&G’s most recent electric and gas distribution base rate case, concluded in 2018, established the tax adjustment credit (TAC) that provides for the refund of these excess ADIT regulatory liabilities as well as the flow through to customers of historical and current accumulated deferred income taxes for tax-deductible repairs. The flow through of the current tax benefits results in lower revenues and lower income tax expense, as well as the recognition of a regulatory asset, as management believes it is probable that the accumulated tax benefits, treated as a flow-through item to PSE&G customers, will be recovered from customers in the future. The accounting for the return of the excess ADIT and the flow-through results in an annual effective tax rate for PSE&G and PSEG that is currently significantly lower than the statutory tax rate.
We identified the accounting for the TAC as a critical audit matter due to the complexity in accounting for the impact of rate regulation on income tax expense. Auditing the significant judgments made by management to support its assertion that the TAC regulatory assets are probable of future recovery required auditor judgment and specialized knowledge of accounting matters specific to rate regulation. Further, the determination of the estimated benefit of current tax-deductible repairs under the Internal Revenue Code, and the resulting impacts on the TAC regulatory asset and income tax expense recorded in the financial statements was complex and required the involvement of our income tax specialists.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures to evaluate the accounting for the impact of rate regulation on income tax expense and associated regulatory assets and regulatory liabilities included the following, among others:
We tested the effectiveness of controls over the calculation of the amounts refunded through the TAC, including controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering the TAC regulatory assets in future rates.
We evaluated management’s analysis over the assertion that the TAC regulatory assets are probable of recovery.
We evaluated relevant regulatory orders related to the ratemaking treatment of income taxes.
With the assistance of our income tax specialists, we tested the accuracy of recorded income tax expense and tax related regulatory assets and liabilities.
We evaluated the financial statement presentation and related disclosures for consistency with our understanding.
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| /s/ DELOITTE & TOUCHE LLP |
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| Parsippany, New Jersey |
February 26, 20182020 |
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”) as of December 31, 20172019 and 2016,2018, and 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, and2019, 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, 20172019 and 2016,2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2019, 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.
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| /s/ DELOITTE & TOUCHE LLP |
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| Parsippany, New Jersey |
February 26, 20182020 |
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, 20172019 and 2016,2018, 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, 2017,2019, 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, 20172019 and 2016,2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2019, 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.
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| /s/ DELOITTE & TOUCHE LLP |
| |
| Parsippany, New Jersey |
February 26, 20182020 |
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, | |
| | | | 2019 | | 2018 | | 2017 | |
| | OPERATING REVENUES | | $ | 10,076 |
| | $ | 9,696 |
| | $ | 9,094 |
| |
| | OPERATING EXPENSES | | | | | | | |
| | Energy Costs | | 3,372 |
| | 3,225 |
| | 2,778 |
| |
| | Operation and Maintenance | | 3,111 |
| | 3,069 |
| | 2,901 |
| |
| | Depreciation and Amortization | | 1,248 |
| | 1,158 |
| | 1,986 |
| |
| | (Gain) Loss on Asset Dispositions | | 402 |
| | (54 | ) | | — |
| |
| | Total Operating Expenses | | 8,133 |
| | 7,398 |
| | 7,665 |
| |
| | OPERATING INCOME | | 1,943 |
| | 2,298 |
| | 1,429 |
| |
| | Income from Equity Method Investments | | 14 |
| | 15 |
| | 14 |
| |
| | Net Gains (Losses) on Trust Investments | | 260 |
| | (143 | ) | | 134 |
| |
| | Other Income (Deductions) | | 125 |
| | 85 |
| | 82 |
| |
| | Non-Operating Pension and OPEB Credits (Costs) | | 177 |
| | 76 |
| | — |
| |
| | Interest Expense | | (569 | ) | | (476 | ) | | (391 | ) | |
| | INCOME BEFORE INCOME TAXES | | 1,950 |
| | 1,855 |
| | 1,268 |
| |
| | Income Tax Benefit (Expense) | | (257 | ) | | (417 | ) | | 306 |
| |
| | NET INCOME | | $ | 1,693 |
| | $ | 1,438 |
| | $ | 1,574 |
| |
| | WEIGHTED AVERAGE COMMON SHARES OUTSTANDING: | | | | | | | |
| | BASIC | | 504 |
| | 504 |
| | 505 |
| |
| | DILUTED | | 507 |
| | 507 |
| | 507 |
| |
| | NET INCOME PER SHARE: | | | | | | | |
| | BASIC | | $ | 3.35 |
| | $ | 2.85 |
| | $ | 3.12 |
| |
| | DILUTED | | $ | 3.33 |
| | $ | 2.83 |
| | $ | 3.10 |
| |
| | | | | | | | | |
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
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, | |
| | | | 2019 | | 2018 | | 2017 | |
| | NET INCOME | | $ | 1,693 |
| | $ | 1,438 |
| | $ | 1,574 |
| |
| | Other Comprehensive Income (Loss), net of tax | | | | | | | |
| | Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(26), $11 and $(37) for the years ended 2019, 2018 and 2017, respectively | | 41 |
| | (17 | ) | | 44 |
| |
| | Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $6, $1, and $1 for the years ended 2019, 2018 and 2017, respectively | | (14 | ) | | (1 | ) | | (2 | ) | |
| | Pension/OPEB adjustment, net of tax (expense) benefit of $18, $(18) and $(4) for the years ended 2019, 2018 and 2017, respectively | | (58 | ) | | 46 |
| | (8 | ) | |
| | Other Comprehensive Income (Loss), net of tax | | (31 | ) | | 28 |
| | 34 |
| |
| | COMPREHENSIVE INCOME | | $ | 1,662 |
| | $ | 1,466 |
| | $ | 1,608 |
| |
| | | | | | | | | |
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
Millions
|
| | | | | | | | | |
| | | | | | |
| | | 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 |
| |
| | | | | | |
|
| | | | | | | | | |
| | | | | | |
| | | December 31, | |
| | | 2019 | | 2018 | |
| | ASSETS | |
| | CURRENT ASSETS | | | | |
| | Cash and Cash Equivalents | $ | 147 |
| | $ | 177 |
| |
| | Accounts Receivable, net of allowances of $60 in 2019 and $63 in 2018 | 1,313 |
| | 1,435 |
| |
| | Tax Receivable | 21 |
| | 242 |
| |
| | Unbilled Revenues | 239 |
| | 240 |
| |
| | Fuel | 310 |
| | 331 |
| |
| | Materials and Supplies, net | 587 |
| | 571 |
| |
| | Prepayments | 79 |
| | 94 |
| |
| | Derivative Contracts | 113 |
| | 11 |
| |
| | Regulatory Assets | 351 |
| | 389 |
| |
| | Assets Held for Sale | 30 |
| | — |
| |
| | Other | 41 |
| | 17 |
| |
| | Total Current Assets | 3,231 |
| | 3,507 |
| |
| | PROPERTY, PLANT AND EQUIPMENT | 45,944 |
| | 44,201 |
| |
| | Less: Accumulated Depreciation and Amortization | (10,100 | ) | | (9,838 | ) | |
| | Net Property, Plant and Equipment | 35,844 |
| | 34,363 |
| |
| | NONCURRENT ASSETS | | | | |
| | Regulatory Assets | 3,677 |
| | 3,399 |
| |
| | Operating Lease Right-of-Use Assets | 282 |
| | — |
| |
| | Long-Term Investments | 812 |
| | 896 |
| |
| | Nuclear Decommissioning Trust (NDT) Fund | 2,216 |
| | 1,878 |
| |
| | Long-Term Tax Receivable | 150 |
| | — |
| |
| | Long-Term Receivable of Variable Interest Entity | 813 |
| | 624 |
| |
| | Rabbi Trust Fund | 246 |
| | 224 |
| |
| | Goodwill | — |
| | 16 |
| |
| | Other Intangibles | 149 |
| | 143 |
| |
| | Derivative Contracts | 24 |
| | 1 |
| |
| | Other | 286 |
| | 275 |
| |
| | Total Noncurrent Assets | 8,655 |
| | 7,456 |
| |
| | TOTAL ASSETS | $ | 47,730 |
| | $ | 45,326 |
| |
| | | | | | |
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, | |
| | | 2019 | | 2018 | |
| | LIABILITIES AND CAPITALIZATION | |
| | CURRENT LIABILITIES |
| |
| |
| | Long-Term Debt Due Within One Year | $ | 1,365 |
| | $ | 1,294 |
| |
| | Commercial Paper and Loans | 1,115 |
| | 1,016 |
| |
| | Accounts Payable | 1,358 |
| | 1,451 |
| |
| | Derivative Contracts | 36 |
| | 11 |
| |
| | Accrued Interest | 116 |
| | 110 |
| |
| | Accrued Taxes | 41 |
| | 26 |
| |
| | Clean Energy Program | 143 |
| | 143 |
| |
| | Obligation to Return Cash Collateral | 119 |
| | 136 |
| |
| | Regulatory Liabilities | 234 |
| | 311 |
| |
| | Other | 520 |
| | 437 |
| |
| | Total Current Liabilities | 5,047 |
| | 4,935 |
| |
| | NONCURRENT LIABILITIES | | | | |
| | Deferred Income Taxes and Investment Tax Credits (ITC) | 6,256 |
| | 5,713 |
| |
| | Regulatory Liabilities | 3,002 |
| | 3,221 |
| |
| | Operating Leases | 273 |
| | — |
| |
| | Asset Retirement Obligations | 1,087 |
| | 1,063 |
| |
| | Other Postretirement Benefit (OPEB) Costs | 734 |
| | 704 |
| |
| | OPEB Costs of Servco | 626 |
| | 501 |
| |
| | Accrued Pension Costs | 952 |
| | 791 |
| |
| | Accrued Pension Costs of Servco | 171 |
| | 109 |
| |
| | Environmental Costs | 349 |
| | 327 |
| |
| | Derivative Contracts | 1 |
| | 4 |
| |
| | Long-Term Accrued Taxes | 182 |
| | 181 |
| |
| | Other | 218 |
| | 232 |
| |
| | Total Noncurrent Liabilities | 13,851 |
| | 12,846 |
| |
| | COMMITMENTS AND CONTINGENT LIABILITIES (See Note 15) |
|
| |
| |
| | CAPITALIZATION | | | | |
| | LONG-TERM DEBT
| 13,743 |
| | 13,168 |
| |
| | STOCKHOLDERS’ EQUITY | | | | |
| | Common Stock, no par, authorized 1,000 shares; issued, 2019 and 2018— 534 shares | 5,003 |
| | 4,980 |
| |
| | Treasury Stock, at cost, 2019 and 2018—30 shares | (831 | ) | | (808 | ) | |
| | Retained Earnings | 11,406 |
| | 10,582 |
| |
| | Accumulated Other Comprehensive Loss | (489 | ) | | (377 | ) | |
| | Total Stockholders’ Equity | 15,089 |
| | 14,377 |
| |
| | Total Capitalization | 28,832 |
| | 27,545 |
| |
| | TOTAL LIABILITIES AND CAPITALIZATION | $ | 47,730 |
| | $ | 45,326 |
| |
| | | | | | |
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, | |
| | | | 2019 | | 2018 | | 2017 | |
| | CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | |
| | Net Income | | $ | 1,693 |
| | $ | 1,438 |
| | $ | 1,574 |
| |
| | Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | |
| | Depreciation and Amortization | | 1,248 |
| | 1,158 |
| | 1,986 |
| |
| | Amortization of Nuclear Fuel | | 178 |
| | 187 |
| | 199 |
| |
| | (Gain) Loss on Asset Dispositions | | 402 |
| | (54 | ) | | — |
| |
| | Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual | | 108 |
| | 97 |
| | 103 |
| |
| | Provision for Deferred Income Taxes (Other than Leases) and ITC | | 180 |
| | 568 |
| | (167 | ) | |
| | Non-Cash Employee Benefit Plan (Credits) Costs | | (48 | ) | | 70 |
| | 89 |
| |
| | Leveraged Lease (Income) Loss, Adjusted for Rents Received and Deferred Taxes | | (14 | ) | | (149 | ) | | (159 | ) | |
| | Net (Gain) Loss on Lease Investments | | 32 |
| | 5 |
| | 48 |
| |
| | Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives | | (290 | ) | | 116 |
| | 188 |
| |
| | Cost of Removal | | (108 | ) | | (160 | ) | | (107 | ) | |
| | Net Change in Regulatory Assets and Liabilities | | 25 |
| | (153 | ) | | (188 | ) | |
| | Net (Gains) Losses and (Income) Expense from NDT Fund | | (296 | ) | | 98 |
| | (156 | ) | |
| | Net Change in Certain Current Assets and Liabilities: | | | | | | | |
| | Tax Receivable | | 77 |
| | 17 |
| | 65 |
| |
| | Accrued Taxes | | (9 | ) | | (69 | ) | | 16 |
| |
| | Cash Collateral | | 349 |
| | (247 | ) | | (90 | ) | |
| | Other Current Assets and Liabilities | | (145 | ) | | 70 |
| | (72 | ) | |
| | Employee Benefit Plan Funding and Related Payments | | (39 | ) | | (101 | ) | | (81 | ) | |
| | Other | | 36 |
| | 22 |
| | 12 |
| |
| | Net Cash Provided By (Used In) Operating Activities | | 3,379 |
| | 2,913 |
| | 3,260 |
| |
| | CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | |
| | Additions to Property, Plant and Equipment | | (3,166 | ) | �� | (3,912 | ) | | (4,190 | ) | |
| | Purchase of Emissions Allowances and RECs | | (98 | ) | | (146 | ) | | (117 | ) | |
| | Proceeds from Sales of Trust Investments | | 1,787 |
| | 1,501 |
| | 2,319 |
| |
| | Purchases of Trust Investments | | (1,814 | ) | | (1,473 | ) | | (2,340 | ) | |
| | Other | | 146 |
| | 114 |
| | 72 |
| |
| | Net Cash Provided By (Used In) Investing Activities | | (3,145 | ) | | (3,916 | ) | | (4,256 | ) | |
| | CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | |
| | Net Change in Commercial Paper and Loans | | 99 |
| | 474 |
| | 154 |
| |
| | Issuance of Long-Term Debt | | 1,900 |
| | 2,750 |
| | 2,175 |
| |
| | Redemption of Long-Term Debt | | (1,250 | ) | | (1,350 | ) | | (500 | ) | |
| | Cash Dividends Paid on Common Stock | | (950 | ) | | (910 | ) | | (870 | ) | |
| | Other | | (56 | ) | | (77 | ) | | (74 | ) | |
| | Net Cash Provided By (Used In) Financing Activities | | (257 | ) | | 887 |
| | 885 |
| |
| | Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | | (23 | ) | | (116 | ) | | (111 | ) | |
| | Cash, Cash Equivalents and Restricted Cash at Beginning of Period | | 199 |
| | 315 |
| | 426 |
| |
| | Cash, Cash Equivalents and Restricted Cash at End of Period | | $ | 176 |
| | $ | 199 |
| | $ | 315 |
| |
| | Supplemental Disclosure of Cash Flow Information: | | | | | | | |
| | Income Taxes Paid (Received) | | $ | 41 |
| | $ | 99 |
| | $ | (8 | ) | |
| | Interest Paid, Net of Amounts Capitalized | | $ | 539 |
| | $ | 454 |
| | $ | 377 |
| |
| | Accrued Property, Plant and Equipment Expenditures | | $ | 499 |
| | $ | 517 |
| | $ | 722 |
| |
| | | | | | | | | |
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 January 1, 2017 | | 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 at $1.72 per share 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 |
| |
| | Net Income | | — |
| | — |
| | — |
| | — |
| | 1,438 |
| | — |
| | 1,438 |
| |
| | Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments | | — |
| | — |
| | — |
| | — |
| | 176 |
| | (176 | ) | | — |
| |
| | Other Comprehensive Income (Loss), net of tax (expense) benefit of $(6) | | — |
| | — |
| | — |
| | — |
| | — |
| | 28 |
| | 28 |
| |
| | Comprehensive Income | | | | | | | | | | | | | | 1,466 |
| |
| | Cash Dividends at $1.80 per share on Common Stock | | — |
| | — |
| | — |
| | — |
| | (910 | ) | | — |
| | (910 | ) | |
| | Other | | — |
| | 19 |
| | (1 | ) | | (45 | ) | | — |
| | — |
| | (26 | ) | |
| | Balance as of December 31, 2018 | | 534 |
| | $ | 4,980 |
| | (30 | ) | | $ | (808 | ) | | $ | 10,582 |
| | $ | (377 | ) | | $ | 14,377 |
| |
| | Net Income | | — |
| | — |
| | — |
| | — |
| | 1,693 |
| | — |
| | 1,693 |
| |
| | Cumulative Effect Adjustment to Reclassify Stranded Tax Effects Resulting from the Change in the Federal Corporate Income Tax Rate | | — |
| | — |
| | — |
| | — |
| | 81 |
| | (81 | ) | | — |
| |
| | Other Comprehensive Income (Loss), net of tax (expense) benefit of $(2) | | — |
| | — |
| | — |
| | — |
| | — |
| | (31 | ) | | (31 | ) | |
| | Comprehensive Income | | | | | | | | | | | | | | 1,662 |
| |
| | Cash Dividends at $1.88 per share on Common Stock | | — |
| | — |
| | — |
| | — |
| | (950 | ) | | — |
| | (950 | ) | |
| | Other | | — |
| | 23 |
| | — |
| | (23 | ) | | — |
| | — |
| | — |
| |
| | Balance as of December 31, 2019 | | 534 |
| | $ | 5,003 |
| | (30 | ) | | $ | (831 | ) | | $ | 11,406 |
| | $ | (489 | ) | | $ | 15,089 |
| |
| | | | | | | | | | | | | | | | | |
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, | |
| | | | 2019 | | 2018 | | 2017 | |
| | OPERATING REVENUES | | $ | 6,625 |
| | $ | 6,471 |
| | $ | 6,324 |
| |
| | OPERATING EXPENSES | | | | | | | |
| | Energy Costs | | 2,738 |
| | 2,520 |
| | 2,421 |
| |
| | Operation and Maintenance | | 1,581 |
| | 1,575 |
| | 1,458 |
| |
| | Depreciation and Amortization | | 837 |
| | 770 |
| | 685 |
| |
| | Total Operating Expenses | | 5,156 |
| | 4,865 |
| | 4,564 |
| |
| | OPERATING INCOME | | 1,469 |
| | 1,606 |
| | 1,760 |
| |
| | Net Gains (Losses) on Trust Investments | | 2 |
| | (1 | ) | | 2 |
| |
| | Other Income (Deductions) | | 83 |
| | 80 |
| | 85 |
| |
| | Non-Operating Pension and OPEB Credits (Costs) | | 150 |
| | 59 |
| | (8 | ) | |
| | Interest Expense | | (361 | ) | | (333 | ) | | (303 | ) | |
| | INCOME BEFORE INCOME TAXES | | 1,343 |
| | 1,411 |
| | 1,536 |
| |
| | Income Tax Expense | | (93 | ) | | (344 | ) | | (563 | ) | |
| | NET INCOME | | $ | 1,250 |
| | $ | 1,067 |
| | $ | 973 |
| |
| | | | | | | | | |
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, | |
| | | | 2019 | | 2018 | | 2017 | |
| | NET INCOME | | $ | 1,250 |
| | $ | 1,067 |
| | $ | 973 |
| |
| | Other Comprehensive Income (Loss), net of tax | | | | | | | |
| | Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(1), $1 and $0 for the years ended 2019, 2018 and 2017, respectively | | 3 |
| | (1 | ) | | (1 | ) | |
| | COMPREHENSIVE INCOME | | $ | 1,253 |
| | $ | 1,066 |
| | $ | 972 |
| |
| | | | | | | | | |
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, | |
| | | 2019 | | 2018 | |
| | ASSETS | |
| | CURRENT ASSETS | | | | |
| | Cash and Cash Equivalents | $ | 21 |
| | $ | 39 |
| |
| | Accounts Receivable, net of allowances of $60 in 2019 and $63 in 2018 | 901 |
| | 879 |
| |
| | Tax Receivable | — |
| | 20 |
| |
| | Accounts Receivable—Affiliated Companies | 1 |
| | 123 |
| |
| | Unbilled Revenues | 239 |
| | 240 |
| |
| | Materials and Supplies, net | 213 |
| | 196 |
| |
| | Prepayments | 35 |
| | 10 |
| |
| | Regulatory Assets | 351 |
| | 389 |
| |
| | Other | 28 |
| | 11 |
| |
| | Total Current Assets | 1,789 |
| | 1,907 |
| |
| | PROPERTY, PLANT AND EQUIPMENT | 33,900 |
| | 31,633 |
| |
| | Less: Accumulated Depreciation and Amortization | (6,623 | ) | | (6,277 | ) | |
| | Net Property, Plant and Equipment | 27,277 |
| | 25,356 |
| |
| | NONCURRENT ASSETS | | | | |
| | Regulatory Assets | 3,677 |
| | 3,399 |
| |
| | Operating Lease Right-of-Use Assets | 98 |
| | — |
| |
| | Long-Term Investments | 248 |
| | 270 |
| |
| | Rabbi Trust Fund | 48 |
| | 45 |
| |
| | Other | 129 |
| | 132 |
| |
| | Total Noncurrent Assets | 4,200 |
| | 3,846 |
| |
| | TOTAL ASSETS | $ | 33,266 |
| | $ | 31,109 |
| |
| | | | | | |
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, | |
| | | 2019 | | 2018 | |
| | LIABILITIES AND CAPITALIZATION | |
| | CURRENT LIABILITIES | | | | |
| | Long-Term Debt Due Within One Year | $ | 259 |
| | $ | 500 |
| |
| | Commercial Paper and Loans | 362 |
| | 272 |
| |
| | Accounts Payable | 639 |
| | 713 |
| |
| | Accounts Payable—Affiliated Companies | 390 |
| | 321 |
| |
| | Accrued Interest | 91 |
| | 84 |
| |
| | Clean Energy Program | 143 |
| | 143 |
| |
| | Obligation to Return Cash Collateral | 119 |
| | 136 |
| |
| | Regulatory Liabilities | 234 |
| | 311 |
| |
| | Other | 436 |
| | 345 |
| |
| | Total Current Liabilities | 2,673 |
| | 2,825 |
| |
| | NONCURRENT LIABILITIES | | | | |
| | Deferred Income Taxes and ITC | 4,189 |
| | 3,830 |
| |
| | Regulatory Liabilities | 3,002 |
| | 3,221 |
| |
| | Operating Leases | 87 |
| | — |
| |
| | Asset Retirement Obligations | 303 |
| | 302 |
| |
| | OPEB Costs | 495 |
| | 486 |
| |
| | Accrued Pension Costs | 501 |
| | 400 |
| |
| | Environmental Costs | 294 |
| | 268 |
| |
| | Long-Term Accrued Taxes | 115 |
| | 69 |
| |
| | Other | 136 |
| | 124 |
| |
| | Total Noncurrent Liabilities | 9,122 |
| | 8,700 |
| |
| | COMMITMENTS AND CONTINGENT LIABILITIES (See Note 15) |
| |
| |
| | CAPITALIZATION |
| | | |
| | LONG-TERM DEBT | 9,568 |
| | 8,684 |
| |
| | STOCKHOLDER’S EQUITY | | | | |
| | Common Stock; 150 shares authorized; issued and outstanding, 2019 and 2018—132 shares | 892 |
| | 892 |
| |
| | Contributed Capital | 1,095 |
| | 1,095 |
| |
| | Basis Adjustment | 986 |
| | 986 |
| |
| | Retained Earnings | 8,928 |
| | 7,928 |
| |
| | Accumulated Other Comprehensive Income (Loss) | 2 |
| | (1 | ) | |
| | Total Stockholder’s Equity | 11,903 |
| | 10,900 |
| |
| | Total Capitalization | 21,471 |
| | 19,584 |
| |
| | TOTAL LIABILITIES AND CAPITALIZATION | $ | 33,266 |
| | $ | 31,109 |
| |
| | | | | | |
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, | |
| | | | 2019 | | 2018 | | 2017 | |
| | CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | |
| | Net Income | | $ | 1,250 |
| | $ | 1,067 |
| | $ | 973 |
| |
| | Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | |
| | Depreciation and Amortization | | 837 |
| | 770 |
| | 685 |
| |
| | Provision for Deferred Income Taxes and ITC | | (28 | ) | | 405 |
| | 616 |
| |
| | Non-Cash Employee Benefit Plan (Credits) Costs | | (62 | ) | | 37 |
| | 50 |
| |
| | Cost of Removal | | (108 | ) | | (160 | ) | | (107 | ) | |
| | Net Change in Other Regulatory Assets and Liabilities | | 25 |
| | (153 | ) | | (188 | ) | |
| | Net Change in Certain Current Assets and Liabilities | | | | | | | |
| | Accounts Receivable and Unbilled Revenues | | (18 | ) | | 65 |
| | (106 | ) | |
| | Materials and Supplies | | (14 | ) | | 1 |
| | (13 | ) | |
| | Prepayments | | (9 | ) | | 14 |
| | (35 | ) | |
| | Accounts Payable | | (59 | ) | | 64 |
| | 1 |
| |
| | Accounts Receivable/Payable—Affiliated Companies, net | | 203 |
| | (139 | ) | | 101 |
| |
| | Other Current Assets and Liabilities | | 62 |
| | 5 |
| | 15 |
| |
| | Employee Benefit Plan Funding and Related Payments | | (21 | ) | | (85 | ) | | (68 | ) | |
| | Other | | (23 | ) | | (38 | ) | | (86 | ) | |
| | Net Cash Provided By (Used In) Operating Activities | | 2,035 |
| | 1,853 |
| | 1,838 |
| |
| | CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | |
| | Additions to Property, Plant and Equipment | | (2,542 | ) | | (2,896 | ) | | (2,919 | ) | |
| | Proceeds from Sales of Trust Investments | | 36 |
| | 20 |
| | 36 |
| |
| | Purchases of Trust Investments | | (34 | ) | | (22 | ) | | (37 | ) | |
| | Solar Loan Investments | | 8 |
| | (5 | ) | | 7 |
| |
| | Other | | 10 |
| | 9 |
| | 10 |
| |
| | Net Cash Provided By (Used In) Investing Activities | | (2,522 | ) | | (2,894 | ) | | (2,903 | ) | |
| | CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | |
| | Net Change in Commercial Paper and Loans | | 90 |
| | 272 |
| | — |
| |
| | Issuance of Long-Term Debt | | 1,150 |
| | 1,350 |
| | 775 |
| |
| | Redemption of Long-Term Debt | | (500 | ) | | (750 | ) | | — |
| |
| | Contributed Capital | | — |
| | — |
| | 150 |
| |
| | Cash Dividend Paid | | (250 | ) | | — |
| | — |
| |
| | Other | | (14 | ) | | (14 | ) | | (9 | ) | |
| | Net Cash Provided By (Used In) Financing Activities | | 476 |
| | 858 |
| | 916 |
| |
| | Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | | (11 | ) | | (183 | ) | | (149 | ) | |
| | Cash, Cash Equivalents and Restricted Cash at Beginning of Period | | 61 |
| | 244 |
| | 393 |
| |
| | Cash, Cash Equivalents and Restricted Cash at End of Period | | $ | 50 |
| | $ | 61 |
| | $ | 244 |
| |
| | Supplemental Disclosure of Cash Flow Information: | | | | | | | |
| | Income Taxes Paid (Received) | | $ | (48 | ) | | $ | 94 |
| | $ | (104 | ) | |
| | Interest Paid, Net of Amounts Capitalized | | $ | 343 |
| | $ | 318 |
| | $ | 294 |
| |
| | Accrued Property, Plant and Equipment Expenditures | | $ | 335 |
| | $ | 350 |
| | $ | 429 |
| |
| | | | | | | | | |
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 | | Basis Adjustment | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total | |
| | Balance as of January 1, 2017 | | $ | 892 |
| | $ | 945 |
| | $ | 986 |
| | $ | 5,888 |
| | $ | 1 |
| | $ | 8,712 |
| |
| | Net Income | | — |
| | — |
| | — |
| | 973 |
| | — |
| | 973 |
| |
| | Other Comprehensive Income (Loss), 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 |
| |
| | Net Income | | — |
| | — |
| | — |
| | 1,067 |
| | — |
| | 1,067 |
| |
| | Other Comprehensive Income (Loss), net of tax (expense) benefit of $1 | | — |
| | — |
| | — |
| | — |
| | (1 | ) | | (1 | ) | |
| | Comprehensive Income | | | | | | | | | | |
| 1,066 |
| |
| | Balance as of December 31, 2018 | | $ | 892 |
| | $ | 1,095 |
| | $ | 986 |
| | $ | 7,928 |
| | $ | (1 | ) | | $ | 10,900 |
| |
| | Net Income | | — |
| | — |
| | — |
| | 1,250 |
| | — |
| | 1,250 |
| |
| | Other Comprehensive Income (Loss), net of tax (expense) benefit of $(1) | | — |
| | — |
| | — |
| | — |
| | 3 |
| | 3 |
| |
| | Comprehensive Income | | | | | | | | | | |
| 1,253 |
| |
| | Cash Dividends Paid | | — |
| | — |
| | — |
| | (250 | ) | | — |
| | (250 | ) | |
| | Balance as of December 31, 2019 | | $ | 892 |
| | $ | 1,095 |
| | $ | 986 |
| | $ | 8,928 |
| | $ | 2 |
| | $ | 11,903 |
| |
| | | | | | | | | | | | | | | |
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 |
| |
| | | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | Years Ended December 31, | |
| | | | 2019 | | 2018 | | 2017 | |
| | OPERATING REVENUES | | $ | 4,385 |
| | $ | 4,146 |
| | $ | 3,860 |
| |
| | OPERATING EXPENSES | | | | | | | |
| | Energy Costs | | 2,118 |
| | 2,197 |
| | 1,913 |
| |
| | Operation and Maintenance | | 1,040 |
| | 1,053 |
| | 1,046 |
| |
| | Depreciation and Amortization | | 377 |
| | 354 |
| | 1,268 |
| |
| | (Gain) Loss on Asset Dispositions | | 402 |
| | (54 | ) | | — |
| |
| | Total Operating Expenses | | 3,937 |
| | 3,550 |
| | 4,227 |
| |
| | OPERATING INCOME (LOSS) | | 448 |
| | 596 |
| | (367 | ) | |
| | Income from Equity Method Investments | | 14 |
| | 15 |
| | 14 |
| |
| | Net Gains (Losses) on Trust Investments | | 253 |
| | (140 | ) | | 125 |
| |
| | Other Income (Deductions) | | 54 |
| | 21 |
| | 20 |
| |
| | Non-Operating Pension and OPEB (Costs) Credits | | 21 |
| | 15 |
| | 8 |
| |
| | Interest Expense | | (119 | ) | | (76 | ) | | (50 | ) | |
| | INCOME (LOSS) BEFORE INCOME TAXES | | 671 |
| | 431 |
| | (250 | ) | |
| | Income Tax Benefit (Expense) | | (203 | ) | | (66 | ) | | 729 |
| |
| | NET INCOME | | $ | 468 |
| | $ | 365 |
| | $ | 479 |
| |
| | | | | | | | | |
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 |
| |
| | | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | Years Ended December 31, | |
| | | | 2019 | | 2018 | | 2017 | |
| | NET INCOME | | $ | 468 |
| | $ | 365 |
| | $ | 479 |
| |
| | Other Comprehensive Income (Loss), net of tax | | | | | | | |
| | Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(22), $9, and $(39) for the years ended 2019, 2018 and 2017, respectively | | 32 |
| | (13 | ) | | 46 |
| |
| | Pension/OPEB adjustment, net of tax (expense) benefit of $13, $(16) and $(3) for the years ended 2019, 2018 and 2017, respectively | | (45 | ) | | 41 |
| | (7 | ) | |
| | Other Comprehensive Income (Loss), net of tax | | (13 | ) | | 28 |
| | 39 |
| |
| | COMPREHENSIVE INCOME | | $ | 455 |
| | $ | 393 |
| | $ | 518 |
| |
| | | | | | | | | |
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 |
| |
| | | | | | |
|
| | | | | | | | | |
| | | | | | |
| | | December 31, | |
| | | 2019 | | 2018 | |
| | ASSETS | |
| | CURRENT ASSETS | | | | |
| | Cash and Cash Equivalents | $ | 21 |
| | $ | 22 |
| |
| | Accounts Receivable | 309 |
| | 477 |
| |
| | Accounts Receivable—Affiliated Companies | 408 |
| | 274 |
| |
| | Short-Term Loan to Affiliate | 149 |
| | — |
| |
| | Fuel | 310 |
| | 331 |
| |
| | Materials and Supplies, net | 372 |
| | 373 |
| |
| | Derivative Contracts | 113 |
| | 11 |
| |
| | Prepayments | 11 |
| | 14 |
| |
| | Assets Held for Sale | 28 |
| | — |
| |
| | Other | 5 |
| | 5 |
| |
| | Total Current Assets | 1,726 |
| | 1,507 |
| |
| | PROPERTY, PLANT AND EQUIPMENT | 11,699 |
| | 12,224 |
| |
| | Less: Accumulated Depreciation and Amortization | (3,273 | ) | | (3,382 | ) | |
| | Net Property, Plant and Equipment | 8,426 |
| | 8,842 |
| |
| | NONCURRENT ASSETS | | | | |
| | Operating Lease Right-of-Use Assets | 71 |
| | — |
| |
| | NDT Fund | 2,216 |
| | 1,878 |
| |
| | Long-Term Investments | 66 |
| | 86 |
| |
| | Goodwill | — |
| | 16 |
| |
| | Other Intangibles | 149 |
| | 143 |
| |
| | Rabbi Trust Fund | 62 |
| | 56 |
| |
| | Derivative Contracts | 24 |
| | 1 |
| |
| | Other | 65 |
| | 65 |
| |
| | Total Noncurrent Assets | 2,653 |
| | 2,245 |
| |
| | TOTAL ASSETS | $ | 12,805 |
| | $ | 12,594 |
| |
| | | | | | |
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 |
| |
| | | | | | |
|
| | | | | | | | | |
| | | | | | |
| | | December 31, | |
| | | 2019 | | 2018 | |
| | LIABILITIES AND MEMBER’S EQUITY | |
| | CURRENT LIABILITIES | | | | |
| | Long-Term Debt Due Within One Year | $ | 406 |
| | $ | 44 |
| |
| | Accounts Payable | 505 |
| | 498 |
| |
| | Accounts Payable—Affiliated Companies | 5 |
| | 16 |
| |
| | Short-Term Loan from Affiliate | — |
| | 193 |
| |
| | Derivative Contracts | 31 |
| | 11 |
| |
| | Accrued Interest | 21 |
| | 21 |
| |
| | Other | 91 |
| | 59 |
| |
| | Total Current Liabilities | 1,059 |
| | 842 |
| |
| | NONCURRENT LIABILITIES | | | | |
| | Deferred Income Taxes and ITC | 1,876 |
| | 1,619 |
| |
| | Operating Leases | 62 |
| | — |
| |
| | Asset Retirement Obligations | 781 |
| | 758 |
| |
| | OPEB Costs | 192 |
| | 176 |
| |
| | Accrued Pension Costs | 284 |
| | 246 |
| |
| | Derivative Contracts | 1 |
| | 4 |
| |
| | Long-Term Accrued Taxes | 115 |
| | 76 |
| |
| | Other | 111 |
| | 122 |
| |
| | Total Noncurrent Liabilities | 3,422 |
| | 3,001 |
| |
| | COMMITMENTS AND CONTINGENT LIABILITIES (See Note 15) |
| |
| |
| | LONG-TERM DEBT
| 2,434 |
| | 2,791 |
| |
| | MEMBER’S EQUITY | | | | |
| | Contributed Capital | 2,214 |
| | 2,214 |
| |
| | Basis Adjustment | (986 | ) | | (986 | ) | |
| | Retained Earnings | 5,063 |
| | 5,051 |
| |
| | Accumulated Other Comprehensive Loss | (401 | ) | | (319 | ) | |
| | Total Member’s Equity | 5,890 |
| | 5,960 |
| |
| | TOTAL LIABILITIES AND MEMBER’S EQUITY | $ | 12,805 |
| | $ | 12,594 |
| |
| | | | | | |
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 |
| |
| | | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | Years Ended December 31, | |
| | | | 2019 | | 2018 | | 2017 | |
| | CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | |
| | Net Income | | $ | 468 |
| | $ | 365 |
| | $ | 479 |
| |
| | Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | |
| | Depreciation and Amortization | | 377 |
| | 354 |
| | 1,268 |
| |
| | Amortization of Nuclear Fuel | | 178 |
| | 187 |
| | 199 |
| |
| | (Gain) Loss on Asset Dispositions | | 402 |
| | (54 | ) | | — |
| |
| | Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual | | 108 |
| | 97 |
| | 103 |
| |
| | Provision for Deferred Income Taxes and ITC | | 248 |
| | 206 |
| | (807 | ) | |
| | Non-Cash Employee Benefit Plan Costs | | 7 |
| | 23 |
| | 28 |
| |
| | Interest Accretion on Asset Retirement Obligation | | 40 |
| | 41 |
| | 30 |
| |
| | Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives | | (290 | ) | | 116 |
| | 188 |
| |
| | Net (Gains) Losses and (Income) Expense from NDT Fund | | (296 | ) | | 98 |
| | (156 | ) | |
| | Net Change in Certain Current Assets and Liabilities | | | | | | | |
| | Fuel, Materials and Supplies | | (1 | ) | | (39 | ) | | 42 |
| |
| | Cash Collateral | | 349 |
| | (247 | ) | | (90 | ) | |
| | Accounts Receivable | | (32 | ) | | 51 |
| | (45 | ) | |
| | Accounts Payable | | 5 |
| | (13 | ) | | 39 |
| |
| | Accounts Receivable/Payable—Affiliated Companies, net | | (112 | ) | | (56 | ) | | (2 | ) | |
| | Other Current Assets and Liabilities | | 14 |
| | (40 | ) | | 10 |
| |
| | Employee Benefit Plan Funding and Related Payments | | (11 | ) | | (9 | ) | | (7 | ) | |
| | Other | | 25 |
| | 4 |
| | 47 |
| |
| | Net Cash Provided By (Used In) Operating Activities | | 1,479 |
| | 1,084 |
| | 1,326 |
| |
| | CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | |
| | Additions to Property, Plant and Equipment | | (607 | ) | | (996 | ) | | (1,231 | ) | |
| | Purchase of Emissions Allowances and RECs | | (98 | ) | | (146 | ) | | (117 | ) | |
| | Proceeds from Sales of Trust Investments | | 1,658 |
| | 1,423 |
| | 2,182 |
| |
| | Purchases of Trust Investments | | (1,685 | ) | | (1,392 | ) | | (2,199 | ) | |
| | Short-Term Loan to Affiliate | | (149 | ) | | — |
| | 87 |
| |
| | Other | | 120 |
| | 60 |
| | 46 |
| |
| | Net Cash Provided By (Used In) Investing Activities | | (761 | ) | | (1,051 | ) | | (1,232 | ) | |
| | CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | |
| | Issuance of Long-Term Debt | | — |
| | 700 |
| | — |
| |
| | Cash Dividend Paid | | (525 | ) | | (400 | ) | | (350 | ) | |
| | Redemption of Long-Term Debt | | — |
| | (250 | ) | | — |
| |
| | Short-Term Loan from Affiliate | | (193 | ) | | (88 | ) | | 281 |
| |
| | Other | | (1 | ) | | (5 | ) | | (4 | ) | |
| | Net Cash Provided By (Used In) Financing Activities | | (719 | ) | | (43 | ) | | (73 | ) | |
| | Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | | (1 | ) | | (10 | ) | | 21 |
| |
| | Cash, Cash Equivalents and Restricted Cash at Beginning of Period | | 22 |
| | 32 |
| | 11 |
| |
| | Cash, Cash Equivalents and Restricted Cash at End of Period | | $ | 21 |
| | $ | 22 |
| | $ | 32 |
| |
| | Supplemental Disclosure of Cash Flow Information: | | | | | | | |
| | Income Taxes Paid (Received) | | $ | (41 | ) | | $ | (92 | ) | | $ | 77 |
| |
| | Interest Paid, Net of Amounts Capitalized | | $ | 113 |
| | $ | 73 |
| | $ | 48 |
| |
| | Accrued Property, Plant and Equipment Expenditures | | $ | 164 |
| | $ | 167 |
| | $ | 293 |
| |
| | | | | | | | | |
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 |
| |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | Contributed Capital | | Basis Adjustment | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total | |
| | Balance as of January 1, 2017 | | $ | 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 |
| |
| | Net Income | | — |
| | — |
| | 365 |
| | — |
| | 365 |
| |
| | Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments
| | — |
| | — |
| | 175 |
| | (175 | ) | | — |
| |
| | Other Comprehensive Income (Loss), net of tax (expense) benefit of $(7) | | — |
| | — |
| | — |
| | 28 |
| | 28 |
| |
| | Comprehensive Income | | | | | | | | | | 393 |
| |
| | Cash Dividends Paid | | — |
| | — |
| | (400 | ) | | — |
| | (400 | ) | |
| | Balance as of December 31, 2018 | | $ | 2,214 |
| | $ | (986 | ) | | $ | 5,051 |
| | $ | (319 | ) | | $ | 5,960 |
| |
| | Net Income | | — |
| | — |
| | 468 |
| | — |
| | 468 |
| |
| | Cumulative Effect Adjustment to Reclassify Stranded Tax Effects Resulting from the Change in the Federal Corporate Income Tax Rate | | — |
| | — |
| | 69 |
| | (69 | ) | | — |
| |
| | Other Comprehensive Income (Loss), net of tax (expense) benefit of $(9) | | — |
| | — |
| | — |
| | (13 | ) | | (13 | ) | |
| | Comprehensive Income | | | | | | | | | | 455 |
| |
| | Cash Dividends Paid | | — |
| | — |
| | (525 | ) | | — |
| | (525 | ) | |
| | Balance as of December 31, 2019 | | $ | 2,214 |
| | $ | (986 | ) | | $ | 5,063 |
| | $ | (401 | ) | | $ | 5,890 |
| |
| | | | | | | | | | | | | |
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
Public Service Enterprise Group Incorporated (PSEG) is a 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 direct wholly owned 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). PSE&G also invests in solar generation projects and energy efficiency and related programs in New Jersey, which are regulated by the BPU.
