Cover Page
Cover Page - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Jan. 31, 2022 | Jun. 30, 2021 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2021 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Transition Report | false | ||
Entity File Number | 333-21011 | ||
Entity Registrant Name | FIRSTENERGY CORP | ||
Entity Tax Identification Number | 34-1843785 | ||
Entity Incorporation, State or Country Code | OH | ||
Entity Address, Address Line One | 76 South Main Street | ||
Entity Address, City or Town | Akron | ||
Entity Address, State or Province | OH | ||
Entity Address, Postal Zip Code | 44308 | ||
City Area Code | (800) | ||
Local Phone Number | 736-3402 | ||
Title of 12(b) Security | Common Stock, $0.10 par value per share | ||
Trading Symbol | FE | ||
Security Exchange Name | NYSE | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
ICFR Auditor Attestation Flag | true | ||
Entity Shell Company | false | ||
Entity Public Float | $ 20,228,791,176 | ||
Entity Common Stock Shares Outstanding | 570,344,389 | ||
Documents Incorporated by Reference | Documents Incorporated By Reference PART OF FORM 10-K INTO WHICH DOCUMENT DOCUMENT IS INCORPORATED Proxy Statement for 2022 Annual Meeting of Shareholders of FirstEnergy Corp. to be held May 17, 2022 Part III | ||
Entity Central Index Key | 0001031296 | ||
Document Fiscal Year Focus | 2021 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2021 | |
Auditor [Abstract] | |
Auditor Name | PricewaterhouseCoopers LLP |
Auditor Firm ID | 238 |
Auditor Location | Cleveland, Ohio |
Consolidated Statements of Inco
Consolidated Statements of Income - USD ($) shares in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | ||
REVENUES: | ||||
Total revenues | [1] | $ 11,132 | $ 10,790 | $ 11,035 |
OPERATING EXPENSES: | ||||
Fuel | 481 | 369 | 497 | |
Purchased power | 2,964 | 2,701 | 2,927 | |
Other operating expenses | 3,196 | 3,291 | 2,952 | |
Provision for depreciation | 1,302 | 1,274 | 1,220 | |
Amortization (deferral) of regulatory assets, net | 269 | (53) | (79) | |
General taxes | 1,073 | 1,046 | 1,008 | |
DPA penalty (Note 13) | 230 | 0 | 0 | |
Gain on sale of Yards Creek (Note 12) | (109) | 0 | 0 | |
Total operating expenses | 9,406 | 8,628 | 8,525 | |
OPERATING INCOME | 1,726 | 2,162 | 2,510 | |
OTHER INCOME (EXPENSE): | ||||
Miscellaneous income (expense), net | 517 | 432 | 243 | |
Pension and OPEB mark-to-market adjustment | 382 | (477) | (674) | |
Interest expense | (1,141) | (1,065) | (1,033) | |
Capitalized financing costs | 75 | 77 | 71 | |
Total other expense | (167) | (1,033) | (1,393) | |
INCOME BEFORE INCOME TAXES | 1,559 | 1,129 | 1,117 | |
INCOME TAXES | 320 | 126 | 213 | |
INCOME FROM CONTINUING OPERATIONS | 1,239 | 1,003 | 904 | |
Discontinued operations (Note 3) | [2] | 44 | 76 | 8 |
NET INCOME | 1,283 | 1,079 | 912 | |
INCOME ALLOCATED TO PREFERRED STOCKHOLDERS (Note 1) | 0 | 0 | 4 | |
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS | $ 1,283 | $ 1,079 | $ 908 | |
EARNINGS PER SHARE OF COMMON STOCK: | ||||
Basic - Continuing Operations (in dollars per share) | $ 2.27 | $ 1.85 | $ 1.69 | |
Basic - Discontinued Operations (in dollars per share) | 0.08 | 0.14 | 0.01 | |
Basic - Net Income Attributable to Common Stockholders (in dollars per share) | 2.35 | 1.99 | 1.70 | |
Diluted - Continuing Operations (in dollars per share) | 2.27 | 1.85 | 1.67 | |
Diluted - Discontinued Operations (in dollars per share) | 0.08 | 0.14 | 0.01 | |
Diluted - Net Income Attributable to Common Stockholders (in dollars per share) | $ 2.35 | $ 1.99 | $ 1.68 | |
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING: | ||||
Basic (in shares) | 545 | 542 | 535 | |
Diluted (in shares) | 546 | 543 | 542 | |
Distribution services and retail generation | ||||
REVENUES: | ||||
Total revenues | $ 9,009 | $ 8,688 | $ 8,720 | |
Transmission | ||||
REVENUES: | ||||
Total revenues | 1,608 | 1,613 | 1,510 | |
Other | ||||
REVENUES: | ||||
Total revenues | $ 515 | $ 489 | $ 805 | |
[1] | Includes excise and gross receipts tax collections of $374 million, $362 million and $373 million in 2021, 2020 and 2019, respectively. | |||
[2] | Net of income tax benefit of $48 million, $59 million, and $5 million in 2021, 2020 and 2019, respectively. |
Consolidated Statements of In_2
Consolidated Statements of Income (Loss) (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Income Statement [Abstract] | |||
Excise tax collections included in Revenue | $ 374 | $ 362 | $ 373 |
Income tax benefit | $ 48 | $ 59 | $ 5 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Statement of Comprehensive Income [Abstract] | |||
NET INCOME | $ 1,283 | $ 1,079 | $ 912 |
OTHER COMPREHENSIVE INCOME (LOSS): | |||
Pension and OPEB prior service costs | (14) | (34) | (31) |
Amortized losses on derivative hedges | 1 | 1 | 2 |
Other comprehensive loss | (13) | (33) | (29) |
Income tax benefits on other comprehensive loss | (3) | (8) | (8) |
Other comprehensive loss, net of tax | (10) | (25) | (21) |
COMPREHENSIVE INCOME | $ 1,273 | $ 1,054 | $ 891 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
CURRENT ASSETS: | ||
Cash and cash equivalents | $ 1,462 | $ 1,734 |
Restricted cash | 49 | 67 |