PSEG Power LLC (Power)—which is a multi-regional energy supply company that integrates the operations of its merchant nuclear and fossil generating assets with its power marketing businesses and fuel supply functions through competitive energy sales in well-developed energy markets primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, Power owns and operates solar generation in various states. Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate.
| |
| • | 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). PSE&G also invests in regulated solar generation projects and energy efficiency and related programs in New Jersey, which are regulated by the BPU. |
| |
| • | PSEG Power LLC (PSEG Power)—which is a multi-regional energy supply company that integrates the operations of its merchant nuclear and fossil generating assets with its power marketing businesses and fuel supply functions through competitive energy sales in well-developed energy markets primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, PSEG 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 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 has investments in leveraged leases; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.
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).
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 4.5. 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. For investments in which significant influence does not exist and the investor is not the primary beneficiary, the cost method of accounting is applied. 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 6.7. Regulatory Assets and Liabilities.
Cash, Cash Equivalents and Restricted Cash
Cash equivalents consist of short-term, highly liquid investments with original maturities of three months or less. Restricted cash consists primarily of deposits received related to various construction projects at PSE&G.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2018 and 2019.
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | PSE&G | | PSEG Power | | Other (A) | | Consolidated | |
| | | Millions | |
| | As of December 31, 2018 | | | | | | | | |
| | Cash and Cash Equivalents | $ | 39 |
| | $ | 22 |
| | $ | 116 |
| | $ | 177 |
| |
| | Restricted Cash in Other Current Assets | 8 |
| | — |
| | — |
| | 8 |
| |
| | Restricted Cash in Other Noncurrent Assets | 14 |
| | — |
| | — |
| | 14 |
| |
| | Cash, Cash Equivalents and Restricted Cash | $ | 61 |
| | $ | 22 |
| | $ | 116 |
| | $ | 199 |
| |
| | As of December 31, 2019 | | | | | | | | |
| | Cash and Cash Equivalents | $ | 21 |
| | $ | 21 |
| | $ | 105 |
| | $ | 147 |
| |
| | Restricted Cash in Other Current Assets | 11 |
| | — |
| | — |
| | 11 |
| |
| | Restricted Cash in Other Noncurrent Assets | 18 |
| | — |
| | — |
| | 18 |
| |
| | Cash, Cash Equivalents and Restricted Cash | $ | 50 |
| | $ | 21 |
| | $ | 105 |
| | $ | 176 |
| |
| | | | | | | | | | |
| |
| (A) | Includes amounts applicable to PSEG (parent company), Energy Holdings and Services. |
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 fuels 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, 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 are 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 PSEG 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 16.18. 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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the end of the respective accounting period. The unbilled revenue is estimated each month based on usage per day, the number 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 PSEG Power’s revenues relate to bilateral contracts, which are accounted for on the accrual basis as the energy is delivered. PSEG Power’s revenue also includes changes in the value of energy derivative contracts that are not designated as NPNS. See Note 16.18. Financial Risk Management Activities for further discussion.
PJM Interconnection, L.L.C. (PJM), the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO) facilitate the dispatch of energy and energy-related products. PSEG Power generally reports electricity sales and purchases conducted with those individual ISOs 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 the individual ISOs.
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 Operations and Maintenance (O&M) Expense, respectively. See Note 4.5. 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 3. Revenues.
Depreciation and Amortization (D&A)
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:
|
| | | | | | | | | | | |
| | | | | | | | | |
| | | | 2019 | | 2018 | | 2017 | |
| | | | Avg Rate | | Avg Rate | | Avg Rate | |
| | Electric Transmission | | 2.41 | % | | 2.42 | % | | 2.41 | % | |
| | Electric Distribution | | 2.54 | % | | 2.51 | % | | 2.51 | % | |
| | Gas Distribution | | 1.85 | % | | 1.61 | % | | 1.63 | % | |
| | | | | | | | | |
|
| | | | | | | | | | | |
| | | | | | | | | |
| | | | 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 | % | |
| | | | | | | | | |
PSEG Power calculates depreciation on generation-related assets under the straight-line method based on the assets’ estimated useful lives. The estimated useful lives are:
general plant assets—3 years to 20 years
fossil production assets—30 years to 7056 years
nuclear generation assets—approximately 60 years
pumped storage facilities—76 years
| |
| • | pumped storage facilities—76 years |
solar assets—25 years to 35 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 PSEG Power. 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, 20172019, 20162018 and 20152017 were as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | 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 | % | |
| | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | AFUDC/IDC Capitalized | |
| | | | 2019 | | 2018 | | 2017 | |
| | | | Millions | | Avg Rate | | Millions | | Avg Rate | | Millions | | Avg Rate | |
| | PSE&G | | $ | 81 |
| | 7.22 | % | | $ | 70 |
| | 7.74 | % | | $ | 73 |
| | 7.42 | % | |
| | PSEG Power | | $ | 27 |
| | 4.60 | % | | $ | 67 |
| | 4.60 | % | | $ | 78 |
| | 4.60 | % | |
| | | | | | | | | | | | | | | |
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 separate return 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 deferred in prior years are being amortized over the useful lives of the related property.
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 20.22. 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 3.4. Early Plant RetirementsRetirements/Asset Dispositions for more information.
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 generation units are generally evaluated at a regional portfolio level (PJM, NYISO, ISO-NE) along with cash flows generated from the customer supply and risk management activities, inclusive of cash flows from contracts, including those that are accounted for as derivatives and meet the NPNS scope exception. In certain cases, generation assets are evaluated on an individual basis where those assets are individually contracted on a long-term basis with a third party and operations are independent of other generation assets (typically PSEG 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 plantasset subject to lease using specific assumptions tailored to each plant.asset. 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.
Accounts Receivable—Allowance for Doubtful Accounts
PSE&G’s accounts receivable are reported in the balance sheet as gross outstanding amounts adjusted for doubtful accounts. The allowance for doubtful accounts reflects PSE&G’s best estimates of losses on the accounts receivable balances. The allowance is based on accounts receivable aging, historical experience, write-off forecasts and other currently available evidence.
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
PSE&G’s and PSEG 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 PSEG Power is valued at the lower of average cost or market and includes stored natural gas, coal, fuel oil and propane used to
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
PSEG Power capitalizes costs, including those related to its jointly-owned facilities, which increase the capacity, improve or extend the life of an existing asset, represent a newly acquired or constructed asset 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. PSEG Power also capitalizes spare parts that meet specific criteria. Capitalized spares are depreciated over the remaining lives of their associated assets.
Leases
Effective January 1, 2019, PSEG and its subsidiaries adopted new accounting guidance. See Note 2. Recent Accounting Standards for additional information.
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.
PSEG 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, PSE&G and PSEG Power. 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 and PSEG Power’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 real estate assets and solar generating facilities. PSEG and subsidiaries account for the lease and non-lease components as a single lease component.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 9. Long-Term Investments and Note 10. Financing Receivables.
Available-for-Sale SecuritiesSee Note 8. Leases for detailed information on leases.
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 PSEG Power’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.
Realized gains and losses on available-for-sale securities are recorded in earnings andEffective January 1, 2018, unrealized gains and losses on suchequity security investments are recorded in Net Income instead of Other Comprehensive Income (Loss). The debt securities arecontinue to be classified as available-for-sale with the unrealized gains and losses 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 Securities11. 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 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 is 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 12.14. Pension, and Other Postretirement Benefits (OPEB) and Savings Plans for further discussion.
Basis Adjustment
PSE&G and PSEG Power have recorded a Basis Adjustment in their respective Consolidated Balance Sheets 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 million, net of tax, was recorded as a Basis Adjustment on PSE&G’s and PSEG Power’s Consolidated Balance Sheets. The $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.
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
New Standards IssuedAdopted in 2019
Leases—Accounting Standards Update (ASU) 2016-02, updated by ASUs 2018-01, 2018-10, 2018-11, 2018-20 and Adopted
Business Combinations: Clarifying the Definition of a Business2019-01
This accounting standard, was issued mainly to provide more consistency in how the definition of a business is applied to acquisitions or dispositions. 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 standard is effective for annual and interim periods beginning after December 15, 2017; however, entities were able to adopt it for transactions that closed before the effective date but had not been reported in financial statements that had been issued or made available for issuance. PSEG adopted this standard in the third quarter 2017 with the acquisition of a solar project. This standard upon adoption had no impact on PSEG’s financial statements.
Revenue from Contracts with Customers
This accounting standard clarifies the principles for recognizing revenue and removes inconsistencies in revenue recognition requirements; improves comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets; and provides improved disclosures.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The guidance provides a five-step model to be used for recognizing 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 in 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.
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 also be disclosed including PSE&G appliance service and repair and Power solar power revenues.
PSEG will elect the invoice practical expedient, where applicable, in recording its revenue. Under the practical expedient, PSEG has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of PSEG’s performance completed to date. PSEG may recognize revenue in the amount to which it has a right to invoice. As such under this practical expedient, there are no future performance obligations to disclose. Where PSEG has entered into fixed consideration contracts, it will disclose its remaining performance obligations under these agreements.
Recognition and Measurement of Financial Assets and Financial Liabilities
This accounting standard will change how entities measure equity investments that are not consolidated or accounted for under 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.
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
continue the current balance sheet classification of restricted cash or restricted cash equivalents. 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 issued 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 retrospectively for the presentation 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, 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 beginning 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 classify 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. As a result of adopting this new standard, PSE&G expects to reduce its charge to expense by approximately $55 million to $65 million in 2018.
Stock Compensation - Scope of Modification Accounting
This accounting standard provides clarity and reduces both diversity in practice and complexity when applying 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 replacesupdates, replace existing lease accounting guidance and requiresrequire 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. Aand a lessor will classify its leases as operating orleases, 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 requireleases. The standard requires 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, existingExisting guidance related to leveraged leases willdoes not change.
PSEG adopted the optional transition method on January 1, 2019. There was no cumulative effect adjustment required to be
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
recorded to Retained Earnings at adoption. The optional transition method requires disclosure under Accounting Standards Codification (ASC) 840—Leases, the previously existing lease guidance for prior periods.
PSEG elected various practical expedients allowed by the standard, is effectiveincluding the package of three practical expedients related to not reassessing existing or expired contracts and initial direct costs; and excluding evaluation of land easements that exist or expired before adoption that were not previously accounted for annualas leases.
The impact of adoption on PSEG’s Consolidated Balance Sheet was to record Operating Lease Right-of-Use Assets of $261 million and interim periods beginning after December 15, 2018Operating Lease Liabilities of $282 million. As part of that impact, PSEG reclassified deferred rent incentives and deferred rent liabilities of approximately $21 million, which were previously classified as Other Noncurrent Liabilities, to Operating Lease Right-of-Use Assets in accordance with retrospective application to previously issued financial statements for 2018this standard. PSE&G’s assets and 2017. Early application is permitted.liabilities each increased by $91 million and PSEG is currently analyzing the impactPower’s assets and liabilities each increased by $46 million. PSEG’s adoption of this standard did not have a material impact on its financial statements.the Consolidated Statements of Operations or Consolidated Statements of Cash Flows of PSEG, PSE&G and PSEG Power. See Note 8. Leases for additional information.
Derivatives and Hedging: Targeted Improvements to Accounting for Hedging ActivitiesActivities—ASU 2017-12, updated by ASU 2018-16 and 2019-04
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-financialstatements 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 performedaccounting.
PSEG adopted this standard 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.January 1, 2019. The standard requires using a modified retrospective method upon adoption. Early adoption is permitted. PSEG is currently analyzinganalyzed the impact of this standard on its consolidated financial statements. statements and determined that the standard could enable PSEG to enter into certain transactions that can be deemed hedges that previously would not have qualified. Adoption of this standard did not have a material impact on the financial statements of PSEG, PSE&G and PSEG Power.
Premium Amortization on Purchased Callable Debt SecuritiesSecurities—ASU 2017-08
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 applyPSEG adopted this standard on January 1, 2019 on a modified retrospective basis through a cumulative-effectcumulative effect adjustment directly to retained earningsRetained 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 impact2019. Adoption of this standard did not have a material impact on itsthe financial statements.statements of PSEG, PSE&G and PSEG Power.
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive IncomeIncome—ASU 2018-02
This accounting standard would affectaffects any entity that is required to apply the provisions of the Accounting Standards CodificationASC topic, “Income Statement-Reporting Comprehensive Income,” and has items of other comprehensive incomeOther Comprehensive Income for which the related tax effects are presented in other comprehensive incomeOther Comprehensive Income as required by GAAP. Specifically, this standard would allowallows entities to record a reclassification from accumulated other comprehensive incomeAccumulated Other Comprehensive Income to retained earningsRetained Earnings for stranded tax effects resulting from the newly enactedrecent decrease in the 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 applyPSEG adopted this standard retrospectivelyon January 1, 2019. The impact of adoption on PSEG’s Consolidated Balance Sheet was 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.increase Retained Earnings and Accumulated Other Comprehensive Loss by approximately $81 million. PSEG is currently analyzing thePower’s Retained Earnings and Accumulated Other Comprehensive Loss increased by approximately $69 million. 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 impactPSE&G’s Consolidated Balance Sheet was immaterial. PSEG’s adoption of this standard did not have a material impact on its financial statements.the Consolidated Statements of Operations or Consolidated Statements of Cash Flows of PSEG, PSE&G and PSEG Power.
Simplifying the Test for Goodwill Impairment—ASU 2017-04
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 thisThis standard requires application on a prospective basis and will be required to disclosedisclosure of 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 assessingearly adopted this standard in the impactfourth quarter of this guidance upon its financial statements.
2019. See Note 12. Goodwill and Other Intangibles. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
New Standards Issued But Not Yet Adopted As of December 31, 2019
Measurement of Credit Losses on Financial Instruments—ASU 2016-13, updated by ASU 2018-19, 2019-04, 2019-05, 2019-11 and 2020-02
This accounting standard provides a new model for recognizing credit losses on financial assets. 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 debt securities will 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 the allowance for credit losses by financial asset type, including 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. PSEG adopted this standard on January 1, 2020 on a modified retrospective basis through a cumulative effect charge to Retained Earnings. The impact of adoption of this standard was immaterial on the financial statements of PSEG, PSE&G and PSEG Power.
Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement—ASU 2018-13
This accounting standard modifies the disclosure requirements for fair value measurements. Certain current disclosure requirements relating to Level 3 fair value measurements, and transfers between Level 1 and Level 2 fair value measurements will be eliminated. The standard will also add certain other disclosure requirements for Level 3 fair value measurements.
The standard is effective for annual and interim periods beginning after December 15, 2019. Certain amendments in the standard will be applied prospectively for only the most recent interim or annual period presented in the initial fiscal year of adoption. All other amendments of the standard will be applied retrospectively to all periods presented upon their effective date. Early adoption is permitted.
Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract—ASU 2018-15
This accounting standard aligns the capitalization requirements for implementation costs incurred in a hosting arrangement that is a service contract with capitalization requirements for implementation costs incurred to develop or obtain internal-use software, including hosting arrangements that include an internal-use software license. The standard follows the guidance in ASC 350—Intangibles—Goodwill and Other to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The standard requires the amortization of capitalized costs to be presented in O&M Expense. In addition, the standard also adds presentation requirements for these costs in the statements of cash flows and financial position.
The standard is effective for annual and interim periods beginning after December 15, 2019. Early adoption is permitted, including adoption in any interim period. This standard can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. PSEG adopted this standard prospectively on January 1, 2020. PSEG, PSE&G and PSEG Power do not expect a material impact on their respective financial statements.
Targeted Improvements to Related Party Guidance for Variable Interest Entities (VIE)-ASU 2018-17
This accounting standard improves the VIE guidance in the area of decision-making fees. Consistent with how indirect interests held through related parties under common control are considered for determining whether a reporting entity must consolidate a VIE, indirect interests held through related parties in common control arrangements will be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests.
This standard is effective for annual and interim periods beginning after December 15, 2019. The standard is required to be applied retrospectively with a cumulative effect adjustment to Retained Earnings at the beginning of the earliest period presented. Early adoption is permitted. PSEG adopted this standard on January 1, 2020. Adoption of this standard did not have an impact on the financial statements of PSEG, PSE&G and PSEG Power.
Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans—ASU 2018-14
This accounting standard modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans, including the elimination of certain current disclosure requirements. Certain other disclosure requirements related to interest crediting rates have been added and certain clarifications were made to other disclosure requirements.
The standard is effective for fiscal years ending after December 15, 2020 and early adoption is permitted. Amendments in this standard will be applied on a retrospective basis to all periods presented.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Simplifying the Accounting for Income Taxes—ASU 2019-12
This accounting standard simplifies the accounting for income taxes, including the elimination of certain exceptions to current requirements. Certain other requirements related to franchise taxes that are partially based on income, step-up of tax basis of goodwill and allocation of consolidated taxes to legal entities have been added and certain clarifications were made to other requirements.
The standard is effective for fiscal years beginning after December 15, 2020 and early adoption is permitted. Certain amendments in this standard will be applied on a retrospective basis to all periods presented. Certain other amendments will be applied on either a retrospective basis for all periods presented or a modified retrospective basis through a cumulative effect adjustment to Retained Earnings as of the beginning of the fiscal year of adoption. All other amendments will be applied on a prospective basis. PSEG is currently analyzing the impact of this standard on its financial statements.
Clarifying the Interactions between Investments-Equity Securities, Investments-Equity Method and Joint Ventures, and Derivatives and Hedging—ASU 2020-01
This accounting standard clarifies that an entity should consider transaction prices for purposes of measuring the fair value of certain equity securities immediately before applying or upon discontinuing the equity method. This accounting standard also clarifies that when accounting for contracts entered into to purchase equity securities, an entity should not consider whether, upon the settlement of the forward contract or exercise of the purchased option, the underlying securities would be accounted for under the equity method or the fair value option.
The standard is effective for fiscal years beginning after December 15, 2020. Amendments in this standard will be applied prospectively. Under a prospective transition, PSEG will apply the amendments at the beginning of the interim period that includes the adoption date. PSEG is currently analyzing the impact of this standard on its financial statements.
Note 3. Revenues
Nature of Goods and Services
The following is a description of principal activities by reportable segment from which PSEG, PSE&G and PSEG Power generate their revenues.
PSE&G
Revenues from Contracts with Customers
Electric 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 services 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 period.
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 customer. The formula rate mechanism provides for an annual filing of an estimated revenue requirement with rates effective January 1 of each year and a true-up to that estimate based on actual revenue requirements. The true-up mechanism is an alternative revenue which is outside the scope of revenue from contracts with customers.
Other Revenues from Contracts with Customers
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.
Payment for services rendered and products transferred are typically due within 30 days of month of delivery.
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 weather normalization, green energy program true-ups and transmission formula rate true-ups, are not a material source of PSE&G revenues.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSEG Power
Revenues from Contracts with Customers
Electricity and Related Products—Wholesale and retail load contracts are executed in the different ISO regions 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. Transaction terms generally run from several months to three years. PSEG Power also sells to the ISOs 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. PSEG Power generally reports electricity sales and purchases conducted with those individual ISOs 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 the ISOs. The transactions are reported on a net basis dependent on PSEG Power’s monthly net sale or purchase position through the individual ISOs. The performance obligations with the ISOs are satisfied over time upon delivery of the capacity and revenue is recognized accordingly. In addition to capacity sold through the ISOs, 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 April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded Zero Emission Certificates (ZECs) by the BPU. These nuclear plants are expected to receive ZEC revenue for approximately three years, through May 2022 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. See Note 4. Early Plant RetirementsRetirements/Asset Dispositions for additional information.
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. The performance obligation is primarily delivery of gas which is satisfied over time. Revenue is recognized as gas is delivered. 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 under these contracts is satisfied over time upon delivery of the gas or capacity, and revenue is recognized accordingly.
Other Revenues from Contracts with Customers
PSEG Power enters into bilateral contracts to sell solar power and solar RECs from its solar facilities. Contract terms range from 15 to 30 years. The performance obligations are generally solar power and RECs which are transferred to customers upon generation. Revenue is recognized upon generation of the solar power.
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 18. Financial Risk Management Activities for further discussion. PSEG Power is also a party to solar contracts that qualify as leases and are accounted for in accordance with lease accounting guidance.
Other
Revenues from Contracts with Customers
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.
Revenues Unrelated to Contracts with Customers
Energy Holdings generates lease revenues which are recorded pursuant to lease accounting guidance.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Disaggregation of Revenues |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | PSE&G | | PSEG Power | | Other | | Eliminations | | Consolidated | |
| | | Millions | |
| | Year Ended December 31, 2019 | | | | | | | | | | |
| | Revenues from Contracts with Customers | | | | | | | | | | |
| | Electric Distribution | $ | 3,224 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 3,224 |
| |
| | Gas Distribution | 1,870 |
| | — |
| | — |
| | (15 | ) | | 1,855 |
| |
| | Transmission | 1,181 |
| | — |
| | — |
| | — |
| | 1,181 |
| |
| | Electricity and Related Product Sales | | | | | | | | | | |
| | PJM | | | | | | | | | | |
| | Third-Party Sales | — |
| | 1,785 |
| | — |
| | — |
| | 1,785 |
| |
| | Sales to Affiliates | — |
| | 536 |
| | — |
| | (536 | ) | | — |
| |
| | NY-ISO | — |
| | 143 |
| | — |
| | — |
| | 143 |
| |
| | ISO-NE | — |
| | 137 |
| | — |
| | — |
| | 137 |
| |
| | Gas Sales | | | | | | | | | | |
| | Third-Party Sales | — |
| | 92 |
| | — |
| | — |
| | 92 |
| |
| | Sales to Affiliates | — |
| | 927 |
| | — |
| | (927 | ) | | — |
| |
| | Other Revenues from Contracts with Customers (A) | 284 |
| | 46 |
| | 566 |
| | (5 | ) | | 891 |
| |
| | Total Revenues from Contracts with Customers | 6,559 |
| | 3,666 |
| | 566 |
| | (1,483 | ) | | 9,308 |
| |
| | Revenues Unrelated to Contracts with Customers (B) | 66 |
| | 719 |
| | (17 | ) | | — |
| | 768 |
| |
| | Total Operating Revenues | $ | 6,625 |
| | $ | 4,385 |
| | $ | 549 |
| | $ | (1,483 | ) | | $ | 10,076 |
| |
| | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | PSE&G | | PSEG Power | | Other | | Eliminations | | Consolidated | |
| | | Millions | |
| | Year Ended December 31, 2018 | | | | | | | | | | |
| | Revenues from Contracts with Customers | | | | | | | | | | |
| | Electric Distribution | $ | 3,131 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 3,131 |
| |
| | Gas Distribution | 1,756 |
| | — |
| | — |
| | (18 | ) | | 1,738 |
| |
| | Transmission | 1,236 |
| | — |
| | — |
| | — |
| | 1,236 |
| |
| | Electricity and Related Product Sales | | | | | | | | | | |
| | PJM | | | | | | | | | | |
| | Third-Party Sales | — |
| | 1,933 |
| | — |
| | — |
| | 1,933 |
| |
| | Sales to Affiliates | — |
| | 609 |
| | — |
| | (609 | ) | | — |
| |
| | NY-ISO | — |
| | 209 |
| | — |
| | — |
| | 209 |
| |
| | ISO-NE | — |
| | 92 |
| | — |
| | — |
| | 92 |
| |
| | Gas Sales | | | | | | | | | | |
| | Third-Party Sales | — |
| | 151 |
| | — |
| | — |
| | 151 |
| |
| | Sales to Affiliates | — |
| | 861 |
| | — |
| | (861 | ) | | — |
| |
| | Other Revenues from Contracts with Customers (A) | 275 |
| | 44 |
| | 532 |
| | (4 | ) | | 847 |
| |
| | Total Revenues from Contracts with Customers | 6,398 |
| | 3,899 |
| | 532 |
| | (1,492 | ) | | 9,337 |
| |
| | Revenues Unrelated to Contracts with Customers (B) | 73 |
| | 247 |
| | 39 |
| | — |
| | 359 |
| |
| | Total Operating Revenues | $ | 6,471 |
| | $ | 4,146 |
| | $ | 571 |
| | $ | (1,492 | ) | | $ | 9,696 |
| |
| | | | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | PSE&G | | PSEG Power | | Other | | Eliminations | | Consolidated | |
| | | Millions | |
| | Year Ended December 31, 2017 | | | | | | | | | | |
| | Revenues from Contracts with Customers | | | | | | | | | | |
| | Electric Distribution | $ | 3,088 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 3,088 |
| |
| | Gas Distribution | 1,684 |
| | — |
| | — |
| | (14 | ) | | 1,670 |
| |
| | Transmission | 1,222 |
| | — |
| | — |
| | — |
| | 1,222 |
| |
| | Electricity and Related Product Sales | | | | | | | | | | |
| | PJM | | | | | | | | | | |
| | Third-Party Sales | — |
| | 1,199 |
| | — |
| | — |
| | 1,199 |
| |
| | Sales to Affiliates | — |
| | 734 |
| | — |
| | (734 | ) | | — |
| |
| | NY-ISO | — |
| | 181 |
| | — |
| | — |
| | 181 |
| |
| | ISO-NE | — |
| | 39 |
| | — |
| | — |
| | 39 |
| |
| | Gas Sales | | | | | | | | | | |
| | Third-Party Sales | — |
| | 134 |
| | — |
| | — |
| | 134 |
| |
| | Sales to Affiliates | — |
| | 804 |
| | — |
| | (804 | ) | | — |
| |
| | Other Revenues from Contracts with Customers (A) | 265 |
| | 42 |
| | 511 |
| | (4 | ) | | 814 |
| |
| | Total Revenues from Contracts with Customers | 6,259 |
| | 3,133 |
| | 511 |
| | (1,556 | ) | | 8,347 |
| |
| | Revenues Unrelated to Contracts with Customers (B) | 65 |
| | 727 |
| | (45 | ) | | — |
| | 747 |
| |
| | Total Operating Revenues | $ | 6,324 |
| | $ | 3,860 |
| | $ | 466 |
| | $ | (1,556 | ) | | $ | 9,094 |
| |
| | | | | | | | | | | | |
| |
| (A) | Includes primarily revenues from appliance repair services at PSE&G, solar power projects and energy management and fuel service contracts with LIPA at PSEG Power, and PSEG LI’s OSA with LIPA in Other. |
| |
| (B) | Includes primarily alternative revenues at PSE&G, derivative contracts at PSEG Power, and lease contracts in Other. For the years ended December 31, 2019, 2018 and 2017, Other includes losses of $58 million, $8 million and $77 million, respectively, related to Energy Holdings’ investments in leases. For additional information, see Note 9. Long-Term Investments. |
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, 2019 and 2018. Substantially all of PSE&G’s accounts receivable result from contracts with customers that are priced at tariff rates. Allowances represented approximately 6 percent and 7 percent of accounts receivable as of December 31, 2019 and 2018, respectively.
PSEG Power
PSEG Power generally collects consideration upon satisfaction of performance obligations, and therefore, PSEG Power had no material contract balances as of December 31, 2019 and 2018.
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 Consolidated Balance Sheets. In the wholesale energy markets in which PSEG Power operates, payment for services rendered and products transferred are typically due within 30 days of month of delivery. As such, there is little credit risk associated with these receivables and PSEG Power typically records no allowances.
Other
PSEG LI does not have any material contract balances as of December 31, 2019 and 2018.
Remaining Performance Obligations under Fixed Consideration Contracts
PSEG Power and PSE&G primarily record revenues as allowed by the guidance, 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 the entity's performance completed to date, the entity may recognize revenue in the amount to which the entity has a right to invoice. PSEG has future performance obligations under contracts with fixed consideration as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSEG Power
As previously stated, capacity transactions with ISOs are reported on a net basis dependent on PSEG Power’s monthly net sale or purchase position through the individual ISOs.
Capacity Revenues from the PJM Annual Base Residual and Incremental Auctions—The Base Residual Auction is conducted annually three years in advance of the operating period. PSEG Power expects to realize the following average capacity prices resulting from the base and incremental auctions, including unit specific bilateral contracts for previously cleared capacity obligations. These numbers exclude cleared capacity associated with our ownership interests in the Keystone and Conemaugh generation plants that were sold in September 2019. For additional information see Note 4. Early Plant Retirements/Asset Dispositions.
|
| | | | | | | |
| | | | | | | |
| | Delivery Year | | $ per Megawatt (MW)-Day | | MW Cleared | |
| | June 2019 to May 2020 | | $116 | | 8,300 |
| |
| | June 2020 to May 2021 | | $179 | | 7,300 |
| |
| | June 2021 to May 2022 | | $182 | | 6,900 |
| |
| | | | | | | |
Capacity Payments from the ISO-NE Forward Capacity Market—The Forward Capacity Market (FCM) Auction is conducted annually three years in advance of the operating period. The table below includes PSEG Power’s cleared capacity in the FCM Auction for the Bridgeport Harbor Station 5 (BH5), which cleared the 2019/2020 auction at $231/MW-day for seven years, and the planned retirement of Bridgeport Harbor Station 3 (BH3) in 2021. PSEG Power expects to realize the following average capacity prices for capacity obligations to be satisfied resulting from the FCM auctions which have been completed:
|
| | | | | | | |
| | | | | | | |
| | Delivery Year | | $ per MW-Day (A) | | MW Cleared |
| |
| | June 2019 to May 2020 | | $231 | | 1,330 |
| |
| | June 2020 to May 2021 | | $195 | | 1,330 |
| |
| | June 2021 to May 2022 | | $192 | | 950 |
| |
| | June 2022 to May 2023 | | $179 | | 950 |
| |
| | June 2023 to May 2024 | | $231 | | 480 |
| |
| | June 2024 to May 2025 | | $231 | | 480 |
| |
| | June 2025 to May 2026 | | $231 | | 480 |
| |
| | | | | | | |
| |
| (A) | Capacity cleared prices for BH5 through 2026 will be escalated based upon the Handy-Whitman Index. These adjustments are not included above. |
Bilateral capacity contracts—Capacity obligations pursuant to contract terms through 2029 are anticipated to result in revenues totaling $168 million.
Other
The LIPA OSA is a 12-year services contract ending in 2025 with annual fixed and incentive components. The fixed fee for the provision of services thereunder in 2020 is $67 million and could increase each year based on the change in the Consumer Price Index (CPI).
Note 4. Early Plant Retirements/Asset Dispositions
Nuclear
In April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded ZECs by the BPU. 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 $0.004 per kilowatt-hour (KWh) used (which is equivalent to approximately $10 per megawatt hour (MWh) generated in payments to selected nuclear plants (ZEC payment)). These nuclear plants are expected to receive ZEC revenue for approximately three years, through May 2022, and will be obligated to maintain operations during that period, subject to exceptions specified in the ZEC legislation. PSEG Power has and will continue to recognize revenue monthly as the nuclear plants generate electricity and satisfy their performance obligations. The ZEC legislation requires nuclear plants to reapply for any subsequent three year periods. The ZEC payment may be adjusted by the BPU (a) at any time to offset environmental or fuel diversity payments that a selected nuclear plant may receive from another source or (b) at certain times specified in the ZEC legislation if the BPU determines that the purposes of the ZEC legislation can be achieved through a reduced charge that will nonetheless be sufficient to achieve the state’s air quality and other environmental objectives by
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
preventing the retirement of nuclear plants. The BPU’s decision awarding ZECs has been appealed by the Division of Rate Counsel. PSEG cannot predict the outcome of this matter. In the event that (i) the ZEC program is overturned or otherwise materially adversely modified through legal process, (ii) the terms and conditions of the subsequent period under the ZEC program, including the amount of ZEC payments that may be awarded, materially differ from those of the current ZEC period, or (iii) any of the Salem 1, Salem 2 and Hope Creek plants is not awarded ZEC payments by the BPU and does not otherwise experience a material financial change, PSEG Power will take all necessary steps to retire all of these plants subsequent to the initial ZEC period at or prior to a scheduled refueling outage. Alternatively, if all of the Salem 1, Salem 2 and Hope Creek plants are selected to continue to receive ZEC payments but the financial condition of the plants is materially adversely impacted by changes in commodity prices, FERC’s changes to the capacity market construct (absent sufficient capacity revenues provided under a program approved by the BPU in accordance with a FERC-authorized capacity mechanism), or, in the case of the Salem nuclear plants, decisions by the EPA and state environmental regulators regarding the implementation of Section 316(b) of the Clean Water Act and related state regulations, or other factors, PSEG Power would still take all necessary steps to retire all of these plants. The costs and accounting charges associated with any such retirement, which may include, among other things, accelerated D&A, impairment charges, potential penalties associated with the early termination of capacity obligations and fuel contracts, accelerated asset retirement costs, severance costs, environmental remediation costs and, in certain circumstances potential additional funding of the NDT Fund, would be material to both PSEG and PSEG Power.
Fossil
In October 2016,June 2017, PSEG Power determined that it would ceasecompleted its retirement of the 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 ofstations.
During the year ended 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 endsignificant shortening of their expected economic useful lives in 2017. Duringlives. In December 2018, PSEG Power completed the year ended December 31, 2017, Power recognized pre-tax charges in Energy Costssale 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. Ifretired Hudson and Mercer units. PSEG Power determines not to usetransferred all land rights and structures on the sites for alternative industrial activity,to a third-party purchaser, along with the early retirementassumption of the units at such sites would trigger obligations under certain environmental regulations, including possible remediation. The amountsliabilities for any such environmental remediation are neither currently probable nor estimable but may be material.the sites. As a result of the sale and transfer of liabilities, PSEG Power recorded a pre-tax gain in 2018 of $54 million.
AsIn September 2019, PSEG Power completed the sale of December 31, 2016, Power had reduced the estimated useful life of Bridgeport Harbor Station unit 3 (BH3) from 2025 to the summer of 2021 as it was more likely than not it will retire the unit by this time.
PSEG and Power continue to monitor their other coal assets, includingits ownership interests in the Keystone and Conemaugh generating stations, to assess their economic viability through the endgeneration plants and related assets and liabilities. PSEG Power recorded a pre-tax loss on disposition 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 assetsapproximately $400 million in the future. These generating stations may be impactedsecond quarter of 2019 as the sale price was less than book value.
On February 23, 2020, PSEG Fossil LLC (Fossil), a direct wholly owned subsidiary of PSEG Power, entered into a Purchase Agreement with Yards Creek Energy, LLC (Yards Creek Energy), an affiliate of LS Power, relating to the sale 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 changeFossil of its ownership interests in the heldYards Creek generation facility and related assets, including the assumption by Yards Creek Energy of related liabilities. The transaction is targeted to close during the second half of 2020, subject to customary closing conditions and regulatory approvals. As a result, in the fourth quarter of 2019, $28 million of Property, Plant and Equipment was reclassified as Assets Held for use classification of our remaining coal units may have a material adverse impactSale on PSEG’s and PSEG 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-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. 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.Consolidated Balance Sheets.
Note 4.5. 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 reimbursable 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 reimbursement 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, 20162019, 2018 and 2015,2017, Servco recorded $438$490 million, $458 million $410 million
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
and $375$438 million, respectively, of O&M costs, the full reimbursement of 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 5.6. Property, Plant and Equipment and Jointly-Owned Facilities
Information related to Property, Plant and Equipment as of December 31, 20172019 and 20162018 is detailed below:
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | 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 | | PSEG Power | | Other | | PSEG Consolidated | |
| | | Millions | |
| | 2019 | | | | | | | | |
| | Transmission and Distribution: | | | | | | | | |
| | Electric Transmission | $ | 12,908 |
| | $ | — |
| | $ | — |
| | $ | 12,908 |
| |
| | Electric Distribution | 9,255 |
| | — |
| | — |
| | 9,255 |
| |
| | Gas Distribution and Transmission | 8,430 |
| | — |
| | — |
| | 8,430 |
| |
| | Construction Work in Progress | 1,607 |
| | — |
| | — |
| | 1,607 |
| |
| | Other | 639 |
| | — |
| | — |
| | 639 |
| |
| | Total Transmission and Distribution | 32,839 |
| | — |
| | — |
| | 32,839 |
| |
| | Generation: | | | | | | | | |
| | Fossil Production | — |
| | 6,570 |
| | — |
| | 6,570 |
| |
| | Nuclear Production | — |
| | 3,087 |
| | — |
| | 3,087 |
| |
| | Nuclear Fuel in Service | — |
| | 761 |
| | — |
| | 761 |
| |
| | Other Production-Solar | 663 |
| | 911 |
| | — |
| | 1,574 |
| |
| | Construction Work in Progress | — |
| | 277 |
| | — |
| | 277 |
| |
| | Total Generation | 663 |
| | 11,606 |
| | — |
| | 12,269 |
| |
| | Other | 398 |
| | 93 |
| | 345 |
| | 836 |
| |
| | Total | $ | 33,900 |
| | $ | 11,699 |
| | $ | 345 |
| | $ | 45,944 |
| |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | PSE&G | | PSEG Power | | Other | | PSEG Consolidated | |
| | | Millions | |
| | 2018 | | | | | | | | |
| | Transmission and Distribution: | | | | | | | | |
| | Electric Transmission | $ | 11,991 |
| | $ | — |
| | $ | — |
| | $ | 11,991 |
| |
| | Electric Distribution | 8,989 |
| | — |
| | — |
| | 8,989 |
| |
| | Gas Distribution and Transmission | 7,854 |
| | — |
| | — |
| | 7,854 |
| |
| | Construction Work in Progress | 1,170 |
| | — |
| | — |
| | 1,170 |
| |
| | Other | 624 |
| | — |
| | — |
| | 624 |
| |
| | Total Transmission and Distribution | 30,628 |
| | — |
| | — |
| | 30,628 |
| |
| | Generation: | | | | | | | | |
| | Fossil Production | — |
| | 6,541 |
| | — |
| | 6,541 |
| |
| | Nuclear Production | — |
| | 2,971 |
| | — |
| | 2,971 |
| |
| | Nuclear Fuel in Service | — |
| | 765 |
| | — |
| | 765 |
| |
| | Other Production-Solar | 623 |
| | 833 |
| | — |
| | 1,456 |
| |
| | Construction Work in Progress | — |
| | 1,011 |
| | — |
| | 1,011 |
| |
| | Total Generation | 623 |
| | 12,121 |
| | — |
| | 12,744 |
| |
| | Other | 382 |
| | 103 |
| | 344 |
| | 829 |
| |
| | Total | $ | 31,633 |
| | $ | 12,224 |
| | $ | 344 |
| | $ | 44,201 |
| |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | 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 |
| |
| | | | | | | | | | | |
As part of its solar production portfolio, PSEG Power owns and operates two California-based solar facilities with an aggregate capacity of approximately 30 MW direct current whose output is sold to Pacific Gas and Electric Company (PG&E) under power purchase agreements (PPAs) with twenty year terms. The net book value of these solar facilities was approximately $55 million as of December 31, 2019. In January 2019, PG&E and its parent company PG&E Corporation filed for Chapter 11 bankruptcy protection. PSEG Power cannot predict the ultimate outcome that this bankruptcy proceeding will have on its ability to collect all of the future revenues from these facilities due under the PPAs; however, any adverse changes to the terms of
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSEG Power’s PPAs as a result of this bankruptcy proceeding could result in the future impairment of these assets in amounts up to their current net book value.
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, | |
| | | | | | 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 |
| | $ | — |
| |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | As of December 31, | |
| | | | | | 2019 | | 2018 | |
| | | | Ownership | | | | Accumulated | | | | Accumulated | |
| | | | Interest | | Plant | | Depreciation | | Plant | | Depreciation | |
| | | | | | Millions | |
| | PSE&G: | | | | | | | | | | | |
| | Transmission Facilities | | Various |
| | $ | 161 |
| | $ | 60 |
| | $ | 162 |
| | $ | 58 |
| |
| | PSEG Power: | | | | | | | | | | | |
| | Coal Generating (A): | | | | | | | | | | | |
| | Conemaugh | | 23 | % | | N/A |
| | N/A |
| | $ | 417 |
| | $ | 192 |
| |
| | Keystone | | 23 | % | | N/A |
| | N/A |
| | $ | 416 |
| | $ | 200 |
| |
| | Nuclear Generating: | | | | | | | | | | | |
| | Peach Bottom | | 50 | % | | $ | 1,340 |
| | $ | 435 |
| | $ | 1,334 |
| | $ | 389 |
| |
| | Salem | | 57 | % | | $ | 1,256 |
| | $ | 384 |
| | $ | 1,196 |
| | $ | 333 |
| |
| | Nuclear Support Facilities | | Various |
| | $ | 247 |
| | $ | 107 |
| | $ | 244 |
| | $ | 95 |
| |
| | Pumped Storage Facilities: | | | | | | | | | | | |
| | Yards Creek (B) | | 50 | % | | $ | 55 |
| | $ | 27 |
| | $ | 48 |
| | $ | 26 |
| |
| | Merrill Creek Reservoir | | 14 | % | | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | — |
| |
| | | | | | | | | | | | | |
| |
| (A) | In September 2019, PSEG Power completed the sale of its ownership interests in the Keystone and Conemaugh generation plants and related assets and liabilities. |
| |
| (B) | On February 23, 2020, a Purchase Agreement was entered into to sell ownership interests in this generation facility. See Note 4. Early Plant Retirements/Asset Dispositions for additional information. |
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. PSEG Power is the operator of Salem and Exelon Generation 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 of the normal Power governance process.
PSEG 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 PSEG Power’s approval as part of the normal PSEG Power governance process.
PSEG 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 PSEG Power’s approval as part of the normal PSEG Power governance process.
Note 6.7. 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, 20172019 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, | |
| | | | 2019 | | 2018 | |
| | | | Millions | |
| | Regulatory Assets | | | | | |
| | Current | | | | | |
| | New Jersey Clean Energy Program | | $ | 143 |
| | $ | 143 |
| |
| | Electric Energy Costs—Basic Generation Service (BGS) | | 57 |
| | 115 |
| |
| | 2018 Distribution Base Rate Case Regulatory Assets (BRC) | | 56 |
| | 56 |
| |
| | Societal Benefits Charge (SBC) | | 30 |
| | 9 |
| |
| | Green Program Recovery Charges (GPRC) | | 10 |
| | 34 |
| |
| | Other | | 55 |
| | 32 |
| |
| | Total Current Regulatory Assets | | $ | 351 |
| | $ | 389 |
| |
| | Noncurrent | | | | | |
| | Pension and OPEB Costs | | $ | 1,284 |
| | $ | 1,090 |
| |
| | Deferred Income Tax Regulatory Assets | | 966 |
| | 896 |
| |
| | Manufactured Gas Plant (MGP) Remediation Costs | | 357 |
| | 321 |
| |
| | Electric Transmission and Gas Cost of Removal | | 216 |
| | 223 |
| |
| | Asset Retirement Obligation | | 172 |
| | 166 |
| |
| | BRC | | 159 |
| | 214 |
| |
| | Remediation Adjustment Charge (RAC) (Other SBC) | | 158 |
| | 175 |
| |
| | GPRC | | 118 |
| | 95 |
| |
| | Unamortized Loss on Reacquired Debt and Debt Expense | | 42 |
| | 49 |
| |
| | Gas Costs—BGSS | | 27 |
| | 31 |
| |
| | Other | | 178 |
| | 139 |
| |
| | Total Noncurrent Regulatory Assets | | $ | 3,677 |
| | $ | 3,399 |
| |
| | Total Regulatory Assets | | $ | 4,028 |
| | $ | 3,788 |
| |
| | | | | | | |
|
| | | | | | | | | | |
| | | | | | | |
| | | | 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, | |
| | | | 2019 | | 2018 | |
| | | | Millions | |
| | Regulatory Liabilities | | | | | |
| | Current | | | | | |
| | Deferred Income Tax Regulatory Liabilities | | $ | 193 |
| | $ | 299 |
| |
| | Weather Normalization Charge (WNC) | | 15 |
| | — |
| |
| | Tax Adjustment Credit (TAC) | | 12 |
| | 4 |
| |
| | Gas Margin Adjustment Clause | | 5 |
| | 8 |
| |
| | Other | | 9 |
| | — |
| |
| | Total Current Regulatory Liabilities | | $ | 234 |
| | $ | 311 |
| |
| | Noncurrent | | | | | |
| | Deferred Income Tax Regulatory Liabilities | | $ | 2,955 |
| | $ | 3,170 |
| |
| | Electric Distribution Cost of Removal | | 47 |
| | 51 |
| |
| | Total Noncurrent Regulatory Liabilities | | $ | 3,002 |
| | $ | 3,221 |
| |
| | Total Regulatory Liabilities | | $ | 3,236 |
| | $ | 3,532 |
| |
| | | | | | | |
|
| | | | | | | | | | |
| | | | | | | |
| | | | 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
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: These costs represent the differences between rate 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: These amounts represent the portion of deferred income taxes that will be recovered or refunded through future rates, based upon established regulatory practices. In December 2017, new tax legislation was enacted (Tax Act) 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 Financial Accounting Standards Board (FASB) Accounting Standards Codification 740, Income Taxes (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 reduction in tax rate is the primary reason for the decrease in the Regulatory Asset.
Electric and Gas Cost of Removal: PSE&G accrues and collects in rates for the cost of removing, dismantling and disposing of its transmission and distribution assets upon retirement. The regulatory asset or liability for non-legally required cost of removal represents the difference between amounts collected in rates and costs actually incurred.
Electric Energy Costs—Basic Generation Service: These costs represent the over or under recovered amounts associated with Basic Generation Services (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 PSE&G’s existing $2.1 billion Accumulated Deferred Income Tax liabilities that are in excess 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% effective January 1, 2018. The excess deferred income taxes are primarily related 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.
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: These costs represent the over or under recovered amounts associated with Basic Gas Supply Service (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 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 annually with the BPU for recovery of amounts that include a return on and of its investment over the lives of the underlying investments and capital assets which range from 5 to 10 years. Interest is accrued monthly on any over or under recovered balances. Components of the GPRC 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), Solar 4 All Extension, Solar 4 All Extension II, Solar Loan II Program, Solar Loan III Program and the Energy Efficiency 2017 Program.
MGP Remediation Costs: Represents the low end of the range for the remaining environmental investigation and remediation program cleanup costs for manufactured gas plants 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
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| • | Asset Retirement Obligation: These costs represent the differences between rate-regulated cost of removal accounting and asset retirement accounting under GAAP. These costs will be recovered in future rates as assets are retired. |
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| • | 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. |
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| • | 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, investment tax credits and other flow-through items, including the flowback to customers of accumulated deferred income taxes related to tax repair deductions. As part of its 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, 2019 and 2018, PSE&G had provided $58 million and $15 million, respectively, in current tax repair flowbacks to customers. The recovery and amortization of the tax repair-related Deferred Income Tax Regulatory Assets will be determined in PSE&G’s subsequent base rate cases. |
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| • | Deferred Income Tax Regulatory Liabilities: These liabilities relate to amounts due to customers for excess deferred income taxes as a result of the reduction in the federal income tax provided in the Tax Cuts and Jobs Act of 2017 (the Tax Act), and accumulated deferred income taxes from previously realized tax repair deductions as described above. As part of its settlement with its regulators, PSE&G agreed to refund the excess deferred income taxes as follows: |
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| • | $705 million of distribution-related excess deferred income taxes refunded to customers over five years through PSE&G’s TAC mechanism with the remaining $1.1 billion of distribution-related excess deferred income taxes refunded to customers over the remaining useful life of distribution property, plant and equipment. As of December 31, 2019 and 2018, the balance remaining to be flowed back to customers was $1.6 billion and $1.8 billion, respectively. |
$150 million of transmission-related excess deferred income taxes refunded to customers during the year ended December 31, 2019 with the remaining $977 million of transmission-related excess deferred income taxes returned over the remaining useful life of the property, plant and equipment.
MTM Contracts: The estimated fair valueIn addition, PSE&G agreed to flow back to customers $581 million of gas hedge contracts and gas cogeneration supply contract. The regulatory asset/liability is offset bypreviously realized tax repair deductions over 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 Efficiency and Renewable Energy Programsten-year period through the first half of 2018. 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 recorded the unrecognized costs for defined benefit pension and other OPEB plans on the balance sheet as a Regulatory Asset. These costs represent actuarial gains or losses, 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 plants 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); (2) Energy Efficiency and Renewable Energy 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.TAC mechanism. As of December 31, 2017, this includes2019 and 2018, 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 thebalance remaining life of the debt.
WNC: This represents the over or under recovery of 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 recoveries are returnedbe flowed back to customers in the next winter season while under recoveries (subject to an earnings cap) are recovered from customers in the next winter season.was $537 million and $575 million, respectively.
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| • | Electric and Gas Cost of Removal: PSE&G accrues and collects in rates for the cost of removing, dismantling and disposing of its T&D assets upon retirement. The Regulatory Asset or Liability for non-legally required cost of removal represents the difference between amounts collected in rates and costs actually incurred. |
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| • | Electric Energy Costs—BGS: These costs represent the over or under recovered amounts associated with 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. |
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| • | Gas Costs—BGSS: These costs represent the over or under recovered amounts associated with 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. |
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| • | 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 annual filing. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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| • | GPRC: This amount represents costs of the over or under collected balances associated with various renewable energy and energy efficiency programs. PSE&G files annually with the BPU for recovery of amounts that include a return on and of its investment over the lives of the underlying investments and capital assets which range from five to ten years. Interest is accrued monthly on any over or under recovered balances. Components of the GPRC 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®), Solar 4 All® Extension, Solar 4 All® Extension II, Solar Loan II Program, Solar Loan III Program and the Energy Efficiency (EE) 2017 Program. |
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| • | MGP Remediation Costs: Represents the low end of the range for the remaining environmental investigation and remediation program cleanup costs for MGPs 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. |
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| • | New Jersey Clean Energy Program: The BPU approved future funding requirements for Energy Efficiency and Renewable Energy Programs through the first half of 2020. The BPU funding requirements are recovered through the SBC. |
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| • | Pension and OPEB Costs: Pursuant to the adoption of accounting guidance for employers’ defined benefit pension and OPEB plans, PSE&G recorded the unrecognized costs for defined benefit pension and other OPEB plans on the balance sheet as a Regulatory Asset. These costs represent actuarial gains or losses and prior service costs which have not been expensed. These costs are amortized and recovered in future rates. |
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| • | RAC (Other SBC): Costs incurred to clean up MGPs which are recovered over seven years with interest through an annual filing. |
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| • | 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; (2) Energy Efficiency and Renewable Energy 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. |
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| • | TAC: This represents the over or under collected 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 Base Rate Case Settlement. Over or under collected balances are returned or recovered through an annual filing. PSE&G includes a return component on the flowback of the excess accumulated deferred income taxes and the previously realized tax repairs. Interest is accrued monthly on any over or under recovered balances. |
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| • | 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. |
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| • | WNC: This represents the over or under recovery of gas margin which is filed annually with the BPU. 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 recoveries are returned to customers in the next winter season while under recoveries (subject to an earnings cap) are recovered from customers in the next winter season. |
Significant 20172018 and 2019 regulatory orders received and currently pending rate filings with FERC and the BPU by PSE&G are as follows:
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| • | Electric and Gas Distribution Base Rate Filings—In October 2018, the BPU issued an Order approving the settlement of PSE&G’s distribution base rate proceeding with new rates effective November 1, 2018. The settlement resulted in a net reduction in overall annual revenues of approximately $13 million, comprised of a $212 million increase in base revenues, including recovery of deferred storm costs, offset by the return of tax benefits of approximately $225 million. The tax benefits include the flowback to customers of excess accumulated deferred income taxes resulting from the reduction of the federal income tax rates provided in the Tax Act as well as the accumulated deferred income taxes from previously realized tax repair deductions and tax benefits from future tax repair deductions as realized. The Order provided for a $9.5 billion rate base, a 9.6% return on equity for PSE&G’s distribution business and a 54% equity component of its capitalization structure. In addition to the $13 million annual revenue reduction, the Order provided for a $28 million one-time refund to customers in November and December 2018 for taxes collected at the higher federal income tax rate for the January 1 to March 31, 2018 period. Previously, |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the BPU in 2014. The filing requests an approximate one percent increase in revenues and seekshad approved a rate reduction effective April 1, 2018, to recover investments made to strengthenPSE&G’s then-current electric and gas distribution systems. In its filing, PSE&G requested that thesebase rates take into account a reduction inof approximately $71 million and $43 million, respectively, on an annual basis, to reflect the revenue requirement aslower federal income tax rate for the period April 1 and forward. As a result of the federal corporateagreement to flow back tax repair-related accumulated deferred income tax rate reduction from 35% to 21% providedtaxes in the Tax Act, includingsettlement, PSE&G recognized a one-time credit for estimated excess income taxes collected between January 1, 2018Regulatory Liability and the time new rates go into effect, and the flow back to customers of certain additional tax benefits. PSE&G anticipates the new base rates will go into effect in the fourth quarter of 2018.
Separately, in January 2018, the BPU issued an order commencing a proceeding to ensure that the rate revenue resulting from expenses relating to taxes reflected in rates but no longer owed as the result of the Tax Act shall be passed onto the ratepayers. The BPU directed New Jersey utilities (including PSE&G) to make filings by March 2, 2018 setting forth interim rates to be effective April 1, 2018 reflecting the new federal corporate tax rate, and to subsequently file proposed final rates, effective July 1, 2018, incorporating all other effects of the Tax Act. This proceeding is currently pending.corresponding Regulatory Asset.
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| • | Transmission Formula Rate Filings—In October 2019, PSE&G filed its 2020 Transmission Formula Rate Annual Update with FERC requesting approximately $332 million in increased annual transmission revenue effective January 1, 2020, subject to true-up. |
Transmission Formula Rate Filings—In June 2017,2019, PSE&G filed its 20162018 true-up adjustment pertaining to its transmission formula rates in effect for 2016.2018. This filing resulted in an additional revenue requirement adjustment of $12$52 million more than the 20162018 originally filed revenues.
Forrevenue requirement. PSE&G had previously recognized the year ended December 31, 2017, PSE&G recorded an estimated true-up adjustmentmajority of $16 million to its 2017 Annual Formula rate. That true-up will be filed by no later than June 15, 2018.
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 annualadditional revenue requirement to reflect the federal corporate income tax rate reduction from 35% to 21%, effective January 1,in its 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.Consolidated Statement of Operations.
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| • | BGSS—In September 2019, the BPU provisionally approved PSE&G’s request to decrease its BGSS rates from approximately 35 cents to 34 cents per therm for residential gas customers effective October 1, 2019. In December 2019, a self-implementing reduction of 2 cents per therm was filed with the BPU to further reduce the BGSS rate to approximately 32 cents per therm effective January 1, 2020, which was given final approval by the BPU in February 2020. The final reduction in the BGSS rate to 32 cents per therm will decrease annual BGSS revenues by approximately $34 million. In addition, PSE&G issued a self-implementing one-time bill credit of 7.5 cents per therm to be returned during the months of February and March 2020. |
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| • | Gas System Modernization Program II (GSMP II)—In November 2019, the BPU approved PSE&G’s first GSMP II cost recovery petition requesting approximately $17 million in gas revenues on an annual basis, which included GSMP II investments in service as of August 31, 2019. The increase was effective December 1, 2019. |
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,December 2019, PSE&G filed its Energy Strong electricsecond GSMP II cost recovery petition seeking BPU approval to recover thein gas base rates an estimated annual revenue requirements associated with Energy Strong capitalized investment costs placed in service fromincrease of $18 million effective June 1, 2017 through November 30, 2017. The filing was updated in December 2017 requesting an annual2020. This increase in electric revenues of $8 million. This matter is pending.
Gas System Modernization Program (GSMP)—In July of each year, PSE&G files withrepresents the BPU for base rate recovery of GSMP investments which include a return of and on its investment.investment for GSMP II investments expected to be in service through February 29, 2020. The request will be updated in March 2020 for actual costs.
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| • | Gas System Modernization Program I (GSMP I)—In September 2019, the BPU approved PSE&G’s final GSMP I cost recovery petition requesting approximately $11 million in gas revenues, on an annual basis, which included GSMP I investments in service as of June 30, 2019. The increase was effective October 1, 2019. |
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| • | GPRC—In February 2020, the BPU approved a six-month extension of PSE&G’s Energy Efficiency (EE) 2017 component of its GPRC programs, authorizing $111 million of EE investments and $19 million of administrative costs for recovery over the course of the programs though its existing filing mechanism. In September 2019, the BPU approved a one year extension of PSE&G’s EE 2017 component of its GPRC programs, authorizing an additional $27 million of EE investments and $6 million of additional administrative costs for recovery though its existing filing mechanism. |
In December 2017,January 2020, 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 20162019 GPRC cost recovery petition to recover approximately$37requesting recovery of approximately $52 million and $13$11 million in electric and gas revenues, respectively, on an annual basis associated withbasis. This increase was effective February 1, 2020.
In May 2019, the BPU approved 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 20172018 GPRC cost recovery petition requesting recovery of approximately $47$65 million and $13$6 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.basis.
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| • | RAC—In January 2020, PSE&G filed its RAC 27 petition with the BPU seeking recovery of $53 million of net MGP remediation expenditures from August 1, 2018 through July 31, 2019. This matter is pending. |
In August 2017,2019, 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 deploymentRAC 26 filing requesting recovery 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 $54approximately $73 million in net deficiency gas revenues as a result of the warmer than normal 2015-2016 Winter Period.MGP remediation expenditures from August 1, 2017 through July 31, 2018.
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| • | SBC—In January 2020, the BPU approved PSE&G’s petition to increase electric and gas rates by approximately $27 million and $7 million, respectively, on an annual basis, in order to recover electric and gas costs incurred through October 31, 2019 under its EE and Renewable Energy and Social Programs. The new rates were effective February 1, 2020. |
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| • | TAC—In January 2020, the BPU approved PSE&G’s initial TAC filing on a provisional basis allowing a reduction to electric and gas revenues by $15 million and $10 million, respectively, on an annual basis effective February 1, 2020. The TAC was a result of the settlement of PSE&G’s distribution base rate case in 2018. The TAC allows for the flowback to customers of excess accumulated deferred income taxes resulting from the reduction of the federal income |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
tax rates provided in the Tax Act as well as the accumulated deferred income taxes from previously realized tax repair deductions and tax benefits from future tax repair deductions as realized.
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| • | WNC—In February 2020, the BPU gave final approval to PSE&G’s 2019-2020 WNC rates allowing an approximate $8 million of overcollections from the colder-than-normal 2018-2019 Winter Period, to be refunded to customers over the 2019-2020 Winter Period, with rates effective October 1, 2019. |
In September 2017,March 2019, the BPU approved onthe final 2018-2019 WNC rates which allowed a provisional basis, PSE&G’s petitionnet recovery of $14 million to collect $31be collected over the 2018-2019 Winter Period. The $14 million in net deficiency gas revenues as arecovery was the result of the warmer than normal 2016-2017 Winter Period and a remaining carryover balance$9 million of $24 million in net deficiency gasexcess revenues from the 2015-2016colder-than-normal 2017-2018 Winter Period offset by $23 million of remaining prior Winter Period undercollection.
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| • | ZEC Program—In April 2019, the BPU authorized the New Jersey EDCs, including PSE&G, to purchase ZECs from eligible nuclear plants selected by the BPU. In conjunction with this Order, the BPU authorized tariffs to collect a non-bypassable distribution charge in the amount of $0.004 per KWh from each EDC’s retail distribution customers to be used to purchase ZECs from the selected plants. Each EDC purchases ZECs on a monthly basis with payment to be made annually following completion of each energy year. Under the program, any revenue collected in excess of the purchase price will be refunded to customers in the following year. |
For the energy year ended May 31, 2019, PSE&G purchased approximately $17 million in ZECs, including interest, from the eligible nuclear plants selected by the BPU. The payment for $17 million was made in August 2019. In addition, there was approximately $0.2 million, including interest, in overcollected revenues which will be refunded to customers pending BPU approval of the refunding mechanism.
Note 8. Leases
As of December 31, 2019, PSEG and its subsidiaries were both a lessee and a lessor in operating leases.
Lessee
PSE&G
PSE&G has 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 2039, some of which include options to extend the leases for up to 2five-year terms. Some leases have fixed rent payments that have escalations based on certain indices, such as the CPI. Certain leases contain variable payments.
PSEG Power
PSEG Power has operating leases for buildings, land leases for its solar generating facilities, merchant transmission and equipment. These leases have remaining terms through 2055, some of which include options to extend the leases for up to 7 five-year terms and certain other leases which include options to extend the leases for 15 to 20 year terms. Some leases have fixed rent payments that have escalations based on certain indices, such as the CPI. Certain leases contain variable payments.
Other
Services has operating leases for real estate and office equipment. These leases have remaining terms through 2030. Services’ lease for its headquarters, which ends in 2030, includes options to extend for 2 five-year terms. Energy Holdings has land leases with remaining lease terms through 2027, some of which include options to extend the leases for up to 8 five-year terms. Some leases have fixed rent payments that have escalations based on certain indices, such as the CPI. Certain leases contain variable payments.
Operating Lease Costs
The following amounts relate to total operating lease costs, including both amounts recognized in the Consolidated Statements of Operations during the year ended December 31, 2019 and any amounts capitalized as part of the cost of another asset, and the cash flows arising from lease transactions.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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| | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | PSE&G | | PSEG Power | | Other | | Total | |
| | | Millions | |
| | Operating Lease Costs | | | | | | | | |
| | Year Ended December 31, 2019 | | | | | | | | |
| | Long-term Lease Costs | $ | 24 |
| | $ | 13 |
| | $ | 15 |
| | $ | 52 |
| |
| | Short-term Lease Costs | 14 |
| | 10 |
| | — |
| | 24 |
| |
| | Variable Lease Costs | 2 |
| | 10 |
| | 10 |
| | 22 |
| |
| | Total Operating Lease Costs | $ | 40 |
| | $ | 33 |
| | $ | 25 |
| | $ | 98 |
| |
| | | | | | | | | | |
| | Year Ended December 31, 2019 | | | | | | | | |
| | Cash Paid for Amounts Included in the Measurement of Operating Lease Liabilities | $ | 16 |
| | $ | 11 |
| | $ | 15 |
| | $ | 42 |
| |
| | | | | | | | | | |
| | Weighted Average Remaining Lease Term in Years | 13 |
| | 14 |
| | 10 |
| | 12 |
| |
| | Weighted Average Discount Rate | 3.6 | % | | 4.4 | % | | 4.2 | % | | 4.1 | % | |
| | | | | | | | | | |
Operating lease commitments as of December 31, 2018 had the following maturities:
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | PSE&G | | PSEG Power | | Other | | Total | |
| | | | Millions | |
| | 2019 | | $ | 15 |
| | $ | 11 |
| | $ | 15 |
| | $ | 41 |
| |
| | 2020 | | 11 |
| | 13 |
| | 16 |
| | 40 |
| |
| | 2021 | | 10 |
| | 13 |
| | 16 |
| | 39 |
| |
| | 2022 | | 8 |
| | 14 |
| | 16 |
| | 38 |
| |
| | 2023 | | 8 |
| | 8 |
| | 15 |
| | 31 |
| |
| | Thereafter | | 66 |
| | 51 |
| | 105 |
| | 222 |
| |
| | Total Minimum Lease Payments | | $ | 118 |
| | $ | 110 |
| | $ | 183 |
| | $ | 411 |
| |
| | | | | | | | | | | |
Operating lease liabilities as of December 31, 2019 had the following maturities:
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | PSE&G | | PSEG Power | | Other | | Total | |
| | | | Millions | |
| | 2020 | | $ | 15 |
| | $ | 13 |
| | $ | 16 |
| | $ | 44 |
| |
| | 2021 | | 13 |
| | 14 |
| | 16 |
| | 43 |
| |
| | 2022 | | 10 |
| | 14 |
| | 16 |
| | 40 |
| |
| | 2023 | | 9 |
| | 8 |
| | 15 |
| | 32 |
| |
| | 2024 | | 8 |
| | 3 |
| | 15 |
| | 26 |
| |
| | Thereafter | | 71 |
| | 48 |
| | 90 |
| | 209 |
| |
| | Total Minimum Lease Payments | | $ | 126 |
| | $ | 100 |
| | $ | 168 |
| | $ | 394 |
| |
| | | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following is a reconciliation of the undiscounted cash flows to the discounted Operating Lease Liabilities recognized on the Consolidated Balance Sheets:
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | As of December 31, 2019 | |
| | | | PSE&G | | PSEG Power | | Other | | Total | |
| | | | Millions | |
| | Undiscounted Cash Flows | | $ | 126 |
| | $ | 100 |
| | $ | 168 |
| | $ | 394 |
| |
| | Reconciling Amount due to Discount Rate | | (27 | ) | | (28 | ) | | (33 | ) | | (88 | ) | |
| | Total Discounted Operating Lease Liabilities | | $ | 99 |
| | $ | 72 |
| | $ | 135 |
| | $ | 306 |
| �� |
| | | | | | | | | | | |
As of December 31, 2019, the current portions of Operating Lease Liabilities included in Other Current Liabilities were $33 million, $12 million and $10 million for PSEG, PSE&G and PSEG Power, respectively.
Lessor
PSEG Power
Certain of PSEG Power’s sales agreements related to its solar generating plants qualify as operating leases with remaining terms through 2043 with no extension terms. Lease income is based on solar energy generation; therefore, all rental income is variable under these leases. As of December 31, 2019, PSEG Power’s solar generating plants subject to these leases had a total recoverycarrying value of $55$393 million.
Other
Energy Holdings is the lessor in leveraged leases. See Note 9. Long-Term Investments and Note 10. Financing Receivables.
Energy Holdings is the lessor in various operating leases for domestic energy and real estate assets with remaining terms through 2036. As of December 31, 2019, Energy Holdings’ property subject to these leases had a total carrying value of $22 million in net deficiency revenues. .
The deficiency will be collected from customers overfollowing is the 2017-2018operating lease income for PSEG Power and 2018-2019 Winter Periods (October 1 through May 31). Final approval in this matter is pending.Energy Holdings for the year ended December 31, 2019:
Remediation Adjustment Charge (RAC)—In June 2017, |
| | | | | | | | | | | | | |
| | | | | | | | |
| | | PSEG Power | | Energy Holdings | | Total | |
| | | Millions | |
| | Operating Lease Income | | | | | | |
| | Year Ended December 31, 2019 | | | | | | |
| | Fixed Lease Income | $ | — |
| | $ | 22 |
| | $ | 22 |
| |
| | Variable Lease Income | 23 |
| | — |
| | 23 |
| |
| | Total Operating Lease Income | $ | 23 |
| | $ | 22 |
| | $ | 45 |
| |
| | | | | | | | |
Energy Holdings’ operating leases had the BPU approved PSE&G’s filing with respect to its RAC 24 petition allowing recoveryfollowing 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 recovery of $63 million of net Manufactured Gas Plant expenditures from August 1, 2016 through July 31, 2017. This matter is pending.
2019: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. |
| | | | | | | |
| | | | | | |
| | | | Millions | |
| | 2020 | | $ | 20 |
| | |
| | 2021 | | 18 |
| | |
| | 2022 | | 17 |
| | |
| | 2023 | | 17 |
| | |
| | 2024 | | 16 |
| | |
| | Thereafter | | 172 |
| | |
| | Total Minimum Future Lease Receipts | | $ | 260 |
| | |
| | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 7.9. Long-Term Investments
Long-Term Investments as of December 31, 20172019 and 20162018 included the following:
|
| | | | | | | | | | |
| | | | | | | |
| | | | 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 |
| |
| | | | | | | |
|
| | | | | | | | | | |
| | | | | | | |
| | | | As of December 31, | |
| | | | 2019 | | 2018 | |
| | | | Millions | |
| | PSE&G | | | | | |
| | Life Insurance and Supplemental Benefits | | $ | 111 |
| | $ | 121 |
| |
| | Solar Loans | | 137 |
| | 149 |
| |
| | PSEG Power | | | |
| | Equity Method Investments (A) | | 66 |
| | 86 |
| |
| | Energy Holdings | | | | | |
| | Lease Investments | | 497 |
| | 540 |
| |
| | Equity Method Investments | | 1 |
| | — |
| |
| | Total Long-Term Investments | | $ | 812 |
| | $ | 896 |
| |
| | | | | | | |
| |
| (A) | During the three years ended December 31, 2017, 20162019, 2018 and 20152017, dividends from these investments were $15 million, $16 million and $18 million, $18 million and $16 million, respectively. |
Leases
Energy Holdings, through several of its indirect subsidiary companies, 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 thirdsecond quarter of 2016,2019, Energy Holdings completed its annual review of estimated residual values embedded in the NRG REMA, LLC (REMA) leveraged leases. The outcome indicated that the revisedupdated residual value estimates wereestimate of the coal-fired Powerton lease was lower than the recorded residual valuesvalue and the decline was deemed to be other than temporary due to theas a result of expected future 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.market conditions. As a result, a pre-tax write-down of $137$58 million was reflected in Operating Revenues in the quarter ended September 30, 2016,2019, calculated by comparing the gross investment in the leases before and after the revised residual estimates. During the fourth quarter of 2016, Energy Holdings recorded a $10 million 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 Leases as of December 31, 2016. For additional information, see Note 8. Financing Receivables.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DuringIn the first quarter of 2017, due2020, PSEG’s Board of Directors approved the marketing and sale of certain non-core assets held by subsidiaries of Energy Holdings. As a result, PSEG expects to continuingreclassify approximately $160 million as Assets Held for Sale on its Consolidated Balance Sheet in the first quarter of 2020.
Due to liquidity issues facing NRG REMA, LLC (REMA) prior to its emergence from bankruptcy protection, economic challenges facing coal generation in PJM and based upon an ongoing reviewreviews of available alternatives as well as certain recent discussions with REMA management leading up to and in connection with REMA’s bankruptcy, Energy Holdings recorded an additional $55pre-tax charges of $20 million pre-tax charge for its current best estimate of loss related to the lease receivables.