Receivables- | ||
Customers | 1,192 | 1,367 |
Less — Allowance for uncollectible customer receivables | 159 | 164 |
Current accounts receivable | 1,033 | 1,203 |
Other, net of allowance for uncollectible accounts of $10 in 2021 and $26 in 2020 | 246 | 236 |
Materials and supplies, at average cost | 260 | 317 |
Prepaid taxes and other | 187 | 157 |
Total current assets | 3,237 | 3,714 |
PROPERTY, PLANT AND EQUIPMENT: | ||
In service | 46,002 | 43,654 |
Less — Accumulated provision for depreciation | 12,672 | 11,938 |
Net Plant | 33,330 | 31,716 |
Construction work in progress | 1,414 | 1,578 |
Total | 34,744 | 33,294 |
PROPERTY, PLANT AND EQUIPMENT, NET - HELD FOR SALE (NOTE 13) | 0 | 45 |
INVESTMENTS AND OTHER NONCURRENT ASSETS | ||
Goodwill | 5,618 | 5,618 |
Investments (Note 8) | 655 | 605 |
Regulatory assets | 71 | 82 |
Other | 1,107 | 1,106 |
Total deferred charges and other assets | 7,451 | 7,411 |
Total assets | 45,432 | 44,464 |
CURRENT LIABILITIES: | ||
Currently payable long-term debt | 1,606 | 146 |
Short-term borrowings | 0 | 2,200 |
Accounts payable | 943 | 827 |
Accrued interest | 283 | 282 |
Accrued taxes | 647 | 640 |
Accrued compensation and benefits | 313 | 349 |
Dividends payable (Note 9) | 222 | 212 |
Other | 402 | 348 |
Total current liabilities | 4,416 | 5,004 |
Stockholders’ equity- | ||
Common Stock, Value, Outstanding | 57 | 54 |
Other paid-in capital | 10,238 | 10,076 |
Accumulated other comprehensive loss | (15) | (5) |
Accumulated deficit | (1,605) | (2,888) |
Total stockholders' equity | 8,675 | 7,237 |
Long-term debt and other long-term obligations | 22,248 | 22,131 |
Total capitalization | 30,923 | 29,368 |
NONCURRENT LIABILITIES: | ||
Accumulated deferred income taxes | 3,437 | 3,095 |
Retirement benefits | 2,669 | 3,345 |
Regulatory liabilities | 2,124 | 1,826 |
Other | 1,863 | 1,826 |
Total noncurrent liabilities | 10,093 | 10,092 |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 13) | ||
Total liabilities and capitalization | 45,432 | 44,464 |
Customer | ||
Receivables- | ||
Customers | 1,192 | 1,367 |
Less — Allowance for uncollectible customer receivables | 159 | 164 |
Current accounts receivable | $ 1,033 | $ 1,203 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Receivables- | ||
Allowance for uncollectible accounts | $ 159 | $ 164 |
Stockholders’ equity- | ||
Common stock, par value (in dollars per share) | $ 0.10 | $ 0.10 |
Common stock, authorized (in shares) | 700,000,000 | 700,000,000 |
Common stock, outstanding (in shares) | 570,261,104 | 543,117,533 |
Other | ||
Receivables- | ||
Allowance for uncollectible accounts | $ 10 | $ 26 |
Consolidated Statements of Comm
Consolidated Statements of Common Stockholders' Equity (FirstEnergy Corp.) - USD ($) $ in Millions | Total | Common Stock | OPIC | AOCI | Accumulated Deficit | Series A Convertible Preferred StockPreferred Stock |
Beginning Balance (in shares) at Dec. 31, 2018 | 512,000,000 | 700,000 | ||||
Beginning Balance at Dec. 31, 2018 | $ 6,814 | $ 51 | $ 11,530 | $ 41 | $ (4,879) | $ 71 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
NET INCOME | 912 | 912 | ||||
Other comprehensive loss, net of tax | (21) | (21) | ||||
Stock-based compensation | 41 | 41 | ||||
Cash dividends declared on common stock | (824) | (824) | ||||
Cash dividends declared on preferred stock | (3) | (3) | ||||
Stock Investment Plan and certain share-based benefit plans (in shares) | 3,000,000 | |||||
Stock Investment Plan and certain share-based benefit plans | 56 | $ 0 | 56 | |||
Conversion of Series A Convertible Stock (in shares) | 26,000,000 | (700,000) | ||||
Conversion of Series A Convertible Stock | 0 | $ 3 | 68 | $ (71) | ||
Ending Balance (in shares) at Dec. 31, 2019 | 541,000,000 | 0 | ||||
Ending Balance at Dec. 31, 2019 | 6,975 | $ 54 | 10,868 | 20 | (3,967) | $ 0 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
NET INCOME | 1,079 | 1,079 | ||||
Other comprehensive loss, net of tax | (25) | (25) | ||||
Stock-based compensation | 26 | 26 | ||||
Cash dividends declared on common stock | (846) | (846) | ||||
Stock Investment Plan and certain share-based benefit plans (in shares) | 2,000,000 | |||||
Stock Investment Plan and certain share-based benefit plans | $ 28 | $ 0 | 28 | |||
Ending Balance (in shares) at Dec. 31, 2020 | 543,117,533 | 543,000,000 | 0 | |||
Ending Balance at Dec. 31, 2020 | $ 7,237 | $ 54 | 10,076 | (5) | (2,888) | $ 0 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
NET INCOME | 1,283 | 1,283 | ||||
Other comprehensive loss, net of tax | (10) | (10) | ||||
Stock-based compensation | 26 | 26 | ||||
Cash dividends declared on common stock | (859) | (859) | ||||
Stock issuance (Note 9) (in shares) | 26,000,000 | |||||
Common Stock issuance (Note 9) | 974 | $ 3 | 971 | |||
Share-based benefit plans (in shares) | 1,000,000 | |||||
Share-based benefit plans | $ 24 | 24 | ||||
Ending Balance (in shares) at Dec. 31, 2021 | 570,261,104 | 570,000,000 | 0 | |||
Ending Balance at Dec. 31, 2021 | $ 8,675 | $ 57 | $ 10,238 | $ (15) | $ (1,605) | $ 0 |
Consolidated Statements of Stoc
Consolidated Statements of Stockholders' Equity (Parenthetical) - $ / shares | Dec. 21, 2021 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Statement of Stockholders' Equity [Abstract] | ||||