In June 2017, GenOn Energy, Inc. (GenOn)in 2018 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$77 million (including a 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-downimpairment of $7 million was recordedmillion) 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 arewere reflected in Operating Revenues in each year and are included in Gross Investment in Leases as of December 31, 2017.2019.
In JanuaryDecember 2018, certain subsidiariesREMA emerged from its in-court proceeding under Chapter 11 of the Bankruptcy Code. As a result of the restructuring, Energy Holdings REMA, certain holdersrecognized a pre-tax gain in Operating Revenues of approximately $12 million ($9 million after tax). PSEG realized the remaining tax liability related to the restructuring of approximately $120 million with the filing of the pass-through certificatesconsolidated federal 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 specifiedstate income tax returns in the Forbearance occurs.2019.
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).
The following table shows Energy Holdings’ gross and net lease investment as of December 31, 20172019 and 2016.2018.
|
| | | | | | | | | | |
| | | | | | | |
| | | | 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, | |
| | | | 2019 | | 2018 | |
| | | | Millions | |
| | Lease Receivables (net of Non-Recourse Debt) | | $ | 498 |
| | $ | 504 |
| |
| | Estimated Residual Value of Leased Assets | | 202 |
| | 326 |
| |
| | Total Investment in Rental Receivables | | 700 |
| | 830 |
| |
| | Unearned and Deferred Income | | (203 | ) | | (290 | ) | |
| | Gross Investments in Leases | | 497 |
| | 540 |
| |
| | Deferred Tax Liabilities | | (328 | ) | | (354 | ) | |
| | Net Investments in Leases | | $ | 169 |
| | $ | 186 |
| |
| | | | | | | |
The pre-tax income (loss) and income tax effects related to investments in leases, excluding gains and losses on sales and the impacts of the Tax Act, were as follows:
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | Years Ended December 31, | |
| | | | 2019 | | 2018 | | 2017 | |
| | | | Millions | |
| | Pre-Tax Income (Loss) from Leases | | $ | (39 | ) | | $ | 17 |
| | $ | (69 | ) | |
| | Income Tax Expense (Benefit) on Income from Leases | | $ | (22 | ) | | $ | 6 |
| | $ | (26 | ) | |
| | | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | 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
PSEG Power had the following equity method investments as of December 31, 20172019 and 2016:2018:
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | As of December 31, | | | | | |
| | Name | | 2019 | | 2018 | | Location | | % Owned | |
| | | | Millions | | | | | |
| | PSEG Power | | | | | | | | | |
| | Keystone Fuels, LLC (A) | | $ | — |
| | $ | 9 |
| | PA | | 23% | |
| | Conemaugh Fuels, LLC (A) | | — |
| | 8 |
| | PA | | 23% | |
| | Kalaeloa | | 66 |
| | 69 |
| | HI | | 50% | |
| | Total | | $ | 66 |
| | $ | 86 |
| | | | | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | |
| | | | | | | | |
| | | 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 |
| | | | | |
| | | | | | | | | | |
| |
| (A) | In September 2019, PSEG Power completed the sale of its ownership interests in the Keystone and Conemaugh generation plants and related assets and liabilities. |
Note 8.10. Financing Receivables
PSE&G
PSE&G sponsors a solar loan program 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) generated from the installed solar electric system. In the event of a loan default, the basis of the solar loan would be recovered through a regulatory recovery mechanism. None of the solar loans are impaired; however, in the event a loan becomes impaired, the basis of the loan would be recovered through a regulatory recovery mechanism.
A substantial portion of these amounts are noncurrent and reported in 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.”
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | |
| | | | | | | |
| | 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 |
| |
| | | | | | | |
|
| | | | | | | | | | |
| | | | | | | |
| | Outstanding Loans by Class of Customer | |
| | | | As of December 31, | |
| | Consumer Loans | | 2019 | | 2018 | |
| | | | Millions | |
| | Commercial/Industrial | | $ | 156 |
| | $ | 164 |
| |
| | Residential | | 8 |
| | 9 |
| |
| | Total | | $ | 164 |
| | $ | 173 |
| |
| | Current Portion (included in Accounts Receivable) | | (28 | ) | | (24 | ) | |
| | Noncurrent Portion (included in Long-Term Investments) | | $ | 136 |
| | $ | 149 |
| |
| | | | | | | |
Energy Holdings
Energy Holdings had a net investment in domestic energy and real estate assets subject to leveraged lease accounting of $85$169 million as of December 31, 20172019 and $(25)$186 million as of December 31, 20162018 (See Note 7.9. 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, 2019 | | As of December 31, 2019 | |
| | | | Millions | |
| | AA | | $ | 12 |
| |
| | A- | | 58 |
| |
| | BBB+ — BBB | | 258 |
| |
| | BB | | 132 |
| |
| | NR | | 38 |
| |
| | Total | | $ | 498 |
| |
| | | | | |
|
| | | | | | |
| | | | | |
| | | | 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-”“BB” and the “CCC-”“NR” ratings in the preceding table represent lease receivables related to coal and gas-fired assets in Illinois and Pennsylvania, respectively. As of December 31, 2017,2019, the gross investment in the leases of such assets, net of non-recourse debt, was $335$235 million, ($(67)(22) million, net of deferred taxes). A more detailed description of such assets under lease is presented in the following table.follows:
|
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | 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) | |
| | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | Asset | | Location | | Gross Investment | | % Owned | | Total MW | | Fuel Type | | Counterparties’ S&P Credit Ratings | | Counterparty | |
| | | | | | Millions | | | | | | | | | | | |
| | Powerton Station Units 5 and 6 | | IL | | $ | 75 |
| | 64 | % | | 1,538 |
| | Coal | | BB | | NRG Energy, Inc. | |
| | Joliet Station Units 7 and 8 | | IL | | $ | 85 |
| | 64 | % | | 1,036 |
| | Gas | | BB | | NRG Energy, Inc. | |
| | Shawville Station Units 1, 2, 3 and 4 | | PA | | $ | 75 |
| | 100 | % | | 596 |
| | Gas | | NR | | REMA (A) | |
| | | | | | | | | | | | | | | | | |
| |
| (A) | GenOn Energy Inc. (GenOn), and certain of its subsidiaries (which did not include REMA) filed voluntary petitions for relief underREMA emerged from Chapter 11 of the U.S. Bankruptcy Code. GenOn is currently engagedCode 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.December 2018. For additional information, see Note 7.9. 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. Upon the occurrence of certain defaults, indirect subsidiary companies of Energy Holdings would exercise their rights and seek recovery of their investment, 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,
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 Securities11. 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 billion and $3.0 billion, including contingencies. The liability for decommissioning recorded on a discounted basis as of December 31, 20172019 was approximately $756740 million and is included in the Asset Retirement Obligation. 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, 2019 | |
| | | | Cost | | Gross Unrealized Gains | | Gross Unrealized Losses | | Fair Value | |
| | | | Millions | |
| | Equity Securities | | | | | | | | | |
| | Domestic | | $ | 425 |
| | $ | 238 |
| | $ | (4 | ) | | $ | 659 |
| |
| | International | | 400 |
| | 103 |
| | (11 | ) | | 492 |
| |
| | Total Equity Securities | | 825 |
| | 341 |
| | (15 | ) | | 1,151 |
| |
| | Available-for-Sale Debt Securities | | | | | | | | | |
| | Government | | 563 |
| | 16 |
| | (2 | ) | | 577 |
| |
| | Corporate | | 470 |
| | 17 |
| | (1 | ) | | 486 |
| |
| | Total Available-for-Sale Debt Securities | | 1,033 |
| | 33 |
| | (3 | ) | | 1,063 |
| |
| | Total NDT Fund Investments (A) | | $ | 1,858 |
| | $ | 374 |
| | $ | (18 | ) | | $ | 2,214 |
| |
| | | | | | | | | |
|
| |
(A) The NDT Fund Investments table excludes foreign currency of $2 millionas of December 31, 2019,
which is part of the NDT Fund.
|
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | As of December 31, 2018 | |
| | | | Cost | | Gross Unrealized Gains | | Gross Unrealized Losses | | Fair Value | |
| | | | Millions | |
| | Equity Securities | | | | | | | | | |
| | Domestic | | $ | 447 |
| | $ | 153 |
| | $ | (29 | ) | | $ | 571 |
| |
| | International | | 323 |
| | 36 |
| — |
| (30 | ) | | 329 |
| |
| | Total Equity Securities | | 770 |
| | 189 |
| | (59 | ) | | 900 |
| |
| | Available-for-Sale Debt Securities | | | | | | | | | |
| | Government | | 498 |
| | 2 |
| | (9 | ) | | 491 |
| |
| | Corporate | | 501 |
| | 1 |
| | (15 | ) | | 487 |
| |
| | Total Available-for-Sale Debt Securities | | 999 |
| | 3 |
| | (24 | ) | | 978 |
| |
| | Total NDT Fund Investments | | $ | 1,769 |
| | $ | 192 |
| | $ | (83 | ) | | $ | 1,878 |
| |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | 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
Net unrealized gains (losses) on debt securities of $17 million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s and PSEG Power’s Consolidated Balance Sheets as of December 31, 2019. The costportion of thesenet unrealized gains (losses) recognized during 2019 related to equity securities still held at the end of December 31, 2019 was determined on the basis of specific identification.$194 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, | |
| | | | 2019 | | 2018 | |
| | | | Millions | |
| | Accounts Receivable | | $ | 11 |
| | $ | 17 |
| |
| | Accounts Payable | | $ | 11 |
| | $ | 5 |
| |
| | | | | | | |
|
| | | | | | | | | | |
| | | | | | | |
| | | | As of December 31, 2017 | | As of December 31, 2016 | |
| | | | Millions | |
| | Accounts Receivable | | $ | 24 |
| | $ | 8 |
| |
| | Accounts Payable | | $ | 74 |
| | $ | 5 |
| |
| | | | | | | |
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, 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 | ) | |
| | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | As of December 31, 2019 | | As of December 31, 2018 | |
| | | | 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 | | $ | 21 |
| | $ | (1 | ) | | $ | 6 |
| | $ | (3 | ) | | $ | 147 |
| | $ | (26 | ) | | $ | 5 |
| | $ | (3 | ) | |
| | International | | 28 |
| | (2 | ) | | 34 |
| | (9 | ) | | 131 |
| | (28 | ) | | 5 |
| | (2 | ) | |
| | Total Equity Securities | | 49 |
| | (3 | ) | | 40 |
| | (12 | ) | | 278 |
| | (54 | ) | | 10 |
| | (5 | ) | |
| | Available-for-Sale Debt Securities | | | | | | | | | | | | | | | | | |
| | Government (B) | | 99 |
| | (2 | ) | | 30 |
| | — |
| | 51 |
| | — |
| | 317 |
| | (9 | ) | |
| | Corporate (C) | | 49 |
| | — |
| | 12 |
| | (1 | ) | | 150 |
| | (5 | ) | | 222 |
| | (10 | ) | |
| | Total Available-for-Sale Debt Securities | | 148 |
| | (2 | ) | | 42 |
| | (1 | ) | | 201 |
| | (5 | ) | | 539 |
| | (19 | ) | |
| | NDT Trust Investments | | $ | 197 |
| | $ | (5 | ) | | $ | 82 |
| | $ | (13 | ) | | $ | 479 |
| | $ | (59 | ) | | $ | 549 |
| | $ | (24 | ) | |
| | | | | | | | | | | | | | | | | | | |
| |
| (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 unrealizedUnrealized gains and losses are distributed over a broad range of securities with limited impairment durations. Power does not consideron these securities to be other-than-temporarily impaired as of December 31, 2017.are recorded in Net Income. |
| |
| (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. These investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG 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 PSEG Power does not intend to sell these securities before recovery nor will it be more-likely-than-not required to sell, PSEG Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2017.2019. |
| |
| (C) | Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). PSEG 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 PSEG Power does not intend to sell these securities before recovery nor will it be more-likely-than-not required to sell, PSEG Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2017.2019. |
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, | |
| | | | 2019 | | 2018 | | 2017 | |
| | | | Millions | |
| | Proceeds from Sales (A) | | $ | 1,614 |
| | $ | 1,398 |
| | $ | 2,137 |
| |
| | Net Realized Gains (Losses): | | | | | | | |
| | Gross Realized Gains | | $ | 107 |
| | $ | 121 |
| | $ | 157 |
| |
| | Gross Realized Losses | | (53 | ) | | (51 | ) | | (23 | ) | |
| | Net Realized Gains (Losses) on NDT Fund (B) | | 54 |
| | 70 |
| | 134 |
| |
| | Unrealized Gains (Losses) on Equity Securities in NDT Fund (C) | | 196 |
| | (209 | ) | | N/A |
| |
| | Other-Than-Temporary-Impairments (OTTI) | | — |
| | — |
| | (12 | ) | |
| | Net Gains (Losses) on NDT Fund Investments | | $ | 250 |
| | $ | (139 | ) | | $ | 122 |
| |
| | | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | 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) | 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. |
| |
| (C) | Effective January 1, 2018, unrealized gains (losses) on equity securities are recorded in Net Income instead of Other Comprehensive Income (Loss). |
Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in PSEG’s and Power’s Consolidated Statements of Operations. Net unrealized gains of $175 million (after-tax) are included in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Consolidated Balance Sheets as 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.
The available-for-saleNDT Fund debt securities held as of December 31, 20172019 had the following maturities:
|
| | | | | | |
| | | | | |
| | Time Frame | | Fair Value | |
| | | | Millions | |
| | Less than one year | | $ | 19 |
| |
| | 1 - 5 years | | 273 |
| |
| | 6 - 10 years | | 188 |
| |
| | 11 - 15 years | | 51 |
| |
| | 16 - 20 years | | 77 |
| |
| | Over 20 years | | 455 |
| |
| | Total NDT Available-for-Sale Debt Securities | | $ | 1,063 |
| |
| | | | | |
|
| | | | | | |
| | | | | |
| | 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 in the value of these securities would be recognized in Accumulated Other Comprehensive Income (Loss) unless the securities are sold, in which case, any gain would be recognized in income. 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.
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, 2019 | |
| | | | Cost | | Gross Unrealized Gains | | Gross Unrealized Losses | | Fair Value | |
| | | | Millions | |
| | Equity Securities | | | | | | | | | |
| | Domestic | | $ | 21 |
| | $ | 7 |
| | $ | — |
| | $ | 28 |
| |
| | International | | — |
| | — |
| | — |
| | — |
| |
| | Total Equity Securities | | 21 |
| | 7 |
| | — |
| | 28 |
| |
| | Available-for-Sale Debt Securities | | | | | | | | | |
| | Government | | 100 |
| | 4 |
| | — |
| | 104 |
| |
| | Corporate | | 107 |
| | 7 |
| | — |
| | 114 |
| |
| | Total Available-for-Sale Debt Securities | | 207 |
| | 11 |
| | — |
| | 218 |
| |
| | Total Rabbi Trust Investments | | $ | 228 |
| | $ | 18 |
| | $ | — |
| | $ | 246 |
| |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | As of December 31, 2018 | |
| | | | Cost | | Gross Unrealized Gains | | Gross Unrealized Losses | | Fair Value | |
| | | | Millions | |
| | Equity Securities | | | | | | | | | |
| | Domestic | | $ | 22 |
| | $ | 1 |
| | $ | — |
| | $ | 23 |
| |
| | International | | — |
| | — |
| | — |
| | — |
| |
| | Total Equity Securities | | 22 |
| | 1 |
| | — |
| | 23 |
| |
| | Available-for-Sale Debt Securities | | | | | | | | | |
| | Government | | 110 |
| | 1 |
| | (2 | ) | | 109 |
| |
| | Corporate | | 96 |
| | — |
| | (4 | ) | | 92 |
| |
| | Total Available-for-Sale Debt Securities | | 206 |
| | 1 |
| | (6 | ) | | 201 |
| |
| | Total Rabbi Trust Investments | | $ | 228 |
| | $ | 2 |
| | $ | (6 | ) | | $ | 224 |
| |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | 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 |
| |
| | | | | | | | | | | |
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, | |
| | | | 2019 | | 2018 | |
| | | | Millions | |
| | Accounts Receivable | | $ | 2 |
| | $ | 2 |
| |
| | Accounts Payable | | $ | — |
| | $ | — |
| |
| | | | | | | |
|
| | | | | | | | | | |
| | | | | | | |
| | | | As of December 31, 2017 | | As of December 31, 2016 | |
| | | | Millions | |
| | Accounts Receivable | | $ | 2 |
| | $ | 5 |
| |
| | Accounts Payable | | $ | 1 |
| | $ | 3 |
| |
| | | | | | | |
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, 2019 | | As of December 31, 2018 | |
| | | | 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) | | $ | 26 |
| | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | 18 |
| | $ | — |
| | $ | 59 |
| | $ | (2 | ) | |
| | Corporate (B) | | 11 |
| | — |
| | 2 |
| | — |
| | 50 |
| | (3 | ) | | 29 |
| | (1 | ) | |
| | Total Available-for-Sale Debt Securities | | 37 |
| | — |
| | 5 |
| | — |
| | 68 |
| | (3 | ) | | 88 |
| | (3 | ) | |
| | Rabbi Trust Investments | | $ | 37 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | 68 |
| | $ | (3 | ) | | $ | 88 |
| | $ | (3 | ) | |
| | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | 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) | 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 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. 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, 2017.2019. |
| |
(C)(B) | Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). 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, 2017.2019. |
The proceeds from the sales of and the net realized gains (losses) on securities in the Rabbi Trust Fund were:
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | Years Ended December 31, | |
| | | | 2019 | | 2018 | | 2017 | |
| | | | Millions | |
| | Proceeds from Rabbi Trust Sales (A) | | $ | 173 |
| | $ | 103 |
| | $ | 182 |
| |
| | Net Realized Gains (Losses): | | | | | | | |
| | Gross Realized Gains | | $ | 7 |
| | $ | 2 |
| | $ | 17 |
| |
| | Gross Realized Losses | | (3 | ) | | (4 | ) | | (5 | ) | |
| | Net Realized Gains (Losses) on Rabbi Trust (B) | | 4 |
| | (2 | ) | | 12 |
| |
| | Unrealized Gains (Losses) on Equity Securities in Rabbi Trust (C) | | 6 |
| | (2 | ) | | N/A |
| |
| | Net Gains (Losses) on Rabbi Trust Investments | | $ | 10 |
| | $ | (4 | ) | | $ | 12 |
| |
| | | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | 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. |
| |
| (C) | Effective January 1, 2018, unrealized gains (losses) on equity securities are recorded in Net Income instead of Other Comprehensive Income (Loss). |
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, 20172019 had the following maturities:
|
| | | | | | |
| | | | | |
| | Time Frame | | Fair Value | |
| | | | Millions | |
| | Less than one year | | $ | 3 |
| |
| | 1 - 5 years | | 28 |
| |
| | 6 - 10 years | | 33 |
| |
| | 11 - 15 years | | 14 |
| |
| | 16 - 20 years | | 28 |
| |
| | Over 20 years | | 112 |
| |
| | Total Rabbi Trust Available-for-Sale Debt Securities | | $ | 218 |
| |
| | | | | |
|
| | | | | | |
| | | | | |
| | 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 |
| |
| | | | | |
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). 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, PSE&G and PSEG Power are detailed as follows:
|
| | | | | | | | | | |
| | | | | | | |
| | | | As of December 31, | | As of December 31, | |
| | | | 2019 | | 2018 | |
| | | | Millions | |
| | PSE&G | | $ | 48 |
| | $ | 45 |
| |
| | PSEG Power | | 62 |
| | 56 |
| |
| | Other | | 136 |
| | 123 |
| |
| | Total Rabbi Trust Investments | | $ | 246 |
| | $ | 224 |
| |
| | | | | | | |
|
| | | | | | | | | | |
| | | | | | | |
| | | | 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 10.12. Goodwill and Other Intangibles
As of December 31, 2017 and 2016,2018, PSEG Power had goodwill of $16 million related to the Bethlehem Energy Center facility.. PSEG Power conducted an annualconducts a review for goodwill impairment in the fourth quarter of 2017 and concluded thateach year. In 2019, PSEG Power determined its fair value using a market-based enterprise valuation technique. Based on the results of the annual impairment test, PSEG Power’s entire goodwill continueswas determined to remain unimpaired. be impaired. As such, PSEG Power recorded an impairment loss of $16 million in O&M Expense. The decrease in the fair value was primarily due to the continued decline in wholesale power market pricing.
In addition to goodwill, as of December 31, 20172019 and 2016,2018, PSEG Power had intangible assets of $114$149 million and $98$143 million,, respectively, related to emissions allowances and renewable energy credits.RECs. Emissions allowances and renewable energy creditsRECs are recorded at cost and evaluated for impairment at least annually. Emissions expense includes impairments of emissions allowances, if any, 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 PSEG Power’s intangible assets during 20162018 and 20172019 are presented in the following table:as follows:
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | Emissions Allowances | | RECs | | Total Other Intangibles | |
| | | | Millions | |
| | Balance as of January 1, 2018 | | $ | 74 |
| | $ | 40 |
| | $ | 114 |
| |
| | Retirements | | (26 | ) | | (90 | ) | | (116 | ) | |
| | Purchases | | 36 |
| | 110 |
| | 146 |
| |
| | Sales and Transfers, net | | — |
| | (1 | ) | | (1 | ) | |
| | Balance as of December 31, 2018 | | $ | 84 |
| | $ | 59 |
| | $ | 143 |
| |
| | Retirements | | (6 | ) | | (83 | ) | | (89 | ) | |
| | Purchases | | 26 |
| | 72 |
| | 98 |
| |
| | Sales and Transfers, net | | — |
| | (3 | ) | | (3 | ) | |
| | Balance as of December 31, 2019 | | $ | 104 |
| | $ | 45 |
| | $ | 149 |
| |
| | | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | | |
| | | | 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 |
| |
| | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 11.13. Asset Retirement Obligations (AROs)
PSEG, PSE&G and PSEG 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. 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.
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.
PSEG Power’s ARO liability primarily relates to the decommissioning of its nuclear power plants in accordance with NRC requirements. PSEG Power 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.11. Trust Investments. PSEG Power also identified conditional AROs primarily related to PSEG 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. To estimate the fair value of its AROs, PSEG Power 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 cost studies are obtained triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2015.2018. 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 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, PSE&G and PSEG Power during 20162018 and 20172019 are presented in the following table:
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | 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 |
| |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | PSEG | | PSE&G | | PSEG Power | | Other | |
| | | | Millions | |
| | ARO Liability as of January 1, 2018 | | $ | 1,024 |
| | $ | 212 |
| | $ | 810 |
| | $ | 2 |
| |
| | Liabilities Settled | | (10 | ) | | (9 | ) | | (1 | ) | | — |
| |
| | Liabilities Incurred | | 1 |
| | — |
| | 1 |
| | — |
| |
| | Accretion Expense | | 41 |
| | — |
| | 41 |
| | — |
| |
| | Accretion Expense Deferred and Recovered in Rate Base (A) | | 12 |
| | 12 |
| | — |
| | — |
| |
| | Revision to Present Values of Estimated Cash Flows | | (5 | ) | | 87 |
| | (93 | ) | | 1 |
| |
| | ARO Liability as of December 31, 2018 | | $ | 1,063 |
| | $ | 302 |
| | $ | 758 |
| | $ | 3 |
| |
| | Liabilities Settled | | (19 | ) | | (18 | ) | | (1 | ) | | — |
| |
| | Liabilities Incurred | | 3 |
| | 1 |
| | 2 |
| | — |
| |
| | Accretion Expense | | 40 |
| | — |
| | 40 |
| | — |
| |
| | Accretion Expense Deferred and Recovered in Rate Base (A) | | 16 |
| | 16 |
| | — |
| | — |
| |
| | Revision to Present Values of Estimated Cash Flows | | (16 | ) | | 2 |
| | (18 | ) | | — |
| |
| | ARO Liability as of December 31, 2019 | | $ | 1,087 |
| | $ | 303 |
| | $ | 781 |
| | $ | 3 |
| |
| | | | | | | | | | | |
| |
| (A) | Not reflected as expense in Consolidated Statements of Operations |
During 2017,In 2019, PSEG Power’s decrease of $18 million was primarily due to the sale of its interests in the Keystone and Conemaugh units. These changes had an immaterial impact in PSEG Power’s Consolidated Statement of Operations. See Note 4. Early Plant Retirements/Asset Dispositions for additional information. In addition, PSEG Power reviewed its probabilities of early retirement on its nuclear units and concluded that no adjustments were necessary as of December 31, 2019.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In 2018, PSE&G recorded a reduction to its ARO liabilities&G’s increase of $87 million was primarily due to the impact of settlements and changes to cash flow estimates.an increase in labor rates. These changes had no impact in PSE&G’s Consolidated Statement of Operations.
During 2017, Power recorded an increase to its ARO liabilitiesIn 2018, PSEG Power’s decrease of $93 million was primarily due to changes in discount rates and decommissioning assumptions related to nuclear. The changes in decommissioning assumptions, including a higher assumedreduction for the lower probability of early retirement of itsthe nuclear units, were due in part to the enactment of $276 million (See Note 3. Early Plant Retirements for additional information).the New Jersey ZEC legislation in May 2018 and that the Salem and Hope Creek Units were the sole applicants under the ZEC program. This reduction was also due to the sale of the Hudson and Mercer units, partially offset by increases in estimated costs to decommission PSEG Power’s fossil units pursuant to its most recent cost study.
Note 12.14. Pension, Other Postretirement Benefits (OPEB) and Savings Plans
PSEG sponsors 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-contributory pension and OPEB plans sponsored by PSEG and administered by Services. In addition, represented and nonrepresented employees are eligible for participation in PSEG’s two2 defined contribution plans described below.
PSEG, PSE&G and PSEG 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 its 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 had 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 PSEG Power, the charge to Accumulated Other Comprehensive Income (Loss) is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations.
In late June 2019, PSEG approved a plan amendment to its qualified pension plan, effective July 1, 2019. The amendment involved the spin-off of predominantly active participants from the existing qualified pension plan (Pension Plan) into a new qualified pension plan (Pension Plan II). Benefits offered to the plan participants remain unchanged. The existing plan’s pension benefit obligations, as well as the asset values, were remeasured as of July 1, 2019 as a result of the amendment. As of July 1, 2019, the weighted average discount rate for the combined plans decreased from 4.41% to 3.65% and the expected long-term rate of return on plan assets remained at 7.80%. Actuarial gains and losses associated with the Pension Plan will be amortized over the average remaining life expectancy of the inactive participants (as opposed to the average remaining service of active participants prior to the plan being split). Actuarial gains and losses associated with Pension Plan II will be amortized over the average remaining service of active participants. The combined remeasured qualified pension plans’ projected benefit obligation as of July 1, 2019 was $6.4 billion.
In December 2018, PSEG amended certain provisions of its OPEB plans applicable to all current and future Medicare-eligible retirees and spouses who receive or will receive subsidized healthcare from PSEG. Effective January 1, 2021, the PSEG-sponsored Medicare-eligible plans will be replaced by a Medicare private exchange. For each Medicare-eligible retiree and spouse, PSEG will provide annual credits to a Health Reimbursement Arrangement, which can be used to pay for medical, prescription drug, and dental plan premiums, as well as certain out-of-pocket costs. The amendment resulted in a $559 million reduction in PSEG’s OPEB obligation as of December 31, 2016, PSEG merged its three qualified defined benefit pension plans (excluding Servco plans) into one plan, thereby also merging all of the pension plans’ assets. As a result, the total net periodic benefit costs, net of amounts capitalized, decreased by approximately $48 million for the year ended December 31, 2017, as compared to the 2017 amounts that would have been recognized had the plans not been merged. This is due to the amortization period for gains and losses for the merged plan resulting in lower amortization than that of the individual plans. No changes were made to the benefit formulas, vesting provisions, or to the employees covered by the plans.2018.
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, 20172019 and 2016.2018. 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 | |
| | | | 2019 | | 2018 | | 2019 | | 2018 | |
| | | | Millions | |
| | Change in Benefit Obligation | | | | | | | | | |
| | Benefit Obligation at Beginning of Year (A) | | $ | 5,921 |
| | $ | 6,359 |
| | $ | 1,203 |
| | $ | 1,976 |
| |
| | Service Cost | | 123 |
| | 130 |
| | 10 |
| | 18 |
| |
| | Interest Cost | | 218 |
| | 208 |
| | 45 |
| | 66 |
| |
| | Actuarial (Gain) Loss | | 955 |
| | (460 | ) | | 109 |
| | (222 | ) | |
| | Gross Benefits Paid | | (325 | ) | | (316 | ) | | (82 | ) | | (76 | ) | |
| | Plan Amendments | | — |
| | — |
| | — |
| | (559 | ) | |
| | Benefit Obligation at End of Year (A) | | $ | 6,892 |
| | $ | 5,921 |
| | $ | 1,285 |
| | $ | 1,203 |
| |
| | Change in Plan Assets | | | | | | | | | |
| | Fair Value of Assets at Beginning of Year | | $ | 5,120 |
| | $ | 5,812 |
| | $ | 488 |
| | $ | 511 |
| |
| | Actual Return on Plan Assets | | 1,122 |
| | (388 | ) | | 107 |
| | (36 | ) | |
| | Employer Contributions | | 12 |
| | 12 |
| | 27 |
| | 89 |
| |
| | Gross Benefits Paid | | (325 | ) | | (316 | ) | | (82 | ) | | (76 | ) | |
| | Fair Value of Assets at End of Year | | $ | 5,929 |
| | $ | 5,120 |
| | $ | 540 |
| | $ | 488 |
| |
| | Funded Status | | | | | | | | | |
| | Funded Status (Plan Assets less Benefit Obligation) | | $ | (963 | ) | | $ | (801 | ) | | $ | (745 | ) | | $ | (715 | ) | |
| | Additional Amounts Recognized in the Consolidated Balance Sheets | | | | | | | | | |
| | Current Accrued Benefit Cost | | $ | (11 | ) | | $ | (10 | ) | | $ | (11 | ) | | $ | (11 | ) | |
| | Noncurrent Accrued Benefit Cost | | (952 | ) | | (791 | ) | | (734 | ) | | (704 | ) | |
| | Amounts Recognized | | $ | (963 | ) | | $ | (801 | ) | | $ | (745 | ) | | $ | (715 | ) | |
| | Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (B) | | | |
| | Prior Service Credit | | $ | (10 | ) | | $ | (28 | ) | | $ | (433 | ) | | $ | (561 | ) | |
| | Net Actuarial Loss | | 2,150 |
| | 2,005 |
| | 409 |
| | 420 |
| |
| | Total | | $ | 2,140 |
| | $ | 1,977 |
| | $ | (24 | ) | | $ | (141 | ) | |
| | | | | | | | | | | |
| |
| (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 ofor retirement. |
| |
| (B) | Includes $683$695 million ($406499 million, after-tax) and $679$619 million ($398360 million, after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 20172019 and 2016,2018, respectively. Also includes Regulatory Assets of $1,485$1,284 million and Deferred Assets of $133$137 million as of December 31, 20172019 and Regulatory Assets of $1,396$1,090 million and Deferred Assets of $134$127 million as of December 31, 2016.2018. |
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, 2017,2019, PSEG had funded approximately 91%86% of its projected pension benefit obligation. This percentage does not include $231246 million of assets in the Rabbi Trust as of December 31, 20172019 which were used partially to fund the nonqualified pension plans. As of December 31, 2017,2019, the nonqualified pension plans included in the projected benefit obligation in the above table were $167$176 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 $6.16.7 billion as of December 31, 20172019 and $5.65.7 billion as of December 31, 2016.2018.
The following table provides the components of net periodic benefit cost relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis for PSEG, excluding Servco for the years ended December 31, 2017, 20162019, 2018 and 20152017. Amounts shown do not reflect the impacts of capitalization and co-owner allocations. Effective with the adoption of ASU 2017-07 on January 1, 2018, only the service cost component is eligible for capitalization, when applicable.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | 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, | |
| | | | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 | |
| | | | Millions | |
| | Components of Net Periodic Benefit (Credits) Costs | | | | | | | | | | | | | |
| | Service Cost (included in O&M Expense) | | $ | 123 |
| | $ | 130 |
| | $ | 114 |
| | $ | 10 |
| | $ | 18 |
| | $ | 17 |
| |
| | Non-Service Components of Pension and OPEB (Credits) Costs | | | | | | | | | | | | | |
| | Interest Cost | | 218 |
| | 208 |
| | 204 |
| | 45 |
| | 66 |
| | 63 |
| |
| | Expected Return on Plan Assets | | (408 | ) | | (441 | ) | | (394 | ) | | (36 | ) | | (41 | ) | | (34 | ) | |
| | Amortization of Net | | | | | | | | | | | | | |
| | Prior Service Credit | | (18 | ) | | (18 | ) | | (18 | ) | | (128 | ) | | (1 | ) | | (11 | ) | |
| | Actuarial Loss | | 96 |
| | 85 |
| | 97 |
| | 50 |
| | 64 |
| | 51 |
| |
| | Non-Service Components of Pension and OPEB (Credits) Costs | | (112 | ) | | (166 | ) | | (111 | ) | | (69 | ) | | 88 |
| | 69 |
| |
| | Total Benefit (Credits) Costs | | $ | 11 |
| | $ | (36 | ) | | $ | 3 |
| | $ | (59 | ) | | $ | 106 |
| | $ | 86 |
| |
| | | | | | | | | | | | | | | |
Pension costs and OPEB costs for PSEG, PSE&G and PSEG Power are detailed as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | Pension Benefits Years Ended December 31, | | Other Benefits Years Ended December 31, | |
| | | | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 | |
| | | | Millions | |
| | PSE&G | | $ | — |
| | $ | (31 | ) | | $ | (4 | ) | | $ | (62 | ) | | $ | 68 |
| | $ | 54 |
| |
| | PSEG Power | | 4 |
| | (9 | ) | | 1 |
| | 3 |
| | 32 |
| | 27 |
| |
| | Other | | 7 |
| | 4 |
| | 6 |
| | — |
| | 6 |
| | 5 |
| |
| | Total Benefit (Credits) Costs | | $ | 11 |
| | $ | (36 | ) | | $ | 3 |
| | $ | (59 | ) | | $ | 106 |
| | $ | 86 |
| |
| | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | 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 |
| |
| | | | | | | | | | | | | | | |
The following table provides the pre-tax changes recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Deferred Assets:
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | Pension | | OPEB | |
| | | | 2019 | | 2018 | | 2019 | | 2018 | |
| | | | Millions | |
| | Net Actuarial (Gain) Loss in Current Period | | $ | 241 |
| | $ | 369 |
| | $ | 39 |
| | $ | (145 | ) | |
| | Amortization of Net Actuarial Gain (Loss) | | (96 | ) | | (85 | ) | | (50 | ) | | (64 | ) | |
| | Prior Service Cost (Credit) in current period | | — |
| | — |
| | — |
| | (559 | ) | |
| | Amortization of Prior Service Credit | | 18 |
| | 18 |
| | 128 |
| | 1 |
| |
| | Total | | $ | 163 |
| | $ | 302 |
| | $ | 117 |
| | $ | (767 | ) | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | 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 20182020 are as follows:
|
| | | | | | | | | | |
| | | | | | | |
| | | | Pension Benefits | | Other Benefits | |
| | | | 2020 | | 2020 | |
| | | | Millions | |
| | Actuarial Loss | | $ | 92 |
| | $ | 47 |
| |
| | Prior Service Credit | | $ | (10 | ) | | $ | (128 | ) | |
| | | | | | | |
|
| | | | | | | | | | |
| | | | | | | |
| | | | 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 | |
| | | | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 | |
| | Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 | | | |
| | Discount Rate | | 3.30 | % | | 4.41 | % | | 3.73 | % | | 3.20 | % | | 4.31 | % | | 3.76 | % | |
| | Rate of Compensation Increase | | 3.90 | % | | 3.90 | % | | 3.90 | % | | 3.90 | % | | 3.90 | % | | 3.90 | % | |
| | Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 | | | |
| | Discount Rate | | 4.41 | % | | 3.73 | % | | 4.29 | % | | 4.31 | % | | 3.76 | % | | 4.37 | % | |
| | Service Cost Interest Rate | | 4.58 | % | | 3.88 | % | | 4.53 | % | | 4.48 | % | | 3.90 | % | | 4.64 | % | |
| | Interest Cost Interest Rate | | 4.03 | % | | 3.35 | % | | 3.63 | % | | 3.91 | % | | 3.39 | % | | 3.69 | % | |
| | Expected Return on Plan Assets | | 7.80 | % | | 7.80 | % | | 7.80 | % | | 7.79 | % | | 7.80 | % | | 7.80 | % | |
| | Rate of Compensation Increase | | 3.90 | % | | 3.90 | % | | 3.61 | % | | 3.90 | % | | 3.90 | % | | 3.61 | % | |
| | Assumed Health Care Cost Trend Rates as of December 31 | | | | | | | | | |
| | Health Care Costs | | | | | | | | | | | | | |
| | Immediate Rate | | | | | | | | 6.68 | % | | 7.28 | % | | 7.93 | % | |
| | Ultimate Rate | | | | | | | | 4.75 | % | | 4.75 | % | | 4.75 | % | |
| | Year Ultimate Rate Reached | | | | | | | | 2029 |
| | 2026 |
| | 2026 |
| |
| | | | | | | | | | Millions | |
| | Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs | | | |
| | Total of Service Cost and Interest Cost | | | | | | | | $ | 1 |
| | $ | 1 |
| | $ | 13 |
| |
| | Postretirement Benefit Obligation | | | | | | | | $ | 20 |
| | $ | 21 |
| | $ | 240 |
| |
| | Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs | | | |
| | Total of Service Cost and Interest Cost | | | | | | | | $ | (1 | ) | | $ | (1 | ) | | $ | (10 | ) | |
| | Postretirement Benefit Obligation | | | | | | | | $ | (18 | ) | | $ | (20 | ) | | $ | (198 | ) | |
| | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | 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 | ) | |
| | | | | | | | | | | | | | | |
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 17.19. 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, 2017,2019, the pension plan interest and OPEB plan interest in such assets of the Master Trust were approximately 92% and 8%, 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, 20172019 and 2016,2018, 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, 2019 | |
| | | | | | 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) | | $ | 104 |
| | $ | 103 |
| | $ | 1 |
| | $ | — |
| |
| | Equity Securities | | | | | | | | | |
| | Common Stock (B) | | 1,487 |
| | 1,487 |
| | — |
| | — |
| |
| | Commingled (C) | | 1,707 |
| | 1,042 |
| | 665 |
| | — |
| |
| | Preferred Stock (B) | | 19 |
| | 19 |
| | — |
| | — |
| |
| | Other (D) | | 3 |
| | 3 |
| | — |
| | — |
| |
| | Debt Securities (E) | | | | | | | | | |
| | U.S. Treasury | | 544 |
| | — |
| | 544 |
| | — |
| |
| | Government—Other | | 284 |
| | — |
| | 284 |
| | — |
| |
| | Corporate | | 837 |
| | — |
| | 837 |
| | — |
| |
| | Commingled | | 3 |
| | 3 |
| | — |
| | — |
| |
| | Other (Future Contracts) | | (3 | ) | | (3 | ) | | — |
| | — |
| |
| | Subtotal Fair Value | | $ | 4,985 |
| | $ | 2,654 |
| | $ | 2,331 |
| | $ | — |
| |
| | Measured at net asset value practical expedient | | | | | | | | | |
| | Commingled—Equities (F) | | 1,154 |
| | | |
|
| | | |
| | Real Estate Investment (G) | | 302 |
| | | | | | | |
| | Private Equity (H) | | 8 |
| | | | | | | |
| | Total Fair Value (I) | | $ | 6,449 |
| | | | | | | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | Recurring Fair Value Measurements as of December 31, 2018 | |
| | | | | | 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) | | $ | 99 |
| | $ | 88 |
| | $ | 11 |
| | $ | — |
| |
| | Equity Securities | |
|
| | | | | | | |
| | Common Stock (B) | | 1,156 |
| | 1,156 |
| | — |
| | — |
| |
| | Commingled (C) | | 1,338 |
| | 960 |
| | 378 |
| | — |
| |
| | Preferred Stock (B) | | 7 |
| | 7 |
| | — |
| | — |
| |
| | Other (D) | | 1 |
| | 1 |
| | — |
| | — |
| |
| | Debt Securities (E) | |
|
| | | | | | | |
| | U.S. Treasury | | 526 |
| | — |
| | 526 |
| | — |
| |
| | Government—Other | | 302 |
| | — |
| | 302 |
| | — |
| |
| | Corporate | | 948 |
| | — |
| | 948 |
| | — |
| |
| | Subtotal Fair Value | | $ | 4,377 |
| | $ | 2,212 |
| | $ | 2,165 |
| | $ | — |
| |
| | Measured at net asset value practical expedient | | | | | | | | | |
| | Commingled—Equities (F) | | 1,208 |
| | | | | | | |
| | Private Equity (H) | | 10 |
| | | | | | | |
| | Total Fair Value (I) | | $ | 5,595 |
| |
|
| |
|
| |
|
| |
| | | | | | | | | | | |
| |
| (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). |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| |
| (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 termnear-term redemption restrictions which prevent redemption at the published daily NAV are classified as Level 2. |
| |
| (D) | Investment in a publicly traded limited partnership. |
| |
| (E) | Debt securities include mainly investment grade corporate and municipal bonds, USU.S. 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 quotedquotes for similar securities which are a Level 2 measure. |
| |
(E)(F) | In 2016, as part of the implementation of the accounting guidance on investments measured at fair value using NAV as a practical expedient, certainCertain commingled equity funds have been removed fromare 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 determinable fair value due to limitations in publishedthe frequency of publishing 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.(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 MSCI Emerging MarketsMorgan Stanley Capital International Index. |
| |
(F)(G) | 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 are 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. |
| |
| (H) | Private equity investments primarily include various limited partnerships that invest in either operating companies through acquisitions or developing a portfolio of non-USnon-U.S. distressed investments to maximize total return on capital. These investments are valued at NAV (or its equivalent) on an annuala quarterly 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 fromare not included in the fair value hierarchy in accordance with the guidance on NAV practical expedient. |
| |
(G)(I) | Excludes net receivablereceivables of $13$15 million and $14 million atas of December 31, 20172019 and 2016,2018, respectively, which consistsconsist of interest, dividends and receivables and payables related to pending securities sales and purchases. In addition, the table excludes cash and foreign currency of $5 million as of December 31, 2019. |
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 | | 2019 | | 2018 | |
| | Equity Securities | | 68 | % | | 66 | % | |
| | Debt Securities | | 26 |
| | 32 |
| |
| | Other Investments | | 6 |
| | 2 |
| |
| | Total Percentage | | 100 | % | | 100 | % | |
| | | | | | | |
|
| | | | | | | | |
| | | | | | | |
| | | | As of December 31, | |
| | Investments | | 2017 | | 2016 | |
| | Equity Securities | | 69 | % | | 70 | % | |
| | Debt Securities | | 29 |
| | 28 |
| |
| | Other Investments | | 2 |
| | 2 |
| |
| | 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%59% equities, 18% real asset and 30%23% fixed income is consistent with the funds’ financial objectives. 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% for 20172019 and will be 7.8%7.7% for 2018.2020. This expected return was determined based on the study discussed above, including a premium for active management and considered the plans’ historical annualized rate of return since inception.
Plan Contributions
PSEG has no planned contributions to its pension plans in 2018. PSEG plans to make discretionary contributions of $14 million into its OPEB plan during 2018.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Plan Contributions
PSEG does not plan to contribute to its pension and OPEB plans in 2020.
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 | |
| | 2020 | | | $ | 382 |
| | $ | 90 |
| |
| | 2021 | | | 354 |
| | 85 |
| |
| | 2022 | | | 367 |
| | 86 |
| |
| | 2023 | | | 378 |
| | 86 |
| |
| | 2024 | | | 389 |
| | 86 |
| |
| | 2025-2029 | | | 2,074 |
| | 409 |
| |
| | Total | | | $ | 3,944 |
| | $ | 842 |
| |
| | | | | | | | |
|
| | | | | | | | | | | |
| | | | | | | | |
| | 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 |
| |
| | | | | | | | |
401(k) Plans
PSEG sponsors two2 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 compensation to these plans, not to exceed the IRSInternal Revenue Service (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, PSE&G and
PSEG Power are detailed as follows:
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | Thrift Plan and Savings Plan | |
| | | | Years Ended December 31, | |
| | | | 2019 | | 2018 | | 2017 | |
| | | | Millions | |
| | PSE&G | | $ | 25 |
| | $ | 26 |
| | $ | 25 |
| |
| | PSEG Power | | 10 |
| | 10 |
| | 11 |
| |
| | Other | | 5 |
| | 5 |
| | 5 |
| |
| | Total Employer Matching Contributions | | $ | 40 |
| | $ | 41 |
| | $ | 41 |
| |
| | | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | 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 |
| |
| | | | | | | | | |
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 4.5. 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, 20172019 and 2016.2018. 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 | | $ | 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 | ) | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | Pension Benefits | | Other Benefits | |
| | | | 2019 | | 2018 | | 2019 | | 2018 | |
| | | | Millions | |
| | Change in Benefit Obligation | | | | | | | | | |
| | Benefit Obligation at Beginning of Year | | $ | 321 |
| | $ | 320 |
| | $ | 501 |
| | $ | 542 |
| |
| | Service Cost | | 26 |
| | 30 |
| | 16 |
| | 18 |
| |
| | Interest Cost | | 14 |
| | 12 |
| | 22 |
| | 20 |
| |
| | Actuarial (Gain) Loss | | 96 |
| | (38 | ) | | 96 |
| | (73 | ) | |
| | Gross Benefits Paid | | (4 | ) | | (3 | ) | | (6 | ) | | (6 | ) | |
| | Plan Amendments | | — |
| | — |
| | (3 | ) | | — |
| |
| | Benefit Obligation at End of Year (A) | | $ | 453 |
| | $ | 321 |
| | $ | 626 |
| | $ | 501 |
| |
| | Change in Plan Assets | | | | | | | | | |
| | Fair Value of Assets at Beginning of Year | | $ | 212 |
| | $ | 191 |
| | $ | — |
| | $ | — |
| |
| | Actual Return on Plan Assets | | 46 |
| | (16 | ) | | — |
| | — |
| |
| | Employer Contributions | | 28 |
| | 40 |
| | 6 |
| | 6 |
| |
| | Gross Benefits Paid | | (4 | ) | | (3 | ) | | (6 | ) | | (6 | ) | |
| | Fair Value of Assets at End of Year | | $ | 282 |
| | $ | 212 |
| | $ | — |
| | $ | — |
| |
| | Funded Status | | | | | | | | | |
| | Funded Status (Plan Assets less Benefit Obligation) | | $ | (171 | ) | | $ | (109 | ) | | $ | (626 | ) | | $ | (501 | ) | |
| | Additional Amounts Recognized in the Consolidated Balance Sheets | | | | | | | | | |
| | Accrued Pension Costs of Servco | | $ | (171 | ) | | $ | (109 | ) | | N/A |
| | N/A |
| |
| | OPEB Costs of Servco | | N/A |
| | N/A |
| | (626 | ) | | (501 | ) | |
| | Amounts Recognized (B) | | $ | (171 | ) | | $ | (109 | ) | | $ | (626 | ) | | $ | (501 | ) | |
| | | | | | | | | | | |
| |
| (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 ofor 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. |
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 2019, 2018 and 2017 2016 and 2015 were $35 million, $28 million, $40 million and $30$35 million, respectively. Servco has contributed its entire planned contribution amount to its pension plan trusts during 2017.2019. The OPEB-related revenues earned and costs incurred were $6 million, $6 million and $4 million in 2019, 2018 and $2 million in 2017, and 2016, respectively, and immaterial for 2015.
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 | ) | |
| | | | | | | | | | | | | | | |
129 |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | Pension Benefits | | Other Benefits | |
| | | | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 | |
| | Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 | | | |
| | Discount Rate | | 3.52 | % | | 4.60 | % | | 3.90 | % | | 3.60 | % | | 4.67 | % | | 3.96 | % | |
| | 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 | | | | | | | | 6.94 | % | | 8.03 | % | | 7.69 | % | |
| | Ultimate Rate | | | | | | | | 4.75 | % | | 4.75 | % | | 4.75 | % | |
| | Year Ultimate Rate Reached | | | | | | | | 2029 |
| | 2026 |
| | 2026 |
| |
| | | | | | | | | | Millions | |
| | Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs | | | |
| | Postretirement Benefit Obligation | | | | | | | | $ | 135 |
| | $ | 108 |
| | $ | 131 |
| |
| | Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs | | | |
| | Postretirement Benefit Obligation | | | | | | | | $ | (104 | ) | | $ | (83 | ) | | $ | (99 | ) | |
| | | | | | | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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 17.19. 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, 20172019 and 2016,2018, including the fair value measurements and the levels of inputs used in determining those fair values. |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | Recurring Fair Value Measurements as of December 31, 2019 | |
| | | | | | 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) | | $ | 202 |
| | $ | — |
| | $ | 202 |
| | $ | — |
| |
| | Commingled Bonds (A) | | 80 |
| | — |
| | 80 |
| | — |
| |
| | Total | | $ | 282 |
| | $ | — |
| | $ | 282 |
| | $ | — |
| |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | Recurring Fair Value Measurements as of December 31, 2018 | |
| | | | | | 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)
| | $ | 141 |
| | $ | — |
| | $ | 141 |
| | $ | — |
| |
| | Commingled Bonds (A)
| | 71 |
| | — |
| | 71 |
| | — |
| |
| | Total | | $ | 212 |
| | $ | — |
| | $ | 212 |
| | $ | — |
| |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | 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, 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 |
| | $ | — |
| |
| | | | | | | | | | | |
| |
| (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 | | 2019 | | 2018 | |
| | Equity Securities | | 72 | % | | 67 | % | |
| | Debt Securities | | 28 |
| | 33 |
| |
| | Total Percentage | | 100 | % | | 100 | % | |
| | | | | | | |
|
| | | | | | | | |
| | | | | | | |
| | | | As of December 31, | |
| | Investments | | 2017 | | 2016 | |
| | Equity Securities | | 72 | % | | 71 | % | |
| | Debt Securities | | 28 |
| | 29 |
| |
| | 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.an efficient portfolio. The results from 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. The expected long-term rate of return on plan assets was 7.6% for 20172019 and will be 7.6% for 2018.2020. This expected return was determined based on the study discussed above, including a premium for active management.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Plan Contributions
Servco plans to contribute $40$30 million into its pension plan during 2018.2020.
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 | |
| | 2020 | | | $ | 6 |
| | $ | 7 |
| |
| | 2021 | | | 8 |
| | 9 |
| |
| | 2022 | | | 10 |
| | 11 |
| |
| | 2023 | | | 12 |
| | 13 |
| |
| | 2024 | | | 14 |
| | 15 |
| |
| | 2025-2029 | | | 109 |
| | 104 |
| |
| | Total | | | $ | 159 |
| | $ | 159 |
| |
| | | | | | | | |
|
| | | | | | | | | | | |
| | | | | | | | |
| | 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 |
| |
| | | | | | | | |
Servco 401(k) Plans
Servco sponsors two2 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 amounts expensed by Servco for employer matching contributions for the years ended December 31, 2019, 2018 and 2017 2016 and 2015 were $6$8 million, $5$7 million and $4$6 million, respectively, and pursuant to the OSA, Servco recognizes Operating Revenues for the reimbursement of these costs.
Note 13.15. 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 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, 20172019 and 2016.2018. |
| | | | | | | | | | |
| | | | | | | |
| | | | As of December 31, 2019 | | As of December 31, 2018 | |
| | | | Millions | |
| | Face Value of Outstanding Guarantees | | $ | 1,854 |
| | $ | 1,772 |
| |
| | Exposure under Current Guarantees | | $ | 171 |
| | $ | 198 |
| |
| | | | | | | |
| | Letters of Credit Margin Posted | | $ | 121 |
| | $ | 115 |
| |
| | Letters of Credit Margin Received | | $ | 29 |
| | $ | 26 |
| |
| | | | | | | |
| | Cash Deposited and Received | | | | | |
| | Counterparty Cash Collateral Deposited | | $ | — |
| | $ | — |
| |
| | Counterparty Cash Collateral Received | | $ | (4 | ) | | $ | (10 | ) | |
| | Net Broker Balance Deposited (Received) | | $ | 48 |
| | $ | 403 |
| |
| | | | | | | |
| | Additional Amounts Posted | | | | | |
| | Other Letters of Credit | | $ | 82 |
| | $ | 52 |
| |
| | | | | | | |
|
| | | | | | | | | | |
| | | | | | | |
| | | | 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 part of determining credit exposure, PSEG Power nets receivables and payables with the corresponding net fair values of energy contract balances.contracts. See Note 16.18. 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 included one operating electric generating station (Essex Site), whichincluding at 1 site that was transferred to Power, one former generating station and four former manufactured gas plant (MGP) sites.PSEG Power.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In early 2007, certainCertain Potentially Responsible Parties (PRPs), including PSE&G and PSEG Power, formed a Cooperating Parties Group (CPG) and agreed to assume responsibility for conductingconduct a Remedial Investigation and Feasibility Study (RI/FS) of the 17 miles of the lower Passaic River.LPRSA. The CPG has agreed to allocate,allocated, 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 thismembers. The interim allocation which has been revised as parties have exitedis subject to change. In June 2019, the EPA conditionally approved the CPG’s Remedial Investigation. In August 2019, the CPG approximately 7.6 percentsubmitted a draft Feasibility Study (FS) to the EPA which evaluated various adaptive management scenarios for the remediation of only 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 17upper 9 miles of the lower Passaic River. PSEG has provided noticeLPRSA. The CPG is evaluating the EPA’s comments received to insurers concerning this potential claim. Certain PRPs are currently involved in discussions withdate on the draft FS.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Separately, 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 havehas released 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) for the EPA’s own Focused Feasibility Study (FFS) whichLPRSA’s lower 8.3 miles that requires the removal of 3.5 million cubic yards of sediment from the Passaic River’s lower 8.3 milessediments at an estimated cost of $2.3 billion on an undiscounted basis (ROD Remedy). The EPA estimatesAn EPA-commenced process to allocate the total project length to be about 11 years, including a one year period of negotiation withassociated costs is underway and PSEG cannot predict the PRPs, three to four years to design the project and six years for implementation.outcome. Occidental Chemical Corporation (OCC), one of the PRPs, has committed to performcommenced the remedial design required by the ROD Remedy, reserving its right of cost contribution from all other PRPs.
In September 2017, the EPA concluded that an Agency-commenced allocation process for 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 certain of the PRPs agree 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 estimatebut declined to participate in the allocation process. Instead, it filed suit against PSE&G and others seeking cost recovery and contribution under CERCLA but has not quantified alleged damages. The litigation is ongoing and PSEG cannot predict the outcome.
Two PRPs, Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus), have filed for Chapter 11 bankruptcy. The trust representing the creditors in this proceeding has filed a complaint asserting claims against Tierra’s and Maxus’ current and former parent entities, among others. Any damages awarded may be used to fund the remediation of PSE&G’s and Power’s shares of that cost, and (iii) the continued ability of PSE&G to recover such costs in its rates, asLPRSA.
As of December 31, 2017,2019, PSEG has accrued approximately $57 million.$65 million for this matter. Of this amount, $46PSE&G has accrued $52 million has been accrued by PSE&G as an Environmental Costs Liability and a corresponding Regulatory Asset and $11based on its continued ability to recover such costs in its rates. PSEG Power has accrued $13 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.Expense.
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 Departmentand 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 Environmental Protection (NJDEP) directed PSEG,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 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 theany 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 11 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 the possibleany 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.
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$357 million and $403$400 million on an undiscounted basis through 2021,2023, including its $46$52 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$357 million as ofDecember 31, 2017.2019. Of this amount, $79$68 million was recorded in Other Current Liabilities and $279$289 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $358$357 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 regardingPSE&G has agreed to what extentconduct sampling in the Passaic River is required 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 an impact on the Passaic River Superfund remedy.
Clean Water Act (CWA) Permit RenewalsSection 316(b) Rule
Pursuant toThe EPA’s CWA Section 316(b) rule establishes requirements for the Federal Water Pollution Control Act (FWPCA),regulation of cooling water intakes at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. The EPA requires that National Pollutant Discharge Elimination System permits expire withinbe renewed every five years of their effective date. In order to renew theseand that each state Permitting Director manage renewal permits but allowfor its respective power generation facilities on 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.case by case basis. 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 intake rule that establishes requirements for the regulation of cooling water intakes 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 NJPDES 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 the NJDEP’s issuancecertain conditions of the final NJPDES renewal permit, for Salem. NJDEP has grantedincluding the hearing request, but it has not yet been scheduled. The Riverkeeper’s filing does not change the effective dateNJDEP’s
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
application 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. The NJDEP had granted the hearing request but no hearing date has been established.
State permitting decisions at BridgeportBH3 and possibly New Haven could also have a material impact on PSEG 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, PSEG 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. PSEG Power is currently awaiting action byunable to predict the CTDEEP to issue a draft and then a final permit.
Power has negotiated a Community Environmental Benefit Agreement (CEBA) with the Cityoutcome 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,these permitting decisions 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 determinedeffect, if any, that monitoring and reporting practices related to certain permitted wastewater discharges at its Bridgeport Harbor stationthey may have violated conditionson PSEG Power’s future capital requirements, financial condition or results 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.operations.
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 beenwas 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 overseeingU.S. Coast Guard transitioned control of the emergencyfederal response includingto the EPA, and the EPA ended the federal response to the matter in 2018. The response is a part of the NJDEP site remediation program. The parties may be subject to the assessment of civil penalties related to the discharge and response. We are currently in discussions with the U.S. Coast Guard regarding the NJDEP andreimbursement of costs associated with the Army Corps of Engineers, have issued multiple notices, orders and directives to the various parties relatedfederal response to this matter. matter and potential payment of civil penalties. We cannot predict the outcome of these discussions.
The impacted cable was repaired in late-Septemberlate September 2017; however, small amounts of residual dielectric fluid continuesbelieved to be contained within the marina sediment continue to appear on the surface and so the investigation and response actions related to the fluid discharge are ongoing.ongoing, although at a significantly reduced scale. PSE&G may determineremains concerned about future leaks and potential environmental impacts as a result of reintroduction of fluid back into these lines and has determined that retirement of the affected facilities would beis appropriate. Also ongoingA lawsuit in federal court is the processpending 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 counterclaimsaddition, Con Edison filed counter claims against PSE&G and Con EdisonNADC, including 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 Edison 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.and damages. Based on the information currently available and depending on the outcome of the New Jersey federal court 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.
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 desulfurizationBGS, BGSS 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)ZECs
PSE&G obtains its electric supply requirements through the annual New Jersey BGS auctions for two categories of customers who choose not to purchase electric supply from third-party suppliers. The first category, which represents about 80%79% 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 Agreement with the winners of these BGS auctions following the BPU’s approval of the auction results. PSE&G has entered into contracts with winning BGS suppliers, including PSEG Power, to purchase BGS for PSE&G’s load requirements. The winners of the auction (including PSEG Power) are responsible for fulfilling all the requirements of a PJM Load ServingLoad-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, 20182020 is $287.76$359.98 per MW-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
day,MW-day, replacing the BGS-CIEP auction year price ending May 31, 20182020 of $276.83$281.78 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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:
|
| | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | Auction Year | | |
| | | 2017 | | 2018 | | 2019 | | 2020 | | |
| | 36-Month Terms Ending | May 2020 |
| | May 2021 |
| | May 2022 |
| | May 2023 |
| (A) | |
| | Load (MW) | 2,800 |
| | 2,900 |
| | 2,800 |
| | 2,800 |
| | |
| | $ per MWh | $90.78 | | $91.77 | | $98.04 | | $102.16 | | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | 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 | | |
| | | | | | | | | | | |
| |
| (A) | Prices set in the 20182020 BGS auction will become effective on June 1, 20182020 when the 20152017 BGS auction agreements expire. |
PSEG 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, PSEG Power has entered into contracts to directly supply PSE&G and other New Jersey electric distribution companies (EDCs)EDCs with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above.
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 24.26. 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. 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 nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 20202021 and a significant portion through 2022 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, PSEG Power can use the gas to supply its fossil generating stations.stations in New Jersey.
In connection with the sale of its ownership interests in the Keystone and Conemaugh generation plants in September 2019, PSEG Power also has various long-term fueltransferred the related coal purchase commitments for coal through 2021 to support its fossil generation stations.the buyers.
As of December 31, 2017,2019, the total minimum purchase requirements included in these commitments were as follows:
|
| | | | | | |
| | | | | |
| | Fuel Type | | PSEG Power's Share of Commitments through 2024 | |
| | | | Millions | |
| | Nuclear Fuel | | | |
| | Uranium | | $ | 187 |
| |
| | Enrichment | | $ | 357 |
| |
| | Fabrication | | $ | 185 |
| |
| | Natural Gas | | $ | 1,342 |
| |
| | | | | |
|
| | | | | | |
| | | | | |
| | Fuel Type | | Power's Share of Commitments through 2022 | |
| | | | Millions | |
| | Nuclear Fuel | | | |
| | Uranium | | $ | 240 |
| |
| | Enrichment | | $ | 391 |
| |
| | Fabrication | | $ | 170 |
| |
| | Natural Gas | | $ | 1,042 |
| |
| | Coal | | $ | 293 |
| |
| | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Regulatory Proceedings
Pending FERC Compliance
PJM Bidding MatterMatters
In June 2015, Hudson Power Transmission Developers, LLC (Hudson Power), formerly known as TranSource LLC, a merchant transmission developer, filed a complaint against PJM claiming that PJM wrongfully refused to provide data and a transparent process for evaluating transmission network upgrade requests that the first quartertransmission developer had submitted to PJM. Although not named as a respondent, the complaint identifies PSE&G as one of 2014,the companies claimed to have been involved. In January 2018, a FERC administrative law judge (ALJ) issued an order generally finding that PJM and transmission owners, including PSE&G, did not engage in wrongful conduct. In addition, the developer’s assertion of an entitlement to monetary damages was expressly denied. However, in a determination disputed by PSE&G, the order found that the PJM process lacked transparency. In August 2019, FERC reversed the ALJ’s decision on the transparency-related findings. FERC did find that PJM violated its Tariff and FERC orders, but found those errors were immaterial and ordered no remedies. Hudson Power discoveredfiled comments alleging FERC erred in overturning the ALJ’s decision, which was subsequently rejected by FERC. In October 2019, FERC dismissed Hudson Power’s comments on the grounds that it incorrectly calculated certain componentsdid not meet FERC’s requirements for a properly filed rehearing request. Hudson Power did not seek judicial review of its cost-based bidsthis decision.
PSE&G has also received requests for its New Jersey fossil generating units in the PJM energy market. Upon discoveryinformation and a Notice of the errors, PSEGInvestigation from FERC’s Office of Enforcement concerning a transmission project. PSE&G retained outside counsel to assist in the conduct ofwith 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 marketinvestigation. PSE&G is fully cooperating with FERC’s requests for its fossil peaking units differed from the amount for which Power was compensated in the capacity market for those units. PSEG informed FERC, PJMinformation and the PJM Independent Market Monitor (IMM)investigation. It is not possible at this time to predict the outcome 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, Power recorded a pre-tax charge to income in the amount of $25 million related to this matter.
Since September 2014, FERC Staff has been conductingLitigation
Sewaren 7 Construction
In June 2018, a preliminary, non-public staff investigation into these matters. While considerable uncertainty remains ascomplaint was filed in federal court in Newark, New Jersey against PSEG Fossil LLC, a wholly owned subsidiary of PSEG Power, regarding an ongoing dispute with Durr Mechanical Construction, Inc. (Durr), a contractor on the Sewaren 7 project. Among other things, Durr seeks damages of $93 million and alleges that PSEG Power withheld money owed to Durr and that PSEG Power’s intentional conduct led to the final resolutioninability of Durr to obtain prospective contracts. PSEG Power intends to vigorously defend against these matters, based upon developmentsallegations. In December 2018, Durr filed for Chapter 11 bankruptcy in the investigationfederal court in the first quarterSouthern District of 2017, Power believesNew York (SDNY). The SDNY bankruptcy court has allowed 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 this matter.
Caithness Energy, L.L.C. (Caithness)
In August 2018, Caithness, a Long Island power plant developer, filed a complaint in federal district court in the Eastern District of New York (EDNY) against PSEG and PSEG LI alleging violations of state and federal antitrust laws and a claim of intentional interference of prospective business relations. Caithness alleges that PSEG and PSEG LI interfered with LIPA’s consideration of the Caithness proposal for a 750 MW combined cycle generation project that was identified as a finalist for a Request For Proposal issued by LIPA. The complaint alleges hundreds of millions of dollars of harm. The EDNY granted PSEG’s and PSEG LI’s motion to dismiss the complaint but gave Caithness an opportunity to file an amended claim. Pursuant to a request by Caithness, the EDNY dismissed the antitrust claims with prejudice but allowed Caithness the opportunity to file its claim of intentional interference of prospective business in state court. Caithness has not yet refiled this claim in state court. PSEG intends to vigorously defend against these matters.allegations. Based upon the preliminary nature of this matter, a loss is not considered probable nor is the amount of loss, if any, estimable as of December 31, 2019.
Hudson Power
In January 2019, Hudson Power filed a complaint against PJM, PSE&G and three other transmission owners in Pennsylvania state court. Hudson Power sued the transmission owner defendants for fraud and intentional misrepresentation relating to information provided to PJM and FERC regarding the costs of upgrades for Hudson Power’s proposed project. These allegations appear to be based on alleged conduct that is the subject of the Hudson Power proceeding discussed under “Pending FERC Matters.” This action was removed to federal court in the Eastern District of Pennsylvania in February 2019. In light of the FERC proceeding, the federal court granted a motion to stay the federal proceeding until the conclusion of the FERC proceeding. In December 2019, the parties filed a stipulation with the federal court that dismissed all claims brought by Hudson Power, concluding the litigation.
Telephone Consumer Protection Act (TCPA) Matter
In February 2020, a putative class action complaint was filed in federal court in Newark, New Jersey against PSEG for violations of the TCPA related to alleged automated telemarketing calls directed to plaintiffs’ cellular telephone numbers. Due to its preliminary nature, PSEG cannot predict the outcome of this matter.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, PSE&G and PSEG 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, PSE&G’s or PSEG 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, PSE&G’s or PSEG 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, 2017,2019, nuclear sites were required to purchase $450 million of primary liability coverage for each site (through ANI). 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$13.5 billion. PSEG Power’s maximum aggregate assessment per incident is $401$433 million (based on PSEG Power’s ownership interests in Salem, Hope Creek and Peach Bottom) and its maximum aggregate annual assessment per incident is $60$65 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$61 million. NEIL requires its members to maintain an 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 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:NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | 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 14.16. Debt and Credit Facilities
Long-Term Debt
|
| | | | | | | | | | | | |
| | | | | | | | | |
| | | | | | 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 |
| |
| | | | | | | | | |
|
| | | | | | | | | | | | |
| | | | | | | | | |
| | | | | | As of December 31, | |
| | | | Maturity | | 2019 | | 2018 | |
| | | | | | Millions | |
| | PSEG | | | | | | | |
| | Term Loan: | | | | | | | |
| | Variable Rate | | 2019 | | $ | — |
| | $ | 350 |
| |
| | Variable Rate | | 2020 | | 700 |
| | 700 |
| |
| | Total Term Loan | | | | 700 |
| | 1,050 |
| |
| | Senior Notes: | | | | | | | |
| | 1.60% | | 2019 | | — |
| | 400 |
| |
| | 2.00% | | 2021 | | 300 |
| | 300 |
| |
| | 2.65% | | 2022 | | 700 |
| | 700 |
| |
| | 2.88% | | 2024 | | 750 |
| | — |
| |
| | Total Senior Notes | | | | 1,750 |
| | 1,400 |
| |
| | Principal Amount Outstanding | | | | 2,450 |
| | 2,450 |
| |
| | Amounts Due Within One Year | | | | (700 | ) | | (750 | ) | |
| | Net Unamortized Discount and Debt Issuance Costs | | | | (9 | ) | | (7 | ) | |
| | Total Long-Term Debt of PSEG | | | | $ | 1,741 |
| | $ | 1,693 |
| |
| | | | | | | | | |
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 | | 2019 | | 2018 | |
| | | | | | 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): | | | | | | | |
| | 1.80% | | 2019 | | — |
| | 250 |
| |
| | 2.00% | | 2019 | | — |
| | 250 |
| |
| | 3.50% | | 2020 | | 250 |
| | 250 |
| |
| | 7.04% | | 2020 | | 9 |
| | 9 |
| |
| | 1.90% | | 2021 | | 300 |
| | 300 |
| |
| | 2.38% | | 2023 | | 500 |
| | 500 |
| |
| | 3.25% | | 2023 | | 325 |
| | 325 |
| |
| | 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 |
| | 425 |
| |
| | 3.70% | | 2028 | | 375 |
| | 375 |
| |
| | 3.65% | | 2028 | | 325 |
| | 325 |
| |
| | 3.20% | | 2029 | | 375 |
| | — |
| |
| | 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 |
| | — |
| |
| | 3.20% | | 2049 | | 400 |
| | — |
| |
| | Total MTNs | | | | 9,759 |
| | 9,109 |
| |
| | Principal Amount Outstanding | | | | 9,908 |
| | 9,258 |
| |
| | Amounts Due Within One Year | | | | (259 | ) | | (500 | ) | |
| | Net Unamortized Discount and Debt Issuance Costs | | | | (81 | ) | | (74 | ) | |
| | Total Long-Term Debt of PSE&G | | | | $ | 9,568 |
| | $ | 8,684 |
| |
| | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | |
| | | | | | | | | |
| | | | | | As of December 31, | |
| | | | Maturity | | 2019 | | 2018 | |
| | | | | | Millions | |
| | PSEG Power | | | | | | | |
| | Senior Notes: | | | | | | | |
| | 5.13% | | 2020 | | $ | 406 |
| | $ | 406 |
| |
| | 3.00% | | 2021 | | 700 |
| | 700 |
| |
| | 4.15% | | 2021 | | 250 |
| | 250 |
| |
| | 3.85% | | 2023 | | 700 |
| | 700 |
| |
| | 4.30% | | 2023 | | 250 |
| | 250 |
| |
| | 8.63% | | 2031 | | 500 |
| | 500 |
| |
| | Total Senior Notes | | | | 2,806 |
| | 2,806 |
| |
| | Pollution Control Notes: | | | | | | | |
| | Floating Rate (B) | | 2022 | | 44 |
| | 44 |
| |
| | Total Pollution Control Notes | | | | 44 |
| | 44 |
| |
| | Principal Amount Outstanding | | | | 2,850 |
| | 2,850 |
| |
| | Amounts Due Within One Year | | | | (406 | ) | | (44 | ) | |
| | Net Unamortized Discount and Debt Issuance Costs | | | | (10 | ) | | (15 | ) | |
| | Total Long-Term Debt of PSEG Power | | | | $ | 2,434 |
| | $ | 2,791 |
| |
| | | | | | | | | |
|
| | | | | | | | | | | | |
| | | | | | | | | |
| | | | | | 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 |
| |
| | | | | | | | | |
| |
| (A) | Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage. |
| |
| (B) | The Pennsylvania Economic Development Financing Authority (PEDFA) bond that is serviced and secured by PSEG Power Pollution Control Notes is a variable rate bond that is in weekly reset mode. |
Long-Term Debt Maturities
The aggregate principal amounts of maturities for each of the five years following December 31, 20172019 are as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | Year | | PSEG | | PSE&G | | PSEG Power | | Total | |
| | | | | |
| | 2020 | | $ | 700 |
| | $ | 259 |
| | $ | 406 |
| | $ | 1,365 |
| |
| | 2021 | | 300 |
| | 434 |
| | 950 |
| | 1,684 |
| |
| | 2022 | | 700 |
| | — |
| | 44 |
| | 744 |
| |
| | 2023 | | — |
| | 825 |
| | 950 |
| | 1,775 |
| |
| | 2024 | | 750 |
| | 750 |
| | — |
| | 1,500 |
| |
| | Thereafter | | — |
| | 7,640 |
| | 500 |
| | 8,140 |
| |
| | Total | | $ | 2,450 |
| | $ | 9,908 |
| | $ | 2,850 |
| | $ | 15,208 |
| |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | 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 |
| |
| | | | | | | | | | | |
Long-Term Debt Financing Transactions
During 2017,2019, PSEG and its subsidiaries had the following Long-Term Debt issuances, maturities and redemptions:
PSEG
entered into an agreement forissued $750 million of 2.875% Senior Notes due June 2024,
repaid a new$350 million term loan maturing June 2019. The term loan has a balance of $700 million atwith an interest rate of 1 month LIBOR + 0.80%, and can be terminated at any time without penalty,
| |
| • | retired $400 million of 1.60% Senior Notes at maturity. |
PSE&G
•issued $700$400 million of 2.65% Senior3.20% Secured Medium-Term Notes, Series M, due November 2022, and
redeemed at maturity a $500 million term loan at an interest rate of 1 month LIBOR + 0.875% due November 2017.
August 2049,
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSE&G
issued $425$375 million of 3.00%3.20% Secured Medium-Term Notes, Series LM, due May 2027, and2029,
issued $350$375 million of 3.60%3.85% Secured Medium-Term Notes, Series LM, due December 2047.May 2049,
retired $250 million of 1.80% Medium-Term Notes, Series I, at maturity, and
retired $250 million of 2.00% Medium-Term Notes, Series J, at maturity.
In January 2020, PSE&G issued $300 million of 2.45% Medium-Term Notes, Series N, due January 2030 and $300 million of 3.15% Medium-Term Notes, Series N, due January 2050.
PSEG Power
PSEG Power executed an extension of the letter of credit backing $44 million of PEDFA Variable Rate Demand Bonds. The existing letter of credit, which was scheduled to expire in November 2019, was extended through March 2022.
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. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facilities.
The commitments under the $4.2 billion credit facilities are provided by a diverse bank group. As of December 31, 2017,2019, the total available credit capacity was $3.5$2.9 billion.
As of December 31, 2017,2019, no single institution represented more than 8%9% of the total commitments in the credit facilities.
As of December 31, 2017,2019, the total credit capacity was in excess of the anticipated maximum liquidity requirements over PSEG’s 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 our subsidiaries’ liquidity needs.