Dividends declared (in dollars per share) | $ 0.39 | $ 1.56 | $ 1.56 | $ 1.53 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
NET INCOME | $ 1,283 | $ 1,079 | $ 912 |
Adjustments to reconcile net income to net cash from operating activities- | |||
Depreciation and amortization | 1,601 | 1,199 | 1,217 |
Retirement benefits, net of payments | (417) | (301) | (108) |
Pension and OPEB mark-to-market adjustment | (382) | 477 | 676 |
Deferred income taxes and investment tax credits, net | 297 | 113 | 252 |
Asset removal costs charged to income | 0 | 36 | 28 |
Transmission revenue collections, net | 182 | (32) | (55) |
Gain on sale of Yards Creek | (109) | 0 | 0 |
Pension trust contributions | 0 | 0 | (500) |
Settlement agreement and tax sharing payments to the FES Debtors | 0 | (978) | 0 |
Gain on disposal, net of tax (Note 14) | (47) | (76) | (59) |
Changes in current assets and liabilities- | |||
Receivables | 160 | (129) | 271 |
Materials and supplies | 57 | (32) | (37) |
Prepaid taxes and other | 18 | 6 | 10 |
Accounts payable | 117 | (138) | (49) |
Accrued taxes | 7 | 159 | 12 |
Accrued interest | 0 | 33 | 6 |
Accrued compensation and benefits | (36) | 97 | (60) |
Other current liabilities | (16) | (16) | (21) |
Cash collateral, net | 31 | (12) | (10) |
Other | 65 | (62) | (18) |
Net cash provided from operating activities | 2,811 | 1,423 | 2,467 |
New financing- | |||
Long-term debt | 2,100 | 3,425 | 2,300 |
Short-term borrowings, net | 0 | 1,200 | 0 |
Common stock issuance | 1,000 | 0 | 0 |
Redemptions and repayments- | |||
Long-term debt | (532) | (1,114) | (789) |
Short-term borrowings, net | (2,200) | 0 | 0 |
Preferred stock dividend payments | 0 | 0 | (6) |
Common stock dividend payments | (849) | (845) | (814) |
Other | (61) | (59) | (35) |
Net cash provided from (used for) financing activities | (542) | 2,607 | 656 |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Property additions | (2,445) | (2,657) | (2,665) |
Proceeds from sale of Yards Creek | 155 | 0 | 0 |
Sales of investment securities held in trusts | 48 | 186 | 1,637 |
Purchases of investment securities held in trusts | (59) | (208) | (1,675) |
Asset removal costs | (226) | (224) | (217) |
Other | (32) | (5) | 47 |
Net cash used for investing activities | (2,559) | (2,908) | (2,873) |
Net change in cash, cash equivalents and restricted cash | (290) | 1,122 | 250 |
Cash, cash equivalents, and restricted cash at beginning of period | 1,801 | 679 | 429 |
Cash, cash equivalents, and restricted cash at end of period | 1,511 | 1,801 | 679 |
SUPPLEMENTAL CASH FLOW INFORMATION: | |||
Interest (net of amounts capitalized) | 1,085 | 970 | 960 |
Income taxes, net of refunds | $ (7) | $ 6 | $ 12 |
ORGANIZATION AND BASIS OF PRESE
ORGANIZATION AND BASIS OF PRESENTATION | 12 Months Ended |
Dec. 31, 2021 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
ORGANIZATION AND BASIS OF PRESENTATION | ORGANIZATION AND BASIS OF PRESENTATION Unless otherwise indicated, defined terms and abbreviations used herein have the meanings set forth in the accompanying Glossary of Terms. FE was incorporated under Ohio law in 1996. FE’s principal business is the holding, directly or indirectly, of all of the outstanding equity of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), JCP&L, ME, PN, FESC, MP, AGC (a wholly owned subsidiary of MP), PE, WP, and FET and its principal subsidiaries (ATSI, MAIT and TrAIL). In addition, FE holds all of the outstanding equity of other direct subsidiaries including: AE Supply, FirstEnergy Properties, Inc., FEV, FirstEnergy License Holding Company, GPUN, Allegheny Ventures, Inc., and Suvon, LLC, doing business as both FirstEnergy Home and FirstEnergy Advisors. FE does not bill directly or allocate any of its costs to any subsidiary company. Costs are charged to FE's subsidiaries for services received from FESC either through direct billing or through an allocation process. Allocated costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas developed by FESC. Intercompany transactions are generally settled under commercial terms within thirty days. FE and its subsidiaries are principally involved in the transmission, distribution, and generation of electricity. FirstEnergy’s ten utility operating companies comprise one of the nation’s largest investor-owned electric systems, based on serving over six million customers in the Midwest and Mid-Atlantic regions. FirstEnergy’s transmission operations include over 24,000 miles of transmission lines and two regional transmission operation centers. AGC and MP control 3,580 MWs of total capacity. PN, as lessee of the property of its subsidiary, the Waverly Electric Light & Power Company, serves approximately 4,000 customers in the Waverly, New York vicinity. On February 10, 2021, PN entered into an agreement to transfer its customers and the related assets in Waverly, New York to Tri-County Rural Electric Cooperative; the completion of such transfer is subject to several closing conditions including regulatory approval, which are ongoing, but is expected to have an immaterial impact to FirstEnergy's financial statements. FE and its subsidiaries follow GAAP and comply with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not necessarily indicative of results of operations for any future period. FE and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued. FE and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation as appropriate and permitted pursuant to GAAP. As further discussed below, FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary. Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but do not have a controlling financial interest, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage of FE's ownership share of the entity’s earnings is reported in the Consolidated Statements of Income and Comprehensive Income. Certain prior year amounts have been reclassified to conform to the current year presentation. COVID-19 FirstEnergy is continuously evaluating the global COVID-19 pandemic and taking steps to mitigate known risks. FirstEnergy is actively monitoring the continued impact COVID-19 is having on its customers’ receivable balances, which include increasing arrears balances since the pandemic began. FirstEnergy has incurred, and it is expected to incur for the foreseeable future, COVID-19 pandemic related expenses. COVID-19 related expenses consist of additional costs that FirstEnergy is incurring to protect its employees, contractors and customers, and to support social distancing requirements. These costs include, but are not limited to, new or added benefits provided to employees, the purchase of additional personal protection equipment and disinfecting supplies, additional facility cleaning services, COVID-19 test kits, initiated programs and communications to customers on utility response, and increased technology expenses to support remote working, where possible. The full impact on FirstEnergy’s business from the COVID-19 pandemic, including the governmental and regulatory responses, is unknown at this time and difficult to predict. FirstEnergy provides a critical and essential service to its customers and the health and safety of its employees, contractors and customers is its first priority. FirstEnergy is continuously monitoring its supply chain and is working closely with essential vendors to understand the continued impact the COVID-19 pandemic is having on its business; however, FirstEnergy does not currently expect disruptions in its ability to deliver service to customers or any material impact on its capital investment spending plan. FirstEnergy continues to effectively manage operations during the pandemic in order to provide critical service to customers and believes it is well positioned to manage through the economic slowdown. FirstEnergy Distribution and Transmission revenues benefit from geographic and economic diversity across a five-state service territory, which also allows for flexibility with capital investments and measures to maintain sufficient liquidity over the next twelve months. However, the situation remains fluid and future impacts to FirstEnergy that are presently unknown or unanticipated may occur. Furthermore, the likelihood of an impact to FirstEnergy, and the severity of any impact that does occur, could increase the longer the global pandemic persists. Sale of Minority Interest in FirstEnergy Transmission, LLC On November 6, 2021, FirstEnergy, along with FET, entered into the FET P&SA, with Brookfield and Brookfield Guarantors, pursuant to which FET agreed to issue and sell to Brookfield at the closing, and Brookfield agreed to purchase from FET, certain newly issued membership interests of FET, such that Brookfield will own 19.9% of the issued and outstanding membership interests of FET, for a purchase price of $2.375 billion. KATCo, which is currently a subsidiary of FET, will become a wholly owned subsidiary of FE prior to the closing of the transaction and will remain in the Regulated Transmission segment. The transaction is subject to customary closing conditions, including approval from the FERC and review by the CFIUS. On January 5, 2022, the parties to this transaction submitted to FERC an application requesting approval of the transaction no later than April 30, 2022, and on February 10, 2022, the parties filed answers in the FERC docket to certain protests that were filed on January 26, 2022. Pursuant to the terms of the FET P&SA, in connection with the closing, Brookfield, FET and FirstEnergy Corp will enter into the FET LLC Agreement. The FET LLC Agreement, among other things, provides for the governance, exit, capital and distribution, and other arrangements for FET from and following the closing. Under the FET LLC Agreement, Brookfield will be entitled to appoint a number of directors to the FET Board, in approximate proportion to Brookfield’s ownership percentage in FET (rounded to the next whole number). Upon the closing, the FET Board will consist of five directors, one appointed by Brookfield and four appointed by FE. The FET LLC Agreement contains certain investor protections, including, among other things, requiring Brookfield's approval for FET and its subsidiaries to take certain major actions. Under the terms of the