The total credit facilities and available liquidity as of December 31, 20172019 were as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | As of December 31, 2019 | | | |
| | Company/Facility | | Total Facility | | Usage (D) | | Available Liquidity | | Expiration Date | | Primary Purpose | |
| | | | Millions | | | | | |
| | PSEG | | | | | | | | | | | |
| | 5-year Credit Facilities (A) | | $ | 1,500 |
| | $ | 796 |
| | $ | 704 |
| | Mar 2023 | | Commercial Paper Support/Funding/Letters of Credit | |
| | Total PSEG | | $ | 1,500 |
| | $ | 796 |
| | $ | 704 |
| | | | | |
| | PSE&G | | | | | | | | | | | |
| | 5-year Credit Facility (B) | | $ | 600 |
| | $ | 379 |
| | $ | 221 |
| | Mar 2023 | | Commercial Paper Support/Funding/Letters of Credit | |
| | Total PSE&G | | $ | 600 |
| | $ | 379 |
| | $ | 221 |
| | | | | |
| | PSEG Power | | | | | | | | | | | |
| | 3-year Letter of Credit Facilities | | $ | 200 |
| | $ | 121 |
| | $ | 79 |
| | Sept 2021 | | Letters of Credit | |
| | 5-year Credit Facilities (C) | | 1,900 |
| | 40 |
| | 1,860 |
| | Mar 2023 | | Funding/Letters of Credit | |
| | Total PSEG Power | | $ | 2,100 |
| | $ | 161 |
| | $ | 1,939 |
| | | | | |
| | Total | | $ | 4,200 |
| | $ | 1,336 |
| | $ | 2,864 |
| | | | | |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | 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)(B) | PSE&G facility will be reduced by $4 million in March 2022. |
| |
| (C) | PSEG Power facilities will be reduced by $12 million in March 2022. |
| |
| (D) | 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, 2017,2019, PSEG had $542$753 million outstanding at a weighted average interest rate of 1.89%2.08%. PSE&G had no amounts$362 million outstanding at a weighted average interest rate of 1.95% under its Commercial Paper Program as of December 31, 2017.2019. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Fair Value of Debt
The estimated fair values, carrying amounts and methods used to determine fair value of long-term debt as of December 31, 20172019 and 20162018 are included in the following table and accompanying notes as of December 31, 20172019 and 2016.2018. See Note 17.19. 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, 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 |
| |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | December 31, 2019 | | December 31, 2018 | |
| | | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | |
| | | | Millions | |
| | Long-Term Debt: | | | | | | | | | |
| | PSEG (A) (B) | | $ | 2,441 |
| | $ | 2,479 |
| | $ | 2,443 |
| | $ | 2,397 |
| |
| | PSE&G (B) | | 9,827 |
| | 11,107 |
| | 9,184 |
| | 9,374 |
| |
| | PSEG Power (B) | | 2,840 |
| | 3,137 |
| | 2,835 |
| | 2,996 |
| |
| | Total Long-Term Debt | | $ | 15,108 |
| | $ | 16,723 |
| | $ | 14,462 |
| | $ | 14,767 |
| |
| | | | | | | | | | | |
| |
| (A) | As of December 31, 20172019 and 2016,2018, fair value includes floating rate term loans of $700 million and $500$1,050 million, respectively. The fair values of the term loan debt (Level 2 measurement) approximate the carrying valuesvalue 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) is 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. 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. |
Note 15.17. Schedule of Consolidated Capital Stock
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | 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 |
| |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | As of December 31, | |
| | | | Outstanding Shares | | Book Value | |
| | | | 2019 | | 2018 | | 2019 | | 2018 | |
| | | | Millions | |
| | PSEG Common Stock (no par value) (A) | | | | | | | | | |
| | Authorized 1,000 shares | | 504 |
| | 504 |
| | $ | 4,172 |
| | $ | 4,172 |
| |
| | | | | | | | | | | |
| |
| (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 20172019 or 2016.2018. |
As of December 31, 20172019, PSE&G had an aggregate of 7.5 million shares of $100 par value and 10 million shares of $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 16.18. 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, 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.
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 fuels 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 expected generation. PSEG Power also uses derivatives to hedge a portion of its anticipated BGSS obligations with PSE&G. For additional information see Note 13.15. Commitments and Contingent Liabilities. Changes in the fair market value of these derivative contracts are recorded in earnings.
Interest Rates
PSEG, PSEG Power and PSE&G 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 used a mix of fixed and floating rate debt 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, 20172019 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.2018.
Cash Flow Hedges
PSEG uses interest rate swaps and other derivatives, which are designated and effectivequalifying as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. ThereAs of December 31, 2019, PSEG had interest rate hedges outstanding totaling $700 million. These hedges convert PSEG’s $700 million variable-rate term loan due November 2020 into a fixed-rate loan. PSEG interest rate hedges totaling $600 million were terminated during the second quarter and a loss of $(12) million was recorded in Accumulated Other Comprehensive Income (Loss) (after tax) and will amortize to interest expense over the remaining life of PSEG’s $750 million of 2.875% Senior Notes due June 2024. For additional information see Note 16. Debt and Credit Facilities.
The fair value of these hedges was $(5) million as of December 31, 2019 and there were no outstanding interest rate hedges as of December 31, 2017. As of December 31, 2016, PSEG had interest rate hedges outstanding totaling $500 million. These hedges converted PSEG’s $500 million variable rate term loan due November 2017 into a fixed rate loan. As of December 31, 2016, the fair value of these hedges was $1 million and there was no ineffectiveness.2018. The Accumulated Other Comprehensive Income (Loss) (after tax) related to existingoutstanding and terminated interest rate derivatives designated as cash flow hedges was immaterial as of December 31, 2017$(15) million and $2$(1) million as of December 31, 2016.2019 and December 31, 2018, respectively. The after-tax unrealized gainslosses on these hedges expected to be reclassified to earnings during the next 12 months is immaterial.are $(2) 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 PSEG Power and PSEG. For additional information see Note 17.19. Fair Value Measurements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2019 | |
| | | PSEG Power (A) | | PSEG (A) | | Consolidated | |
| | | Not Designated | | | | | | Cash Flow Hedges | | | |
| | Balance Sheet Location | Energy- Related Contracts | | Netting (B) | | Total
PSEG Power | | Interest Rate Swaps | | Total Derivatives | |
| | | Millions | |
| | Derivative Contracts | | | | | | | | | | |
| | Current Assets | $ | 636 |
| | $ | (523 | ) | | $ | 113 |
| | $ | — |
| | $ | 113 |
| |
| | Noncurrent Assets | 163 |
| | (139 | ) | | 24 |
| | — |
| | 24 |
| |
| | Total Mark-to-Market Derivative Assets | $ | 799 |
| | $ | (662 | ) | | $ | 137 |
| | $ | — |
| | $ | 137 |
| |
| | Derivative Contracts | | | | | | | | | | |
| | Current Liabilities | $ | (553 | ) | | $ | 522 |
| | $ | (31 | ) | | $ | (5 | ) | | $ | (36 | ) | |
| | Noncurrent Liabilities | (139 | ) | | 138 |
| | (1 | ) | | — |
| | (1 | ) | |
| | Total Mark-to-Market Derivative (Liabilities) | $ | (692 | ) | | $ | 660 |
| | $ | (32 | ) | | $ | (5 | ) | | $ | (37 | ) | |
| | Total Net Mark-to-Market Derivative Assets (Liabilities) | $ | 107 |
| | $ | (2 | ) | | $ | 105 |
| | $ | (5 | ) | | $ | 100 |
| |
| | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | 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 |
| |
| | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | As of December 31, 2018 | |
| | | | PSEG Power (A) | | Consolidated | |
| | | | Not Designated | | | | | | | |
| | Balance Sheet Location | | Energy- Related Contracts | | Netting (B) | | Total
PSEG Power | | Total Derivatives | |
| | | Millions | |
| | Derivative Contracts | | | | | | | | | |
| | Current Assets | | $ | 426 |
| | $ | (415 | ) | | $ | 11 |
| | $ | 11 |
| |
| | Noncurrent Assets | | 137 |
| | (136 | ) | | 1 |
| | 1 |
| |
| | Total Mark-to-Market Derivative Assets | | $ | 563 |
| | $ | (551 | ) | | $ | 12 |
| | $ | 12 |
| |
| | Derivative Contracts | | | | | | | | | |
| | Current Liabilities | | $ | (521 | ) | | $ | 510 |
| | $ | (11 | ) | | $ | (11 | ) | |
| | Noncurrent Liabilities | | (198 | ) | | 194 |
| | (4 | ) | | (4 | ) | |
| | Total Mark-to-Market Derivative (Liabilities) | | $ | (719 | ) | | $ | 704 |
| | $ | (15 | ) | | $ | (15 | ) | |
| | Total Net Mark-to-Market Derivative Assets (Liabilities) | | $ | (156 | ) | | $ | 153 |
| | $ | (3 | ) | | $ | (3 | ) | |
| | | | | | | | | | | |
| |
| (A) | Substantially all of Power'sPSEG Power’s and PSEG'sPSEG’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, 20172019 and 2016. PSE&G does not have any derivative contracts subject to master netting or similar agreements.2018. |
| |
| (B) | 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 or(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, 2017,2019 and 2016,2018, PSEG Power had net cash collateral/margincollateral payments to counterparties of $146$44 million and $56$393 million, respectively. Of these net cash collateral (receipts) payments, $(2) million as of December 31, 2019 and $153 million as of December 31, 2018 were netted against the corresponding net derivative contract positions. Of the $(2) million as of December 31, 2019, $(1) million was netted against current assets, and $(1) million was netted against noncurrent assets. Of the $153 million as of December 31, 2018, $(2) million was netted against current assets, $(3) million was netted against noncurrent assets, $96 million was netted against current liabilities and $62 million was netted against noncurrent liabilities. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 as of December 31, 2017, $(3) million was netted against current assets, $28 million was netted against current liabilities and $19 million was netted against noncurrent liabilities. Of the $1 million as of December 31, 2016, $(3) 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 Power would represent a three level downgrade from its current 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$35 million and $19$22 million as of December 31, 20172019 and 2016,2018, respectively. As of December 31, 20172019 and 2016,2018, PSEG Power had the contractual right of offset of $13$2 million and $9$7 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$33 million and $10$15 million as of December 31, 20172019 and 2016,2018, 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, 20162019, 2018 and 2015.2017.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | 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, | |
| | | | 2019 | | 2018 | | 2017 | | | | 2019 | | 2018 | | 2017 | |
| | | | Millions | | | | Millions | |
| | PSEG | | | | | | | | | | | | | | | |
| | Interest Rate Swaps | | $ | (23 | ) | | $ | (2 | ) | | $ | — |
| | Interest Expense | | $ | (4 | ) | | $ | — |
| | $ | 3 |
| |
| | Total PSEG | | $ | (23 | ) | | $ | (2 | ) | | $ | — |
| | | | $ | (4 | ) | | $ | — |
| | $ | 3 |
| |
| | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | 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. For the year ended December 31, 2019, the amount of gain (loss) recognized inor loss on interest rate hedges reclassified from Accumulated Other Comprehensive Income (Loss) into income on derivatives (ineffective portion)was $(3) million after tax and immaterial as of December 31, 2017, 20162018 and 2015.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2017.
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, 2017 | | $ | — |
| | $ | — |
| |
| | Loss Recognized in AOCI | | (2 | ) | | (1 | ) | |
| | Less: Gain Reclassified into Income | | — |
| | — |
| |
| | Balance as of December 31, 2018 | | $ | (2 | ) | | $ | (1 | ) | |
| | Loss Recognized in AOCI | | (23 | ) | | (17 | ) | |
| | Less: Loss Reclassified into Income | | 4 |
| | 3 |
| |
| | Balance as of December 31, 2019 | | $ | (21 | ) | | $ | (15 | ) | |
| | | | | | | |
|
| | | | | | | | | | |
| | | | | | | |
| | 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, 20172019, 20162018 and 20152017. 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 PSEG Power has designated as NPNS, such as its BGS contracts and certain other
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
energy supply contracts that it has with other utilities and companies with retail load.
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | 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, | |
| | | | | | 2019 | | 2018 | | 2017 | |
| | | | | | Millions | |
| | PSEG Power | | | | | | | | | |
| | Energy-Related Contracts | | Operating Revenues | | $ | 560 |
| | $ | (182 | ) | | $ | 66 |
| |
| | Energy-Related Contracts | | Energy Costs | | (119 | ) | | (9 | ) | | (11 | ) | |
| | Total PSEG and PSEG Power | | | | $ | 441 |
| | $ | (191 | ) | | $ | 55 |
| |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | 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 |
| |
| | | | | | | | | | | |
The following table summarizes the net notional volume purchases/(sales) of open derivative transactions by commodity as of December 31, 20172019 and 2016.2018.
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | Type | | Notional | | Total | | PSEG | | PSEG Power | | PSE&G | |
| | | | Millions | |
| | As of December 31, 2019 | | | | | | | | | | | |
| | Natural Gas | | Dekatherm (Dth) | | 341 |
| | — |
| | 341 |
| | — |
| |
| | Electricity | | MWh | | (62 | ) | | — |
| | (62 | ) | | — |
| |
| | Financial Transmission Rights (FTRs) | | MWh | | 13 |
| | — |
| | 13 |
| | — |
| |
| | Interest Rate Swaps | | U.S. Dollars | | 700 |
| | 700 |
| | — |
| | — |
| |
| | As of December 31, 2018 | | | | | | | | | | | |
| | Natural Gas | | Dth | | 358 |
| | — |
| | 358 |
| | — |
| |
| | Electricity | | MWh | | (74 | ) | | — |
| | (74 | ) | | — |
| |
| | FTRs | | MWh | | 18 |
| | — |
| | 18 |
| | — |
| |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | 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
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 PSEG Power’s and PSEG’s financial condition, results of operations or net cash flows.
As of December 31, 2017, 99% of the net credit exposure for Power’s operations was with investment grade counterparties. 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 PSEG Power’s credit risk from others,wholesale counterparties, net of collateral, as of December 31, 2017.2019. It further delineates that exposure by the credit rating 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 PSEG Power’s credit risk by credit rating of the counterparties.
As of December 31, 2019, 99% of the net credit exposure for PSEG Power’s wholesale operations was with investment grade counterparties. 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).
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | 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 |
| | |
| | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | Rating | | Current Exposure | | Securities held as Collateral | | Net Exposure | | Number of Counterparties >10% | | Net Exposure of Counterparties >10% | | |
| | | | Millions | | | | Millions | | |
| | Investment Grade | | $ | 505 |
| | $ | 26 |
| | $ | 479 |
| | 2 |
| | $ | 263 |
| (A) | |
| | Non-Investment Grade | | 3 |
| | — |
| | 3 |
| | — |
| | — |
| | |
| | Total | | $ | 508 |
| | $ | 26 |
| | $ | 482 |
| | 2 |
| | $ | 263 |
| | |
| | | | | | | | | | | | | | |
| |
| (A) | Represents net exposure of $213 million with PSE&G.&G and $50 million with a non-affiliated counterparty. |
As of December 31, 2017,2019, collateral held from counterparties where PSEG Power had credit exposure included $1includes $4 million in cash collateral and $25$22 million in letters of credit.
As of December 31, 2017,2019, PSEG Power had 152153 active counterparties.
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 guaranty 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, 2017,2019, primarily all 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. PSE&G’s BGS suppliers’ credit exposure is calculated each business day. As of December 31, 2017,2019, PSE&G had no net credit exposure with suppliers, including PSEG Power.
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 17.19. 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, PSE&G and PSEG 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, PSE&G’s and PSEG Power’s respective assets and (liabilities) measured at fair value on a recurring basis as of December 31, 20172019 and December 31, 2016,2018, 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 PSEG Power.
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, 2019 | |
| | 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) | | $ | 50 |
| | $ | — |
| | $ | 50 |
| | $ | — |
| | $ | — |
| |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | 137 |
| | $ | (662 | ) | | $ | 19 |
| | $ | 770 |
| | $ | 10 |
| |
| | NDT Fund (C) | | | | | | | | | | | |
| | Equity Securities | | $ | 1,151 |
| | $ | — |
| | $ | 1,150 |
| | $ | 1 |
| | $ | — |
| |
| | Debt Securities—U.S. Treasury | | $ | 225 |
| | $ | — |
| | $ | — |
| | $ | 225 |
| | $ | — |
| |
| | Debt Securities—Govt Other | | $ | 352 |
| | $ | — |
| | $ | — |
| | $ | 352 |
| | $ | — |
| |
| | Debt Securities—Corporate | | $ | 486 |
| | $ | — |
| | $ | — |
| | $ | 486 |
| | $ | — |
| |
| | Rabbi Trust (C) | | | | | | | | | | | |
| | Equity Securities | | $ | 28 |
| | $ | — |
| | $ | 28 |
| | $ | — |
| | $ | — |
| |
| | Debt Securities—U.S. Treasury | | $ | 57 |
| | $ | — |
| | $ | — |
| | $ | 57 |
| | $ | — |
| |
| | Debt Securities—Govt Other | | $ | 47 |
| | $ | — |
| | $ | — |
| | $ | 47 |
| | $ | — |
| |
| | Debt Securities—Corporate | | $ | 114 |
| | $ | — |
| | $ | — |
| | $ | 114 |
| | $ | — |
| |
| | Liabilities: | | | | | | | | | | | |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | (32 | ) | | $ | 660 |
| | $ | (43 | ) | | $ | (646 | ) | | $ | (3 | ) | |
| | Interest Rate Swaps (D) | | $ | (5 | ) | | $ | — |
| | $ | — |
| | $ | (5 | ) | | $ | — |
| |
| | PSE&G | | | | | | | | | | | |
| | Assets: | | | | | | | | | | | |
| | Rabbi Trust (C) | | | | | | | | | | | |
| | Equity Securities | | $ | 5 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | — |
| |
| | Debt Securities—U.S. Treasury | | $ | 11 |
| | $ | — |
| | $ | — |
| | $ | 11 |
| | $ | — |
| |
| | Debt Securities—Govt Other | | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | 9 |
| | $ | — |
| |
| | Debt Securities—Corporate | | $ | 23 |
| | $ | — |
| | $ | — |
| | $ | 23 |
| | $ | — |
| |
| | PSEG Power | | | | | | | | | | | |
| | Assets: | | | | | | | | | | | |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | 137 |
| | $ | (662 | ) | | $ | 19 |
| | $ | 770 |
| | $ | 10 |
| |
| | NDT Fund (C) | | | | | | | | | | | |
| | Equity Securities | | $ | 1,151 |
| | $ | — |
| | $ | 1,150 |
| | $ | 1 |
| | $ | — |
| |
| | Debt Securities—U.S. Treasury | | $ | 225 |
| | $ | — |
| | $ | — |
| | $ | 225 |
| | $ | — |
| |
| | Debt Securities—Govt Other | | $ | 352 |
| | $ | — |
| | $ | — |
| | $ | 352 |
| | $ | — |
| |
| | Debt Securities—Corporate | | $ | 486 |
| | $ | — |
| | $ | — |
| | $ | 486 |
| | $ | — |
| |
| | Rabbi Trust (C) | | | | | | | | | | | |
| | Equity Securities | | $ | 8 |
| | $ | — |
| | $ | 8 |
| | $ | — |
| | $ | — |
| |
| | Debt Securities—U.S. Treasury | | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | 14 |
| | $ | — |
| |
| | Debt Securities—Govt Other | | $ | 12 |
| | $ | — |
| | $ | — |
| | $ | 12 |
| | $ | — |
| |
| | Debt Securities—Corporate | | $ | 28 |
| | $ | — |
| | $ | — |
| | $ | 28 |
| | $ | — |
| |
| | Liabilities: | | | | | | | | | | | |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | (32 | ) | | $ | 660 |
| | $ | (43 | ) | | $ | (646 | ) | | $ | (3 | ) | |
| | | | | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | Recurring Fair Value Measurements as of December 31, 2018 | |
| | 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) | | $ | 100 |
| | $ | — |
| | $ | 100 |
| | $ | — |
| | $ | — |
| |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | 12 |
| | $ | (551 | ) | | $ | 29 |
| | $ | 527 |
| | $ | 7 |
| |
| | NDT Fund (C) | | | | | | | | | | | |
| | Equity Securities | | $ | 900 |
| | $ | — |
| | $ | 898 |
| | $ | 2 |
| | $ | — |
| |
| | Debt Securities—U.S. Treasury | | $ | 171 |
| | $ | — |
| | $ | — |
| | $ | 171 |
| | $ | — |
| |
| | Debt Securities—Govt Other | | $ | 320 |
| | $ | — |
| | $ | — |
| | $ | 320 |
| | $ | — |
| |
| | Debt Securities—Corporate | | $ | 487 |
| | $ | — |
| | $ | — |
| | $ | 487 |
| | $ | — |
| |
| | Rabbi Trust (C) | | | | | | | | | | | |
| | Equity Securities | | $ | 23 |
| | $ | — |
| | $ | 23 |
| | $ | — |
| | $ | — |
| |
| | Debt Securities—U.S. Treasury | | $ | 69 |
| | $ | — |
| | $ | — |
| | $ | 69 |
| | $ | — |
| |
| | Debt Securities—Govt Other | | $ | 40 |
| | $ | — |
| | $ | — |
| | $ | 40 |
| | $ | — |
| |
| | Debt Securities—Corporate | | $ | 92 |
| | $ | — |
| | $ | — |
| | $ | 92 |
| | $ | — |
| |
| | Liabilities: | | | | | | | | | | | |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | (15 | ) | | $ | 704 |
| | $ | (36 | ) | | $ | (677 | ) | | $ | (6 | ) | |
| | PSE&G | | | | | | | | | | | |
| | Assets: | | | | | | | | | | | |
| | Rabbi Trust (C) | | | | | | | | | | | |
| | Equity Securities | | $ | 5 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | — |
| |
| | Debt Securities—U.S. Treasury | | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | 14 |
| | $ | — |
| |
| | Debt Securities—Govt Other | | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | 8 |
| | $ | — |
| |
| | Debt Securities—Corporate | | $ | 18 |
| | $ | — |
| | $ | — |
| | $ | 18 |
| | $ | — |
| |
| | PSEG Power | | | | | | | | | | | |
| | Assets: | | | | | | | | | | | |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | 12 |
| | $ | (551 | ) | | $ | 29 |
| | $ | 527 |
| | $ | 7 |
| |
| | NDT Fund (C) | | | | | | | | | | | |
| | Equity Securities | | $ | 900 |
| | $ | — |
| | $ | 898 |
| | $ | 2 |
| | $ | — |
| |
| | Debt Securities—U.S. Treasury | | $ | 171 |
| | $ | — |
| | $ | — |
| | $ | 171 |
| | $ | — |
| |
| | Debt Securities—Govt Other | | $ | 320 |
| | $ | — |
| | $ | — |
| | $ | 320 |
| | $ | — |
| |
| | Debt Securities—Corporate | | $ | 487 |
| | $ | — |
| | $ | — |
| | $ | 487 |
| | $ | — |
| |
| | Rabbi Trust (C) | | | | | | | | | | | |
| | Equity Securities | | $ | 6 |
| | $ | — |
| | $ | 6 |
| | $ | — |
| | $ | — |
| |
| | Debt Securities—U.S. Treasury | | $ | 17 |
| | $ | — |
| | $ | — |
| | $ | 17 |
| | $ | — |
| |
| | Debt Securities—Govt Other | | $ | 10 |
| | $ | — |
| | $ | — |
| | $ | 10 |
| | $ | — |
| |
| | Debt Securities—Corporate | | $ | 23 |
| | $ | — |
| | $ | — |
| | $ | 23 |
| | $ | — |
| |
| | Liabilities: | | | | | | | | | | | |
| | Derivative Contracts: | | | | | | | | | | | |
| | Energy-Related Contracts (B) | | $ | (15 | ) | | $ | 704 |
| | $ | (36 | ) | | $ | (677 | ) | | $ | (6 | ) | |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | 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
| |
| (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. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2016,2019, the fair value measurement table excludes cashforeign currency of $1$2 million which is part of in the NDT Fund. The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.”securities. 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.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.
| |
| (D) | 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. |
| |
| (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.See Note 18. 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 PSEG 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 nonperformance 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 nonperformance risk by counterparty. The impacts of credit and nonperformance 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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The fair value of PSEG 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 PSEG 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 physical 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, 20172019 and 2016.2018.
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | 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, 2019 | | Valuation Technique(s) | | Significant Unobservable Input | | Range | |
| | | | | | | |
| | | | | | Assets | | (Liabilities) | | | | | | | |
| | | | | | Millions | | | | | | | |
| | PSEG Power | | | | | | | | | | | | | |
| | Electricity | | Electric Load Contracts | | $ | 10 |
| | $ | — |
| | Discounted Cash flow | | Historic Load Variability | | 0% to 10% | |
| | Gas | | Gas Physical Contracts | | — |
| | (3 | ) | | Discounted Cash flow | | Average Historical Basis | | -50% to 0% | |
| | Total PSEG and PSEG Power | | $ | 10 |
| | $ | (3 | ) | | | | | | | |
| | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | 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 | ) | | | | | | | |
| | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | Quantitative Information About Level 3 Fair Value Measurements | | | |
| | Commodity | | Level 3 Position | | Fair Value as of December 31, 2018 | | Valuation Technique(s) | | Significant Unobservable Input | | Range | |
| | | | | | | |
| | | | | | Assets | | (Liabilities) | | | | | | | |
| | | | | | Millions | | | | | | | |
| | PSEG Power | | | | | | | | | | | | | |
| | Electricity | | Electric Load Contracts | | $ | 2 |
| | $ | (5 | ) | | Discounted Cash flow | | Historic Load Variability | | 0% to 15% | |
| | Gas | | Gas Physical Contracts | | 5 |
| | (1 | ) | | Discounted Cash flow | | Average Historical Basis | | -40% to 0% | |
| | Total PSEG and PSEG Power | | $ | 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 PSEG 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 PSEG 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, 20172019 and 2016,2018, respectively, follows:
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Year Ended December 31, 20172019 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | 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 |
| |
| | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | Description | | Balance as of December 31, 2018 | | Total Gains or (Losses) Realized/Unrealized Included in Income (A) | | Purchases, (Sales) | | Issuances/ Settlements (B) | | Transfers In/Out (C) | | Balance as of December 31, 2019 | |
| | | | | | | | | | | | | |
| | PSEG and PSEG Power | | | | | | | | | | | |
| | Net Derivative Assets (Liabilities) | | $ | 1 |
| | $ | 14 |
| | $ | — |
| | $ | (8 | ) | | $ | — |
| | $ | 7 |
| |
| | | | | | | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Year Ended December 31, 20162018 |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | Description | | Balance as of December 31, 2017 | | Total Gains or (Losses) Realized/Unrealized Included in Income (A) | | Purchases, (Sales) | | Issuances/ Settlements (B) | | Transfers In/Out (C) | | Balance as of December 31, 2018 | |
| | | | Millions | |
| | PSEG and PSEG Power | | | | | | | | | | | |
| | Net Derivative Assets (Liabilities) | | $ | 7 |
| | $ | (6 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
| |
| | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | 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) |
million is in Energy Costs, all of which is realized.
| |
| (B) | Mainly includes gains/losses on PSE&G’sIncludes $(7) million in settlements for 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.2019. |
| |
| (C) | Represents $(24) millionThere were no transfers in 2019 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 transferred2018 to or from Level 2 to Level 3.
|
As of December 31, 2017,2019, PSEG carried $2.6 billion of net assets that are measured at fair value on a recurring basis, of which $7 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
As of December 31, 2016,2018, PSEG carried $2.6$2.2 billion of net assets that are measured at fair value on a recurring basis, of which $1 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
Note 18.20. Stock Based Compensation
PSEG’s Amended and Restated 2004 Long-Term Incentive Plan (LTIP) is a broad-based equity compensation program that provides for grants of various long-term incentive compensation awards, such as stock options, stock appreciation rights, performance share units, restricted stock, restricted stock units, 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.
The LTIP currently provides for the issuance of equity awards with respect to approximately 16 million shares of common stock. As of December 31, 2017,2019, there were approximately 1412 million shares available for future awards under the LTIP.
Stock Options
Under the 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 Units (RSUs)
Under the LTIP, 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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 20172019 and 20162018 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 Units (PSUs)
Under the LTIP, 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. 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. 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 2019, 2018 and 2017:
|
| | | | | | |
| | | | | | | |
| | Grant Date | | Risk-Free Interest Rate | | Volatility | |
| | | | | | | |
| | February 19, 2019 | | 2.47% | | 16.74% | |
| | February 20, 2018 | | 2.36% | | 17.57% | |
| | February 21, 2017 | | 1.50% | | 20.00% | |
| | | | | | | |
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 for 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.
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | 2019 | | 2018 | | 2017 | |
| | | | Millions | |
| | Compensation Cost included in Operation and Maintenance Expense | | $ | 33 |
| | $ | 30 |
| | $ | 31 |
| |
| | Income Tax Benefit Recognized in Consolidated Statement of Operations | | $ | 9 |
| | $ | 9 |
| | $ | 13 |
| |
| | | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | 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 |
| |
| | | | | | | | | |
For 2019, 2018 and 2017, 2016 and 2015 thePSEG also recorded excess tax benefit of $5 million, $3 million and $4 million, $4 million and $3 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 Options
Changes inAs of January 1, 2019, there were 231,933 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 valueoutstanding, all of each option grant is estimated on the datewhich were exercised in 2019 at a weighted average price of grant using the Black-Scholes option-pricing model.$33.49. There were no option grantsstock options granted or vested in 2017, 20162019, 2018 and 20152017.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Activity for options exercised for the years ended December 31, 2017, 20162019, 2018 and 20152017 is shown below:
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | 2019 | | 2018 | | 2017 | |
| | | | Millions | |
| | Total Intrinsic Value of Options Exercised | | $ | 5 |
| | $ | 2 |
| | $ | 5 |
| |
| | Cash Received from Options Exercised | | $ | 8 |
| | $ | 4 |
| | $ | 26 |
| |
| | Tax Benefit Realized from Options Exercised | | $ | 1 |
| | $ | — |
| | $ | — |
| |
| | | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | 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, 20172019 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, 2019 | | 257,583 |
| | $ | 46.58 |
| | | | | |
| | Granted | | 200,923 |
| | $ | 56.24 |
| | | | | |
| | Vested | | 207,126 |
| | $ | 51.34 |
| | | | | |
| | Canceled/Forfeited | | 36,399 |
| | $ | 50.23 |
| | | | | |
| | Non-vested as of December 31, 2019 | | 214,981 |
| | $ | 50.41 |
| | 1.1 | | $ | 12,694,628 |
| |
| | | |
|
| | | | | | | |
|
| | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | 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, 20162019, 2018 and 20152017 was $44.33, $42.28$56.24, $49.34 and $39.65$44.33 per share, respectively.
The total intrinsic value of restricted stock unitsRSUs distributed during the years ended December 31, 2017, 20162019, 2018 and 20152017 was
$13 $16 million, $17$12 million and $11$13 million, respectively.
As of December 31, 2017,2019, there was approximately $3$4 million of unrecognized compensation cost related to the restricted stock units, which is expected to be recognized over a weighted average period of ten months. Dividend equivalents units of 30,066 accrued on the restricted stock units during the year.
Performance Share Units
Changes in performance share units for the year ended December 31, 2017 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, 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 units during the years ended December 31, 2017, 2016 and 2015 was $45.02, $45.97 and $41.32 per share, respectively.
The total intrinsic value of performance share units distributed during the years ended December 31, 2017, 2016 and 2015 was
$18 million, $17 million and $13 million, respectively.
As of December 31, 2017, there was approximately $16 million of unrecognized compensation cost related to the performance share units,RSUs, which is expected to be recognized over a weighted average period of one year. Dividend equivalents unitsDEUs of 38,42521,535 accrued on the performanceRSUs during the year.
PSUs
Changes in PSUs for the year ended December 31, 2019 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, 2019 | | 377,541 |
| | $ | 51.94 |
| | | | | |
| | Granted | | 320,078 |
| | $ | 62.17 |
| | | | | |
| | Vested | | 299,201 |
| | $ | 54.10 |
| | | | | |
| | Canceled/Forfeited | | 63,903 |
| | $ | 54.52 |
| | | | | |
| | Non-vested as of December 31, 2019 | | 334,515 |
| | $ | 59.30 |
| | 1.6 | | $ | 19,753,111 |
| |
| | | | | | | | | | | |
The weighted average grant date fair value per share unitsfor PSUs during the years ended December 31, 2019, 2018 and 2017 was $62.17, $54.95 and $45.02 per share, respectively.
The total intrinsic value of PSUs distributed during the years ended December 31, 2019, 2018 and 2017 was $17 million, $17 million and $18 million, respectively.
As of December 31, 2019, there was approximately $20 million of unrecognized compensation cost related to the PSUs, which is expected to be recognized over a weighted average period of 1.6 years. DEUs of 33,351 accrued on the PSUs during the year.
Outside Directors
Under the Directors Equity 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 Board as specified by him/her in accordance with the provisions of the Directors Equity 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 for each of the years ended December 31, 2017, 20162019, 2018 and 20152017.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Employee Stock Purchase Plan (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 through payroll deductions. Dividends will behad been reinvested for all employees at 95% of the fair market price unless the participant electselected to receive a cash dividend. Effective October 1, 2019, dividends are to be paid out in cash unless the participant elects the dividends to 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 $1 million for December 31, 2019, and immaterial for each of the years ended December 31, 2017, 20162018 and 2015.2017.
During the years ended December 31, 2017, 20162019, 2018 and 20152017, employees purchased 288,527280,077 shares, 262,763286,559 shares and 250,499288,527 shares, respectively, at an average price of $42.07, $40.70$54.67, $47.44 and $36.66$42.07 per share, respectively. As of December 31, 2017, 3.22019, 2.6 million shares were available for future issuance under this plan.