FET LLC Agreement, for so long as Brookfield holds a 9.9% interest in FET, Brookfield’s consent is required for FET or any of its subsidiaries to incur indebtedness (other than the refinancing of existing indebtedness on commercially reasonable terms reflecting then-current credit market conditions) that would reasonably be expected to result in the FET’s consolidated Debt-to-Capital Ratio (as defined in the FET LLC Agreement) equaling or exceeding (i) prior to the fifth anniversary of the effective date, 65%, and (ii) thereafter, 70%. ACCOUNTING FOR THE EFFECTS OF REGULATION FirstEnergy’s Regulated Distribution and Regulated Transmission segments are subject to regulation that sets the prices (rates) the Utilities and the Transmission Companies are permitted to charge customers based on costs that the regulatory agencies determine are permitted to be recovered. At times, regulatory agencies permit the future recovery of costs that would be currently charged to expense by an unregulated company. The ratemaking process results in the recording of regulatory assets and liabilities based on anticipated future cash inflows and outflows. FirstEnergy reviews the probability of recovery of regulatory assets, and settlement of regulatory liabilities, at each balance sheet date and whenever new events occur. Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory commission order, or passage of new legislation. Upon material changes to these factors, where applicable, FirstEnergy will record new regulatory assets or liabilities and will assess whether it is probable that currently recorded regulatory assets and liabilities will be recovered or settled in future rates. If recovery of a regulatory asset is no longer probable, FirstEnergy will write off that regulatory asset as a charge against earnings. FirstEnergy considers the entire regulatory asset balance as the unit of account for the purposes of balance sheet classification rather than the next years recovery and as such net regulatory assets and liabilities are presented in the non-current section on the FirstEnergy Consolidated Balance Sheets. See Note 12, "Regulatory Matters," of the Notes to Consolidated Financial Statements for additional information. The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2021 and 2020, and the changes during the year ended December 31, 2021: As of December 31, Net Regulatory Assets (Liabilities) by Source 2021 2020 Change (In millions) Customer payables for future income taxes $ (2,345) $ (2,369) $ 24 Spent nuclear fuel disposal costs (101) (102) 1 Asset removal costs (646) (721) 75 Deferred transmission costs (3) 319 (322) Deferred generation costs 118 17 101 Deferred distribution costs 49 79 (30) Contract valuations 7 41 (34) Storm-related costs 660 748 (88) Uncollectible and COVID-19 related costs 56 97 (41) Energy efficiency program costs 47 42 5 New Jersey societal benefit costs 109 112 (3) Regulatory transition costs (18) (20) 2 Vegetation management 33 22 11 Other (19) (9) (10) Net Regulatory Liabilities included on the Consolidated Balance Sheets $ (2,053) $ (1,744) $ (309) The following table provides information about the composition of net regulatory assets that do not earn a current return as of December 31, 2021 and 2020, of which approximately $228 million and $195 million, respectively, are currently being recovered through rates over varying periods, through 2068, depending on the nature of the deferral and the jurisdiction: Regulatory Assets by Source Not Earning a As of December 31, Current Return 2021 2020 Change (in millions) Deferred transmission costs $ 13 $ 17 $ (4) Deferred generation costs 50 5 45 Storm-related costs 549 654 (105) COVID-19 related costs 65 66 (1) Regulatory transition costs 13 16 (3) Vegetation management 31 22 9 Other 11 9 2 Regulatory Assets Not Earning a Current Return $ 732 $ 789 $ (57) DERIVATIVES FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, coal and energy transmission. To manage the volatility related to these exposures, FirstEnergy’s Risk Policy Committee, comprised of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Risk Policy Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. FirstEnergy may use a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. EARNINGS PER SHARE OF COMMON STOCK Basic EPS available to common stockholders is computed using the weighted average number of common shares outstanding during the relevant period as the denominator. The denominator for diluted EPS of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. During 2019, EPS was computed using the two-class method required for participating securities. The convertible preferred stock issued in January 2018 were considered participating securities since the shares participated in dividends on common stock on an “as-converted” basis. All convertible preferred stock outstanding was converted to common stock during 2019. The two-class method uses an earnings allocation formula that treats participating securities as having rights to earnings that otherwise would have been available only to common stockholders. Under the two-class method, net income attributable to common stockholders is derived by subtracting the following from income from continuing operations: • preferred stock dividends; • deemed dividends for the amortization of the beneficial conversion feature recognized at issuance of the preferred stock (if any); and • an allocation of undistributed earnings between the common stock and the participating securities (convertible preferred stock) based on their respective rights to receive dividends. Net losses were not allocated to the convertible preferred stock as they did not have a contractual obligation to share in the losses of FirstEnergy. FirstEnergy allocated undistributed earnings based upon income from continuing operations. Diluted EPS reflects the dilutive effect of potential common shares from share-based awards and convertible shares of preferred stock. The dilutive effect of outstanding share-based awards was computed using the treasury stock method, which assumes any proceeds that could be obtained upon the exercise of the award would be used to purchase common stock at the average market price for the period. The dilutive effect of the convertible preferred stock in 2019 was computed using the if-converted method, which assumes conversion of the convertible preferred stock at the beginning of the period, giving income recognition for the add-back of the preferred stock dividends and undistributed earnings allocated to preferred stockholders. For the Years Ended December 31, Reconciliation of Basic and Diluted EPS of Common Stock 2021 2020 2019 (In millions, except per share amounts) EPS of Common Stock Income from continuing operations $ 1,239 $ 1,003 $ 904 Less: Preferred dividends N/A N/A (3) Less: Undistributed earnings allocated to preferred stockholders N/A N/A (1) Income from continuing operations available to common stockholders 1,239 1,003 900 Discontinued operations, net of tax 44 76 8 Less: Undistributed earnings allocated to preferred stockholders N/A N/A — Income from discontinued operations available to common stockholders 44 76 8 Income attributable to common stockholders, basic $ 1,283 $ 1,079 $ 908 Income allocated to preferred stockholders, preferred dilutive N/A N/A 4 Income attributable to common stockholders, dilutive $ 1,283 $ 1,079 $ 912 Share Count information: Weighted average number of basic shares outstanding 545 542 535 Assumed exercise of dilutive share based awards 1 1 3 Assumed conversion of preferred stock N/A N/A 4 Weighted average number of diluted shares outstanding 546 543 542 Income attributable to common stockholders, per common share: Income from continuing operations, basic $ 2.27 $ 1.85 $ 1.69 Discontinued operations, basic 0.08 0.14 0.01 Income attributable to common stockholders, basic $ 2.35 $ 1.99 $ 1.70 Income from continuing operations, diluted $ 2.27 $ 1.85 $ 1.67 Discontinued operations, diluted 0.08 0.14 0.01 Income attributable to common stockholders, diluted $ 2.35 $ 1.99 $ 1.68 GOODWILL In a business combination, the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed is recognized as goodwill. FirstEnergy evaluates goodwill for impairment annually on July 31 and more frequently if indicators of impairment arise. In evaluating goodwill for impairment, FirstEnergy assesses qualitative factors to determine whether it is more likely than not (that is, likelihood of more than 50%) that the fair value of a reporting unit is less than its carrying value (including goodwill). If FirstEnergy concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then no further testing is required. However, if FirstEnergy concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying value or bypasses the qualitative assessment, then the quantitative goodwill impairment test is performed to identify a potential goodwill impairment and measure the amount of impairment to be recognized, if any. As of July 31, 2021, FirstEnergy performed a qualitative assessment of the Regulated Distribution and Regulated Transmission reporting units' goodwill, assessing economic, industry and market considerations in addition to the reporting units' overall financial performance. Key factors used in the assessment included: growth rates, interest rates, expected investments, utility sector market performance, regulatory and legal developments, and other market considerations. It was determined that the fair values of these reporting units were, more likely than not, greater than their carrying values and a quantitative analysis was not necessary. FirstEnergy's reporting units are consistent with its reportable segments and consist of Regulated Distribution and Regulated Transmission. The following table presents goodwill by reporting unit as of December 31, 2021: (In millions) Regulated Distribution Regulated Transmission Consolidated Goodwill $ 5,004 $ 614 $ 5,618 INVENTORY Materials and supplies inventory includes fuel inventory and the distribution, transmission and generation plant materials, net of reserve for excess and obsolete inventory. Materials charged to inventory are at weighted average cost when purchased and expensed or capitalized, as appropriate, when used or installed. Fuel inventory is accounted for at weighted average cost when purchased and recorded to fuel expense when consumed. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment reflects original cost (net of any impairments recognized), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and financing costs incurred to place the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. FirstEnergy recognizes liabilities for planned major maintenance projects as they are incurred. Property, plant and equipment balances by segment as of December 31, 2021 and 2020, were as follows: December 31, 2021 Property, Plant and Equipment In Service (1) Accum. Depr. Net Plant CWIP Total (In millions) Regulated Distribution $ 31,154 $ (9,284) $ 21,870 $ 774 $ 22,644 Regulated Transmission 13,744 (2,789) 10,955 580 11,535 Corporate/Other 1,104 (599) 505 60 565 Total $ 46,002 $ (12,672) $ 33,330 $ 1,414 $ 34,744 December 31, 2020 Property, Plant and Equipment In Service (1) Accum. Depr. Net Plant CWIP Total (In millions) Regulated Distribution $ 29,775 $ (8,800) $ 20,975 $ 841 $ 21,816 Regulated Transmission 12,912 (2,609) 10,303 671 10,974 Corporate/Other 1,039 (556) 483 66 549 Total $ 43,726 $ (11,965) $ 31,761 $ 1,578 $ 33,339 (1) Includes finance leases of $143 million and $153 million as of December 31, 2021 and 2020, respectively. Regulated Distribution has approximately $2.1 billion of total regulated generation property, plant and equipment as of December 31, 2021. Included within the Regulated Distribution segment is $45 million of assets classified as held for sale as of December 31, 2020 associated with the asset purchase agreement with Yards Creek; see Note 12, "Regulatory Matters," for additional information. FirstEnergy provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The respective annual composite depreciation rates for FirstEnergy were approximately 2.7% in each 2021, 2020 and 2019. For the years ended December 31, 2021, 2020 and 2019, capitalized financing costs on FirstEnergy's Consolidated Statements of Income include $48 million, $49 million and $45 million, respectively, of allowance for equity funds used during construction and $27 million, $28 million and $26 million, respectively, of capitalized interest. Jointly Owned Plants FE, through its subsidiary, AGC, owns an undivided 16.25% interest (487 MWs) in the 3,003 MW Bath County pumped-storage, hydroelectric station in Virginia, operated by the 60% owner, VEPCO, a non-affiliated utility. Total property, plant and equipment includes $153 million representing AGC's share in this facility as of December 31, 2021. AGC is obligated to pay its share of the costs of this jointly owned facility in the same proportion as its ownership interests using its own financing. AGC's share of direct expenses of the joint plant is included in operating expenses on FirstEnergy's Consolidated Statements of Income. AGC provides the generation capacity from this facility to its owner, MP. Asset Retirement Obligations FirstEnergy recognizes an ARO for its legal obligation to perform asset retirement activities associated with its long-lived assets. The ARO liability represents an estimate of the fair value of FirstEnergy's current obligation such that the ARO is accreted monthly to reflect the time value of money. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FirstEnergy uses an expected cash flow approach to measure the fair value of the remediation AROs, considering the expected timing of settlement of the ARO based on the expected economic useful life of associated asset and/or regulatory requirements. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related asset. In certain circumstances, FirstEnergy has recovery of asset retirement costs and, as such, certain accretion and depreciation is offset against regulatory assets. Conditional retirement obligations associated with tangible long-lived assets are recognized at fair value in the period in which they are incurred if a reasonable estimate can be made, even though there may be uncertainty about timing or method of settlement. When settlement is conditional on a future event occurring, it is reflected in the measurement of the liability, not the timing of the liability recognition. AROs as of December 31, 2021, are described further in Note 11, "Asset Retirement Obligations." Asset Impairments FirstEnergy evaluates long-lived assets classified as held and used for impairment when events or changes in circumstances indicate the carrying value of the long-lived assets may not be recoverable. First, the estimated undiscounted future cash flows attributable to the assets is compared with the carrying value of the assets. If the carrying value is greater than the undiscounted future cash flows, an impairment charge is recognized equal to the amount the carrying value of the assets exceeds its estimated fair value. RECEIVABLES Receivables from customers include retail electric sales and distribution deliveries to residential, commercial and industrial customers of the Utilities. There was no material concentration of receivables as of December 31, 2021 and 2020, with respect to any particular segment of FirstEnergy’s customers. Billed and unbilled customer receivables as of