Note 19.21. Other Income and Deductions(Deductions)
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | PSE&G | | PSEG Power | | Other (A) | | Consolidated Total | |
| | | | Millions | |
| | Year Ended December 31, 2019 | | | | | | | | | |
| | NDT Fund Interest and Dividends | | $ | — |
| | $ | 57 |
| | $ | — |
| | $ | 57 |
| |
| | Allowance for Funds Used During Construction | | 59 |
| | — |
| | — |
| | 59 |
| |
| | Solar Loan Interest | | 16 |
| | — |
| | — |
| | 16 |
| |
| | Donations | | — |
| | — |
| | (11 | ) | | (11 | ) | |
| | Other | | 8 |
| | (3 | ) | | (1 | ) | | 4 |
| |
| | Total Other Income (Deductions) | | $ | 83 |
| | $ | 54 |
| | $ | (12 | ) | | $ | 125 |
| |
| | Year Ended December 31, 2018 | | | | | | | | | |
| | NDT Fund Interest and Dividends | | $ | — |
| | $ | 52 |
| | $ | — |
| | $ | 52 |
| |
| | Allowance for Funds Used During Construction | | 54 |
| | — |
| | — |
| | 54 |
| |
| | Solar Loan Interest | | 18 |
| | — |
| | — |
| | 18 |
| |
| | Donations | | — |
| | — |
| | (17 | ) | | (17 | ) | |
| | Other | | 8 |
| | (31 | ) | | 1 |
| | (22 | ) | |
| | Total Other Income (Deductions) | | $ | 80 |
| | $ | 21 |
| | $ | (16 | ) | | $ | 85 |
| |
| | Year Ended December 31, 2017 | | | | | | | | | |
| | NDT Fund Interest and Dividends | | $ | — |
| | $ | 45 |
| | $ | — |
| | $ | 45 |
| |
| | Allowance for Funds Used During Construction | | 56 |
| | — |
| | — |
| | 56 |
| |
| | Solar Loan Interest | | 21 |
| | — |
| | — |
| | 21 |
| |
| | Donations | | (1 | ) | | (2 | ) | | (25 | ) | | (28 | ) | |
| | Other | | 9 |
| | (23 | ) | | 2 |
| | (12 | ) | |
| | Total Other Income (Deductions) | | $ | 85 |
| | $ | 20 |
| | $ | (23 | ) | | $ | 82 |
| |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | 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 20.22. 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 21% in 2019 and 2018 and 35% in 2017 is as follows: |
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | Years Ended December 31, | |
| | PSEG | | 2019 | | 2018 | | 2017 | |
| | | | Millions | |
| | Net Income | | $ | 1,693 |
| | $ | 1,438 |
| | $ | 1,574 |
| |
| | Income Taxes: | | | | | | | |
| | Operating Income: | | | | | | | |
| | Current (Benefit) Expense: | | | | | | | |
| | Federal | | $ | 84 |
| | $ | (97 | ) | | $ | 86 |
| |
| | State | | 18 |
| | 83 |
| | (31 | ) | |
| | Total Current | | 102 |
| | (14 | ) | | 55 |
| |
| | Deferred Expense (Benefit): | | | | | | | |
| | Federal | | 3 |
| | 373 |
| | (482 | ) | |
| | State | | 132 |
| | 71 |
| | 92 |
| |
| | Total Deferred | | 135 |
| | 444 |
| | (390 | ) | |
| | Investment Tax Credit (ITC) | | 20 |
| | (13 | ) | | 29 |
| |
| | Total Income Tax Expense (Benefit) | | $ | 257 |
| | $ | 417 |
| | $ | (306 | ) | |
| | Pre-Tax Income | | $ | 1,950 |
| | $ | 1,855 |
| | $ | 1,268 |
| |
| | Tax Computed at Statutory Rate @ 21% in 2019 and 2018 and 35% in 2017 | | $ | 410 |
| | $ | 390 |
| | $ | 444 |
| |
| | Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: | | | | | | | |
| | State Income Taxes (net of federal income tax) | | 117 |
| | 123 |
| | 36 |
| |
| | Uncertain Tax Positions | | — |
| | (24 | ) | | (3 | ) | |
| | Manufacturing Deduction | | — |
| | — |
| | (13 | ) | |
| | NDT Fund | | 34 |
| | (13 | ) | | 19 |
| |
| | Plant-Related Items | | (2 | ) | | (10 | ) | | (23 | ) | |
| | Tax Credits | | (18 | ) | | (16 | ) | | (22 | ) | |
| | Audit Settlement | | — |
| | — |
| | 6 |
| |
| | Tax Adjustment Credit | | (272 | ) | | (30 | ) | | — |
| |
| | Deferred Tax Expense (Benefit) - Tax Act | | — |
| | 3 |
| | (755 | ) | |
| | Other | | (12 | ) | | (6 | ) | | 5 |
| |
| | Subtotal | | (153 | ) | | 27 |
| | (750 | ) | |
| | Total Income Tax Expense (Benefit) | | $ | 257 |
| | $ | 417 |
| | $ | (306 | ) | |
| | Effective Income Tax Rate | | 13.2 | % | | 22.5 | % | | (24.1 | )% | |
| | | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | 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 | % | |
| | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following is an analysis of deferred income taxes for PSEG:
|
| | | | | | | | | | |
| | | | | | | |
| | | | As of December 31, | |
| | PSEG | | 2019 | | 2018 | |
| | | | Millions | |
| | Deferred Income Taxes | | | | | |
| | Assets: | | | | | |
| | Noncurrent | | | | | |
| | Regulatory Liability Excess Deferred Tax | | $ | 539 |
| | $ | 606 |
| |
| | OPEB | | 151 |
| | 163 |
| |
| | Related to Uncertain Tax Positions | | 97 |
| | 71 |
| |
| | Interest Disallowance Carry Forward | | 76 |
| | — |
| |
| | Operating Leases | | 64 |
| | — |
| |
| | Other | | 128 |
| | — |
| |
| | Total Noncurrent Assets | | $ | 1,055 |
| | $ | 840 |
| |
| | | | | | | |
| | Liabilities: | | | | | |
| | Noncurrent: | | | | | |
| | Plant-Related Items | | $ | 5,051 |
| | $ | 4,817 |
| |
| | New Jersey Corporate Business Tax | | 876 |
| | 756 |
| |
| | Leasing Activities | | 284 |
| | 307 |
| |
| | AROs and NDT Fund | | 277 |
| | 196 |
| |
| | Taxes Recoverable Through Future Rates (net) | | 108 |
| | 89 |
| |
| | Pension Costs | | 98 |
| | 111 |
| |
| | Operating Leases | | 59 |
| | — |
| |
| | Other | | 273 |
| | 12 |
| |
| | Total Noncurrent Liabilities | | $ | 7,026 |
| | $ | 6,288 |
| |
| | Summary of Accumulated Deferred Income Taxes: | | | | | |
| | Net Noncurrent Deferred Income Tax Liabilities | | $ | 5,971 |
| | $ | 5,448 |
| |
| | ITC | | 285 |
| | 265 |
| |
| | Net Total Noncurrent Deferred Income Taxes and ITC | | $ | 6,256 |
| | $ | 5,713 |
| |
| | | | | | | |
|
| | | | | | | | | | |
| | | | | | | |
| | | | 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 |
| |
| | | | | | | |
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 PSE&G with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% in 2019 and 2018 and 35% in 2017 is as follows:
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | Years Ended December 31, | |
| | PSE&G | | 2019 | | 2018 | | 2017 | |
| | | | Millions | |
| | Net Income | | $ | 1,250 |
| | $ | 1,067 |
| | $ | 973 |
| |
| | Income Taxes: | | | | | | | |
| | Operating Income: | | | | | | | |
| | Current (Benefit) Expense: | | | | | | | |
| | Federal | | $ | 121 |
| | $ | (62 | ) | | $ | (52 | ) | |
| | State | | — |
| | 1 |
| | (1 | ) | |
| | Total Current | | 121 |
| | (61 | ) | | (53 | ) | |
| | Deferred Expense (Benefit): | | | | | | | |
| | Federal | | (156 | ) | | 287 |
| | 492 |
| |
| | State | | 117 |
| | 122 |
| | 129 |
| |
| | Total Deferred | | (39 | ) | | 409 |
| | 621 |
| |
| | ITC | | 11 |
| | (4 | ) | | (5 | ) | |
| | Total Income Tax Expense | | $ | 93 |
| | $ | 344 |
| | $ | 563 |
| |
| | Pre-Tax Income | | $ | 1,343 |
| | $ | 1,411 |
| | $ | 1,536 |
| |
| | Tax Computed at Statutory Rate @ 21% in 2019 and 2018 and 35% in 2017 | | $ | 282 |
| | $ | 296 |
| | $ | 538 |
| |
| | Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: | | | | | | | |
| | State Income Taxes (net of federal income tax) | | 92 |
| | 98 |
| | 83 |
| |
| | Uncertain Tax Positions | | 1 |
| | (1 | ) | | (9 | ) | |
| | Plant-Related Items | | (2 | ) | | (10 | ) | | (23 | ) | |
| | Tax Credits | | (8 | ) | | (8 | ) | | (9 | ) | |
| | Tax Adjustment Credit | | (272 | ) | | (30 | ) | | — |
| |
| | Deferred Tax Benefit - Tax Act | | — |
| | — |
| | (10 | ) | |
| | Other | | — |
| | (1 | ) | | (7 | ) | |
| | Subtotal | | (189 | ) | | 48 |
| | 25 |
| |
| | Total Income Tax Expense | | $ | 93 |
| | $ | 344 |
| | $ | 563 |
| |
| | Effective Income Tax Rate | | 6.9 | % | | 24.4 | % | | 36.7 | % | |
| | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following is an analysis of deferred income taxes for PSE&G:
|
| | | | | | | | | | |
| | | | | | | |
| | | | As of December 31, | |
| | PSE&G | | 2019 | | 2018 | |
| | | | Millions | |
| | Deferred Income Taxes | | | | | |
| | Assets: | | | | | |
| | Noncurrent: | | | | | |
| | Regulatory Liability Excess Deferred Tax | | $ | 539 |
| | $ | 606 |
| |
| | OPEB | | 97 |
| | 114 |
| |
| | Related to Uncertain Tax Positions | | 42 |
| | — |
| |
| | Operating Leases | | 21 |
| | — |
| |
| | Other | | 55 |
| | — |
| |
| | Total Noncurrent Assets | | $ | 754 |
| | $ | 720 |
| |
| | Liabilities: | | | | | |
| | Noncurrent: | | | | | |
| | Plant-Related Items | | $ | 3,754 |
| | $ | 3,622 |
| |
| | New Jersey Corporate Business Tax | | 588 |
| | 486 |
| |
| | Pension Costs | | 160 |
| | 159 |
| |
| | Taxes Recoverable Through Future Rates (net) | | 108 |
| | 89 |
| |
| | Conservation Costs | | 44 |
| | 36 |
| |
| | Operating Leases | | 21 |
| | — |
| |
| | Other | | 183 |
| | 84 |
| |
| | Total Noncurrent Liabilities | | $ | 4,858 |
| | $ | 4,476 |
| |
| | Summary of Accumulated Deferred Income Taxes: | | | | | |
| | Net Noncurrent Deferred Income Tax Liabilities | | $ | 4,104 |
| | $ | 3,756 |
| |
| | ITC | | 85 |
| | 74 |
| |
| | Net Total Noncurrent Deferred Income Taxes and ITC | | $ | 4,189 |
| | $ | 3,830 |
| |
| | | | | | | |
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A reconciliation of reported income tax expense for PSEG Power with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% in 2019 and 2018 and 35% in 2017 is as follows:
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | Years Ended December 31, | |
| | PSEG Power | | 2019 | | 2018 | | 2017 | |
| | | | Millions | |
| | Net Income | | $ | 468 |
| | $ | 365 |
| | $ | 479 |
| |
| | Income Taxes: | | | | | | | |
| | Operating Income: | | | | | | | |
| | Current (Benefit) Expense: | | | | | | | |
| | Federal | | $ | (48 | ) | | $ | (164 | ) | | $ | 95 |
| |
| | State | | 3 |
| | 24 |
| | (17 | ) | |
| | Total Current | | (45 | ) | | (140 | ) | | 78 |
| |
| | Deferred Expense (Benefit): | | | | | | | |
| | Federal | | 208 |
| | 214 |
| | (804 | ) | |
| | State | | 31 |
| | 1 |
| | (37 | ) | |
| | Total Deferred | | 239 |
| | 215 |
| | (841 | ) | |
| | ITC | | 9 |
| | (9 | ) | | 34 |
| |
| | Total Income Tax Expense (Benefit) | | $ | 203 |
| | $ | 66 |
| | $ | (729 | ) | |
| | Pre-Tax Income (Loss) | | $ | 671 |
| | $ | 431 |
| | $ | (250 | ) | |
| | Tax Computed at Statutory Rate @ 21% in 2019 and 2018 and 35% in 2017 | | $ | 141 |
| | $ | 91 |
| | $ | (88 | ) | |
| | Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: | | | | | | | |
| | State Income Taxes (net of federal income tax) | | 25 |
| | 21 |
| | (36 | ) | |
| | Manufacturing Deduction | | — |
| | — |
| | (13 | ) | |
| | NDT Fund | | 34 |
| | (13 | ) | | 19 |
| |
| | Tax Credits | | (10 | ) | | (7 | ) | | (12 | ) | |
| | Related to Uncertain Tax Positions | | 11 |
| | (24 | ) | | 7 |
| |
| | Audit Settlement | | — |
| | — |
| | 1 |
| |
| | Deferred Tax Benefit - Tax Act | | — |
| | (1 | ) | | (610 | ) | |
| | Other | | 2 |
| | (1 | ) | | 3 |
| |
| | Subtotal | | 62 |
| | (25 | ) | | (641 | ) | |
| | Total Income Tax Expense (Benefit) | | $ | 203 |
| | $ | 66 |
| | $ | (729 | ) | |
| | Effective Income Tax Rate | | 30.3 | % | | 15.3 | % | | 291.6 | % | |
| | | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | 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 PSEG Power:
|
| | | | | | | | | | |
| | | | | | | |
| | | | As of December 31, | |
| | PSEG Power | | 2019 | | 2018 | |
| | | | Millions | |
| | Deferred Income Taxes | | | | | |
| | Assets: | | | | | |
| | Noncurrent: | | | | | |
| | Related to Uncertain Tax Positions | | $ | 72 |
| | $ | 60 |
| |
| | Pension Costs | | 61 |
| | 52 |
| |
| | OPEB | | 40 |
| | 37 |
| |
| | Operating Leases | | 15 |
| | — |
| |
| | Interest Disallowance Carry Forward | | 12 |
| | — |
| |
| | Contractual Liabilities & Environmental Costs | | 7 |
| | 9 |
| |
| | Other | | 30 |
| | 61 |
| |
| | Total Noncurrent Assets | | $ | 237 |
| | $ | 219 |
| |
| | Liabilities: | | | | | |
| | Noncurrent: | | | | | |
| | Plant-Related Items | | $ | 1,292 |
| | $ | 1,189 |
| |
| | New Jersey Corporate Business Tax | | 282 |
| | 260 |
| |
| | AROs and NDT Fund | | 278 |
| | 197 |
| |
| | Operating Leases | | 15 |
| | — |
| |
| | Other | | 45 |
| | — |
| |
| | Total Noncurrent Liabilities | | $ | 1,912 |
| | $ | 1,646 |
| |
| | Summary of Accumulated Deferred Income Taxes: | | | | | |
| | Net Noncurrent Deferred Income Tax Liabilities | | $ | 1,675 |
| | $ | 1,427 |
| |
| | ITC | | 201 |
| | 192 |
| |
| | Net Total Noncurrent Deferred Income Taxes and ITC | | $ | 1,876 |
| | $ | 1,619 |
| |
| | | | | | | |
|
| | | | | | | | | | |
| | | | | | | |
| | | | 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, the deferred tax effect of asset retirement obligations is presented net of the deferred tax effect of the associated funding of those obligations.
PSEG, PSE&G and PSEG 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 6.7. Regulatory Assets and Liabilities.
In December 2017, the U.S. government enacted comprehensive tax legislation. The Tax Act establishes new tax laws that will take effect inEffective January 1, 2018, including, but not limited to (1) reduction of the U.S. federal corporate income tax rate was reduced from a maximum of 35% to 21%; (2) elimination of resulting in a decrease in PSEG’s, PSE&G’s and PSEG Power’s effective income tax rates. To 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 on net operating losses (NOLs) generated after December 31, 2017, to 80% of taxable income. In addition, certain changes were made to the bonus depreciation 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 fromextent allowed under the Tax Act, enactment date for companies to complete the accounting under ASC 740. In accordance with SAB 118, a company mustPSEG Power’s operating cash flows reflect the full expensing of qualifying capital investments for income tax effects of those aspectspurposes. The impact 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 estimate to be included in the financial statements, it should continue 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 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 change is enacted.
The majority of the current period activity was determined using thelower federal income tax rate on PSE&G was reflected in PSE&G’s 2018 distribution base rate proceeding and its 2018 transmission rate filing. The distribution base rate proceeding established a TAC mechanism that provides for the refund to customers of 35% and statethe excess deferred income tax rateregulatory liabilities as well as the flowback of 9%. As required under ASC 740,previously realized and current period deferred income taxes related to tax repair deductions. The accounting for the ending 2017 deferred tax balances were adjusted to reflect the enactedTAC mechanism results in lower revenues and lower tax expense and a current effective tax rate whichfor PSEG and PSE&G that is significantly lower than the statutory rate.
The decrease in the federal tax rate resulted in PSE&G recording excess deferred income taxes of approximately $2.1 billion and a Regulatory Liability of approximately $2.9 billion as of December 31, 2018. In 2019, PSE&G returned approximately $380 million of excess deferred income taxes and previously realized and current period deferred income taxes related to tax repair deductions to its customers with a reduction to tax expense of approximately $272 million. The flowback to customers of the excess deferred income taxes and previously realized tax repair deductions resulted in a one-time, provisional deferreddecrease of approximately $321 million in the Regulatory Liability. The current period tax benefit of $755 million, including $610 million related to Powerrepair deduction reduces tax expense and $149 million related to Energy Holdings (including other impacts relatedrevenue and recognizes a Regulatory Asset as PSE&G believes it is probable that the current period tax repair deductions flowed through to the new tax legislation, PSEG’s net non-cash provisional earnings benefit was $745 million, including $588 million related to Powercustomers will be recovered from customers in the future. See Note 7. Regulatory Assets and $147 million related to Energy
Liabilities for additional information.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Holdings). In addition,The Tax Act is generally expected to result in lower operating cash flows for PSE&G had excess deferred taxesresulting from the elimination of approximately $2.1 billion asbonus depreciation, partially offset by higher revenues due to the higher rate base.
In November 2018, the IRS issued proposed regulations addressing the interest disallowance rules contained in the Tax Act. For non-regulated businesses, these rules set a cap on the amount of December 31, 2017interest that can be deducted in a given year. Any amount that is disallowed can be carried forward indefinitely. For 2018 and recorded2019, a $2.9 billion revenue impactportion of these excess deferred taxes as Regulatory Liabilities wherePSEG’s and PSEG Power’s interest expense was disallowed for tax purposes but it is probableanticipated that refundsthese amounts will be made to customersrealized in future rates. The amount and timing of any such refund cannot be determined at this time.
Forperiods. However, certain aspects of the proposed regulations are unclear. PSEG recorded taxes based on its interpretation of the relevant statutes.
In September 2019, the IRS released final and additional proposed regulations regarding the application of tax depreciation rules as amended by the Tax Act, which are discussed below,Act. PSEG, PSE&G and PSEG Power made reasonable, good faith estimates for which provisional amounts were recorded.do not believe the final or proposed regulations will materially impact their respective financial statements.
PSEG’s accounting for the following elements ofAmounts recorded under the Tax Act, is incomplete. However, PSEG was ableincluding but not limited to make reasonable, good faith estimates of certain effectsdepreciation and therefore, recorded provisional adjustments forinterest disallowance, are subject to change based on several factors, including but not limited to, 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 PowerIRS and PSE&G, including the information required to compute the applicable depreciable tax basis, and thestate taxing authorities issuing additional guidance and/or further clarification. Any further guidance or clarification could 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 as state tax authorities. The Tax Act could also be subject to potential amendments and technical corrections which could impact PSEG PSE&G and Power’s financial statements.
In December 2015, the U.S. government enacted the Protecting Americans from2019, PSE&G generated a $16 million New Jersey Corporate Business Tax Hikes Act 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 propertyNOL that is placedexpected to be fully realized in service from January 1, 2015 through December 31, 2017 is eligible for 50% bonus depreciation. The provisions of the 2015 Tax Act have generated significant cashfuture. There are no other material tax benefits for PSEG, PSE&G and Power through tax benefits related to the accelerated depreciation. Those tax benefits would have otherwise been received over an estimated average 20 year period. However, the tax benefits have a negative impact on the rate base of several of PSE&G’s programs.carryforwards in other jurisdictions.
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, PSEG Power and Energy Holdings: |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | 2019 | | PSEG | | PSE&G | | PSEG Power | | Energy Holdings | |
| | | | Millions | |
| | Total Amount of Unrecognized Tax Benefits as of January 1, 2019 | | $ | 318 |
| | $ | 108 |
| | $ | 151 |
| | $ | 54 |
| |
| | Increases as a Result of Positions Taken in a Prior Period | | 17 |
| | 5 |
| | 8 |
| | 5 |
| |
| | Decreases as a Result of Positions Taken in a Prior Period | | (37 | ) | | (1 | ) | | (13 | ) | | (22 | ) | |
| | Increases as a Result of Positions Taken during the Current Period | | 27 |
| | 12 |
| | 15 |
| | — |
| |
| | Decreases as a Result of Positions Taken during the Current Period | | — |
| | — |
| | — |
| | — |
| |
| | Decreases as a Result of Settlements with Taxing Authorities | | (4 | ) | | — |
| | — |
| | (4 | ) | |
| | Decreases due to Lapses of Applicable Statute of Limitations | | — |
| | — |
| | — |
| | — |
| |
| | Total Amount of Unrecognized Tax Benefits as of December 31, 2019 | | $ | 321 |
| | $ | 124 |
| | $ | 161 |
| | $ | 33 |
| |
| | Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits | | (184 | ) | | (71 | ) | | (105 | ) | | (7 | ) | |
| | Regulatory Asset—Unrecognized Tax Benefits | | (46 | ) | | (46 | ) | | — |
| | — |
| |
| | Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) | | $ | 91 |
| | $ | 7 |
| | $ | 56 |
| | $ | 26 |
| |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | 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 |
| |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | 2018 | | PSEG | | PSE&G | | PSEG Power | | Energy Holdings | |
| | | | Millions | |
| | Total Amount of Unrecognized Tax Benefits as of January 1, 2018 | | $ | 334 |
| | $ | 135 |
| | $ | 142 |
| | $ | 53 |
| |
| | Increases as a Result of Positions Taken in a Prior Period | | 11 |
| | 4 |
| | 4 |
| | 3 |
| |
| | Decreases as a Result of Positions Taken in a Prior Period | | (70 | ) | | (31 | ) | | (37 | ) | | (2 | ) | |
| | Increases as a Result of Positions Taken during the Current Period | | 52 |
| | 3 |
| | 48 |
| | — |
| |
| | Decreases as a Result of Positions Taken during the Current Period | | (3 | ) | | (3 | ) | | — |
| | — |
| |
| | Decreases as a Result of Settlements with Taxing Authorities | | (6 | ) | | — |
| | (6 | ) | | — |
| |
| | Decreases due to Lapses of Applicable Statute of Limitations | | — |
| | — |
| | — |
| | — |
| |
| | Total Amount of Unrecognized Tax Benefits as of December 31, 2018 | | $ | 318 |
| | $ | 108 |
| | $ | 151 |
| | $ | 54 |
| |
| | Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits | | (173 | ) | | (57 | ) | | (104 | ) | | (12 | ) | |
| | Regulatory Asset—Unrecognized Tax Benefits | | (46 | ) | | (46 | ) | | — |
| | — |
| |
| | Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) | | $ | 99 |
| | $ | 5 |
| | $ | 47 |
| | $ | 42 |
| |
| | | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | 2017 | | PSEG | | PSE&G | | PSEG 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 |
| |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | 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 |
| |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | 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 |
| |
| | | | | | | | | | | |
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, | |
| | | | 2019 | | 2018 | | 2017 | |
| | | | Millions | |
| | PSEG | | $ | 40 |
| | $ | 43 |
| | $ | 70 |
| |
| | PSE&G | | $ | 16 |
| | $ | 12 |
| | $ | 25 |
| |
| | PSEG Power | | $ | 12 |
| | $ | 9 |
| | $ | 24 |
| |
| | Energy Holdings | | $ | 13 |
| | $ | 22 |
| | $ | 21 |
| |
| | | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | 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
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 | | $ | 190 |
| |
| | PSE&G | | $ | 107 |
| |
| | PSEG Power | | $ | 77 |
| |
| | | | | |
|
| | | | | | |
| | | | | |
| | Possible (Increase)/Decrease in Total Unrecognized Tax Benefits | | Over the next 12 Months | |
| | | | Millions | |
| | PSEG | | $ | 69 |
| |
| | PSE&G | | $ | 35 |
| |
| | Power | | $ | 30 |
| |
| | | | | |
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 | | PSEG Power | |
| | United States | | | | | | | |
| | Federal | | 2011-20162011-2018 | | N/A | | N/A | |
| | New Jersey | | 2006-20162011-2018 | | 2011-20162011-2018 | | N/A | |
| | Pennsylvania | | 2014-20162015-2018 | | 2014-20162015-2018 | | N/A | |
| | Connecticut | | 20162016-2018 | | N/A | | N/A | |
| | TexasMaryland | | 2008-2016 | | N/A | | N/A | |
| California | | 2006-20162016-2018 | | N/A | | N/A | |
| | New York | | 2014-20162017-2018 | | N/A | | 2014-2016N/A | |
| | | | | | | | | |
New Jersey State Tax Reform
166In July 2018, the State of New Jersey made changes to its income tax laws, including imposing a temporary surtax on allocated corporate taxable income of 2.5% effective January 1, 2018 and 2019 and 1.5% in 2020 and 2021, as well as requiring corporate taxpayers to file in a combined reporting group as defined under New Jersey law starting in 2019. Both provisions include an exemption for public utilities. PSEG believes PSE&G meets the definition of a public utility and, therefore, will not be impacted by the temporary surtax or be included in the combined reporting group.
The State of New Jersey issued further guidance regarding the temporary surtax and clarified that New Jersey net operating loss carryovers can be deducted in computing a taxpayer’s entire net income. This guidance has the effect of lowering or eliminating the temporary surtax.
There are certain aspects of the law that remain unclear. In particular, PSEG anticipates that the State of New Jersey will issue clarifying guidance regarding the combined reporting rules. Any further guidance or clarification could impact PSEG’s and PSEG Power’s financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 21.23. 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, 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 | ) | |
| | Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments to Retained Earnings | | — |
| | — |
| | (176 | ) | | (176 | ) | |
| | Current Period Other Comprehensive Income (Loss) | | | | | | | | | |
| | Other Comprehensive Income before Reclassifications | | (1 | ) | | 17 |
| | (25 | ) | | (9 | ) | |
| | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | — |
| | 29 |
| | 8 |
| | 37 |
| |
| | Net Current Period Other Comprehensive Income (Loss) | | (1 | ) | | 46 |
| | (17 | ) | | 28 |
| |
| | Net Change in Accumulated Other Comprehensive Income (Loss) | | (1 | ) | | 46 |
| | (193 | ) | | (148 | ) | |
| | Balance as of December 31, 2018 | | $ | (1 | ) | | $ | (360 | ) | | $ | (16 | ) | | $ | (377 | ) | |
| | Cumulative Effect Adjustment to Reclassify Stranded Tax Effects Resulting in the Change in the Federal Corporate Income Tax to Retained Earnings | | — |
| | (81 | ) | | — |
| | (81 | ) | |
| | Current Period Other Comprehensive Income (Loss) | | | | | | | | | |
| | Other Comprehensive Income before Reclassifications | | (17 | ) | | (70 | ) | | 49 |
| | (38 | ) | |
| | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | 3 |
| | 12 |
| | (8 | ) | | 7 |
| |
| | Net Current Period Other Comprehensive Income (Loss) | | (14 | ) | | (58 | ) | | 41 |
| | (31 | ) | |
| | Net Change in Accumulated Other Comprehensive Income (Loss) | | (14 | ) | | (139 | ) | | 41 |
| | (112 | ) | |
| | Balance as of December 31, 2019 | | $ | (15 | ) | | $ | (499 | ) | | $ | 25 |
| | $ | (489 | ) | |
| | | | | | | | | | | |
| | PSEG 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, 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 | ) | |
| | Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments to Retained Earnings | | — |
| | — |
| | (175 | ) | | (175 | ) | |
| | Current Period Other Comprehensive Income (Loss) | | | | | | | | | |
| | Other Comprehensive Income before Reclassifications | | — |
| | 16 |
| | (19 | ) | | (3 | ) | |
| | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | — |
| | 25 |
| | 6 |
| | 31 |
| |
| | Net Current Period Other Comprehensive Income (Loss) | | — |
| | 41 |
| | (13 | ) | | 28 |
| |
| | Net Change in Accumulated Other Comprehensive Income (Loss) | | — |
| | 41 |
| | (188 | ) | | (147 | ) | |
| | Balance as of December 31, 2018 | | $ | — |
| | $ | (306 | ) | | $ | (13 | ) | | $ | (319 | ) | |
| | Cumulative Effect Adjustment to Reclassify Stranded Tax Effects Resulting in the Change in the Federal Corporate Income Tax to Retained Earnings | | — |
| | (69 | ) | | — |
| | (69 | ) | |
| | Current Period Other Comprehensive Income (Loss) | | | | | | | | | |
| | Other Comprehensive Income before Reclassifications | | — |
| | (55 | ) | | 38 |
| | (17 | ) | |
| | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | | — |
| | 10 |
| | (6 | ) | | 4 |
| |
| | Net Current Period Other Comprehensive Income (Loss) | | — |
| | (45 | ) | | 32 |
| | (13 | ) | |
| | Net Change in Accumulated Other Comprehensive Income (Loss) | | — |
| | (114 | ) | | 32 |
| | (82 | ) | |
| | Balance as of December 31, 2019 | | $ | — |
| | $ | (420 | ) | | $ | 19 |
| | $ | (401 | ) | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | 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 | ) | |
| | | | | | | | | | | |
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 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 | | Non-Operating Pension and OPEB Credits (Costs) | | 10 |
| | (4 | ) | | 6 |
| |
| | Amortization of Actuarial Loss | | Non-Operating Pension and OPEB Credits (Costs) | | (51 | ) | | 21 |
| | (30 | ) | |
| | Total Pension and OPEB Plans | | | | (41 | ) | | 17 |
| | (24 | ) | |
| | Available-for-Sale Securities | | | | | | | | | |
| | Realized Gains (Losses) and Other-Than-Temporary Impairments (OTTI) | | Net Gains (Losses) on Trust Investments | | 134 |
| | (69 | ) | | 65 |
| |
| | Total Available-for-Sale Securities | | | | 134 |
| | (69 | ) | | 65 |
| |
| | Total | | | | $ | 96 |
| | $ | (53 | ) | | $ | 43 |
| |
| | | | | | | | | | | |
| | PSEG 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 | | Non-Operating Pension and OPEB Credits (Costs) | | $ | 9 |
| | $ | (4 | ) | | $ | 5 |
| |
| | Amortization of Actuarial Loss | | Non-Operating Pension and OPEB Credits (Costs) | | (44 | ) | | 18 |
| | (26 | ) | |
| | Total Pension and OPEB Plans | | | | (35 | ) | | 14 |
| | (21 | ) | |
| | Available-for-Sale Securities | | | | | | | | | |
| | Realized Gains (Losses) and OTTI | | Net Gains (Losses) on Trust Investments | | 125 |
| | (65 | ) | | 60 |
| |
| | Total Available-for-Sale Securities | | | | 125 |
| | (65 | ) | | 60 |
| |
| | Total | | | | $ | 90 |
| | $ | (51 | ) | | $ | 39 |
| |
| | | | | | | | | | | |
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 | ) | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | PSEG | | | | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement | |
| | | | | | Year Ended December 31, 2018 | |
| | 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 | | Non-Operating Pension and OPEB Credits (Costs) | | $ | 6 |
| | $ | (2 | ) | | $ | 4 |
| |
| | Amortization of Actuarial Loss | | Non-Operating Pension and OPEB Credits (Costs) | | (47 | ) | | 14 |
| | (33 | ) | |
| | Total Pension and OPEB Plans | | | | (41 | ) | | 12 |
| | (29 | ) | |
| | Available-for-Sale Securities | | | | | | | | | |
| | Realized Gains (Losses) | | Net Gains (Losses) on Trust Investments | | (13 | ) | | 5 |
| | (8 | ) | |
| | Total Available-for-Sale Securities | | | | (13 | ) | | 5 |
| | (8 | ) | |
| | Total | | | | $ | (54 | ) | | $ | 17 |
| | $ | (37 | ) | |
| | | | | | | | | | | |
| | PSEG Power | | | | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement | |
| | | | | | Year Ended December 31, 2018 | |
| | 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 | | Non-Operating Pension and OPEB Credits (Costs) | | $ | 5 |
| | $ | (1 | ) | | $ | 4 |
| |
| | Amortization of Actuarial Loss | | Non-Operating Pension and OPEB Credits (Costs) | | (40 | ) | | 11 |
| | (29 | ) | |
| | Total Pension and OPEB Plans | | | | (35 | ) | | 10 |
| | (25 | ) | |
| | Available-for-Sale Securities | | | | | | | | | |
| | Realized Gains (Losses) | | Net Gains (Losses) on Trust Investments | | (11 | ) | | 5 |
| | (6 | ) | |
| | Total Available-for-Sale Securities | | | | (11 | ) | | 5 |
| | (6 | ) | |
| | Total | | | | $ | (46 | ) | | $ | 15 |
| | $ | (31 | ) | |
| | | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | PSEG | | | | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement | |
| | | | | | Year Ended December 31, 2019 | |
| | 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 | | $ | (4 | ) | | $ | 1 |
| | $ | (3 | ) | |
| | Total Cash Flow Hedges | | | | (4 | ) | | 1 |
| | (3 | ) | |
| | Pension and OPEB Plans | | | | | | | | | |
| | Amortization of Prior Service (Cost) Credit | | Non-Operating Pension and OPEB Credits (Costs) | | 26 |
| | (7 | ) | | 19 |
| |
| | Amortization of Actuarial Loss | | Non-Operating Pension and OPEB Credits (Costs) | | (43 | ) | | 12 |
| | (31 | ) | |
| | Total Pension and OPEB Plans | | | | (17 | ) | | 5 |
| | (12 | ) | |
| | Available-for-Sale Securities | | | | | | | | | |
| | Realized Gains (Losses) | | Net Gains (Losses) on Trust Investments | | 13 |
| | (5 | ) | | 8 |
| |
| | Total Available-for-Sale Securities | | | | 13 |
| | (5 | ) | | 8 |
| |
| | Total | | | | $ | (8 | ) | | $ | 1 |
| | $ | (7 | ) | |
| | | | | | | | | | | |
| | PSEG Power | | | | Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement | |
| | | | | | Year Ended December 31, 2019 | |
| | 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 | | Non-Operating Pension and OPEB Credits (Costs) | | $ | 23 |
| | $ | (7 | ) | | $ | 16 |
| |
| | Amortization of Actuarial Loss | | Non-Operating Pension and OPEB Credits (Costs) | | (36 | ) | | 10 |
| | (26 | ) | |
| | Total Pension and OPEB Plans | | | | (13 | ) | | 3 |
| | (10 | ) | |
| | Available-for-Sale Securities | | | | | | | | | |
| | Realized Gains (Losses) | | Net Gains (Losses) on Trust Investments | | 10 |
| | (4 | ) | | 6 |
| |
| | Total Available-for-Sale Securities | | | | 10 |
| | (4 | ) | | 6 |
| |
| | Total | | | | $ | (3 | ) | | $ | (1 | ) | | $ | (4 | ) | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | 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 22.24. Earnings Per Share (EPS) and Dividends
EPS
Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding or vesting of restricted stock awards granted under PSEG’s stock compensation plans and upon payment of performance unitsPSUs or restricted stock units.RSUs. For additional information on PSEG’s stock compensation plans see Note 18.20. Stock Based Compensation. The following table shows the effect of these stock options, performance unitsPSUs and restricted stock unitsRSUs on the weighted average number of shares outstanding used in calculating diluted EPS:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | Years Ended December 31, | |
| | | | 2019 | | 2018 | | 2017 | |
| | | | Basic | | Diluted | | Basic | | Diluted | | Basic | | Diluted | |
| | EPS Numerator: | | | | | | | | | | | | | |
| | (Millions) | | | | | | | | | | | | | |
| | Net Income | | $ | 1,693 |
| | $ | 1,693 |
| | $ | 1,438 |
| | $ | 1,438 |
| | $ | 1,574 |
| | $ | 1,574 |
| |
| | EPS Denominator: | | | | | | | | | | | | | |
| | (Millions) | | | | | | | | | | | | | |
| | Weighted Average Common Shares Outstanding | | 504 |
| | 504 |
| | 504 |
| | 504 |
| | 505 |
| | 505 |
| |
| | Effect of Stock Based Compensation Awards | | — |
| | 3 |
| | — |
| | 3 |
| | — |
| | 2 |
| |
| | Total Shares | | 504 |
| | 507 |
| | 504 |
| | 507 |
| | 505 |
| | 507 |
| |
| | EPS: | | | | | | | | | | | | | |
| | Net Income | | $ | 3.35 |
| | $ | 3.33 |
| | $ | 2.85 |
| | $ | 2.83 |
| | $ | 3.12 |
| | $ | 3.10 |
| |
| | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | 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 |
| |
| | | | | | | | | | | | | | | |
There were approximately 0.4 million and 0.5 million stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect for the years ended December 31, 2016 and 2015, respectively.
For additional information on all the types of long-term incentive awards, see Note 18.20. Stock Based Compensation.
Dividends
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | Years Ended December 31, | |
| | Dividend Payments on Common Stock | | 2019 | | 2018 | | 2017 | |
| | Per Share | | $ | 1.88 |
| | $ | 1.80 |
| | $ | 1.72 |
| |
| | in Millions | | $ | 950 |
| | $ | 910 |
| | $ | 870 |
| |
| | | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | 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, 2018,18, 2020, PSEG’s Board of Directors approved a $0.45$0.49 per share common stock dividend for the first quarter of 2018.2020.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 23.25. Financial Information by Business Segment
Basis of Organization
PSEG’s, PSE&G’s and PSEG Power’s operating segments were determined by management in accordance with GAAP. These segments were determined based on how management measures performance based on segment Net Income, as illustrated in the following table, and how resources are allocated to each business. PSEG’s reportable segments are PSE&G and PSEG Power. PSE&G and PSEG Power each represent a single reportable segment and therefore no separate segment information is provided for these Registrants.
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 solar investments, sundry sales, the appliance service business, wholesale transmission services and other miscellaneous services.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSEG Power
PSEG Power earns revenues by selling energy, capacity and ancillary services on a wholesale basis under contract to power marketers and to load servingload-serving entities and by bidding energy, capacity and ancillary services into the markets for these products. A significant portion of PSEG Power’s revenue is obtained from the various ISOs in which PSEG 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. 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.
Other
This category 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.
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | 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 (A) | | Eliminations (B) | | Consolidated Total | |
| | | | Millions | |
| | Year Ended December 31, 2019 | | | | | | | | | | | |
| | Operating Revenues | | $ | 6,625 |
| | $ | 4,385 |
| | $ | 549 |
| | $ | (1,483 | ) | | $ | 10,076 |
| |
| | Depreciation and Amortization | | 837 |
| | 377 |
| | 34 |
| | — |
| | 1,248 |
| |
| | Operating Income (Loss) | | 1,469 |
| | 448 |
| | 26 |
| | — |
| | 1,943 |
| |
| | Income from Equity Method Investments | | — |
| | 14 |
| | — |
| | — |
| | 14 |
| |
| | Interest Income | | 18 |
| | 7 |
| | 6 |
| | (5 | ) | | 26 |
| |
| | Interest Expense | | 361 |
| | 119 |
| | 94 |
| | (5 | ) | | 569 |
| |
| | Income (Loss) before Income Taxes | | 1,343 |
| | 671 |
| | (64 | ) | | — |
| | 1,950 |
| |
| | Income Tax Expense (Benefit) | | 93 |
| | 203 |
| | (39 | ) | | — |
| | 257 |
| |
| | Net Income (Loss) (C) | | $ | 1,250 |
| | $ | 468 |
| | $ | (25 | ) | | $ | — |
| | $ | 1,693 |
| |
| | Gross Additions to Long-Lived Assets | | $ | 2,542 |
| | $ | 607 |
| | $ | 17 |
| | $ | — |
| | $ | 3,166 |
| |
| | As of December 31, 2019 | | | | | | | | | | | |
| | Total Assets | | $ | 33,266 |
| | $ | 12,805 |
| | $ | 2,715 |
| | $ | (1,056 | ) | | $ | 47,730 |
| |
| | Investments in Equity Method Subsidiaries | | $ | — |
| | $ | 66 |
| | $ | 1 |
| | $ | — |
| | $ | 67 |
| |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | PSE&G | | PSEG Power | | Other (A) | | Eliminations (B) | | Consolidated Total | |
| | | | Millions | |
| | Year Ended December 31, 2018 | | | | | | | | | | | |
| | Operating Revenues | | $ | 6,471 |
| | $ | 4,146 |
| | $ | 571 |
| | $ | (1,492 | ) | | $ | 9,696 |
| |
| | Depreciation and Amortization | | 770 |
| | 354 |
| | 34 |
| | — |
| | 1,158 |
| |
| | Operating Income (Loss) | | 1,606 |
| | 596 |
| | 96 |
| | — |
| | 2,298 |
| |
| | Income from Equity Method Investments | | — |
| | 15 |
| | — |
| | — |
| | 15 |
| |
| | Interest Income | | 21 |
| | 5 |
| | 9 |
| | (6 | ) | | 29 |
| |
| | Interest Expense | | 333 |
| | 76 |
| | 73 |
| | (6 | ) | | 476 |
| |
| | Income (Loss) before Income Taxes | | 1,411 |
| | 431 |
| | 13 |
| | — |
| | 1,855 |
| |
| | Income Tax Expense (Benefit) | | 344 |
| | 66 |
| | 7 |
| | — |
| | 417 |
| |
| | Net Income (Loss) | | $ | 1,067 |
| | $ | 365 |
| | $ | 6 |
| | $ | — |
| | $ | 1,438 |
| |
| | Gross Additions to Long-Lived Assets | | $ | 2,896 |
| | $ | 996 |
| | $ | 20 |
| | $ | — |
| | $ | 3,912 |
| |
| | As of December 31, 2018 | | | | | | | | | | | |
| | Total Assets | | $ | 31,109 |
| | $ | 12,594 |
| | $ | 2,604 |
| | $ | (981 | ) | | $ | 45,326 |
| |
| | Investments in Equity Method Subsidiaries | | $ | — |
| | $ | 86 |
| | $ | — |
| | $ | — |
| | $ | 86 |
| |
| | | | | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | PSE&G | | PSEG Power | | Other (A) | | Eliminations (B) | | Consolidated Total | |
| | | | Millions | |
| | Year Ended December 31, 2017 | | | | | | | | | | | |
| | Operating Revenues | | $ | 6,324 |
| | $ | 3,860 |
| | $ | 466 |
| | $ | (1,556 | ) | | $ | 9,094 |
| |
| | Depreciation and Amortization | | 685 |
| | 1,268 |
| | 33 |
| | — |
| | 1,986 |
| |
| | Operating Income (Loss) | | 1,760 |
| | (367 | ) | | 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 | | 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 PSEG Power. For a further discussion of the intercompany transactions between PSE&G and PSEG Power, see Note 24.26. Related-Party Transactions. |
| |
| (C) | Includes an after-tax loss of $286 million related to the sale of PSEG Power’s ownership interests in the Keystone and Conemaugh generation plants. See Note 4. Early Plant Retirements/Asset Dispositions for additional information. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 24.26. 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 | | 2019 | | 2018 | | 2017 | |
| | | | Millions | |
| | Billings from Affiliates: | | | | | | | |
| | Net Billings from PSEG Power (A) | | $ | 1,512 |
| | $ | 1,514 |
| | $ | 1,580 |
| |
| | Administrative Billings from Services (B) | | 310 |
| | 333 |
| | 331 |
| |
| | Total Billings from Affiliates | | $ | 1,822 |
| | $ | 1,847 |
| | $ | 1,911 |
| |
| | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | 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 | | 2019 | | 2018 | |
| | | | Millions | |
| | Receivables from PSEG (C) | | $ | 1 |
| | $ | 123 |
| |
| | Payable to PSEG Power (A) | | $ | 307 |
| | $ | 245 |
| |
| | Payable to Services (B) | | 83 |
| | 76 |
| |
| | Accounts Payable—Affiliated Companies | | $ | 390 |
| | $ | 321 |
| |
| | Working Capital Advances to Services (D) | | $ | 33 |
| | $ | 33 |
| |
| | Long-Term Accrued Taxes Payable | | $ | 115 |
| | $ | 69 |
| |
| | | | | | | |
|
| | | | | | | | | | |
| | | | | | | |
| | | | 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 |
| |
| | | | | | | |
PSEG Power
The financial statements for PSEG Power include transactions with related parties presented as follows:
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | Years Ended December 31, | |
| | Related Party Transactions | | 2019 | | 2018 | | 2017 | |
| | | | Millions | |
| | Billings to Affiliates: | | | | | | | |
| | Net Billings to PSE&G (A) | | $ | 1,512 |
| | $ | 1,514 |
| | 1,580 |
| |
| | Billings from Affiliates: | | | | | | | |
| | Administrative Billings from Services (B) | | $ | 156 |
| | $ | 145 |
| | $ | 168 |
| |
| | | | | | | | | |
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| | | | 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 |
| |
| | | | | | | | | |
174 |
| | | | | | | | | | |
| | | | | | | |
| | | | Years Ended December 31, | |
| | Related Party Transactions | | 2019 | | 2018 | |
| | | | Millions | |
| | Receivable from PSE&G (A) | | $ | 307 |
| | $ | 245 |
| |
| | Receivables from PSEG (C) | | 101 |
| | 29 |
| |
| | Accounts Receivable—Affiliated Companies | | $ | 408 |
| | $ | 274 |
| |
| | Payable to Services (B) | | $ | 5 |
| | $ | 16 |
| |
| | Accounts Payable—Affiliated Companies | | $ | 5 |
| | $ | 16 |
| |
| | Short-Term Loan to (from) Affiliate (E) | | $ | 149 |
| | $ | (193 | ) | |
| | Working Capital Advances to Services (D) | | $ | 17 |
| | $ | 17 |
| |
| | Long-Term Accrued Taxes Payable | | $ | 115 |
| | $ | 76 |
| |
| | | | | | | |
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 PSEG Power under which PSEG Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. PSEG Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process.process and sells ZECs to PSE&G under the ZEC program. 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 and PSEG Power at cost. In addition, PSE&G and PSEG 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 PSEG Power have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on PSE&G’s and PSEG Power’s Consolidated Balance Sheets. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| |
| (E) | PSEG 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 25.27. Selected Quarterly Data (Unaudited)
The information shown in the following tables, in the opinion of PSEG, PSE&G and PSEG Power includes all adjustments, consisting only of normal recurring accruals, necessary to fairly present such amounts.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | Quarter Ended | |
| | | | March 31, | | June 30, (A) | | September 30, | | December 31, (B) | |
| | | | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 | |
| | PSEG Consolidated: | | Millions, except per share data | |
| | Operating Revenues | | $ | 2,980 |
| | $ | 2,818 |
| | $ | 2,316 |
| | $ | 2,016 |
| | $ | 2,302 |
| | $ | 2,394 |
| | $ | 2,478 |
| | $ | 2,468 |
| |
| | Operating Income | | $ | 786 |
| | $ | 832 |
| | $ | 160 |
| | $ | 411 |
| | $ | 490 |
| | $ | 554 |
| | $ | 507 |
| | $ | 501 |
| |
| | Net Income | | $ | 700 |
| | $ | 558 |
| | $ | 153 |
| | $ | 269 |
| | $ | 403 |
| | $ | 412 |
| | $ | 437 |
| | $ | 199 |
| |
| | Earnings Per Share: | | | | | | | | | | | | | | | | | |
| | Basic: | | | | | | | | | | | | | | | | | |
| | Net Income | | $ | 1.39 |
| | $ | 1.11 |
| | $ | 0.30 |
| | $ | 0.53 |
| | $ | 0.80 |
| | $ | 0.82 |
| | $ | 0.86 |
| | $ | 0.39 |
| |
| | Diluted: | | | | | | | | | | | | | | | | | |
| | Net Income | | $ | 1.38 |
| | $ | 1.10 |
| | $ | 0.30 |
| | $ | 0.53 |
| | $ | 0.79 |
| | $ | 0.81 |
| | $ | 0.86 |
| | $ | 0.39 |
| |
| | Weighted Average Common Shares Outstanding: | | | | | | | | | | | | | | | | | |
| | Basic | | 504 |
| | 504 |
| | 504 |
| | 504 |
| | 504 |
| | 504 |
| | 504 |
| | 504 |
| |
| | Diluted | | 507 |
| | 507 |
| | 507 |
| | 507 |
| | 507 |
| | 507 |
| | 507 |
| | 508 |
| |
| | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | 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, | |
| | | | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 | |
| | PSE&G: | | Millions | |
| | Operating Revenues | | $ | 2,032 |
| | $ | 1,845 |
| | $ | 1,382 |
| | $ | 1,386 |
| | $ | 1,604 |
| | $ | 1,595 |
| | $ | 1,607 |
| | $ | 1,645 |
| |
| | Operating Income | | $ | 465 |
| | $ | 482 |
| | $ | 282 |
| | $ | 358 |
| | $ | 392 |
| | $ | 421 |
| | $ | 330 |
| | $ | 345 |
| |
| | Net Income | | $ | 403 |
| | $ | 319 |
| | $ | 227 |
| | $ | 231 |
| | $ | 344 |
| | $ | 278 |
| | $ | 276 |
| | $ | 239 |
| |
| | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | 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 | ) | |
| | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | Quarter Ended | |
| | | | March 31, | | June 30, (A) | | September 30, | | December 31, (B) | |
| | | | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 | |
| | PSEG Power: | | Millions | |
| | Operating Revenues | | $ | 1,416 |
| | $ | 1,403 |
| | $ | 1,083 |
| | $ | 767 |
| | $ | 771 |
| | $ | 868 |
| | $ | 1,115 |
| | $ | 1,108 |
| |
| | Operating Income (Loss) | | $ | 301 |
| | $ | 329 |
| | $ | (86 | ) | | $ | 42 |
| | $ | 79 |
| | $ | 112 |
| | $ | 154 |
| | $ | 113 |
| |
| | Net Income (Loss) | | $ | 296 |
| | $ | 234 |
| | $ | (40 | ) | | $ | 41 |
| | $ | 53 |
| | $ | 125 |
| | $ | 159 |
| | $ | (35 | ) | |
| | | | | | | | | | | | | | | | | | | |
| |
| (A) | The increasesdecrease in Operating Income and Net Income at PSEG consolidated and PSEG Power in the fourthsecond quarter 2017of 2019 as compared to the same quarter in 2016 were2018 was primarily due to higher coststhe loss in 20162019 related to closing the coal/gas Hudsonsale of PSEG Power’s ownership interests in the Keystone and Mercer units, which were fully depreciatedConemaugh fossil generation plants, offsetting MTM net gains in 2019 as of June 1, 2017. compared to net losses in 2018. |
| |
| (B) | The increasesincrease in Net Income at PSEG consolidated and PSEG Power in the fourth quarter 2017of 2019 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 legislation2018 was primarily due to net gains in December 2017. See Note 20. Income Taxes for additional information.2019 as compared to net losses in 2018 on equity securities in PSEG Power’s NDT Fund. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 26.28. Guarantees of Debt
PSEG 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 PSEG Power’s non-guarantor subsidiaries, as of December 31, 20172019 and 20162018 and for the years ended December 31, 2017, 20162019, 2018 and 20152017.
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | 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 | ) | |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | PSEG Power | | Guarantor Subsidiaries | | Other Subsidiaries | | Consolidating Adjustments | | Total | |
| | | | Millions | |
| | Year Ended December 31, 2019 | | | | | | | | | | | |
| | Operating Revenues | | $ | — |
| | $ | 4,315 |
| | $ | 299 |
| | $ | (229 | ) | | $ | 4,385 |
| |
| | Operating Expenses | | 12 |
| | 3,852 |
| | 302 |
| | (229 | ) | | 3,937 |
| |
| | Operating Income (Loss) | | (12 | ) | | 463 |
| | (3 | ) | | — |
| | 448 |
| |
| | Equity Earnings (Losses) of Subsidiaries | | 554 |
| | (34 | ) | | 14 |
| | (520 | ) | | 14 |
| |
| | Net Gains (Losses) on Trust Investments | | 3 |
| | 250 |
| | — |
| | — |
| | 253 |
| |
| | Other Income (Deductions) | | 168 |
| | 206 |
| | — |
| | (320 | ) | | 54 |
| |
| | Non-Operating Pension and OPEB Credits (Costs) | | — |
| | 20 |
| | 1 |
| | — |
| | 21 |
| |
| | Interest Expense | | (284 | ) | | (104 | ) | | (51 | ) | | 320 |
| | (119 | ) | |
| | Income Tax Benefit (Expense) | | 39 |
| | (265 | ) | | 23 |
| | — |
| | (203 | ) | |
| | Net Income (Loss) | | $ | 468 |
| | $ | 536 |
| | $ | (16 | ) | | $ | (520 | ) | | $ | 468 |
| |
| | Comprehensive Income (Loss) | | $ | 455 |
| | $ | 565 |
| | $ | (16 | ) | | $ | (549 | ) | | $ | 455 |
| |
| | As of December 31, 2019 | | | | | | | | | | | |
| | Current Assets | | $ | 4,235 |
| | $ | 1,870 |
| | $ | 376 |
| | $ | (4,755 | ) | | $ | 1,726 |
| |
| | Property, Plant and Equipment, net | | 46 |
| | 4,426 |
| | 3,954 |
| | — |
| | 8,426 |
| |
| | Investment in Subsidiaries | | 5,363 |
| | 1,075 |
| | — |
| | (6,438 | ) | | — |
| |
| | Noncurrent Assets | | 300 |
| | 2,467 |
| | 100 |
| | (214 | ) | | 2,653 |
| |
| | Total Assets | | $ | 9,944 |
| | $ | 9,838 |
| | $ | 4,430 |
| | $ | (11,407 | ) | | $ | 12,805 |
| |
| | Current Liabilities | | $ | 1,010 |
| | $ | 2,691 |
| | $ | 2,113 |
| | $ | (4,755 | ) | | $ | 1,059 |
| |
| | Noncurrent Liabilities | | 610 |
| | 2,104 |
| | 922 |
| | (214 | ) | | 3,422 |
| |
| | Long-Term Debt | | 2,434 |
| | — |
| | — |
| | — |
| | 2,434 |
| |
| | Member’s Equity | | 5,890 |
| | 5,043 |
| | 1,395 |
| | (6,438 | ) | | 5,890 |
| |
| | Total Liabilities and Member’s Equity | | $ | 9,944 |
| | $ | 9,838 |
| | $ | 4,430 |
| | $ | (11,407 | ) | | $ | 12,805 |
| |
| | Year Ended December 31, 2019 | | | | | | | | | | | |
| | Net Cash Provided By (Used In) Operating Activities | | $ | 107 |
| | $ | 1,507 |
| | $ | 94 |
| | $ | (229 | ) | | $ | 1,479 |
| |
| | Net Cash Provided By (Used In) Investing Activities | | $ | 119 |
| | $ | (846 | ) | | $ | (257 | ) | | $ | 223 |
| | $ | (761 | ) | |
| | Net Cash Provided By (Used In) Financing Activities | | $ | (225 | ) | | $ | (664 | ) | | $ | 164 |
| | $ | 6 |
| | $ | (719 | ) | |
| | | | | | | | | | | | | |
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 | ) | |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | PSEG Power | | Guarantor Subsidiaries | | Other Subsidiaries | | Consolidating Adjustments | | Total | |
| | | | Millions | |
| | Year Ended December 31, 2018 | | | | | | | | | | | |
| | Operating Revenues | | $ | — |
| | $ | 4,078 |
| | $ | 224 |
| | $ | (156 | ) | | $ | 4,146 |
| |
| | Operating Expenses | | 14 |
| | 3,460 |
| | 232 |
| | (156 | ) | | 3,550 |
| |
| | Operating Income (Loss) | | (14 | ) | | 618 |
| | (8 | ) | | — |
| | 596 |
| |
| | Equity Earnings (Losses) of Subsidiaries | | 406 |
| | (28 | ) | | 15 |
| | (378 | ) | | 15 |
| |
| | Net Gains (Losses) on Trust Investments | | (1 | ) | | (139 | ) | | — |
| | — |
| | (140 | ) | |
| | Other Income (Deductions) | | 135 |
| | 166 |
| | — |
| | (280 | ) | | 21 |
| |
| | Non-Operating Pension and OPEB Credits (Costs) | | — |
| | 13 |
| | 2 |
| | — |
| | 15 |
| |
| | Interest Expense | | (230 | ) | | (96 | ) | | (30 | ) | | 280 |
| | (76 | ) | |
| | Income Tax Benefit (Expense) | | 69 |
| | (143 | ) | | 8 |
| | — |
| | (66 | ) | |
| | Net Income (Loss) | | $ | 365 |
| | $ | 391 |
| | $ | (13 | ) | | $ | (378 | ) | | $ | 365 |
| |
| | Comprehensive Income (Loss) | | $ | 393 |
| | $ | 379 |
| | $ | (13 | ) | | $ | (366 | ) | | $ | 393 |
| |
| | As of December 31, 2018 | | | | | | | | | | | |
| | Current Assets | | $ | 4,317 |
| | $ | 1,479 |
| | $ | 304 |
| | $ | (4,593 | ) | | $ | 1,507 |
| |
| | Property, Plant and Equipment, net | | 49 |
| | 4,971 |
| | 3,822 |
| | — |
| | 8,842 |
| |
| | Investment in Subsidiaries | | 5,062 |
| | 1,107 |
| | — |
| | (6,169 | ) | | — |
| |
| | Noncurrent Assets | | 273 |
| | 2,109 |
| | 101 |
| | (238 | ) | | 2,245 |
| |
| | Total Assets | | $ | 9,701 |
| | $ | 9,666 |
| | $ | 4,227 |
| | $ | (11,000 | ) | | $ | 12,594 |
| |
| | Current Liabilities | | $ | 437 |
| | $ | 2,971 |
| | $ | 2,027 |
| | $ | (4,593 | ) | | $ | 842 |
| |
| | Noncurrent Liabilities | | 513 |
| | 1,996 |
| | 730 |
| | (238 | ) | | 3,001 |
| |
| | Long-Term Debt | | 2,791 |
| | — |
| | — |
| | — |
| | 2,791 |
| |
| | Member’s Equity | | 5,960 |
| | 4,699 |
| | 1,470 |
| | (6,169 | ) | | 5,960 |
| |
| | Total Liabilities and Member’s Equity | | $ | 9,701 |
| | $ | 9,666 |
| | $ | 4,227 |
| | $ | (11,000 | ) | | $ | 12,594 |
| |
| | Year Ended December 31, 2018 | | | | | | | | | | | |
| | Net Cash Provided By (Used In) Operating Activities | | $ | (74 | ) | | $ | 1,007 |
| | $ | 42 |
| | $ | 109 |
| | $ | 1,084 |
| |
| | Net Cash Provided By (Used In) Investing Activities | | $ | (402 | ) | | $ | (1,034 | ) | | $ | (406 | ) | | $ | 791 |
| | $ | (1,051 | ) | |
| | Net Cash Provided By (Used In) Financing Activities | | $ | 476 |
| | $ | 27 |
| | $ | 354 |
| | $ | (900 | ) | | $ | (43 | ) | |
| | | | | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | PSEG Power | | Guarantor Subsidiaries | | Other Subsidiaries | | Consolidating Adjustments | | Total | |
| | | | Millions | |
| | Year Ended December 31, 2017 | | | | | | | | | | | |
| | Operating Revenues | | $ | — |
| | $ | 3,821 |
| | $ | 174 |
| | $ | (135 | ) | | $ | 3,860 |
| |
| | Operating Expenses | | 8 |
| | 4,159 |
| | 195 |
| | (135 | ) | | 4,227 |
| |
| | Operating Income (Loss) | | (8 | ) | | (338 | ) | | (21 | ) | | — |
| | (367 | ) | |
| | Equity Earnings (Losses) of Subsidiaries | | 567 |
| | 60 |
| | 14 |
| | (627 | ) | | 14 |
| |
| | Net Gains (Losses) on Trust Investments | | 3 |
| | 122 |
| | — |
| | — |
| | 125 |
| |
| | Other Income (Deductions) | | 71 |
| | 91 |
| | 2 |
| | (144 | ) | | 20 |
| |
| | Non-Operating Pension and OPEB Credits (Costs) | | — |
| | 8 |
| | — |
| | — |
| | 8 |
| |
| | 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 |
| |
| | 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 | ) | |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | 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, PSE&G and PSEG 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 PSEG Power. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The CFO and CEO of each of PSEG, PSE&G and PSEG 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, PSE&G and PSEG Power
We have conducted assessments of our internal control over financial reporting as of December 31, 20172019, 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, PSE&G’s and PSEG Power’s internal control over financial reporting are included on pages 180, 181 182 and 183,182, 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 184.183. Management has concluded that internal control over financial reporting is effective as of December 31, 20172019.
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 20172019 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
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, 20172019 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, 2017.2019.
PSEG’s external auditors, Deloitte & Touche LLP, have audited PSEG’s financial statements for the year ended December 31, 20172019 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 | |
| Chief Executive Officer | |
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/s/ DANIEL J. CREGG | |
| Chief Financial Officer | |
February 26, 20182020 | |
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, 20172019 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, 2017.2019.
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/s/ RALPH IZZO | |
| Chief Executive Officer | |
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/s/ DANIEL J. CREGG | |
| Chief Financial Officer | |
February 26, 20182020 | |
MANAGEMENT REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING—PSEG Power
Management of PSEG Power LLC (Power)(PSEG 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).
PSEG 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 PSEG 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 PSEG Power are being made only in accordance with authorizations of PSEG Power’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of PSEG Power’s assets that could have a material effect on the financial statements.
In connection with the preparation of PSEG Power’s annual financial statements, management of PSEG Power has undertaken an assessment, which includes the design and operational effectiveness of PSEG 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 PSEG Power’s internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of PSEG Power’s financial reporting and the preparation of its financial statements as of December 31, 20172019 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, 2017.2019.
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/s/ RALPH IZZO | |
| Chief Executive Officer | |
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/s/ DANIEL J. CREGG | |
| Chief Financial Officer | |
February 26, 20182020 | |
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”) as of December 31, 2017,2019, 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, 2017,2019, 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, 20172019 of the Company and our report dated February 26, 2018,2020 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.
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, New Jersey
February 26, 20182020
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 PSEG 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 20182020 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, 201816, 2020 and which information set forth under said heading is incorporated herein by this reference thereto.
PSE&G and PSEG 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.jsphttp://corporate.pseg.com/aboutpseg/leadershipandgovernance/standardsofconduct. We will send youYou 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:http://corporate.pseg.com/aboutpseg/leadershipandgovernance/standardsofintegrity:
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 2017,2019, 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“Security Ownership of Directors, Management and Certain Beneficial Owners-Delinquent Section 16(a) Beneficial Ownership Reporting Compliance,”Reports” in
PSEG’s definitive Proxy Statement for the 20182020 Annual Meeting of Stockholders, which definitive Proxy Statement is expected to be filed with the SEC on or about March 12, 201816, 2020 and which information set forth under said heading is incorporated herein by this reference thereto.
PSEG 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 20182020 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 12, 201816, 2020 and such information set forth under such heading is incorporated herein by this reference thereto.
PSEG 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
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 20182020 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 12, 201816, 2020 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.
PowerPSE&G and PSE&GPSEG Power
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”Party Transactions” in PSEG’s definitive Proxy Statement for the 20182020 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 12, 201816, 2020 and such information set forth under such heading is incorporated herein by this reference thereto.
PSEG Power and PSE&G
Omitted pursuant to conditions set forth in General Instruction I of Form 10K.10-K.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by Item 14 of Form 10-K is set forth under the heading “Fees Billed by Deloitte & Touche LLP for 20172019 and 2016”2018” in PSEG’s definitive Proxy Statement for the 20182020 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 12, 2018.16, 2020. 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:
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| a. | Public Service Enterprise Group Incorporated’s Consolidated Balance Sheets as of December 31, 20172019 and 20162018 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Stockholders’ Equity for the three years ended December 31, 20172019 on pages 7773 through 82.78. |
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| b. | Public Service Electric and Gas Company’s Consolidated Balance Sheets as of December 31, 20172019 and 20162018 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Common Stockholder’s Equity for the three years ended December 31, 20172019 on pages 8379 through 88.84. |
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| c. | PSEG Power LLC’s Consolidated Balance Sheets as of December 31, 20172019 and 20162018 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Capitalization and Member’s Equity for the three years ended December 31, 20172019 on pages 8985 through 94.90. |
(B) The following documents are filed as a part of this report:
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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, 20172019 (page 193)192).
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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, 20172019 (page 193)192).
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| c. | PSEG Power’s Financial Statement Schedules: |
Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 20172019 (page 193)192).
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:
| LIST OF EXHIBITS: |
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| a. | | PSEG: |
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| LIST OF EXHIBITS: |
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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 |
| 104 | | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
b. | | PSE&G |
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LIST OF EXHIBITS: |
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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)(31), 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: |
| 4a(2) | | June 1, 1937(31)(32) |
| 4a(3) | | July 1, 1937(32)(33) |
| 4a(4) | | MarchJune 1, 19421991 (No. 1)(33)(34)
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| 4a(5) | | June 1, 1991 (No. 1)(34)
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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)(45) |
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LIST OF EXHIBITS: |
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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 |
| 104 | | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
| c. | | PSEG Power: |
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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 |
| LIST OF EXHIBITS: |
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| 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) |
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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. |
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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 thewith 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 JuneSeptember 30, 2017,2019, File No. 001-09120, on July 28, 2017October 31, 2019 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 JuneSeptember 30, 2017,2019, File No. 001-09120, on July 28, 2017October 31, 2019 and incorporated herein by this reference. |
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| (9) | Filed as Exhibit 10a(3) 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. |
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| (10) | 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, 2011,2018, File No. 001-09120 on November 1, 2011February 27, 2019 and incorporated herein by this reference. |
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| (11) | Filed as Exhibit 10a(7)10a(5) with Annual Report on Form 10-K for the year ended December 31, 2011,2018, File No. 001-09120 on February 27, 20122019 and incorporated herein by this reference. |
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| (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. |
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| (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. |
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| (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. |
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| (15) | Filed as Exhibit 10.3 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. |
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| (16) | 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. |
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(16)(17) | 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. |
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(17)(18) | 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. |
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(18)(19) | 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. |
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(19)(20) | 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. |
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(20)(21) | Filed as Exhibit 10a(19)10a(15) with Annual Report on Form 10-K for the year ended December 31, 2011,2018, File No. 001-09120 on February 27, 2012. |
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(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, 20112019 and incorporated herein by this reference. |
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| (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, 2015.2015, and incorporated herein by this reference. |
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| (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, 2015.2015, and incorporated herein by this reference. |
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| (24) | Filed as Exhibit 3(a)10a(20) with QuarterlyAnnual Report on Form 10-Q10-K for the quarteryear ended June 30, 1986,December 31, 2017, File No. 001-00973,001-09120 on August 28, 1986February 26, 2018 and incorporated herein by this reference. |
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| (25) | Filed as Exhibit 3a(2) with Annual Report3a(1) on Form 10-K for the year ended December 31, 1987,8-A, File No. 001-00973, on March 28, 1988February 4, 1994 and incorporated herein by this reference. |
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| (26) | Filed as Exhibit 3a(2) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference. |
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(26)(27) | Filed as Exhibit 3a(3) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference. |
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(27)(28) | Filed as Exhibit 3a(4) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference. |
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(28)(29) | Filed as Exhibit 3a(5) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference. |
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(29)(30) | 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. |
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(30)(31) | 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)(32) | 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. |
| |
(32)(33) | 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 44(i) on Form 8-A, File No. 001-00973, on June 1, 1991 and incorporated herein by this reference. |
| |
| (35) | Filed as Exhibit 4(i)4(ii) on Form 8-A, File No. 001-00973, on December 1,May 25, 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(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. |
| |
(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, 2013.2013, 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, 2013.2013, 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 4(a)(14)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 4 with Current Report on Form 8-K, File No. 001-00973, on December 1, 1993 and incorporated herein by this reference. |
| |
(45)(46) | Filed as Exhibit 4.64-6 to Registration Statement on Form S-3, File No. 333-76020, filed on December 27, 2001 and incorporated herein by this reference. |
| |
(46)(47) | 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. |
| |
(47)(48) | 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)(49) | 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)(50) | 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)(51) | 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—2019—December 31, 20152017
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 | |
| | 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 |
| |
| | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | 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 | |
| | 2019 | | | | | | | | | | | | | |
| | Allowance for Doubtful Accounts | | $ | 63 |
| | $ | 87 |
| | $ | — |
| | $ | 90 |
| | (A) | | $ | 60 |
| |
| | Materials and Supplies Valuation Reserve | | 9 |
| | 3 |
| | — |
| | 1 |
| | (B) | | 11 |
| |
| | 2018 | | | | | | | | | | | | | |
| | Allowance for Doubtful Accounts | | $ | 59 |
| | $ | 91 |
| | $ | — |
| | $ | 87 |
| | (A) | | $ | 63 |
| |
| | Materials and Supplies Valuation Reserve | | 7 |
| | 4 |
| | — |
| | 2 |
| | (B) | | 9 |
| |
| | 2017 | | | | | | | | | | | | | |
| | Allowance for Doubtful Accounts | | $ | 68 |
| | $ | 76 |
| | $ | — |
| | $ | 85 |
| | (A) | | $ | 59 |
| |
| | Materials and Supplies Valuation Reserve | | 37 |
| | 2 |
| | — |
| | 32 |
| | (C) | | 7 |
| |
| | | | | | | | | | | | | | | |
| |
| (A) | Accounts Receivable written off. |
| |
| (B) | Reduce reserve to appropriate level and to remove obsolete inventory. |
| |
| (C) | Hudson and Mercer inventory written off. |
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 | |
| | 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 |
| |
| | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | 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 | |
| | 2019 | | | | | | | | | | | | | |
| | Allowance for Doubtful Accounts | | $ | 63 |
| | $ | 87 |
| | $ | — |
| | $ | 90 |
| | (A) | | $ | 60 |
| |
| | Materials and Supplies Valuation Reserve | | 2 |
| | — |
| | — |
| | — |
| | | | 2 |
| |
| | 2018 | | | | | | | | | | | | | |
| | Allowance for Doubtful Accounts | | $ | 59 |
| | $ | 91 |
| | $ | — |
| | $ | 87 |
| | (A) | | $ | 63 |
| |
| | Materials and Supplies Valuation Reserve | | — |
| | 2 |
| | — |
| | — |
| | | | 2 |
| |
| | 2017 | | | | | | | | | | | | | |
| | Allowance for Doubtful Accounts | | $ | 68 |
| | $ | 76 |
| | $ | — |
| | $ | 85 |
| | (A) | | $ | 59 |
| |
| | Materials and Supplies Valuation Reserve | | — |
| | — |
| | — |
| | — |
| | | | — |
| |
| | | | | | | | | | | | | | | |
| |
| (A) | Accounts Receivable written off. |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | 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 | | | | | | | |
| | 2019 | | | | | | | | | | | | | |
| | Materials and Supplies Valuation Reserve | | $ | 7 |
| | $ | 3 |
| | $ | — |
| | $ | 1 |
| | (A) | | $ | 9 |
| |
| | 2018 | | | | | | | | | | | | | |
| | Materials and Supplies Valuation Reserve | | $ | 7 |
| | $ | 2 |
| | $ | — |
| | $ | 2 |
| | (A) | | $ | 7 |
| |
| | 2017 | | | | | | | | | | | | | |
| | Materials and Supplies Valuation Reserve | | $ | 37 |
| | $ | 2 |
| | $ | — |
| | $ | 32 |
| | (B) | | $ | 7 |
| |
| | | | | | | | | | | | | | | |
| |
(B)(A) | 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)(B) | 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 |
| | | | Ralph Izzo |
| | | | Chairman of the Board, President and |
| | | | Chief Executive Officer |
Date: February 26, 20182020
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 |
| | | |
/s/ RALPH IZZO | | Chairman of the Board, President, Chief Executive Officer and | | February 26, 20182020 |
| Ralph Izzo | | Director (Principal Executive Officer) | | |
| | | |
/s/ DANIEL J. CREGG | | Executive Vice President and Chief Financial Officer | | February 26, 20182020 |
| Daniel J. Cregg | | (Principal Financial Officer) | | |
| | | |
/s/ STUART J. BLACKROSE M. CHERNICK | | Vice President and Controller | | February 26, 20182020 |
Stuart J. BlackRose M. Chernick | | (Principal Accounting Officer) | | |
| | | |
/s/ WILLIE A. DEESE | | Director | | February 26, 20182020 |
| Willie A. Deese | | | | |
| | | | | |
/s/ ALBERT R. GAMPER, JR.WILLIAM V. HICKEY | | Director | | February 26, 2018 |
Albert R. Gamper, Jr. | | | | |
| | |
/s/ WILLIAM V. HICKEY
| | Director | | February 26, 20182020 |
| William V. Hickey | | | | |
| | | |
/s/ SHIRLEY ANN JACKSON | | Director | | February 26, 20182020 |
| Shirley Ann Jackson | | | | |
| | | |
/s/ DAVID LILLEY | | Director | | February 26, 20182020 |
| David Lilley | | | | |
| | | | | |
/s/ BARRY H. OSTROWSKYBARRY H. OSTROWSKY | | Director | | February 26, 20182020 |
| Barry H. Ostrowsky | | | | |
| | | |
/s/ THOMASLAURA A. RENYISUGG | | Director | | February 26, 20182020 |
ThomasLaura A. Renyi | | | | |
| | |
/s/ HAK CHEOL SHIN
| | Director | | February 26, 2018 |
Hak Cheol Shin | | | | |
| | |
/s/ RICHARD J. SWIFT
| | Director | | February 26, 2018 |
Richard J. SwiftSugg | | | | |
| | | | | |
/s/ JOHN P. SUSAN TOMASKYURMA | | Director | | February 26, 20182020 |
| John P. Surma | | | | |
| | | | |
/s/ RICHARD J. SWIFT | | Director | | February 26, 2020 |
| Richard J. Swift | | | | |
| | |
/s/ SUSAN TOMASKY | | Director | | February 26, 2020 |
| Susan Tomasky | | | | |
| | | | | |
/s/ ALFRED W. ZOLLAR | | Director | | February 26, 20182020 |
| 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/ DAVID M. DALY |
| | | | David M. Daly |
| | | | President and Chief Operating Officer |
Date: February 26, 20182020
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 |
| | | |
/s/ RALPH IZZO | | Chairman of the Board and Chief Executive Officer and | | February 26, 20182020 |
| Ralph Izzo | | Director (Principal Executive Officer) | | |
| | | |
/s/ DANIEL J. CREGG | | Executive Vice President and Chief Financial Officer | | February 26, 20182020 |
| Daniel J. Cregg | | (Principal Financial Officer) | | |
| | | |
/s/ STUART J. BLACKROSE M. CHERNICK | | Vice President and Controller | | February 26, 20182020 |
Stuart J. BlackRose M. Chernick | | (Principal Accounting Officer) | | |
| | | |
/s/ ALBERT R. GAMPER, JR.WILLIAM V. HICKEY | | Director | | February 26, 20182020 |
Albert R. Gamper Jr.William V. Hickey | | | | |
| | | | | |
/s/ SHIRLEY ANN JACKSON | | Director | | February 26, 20182020 |
| Shirley Ann Jackson | | | | |
| | | | | |
/s/ RICHARD J. SWIFT | | Director | | February 26, 20182020 |
| 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.
|
| | | |
| | | | |
| | | | PSEG POWER LLC |
| | | | |
| | | By: | /s/ RALPH A. LAROSSA |
| | | | Ralph A. LaRossa |
| | | | President and Chief Operating Officer |
| | | | |
Date: February 26, 20182020
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 |
| | | |
/s/ RALPH IZZO | | Chairman of the Board and Chief Executive Officer and | | February 26, 20182020 |
| Ralph Izzo | | Director (Principal Executive Officer) | | |
| | | |
/s/ DANIEL J. CREGG | | Executive Vice President and Chief Financial Officer and | | February 26, 20182020 |
| Daniel J. Cregg | | Director (Principal Financial Officer) | | |
�� | | |
/s/ STUART J. BLACKROSE M. CHERNICK | | Vice President and Controller | | February 26, 20182020 |
Stuart J. BlackRose M. Chernick | | (Principal Accounting Officer) | | |
| | | |
/s/ DEREK M. DIRISIO | | Director | | February 26, 20182020 |
| Derek M. DiRisio | | | | |
| | | |
/s/ RALPH A. LAROSSA | | Director | | February 26, 20182020 |
| Ralph A. LaRossa | | | | |
| | | | | |
/s/ TAMARA L. LINDE | | Director | | February 26, 20182020 |
| Tamara L. Linde | | | | |
| | | | | |
/s/ MARGARET M. PEGOSHEILA ROSTIAC | | Director | | February 26, 20182020 |
Margaret M. PegoSheila Rostiac | | | | |