December 31, 2021 and 2020, are included below. As of December 31, Customer Receivables 2021 2020 (In millions) Billed (1) $ 616 $ 800 Unbilled 576 567 1,192 1,367 Less: Uncollectible Reserve 159 164 Total Customer Receivables $ 1,033 $ 1,203 (1) Includes approximately $318 million and $349 million as of December 31, 2021, 2020, respectively, that are past due by greater than 30 days. Activity in the allowance for uncollectible accounts on receivables for the years ended December 31, 2021, 2020 and 2019 are as follows: (In millions) 2021 2020 2019 Customer Receivables Beginning of year balance $ 164 $ 46 $ 50 Charged to income (1) 54 174 81 Charged to other accounts (2) 42 46 47 Write-offs (101) (102) (132) End of year balance $ 159 $ 164 $ 46 Other Receivables Beginning of year balance $ 26 $ 21 $ 2 Charged to income 3 7 27 Charged to other accounts (2) 3 10 1 Write-offs (22) (12) (9) End of year balance $ 10 $ 26 $ 21 Affiliated Companies Receivables (3) Beginning of year balance $ — $ 1,063 $ 920 Charged to income — — 143 Charged to other accounts (2) — — — Write-offs — (1,063) — End of year balance $ — $ — $ 1,063 (1) Customer receivable amounts charged to income for the years ended December 31, 2021, 2020 and 2019 include approximately $12 million, $103 million, and $25 million respectively, deferred for future recovery. (2) Represents recoveries and reinstatements of accounts previously written off for uncollectible accounts. (3) Amounts relate to the FES Debtors and are included in discontinued operations. Write-off of $1.1 billion in 2020 was recognized upon their emergence in February 2020. The allowance for uncollectible customer receivables is based on historical loss information comprised of a rolling 36-month average net write-off percentage of revenues, in conjunction with a qualitative assessment of elements that impact the collectability of receivables to determine if allowances for uncollectible accounts should be further adjusted in accordance with the accounting guidance for credit losses. Management contemplates available current information such as changes in economic factors, regulatory matters, industry trends, customer credit factors, amount of receivable balances that are past-due, payment options and programs available to customers, and the methods that the Utilities are able to utilize to ensure payment. FirstEnergy reviews its allowance for uncollectible customer receivables utilizing a quantitative and qualitative assessment, which includes consideration of the outbreak of COVID-19 and the impact on customer receivable balances outstanding and write-offs since the pandemic began. Beginning March 13, 2020, FirstEnergy temporarily suspended customer disconnections for nonpayment and ceased collection activities as a result of the ongoing COVID-19 pandemic and in accordance with state regulatory requirements. The temporary suspension of disconnections for nonpayment and ceasing of collection activities extended into the fourth quarter of 2020 but resumed for many customers before the end of 2020, except in New Jersey where the moratorium was extended until the end of 2021. Customers are subject to each state's applicable regulations on winter moratoriums. See Note 12, “Regulatory Matters,” for further discussion on applicable regulations that may alter customer disconnections and collection activity as well as regulatory recovery. During 2020, FirstEnergy analyzed the likelihood of loss based on increases in customer accounts in arrears since the pandemic began in mid-March 2020 as well as what collection methods at the time were suspended, and historically been utilized to ensure payment. Based on this assessment, and consideration of other qualitative factors described above, FirstEnergy recognized incremental uncollectible expense of $121 million in the year 2020, of which approximately $90 million was not being collected through rates and as a result was deferred for future recovery under regulatory mechanisms. During 2021, arrears levels continue to be elevated above 2019 pre-pandemic levels. Various regulatory actions have impacted the growth and recovery of past due balances including extensions on moratoriums, significant restrictions regarding disconnections, and extended installment plans. FirstEnergy has experienced a reduction in the amount of receivables that are past due by greater than 30 days since the end of 2020. While total customer arrears balances continue to decrease in 2021, balances that are over 120 days past due continue to be elevated. FirstEnergy considered other factors as part of its qualitative assessment, such as certain federal stimulus and state funding being made available to assist with past due utility bills. As a result of this qualitative analysis, FirstEnergy did not recognize any incremental uncollectible expense for the twelve months ended December 31, 2021. Additionally, as a result of the pandemic-related moratoriums and certain customer installment or extended payment plans offered, the allowance for uncollectible accounts on receivables in 2021 and 2020 are elevated due to the extension of when certain write-offs would have otherwise occurred. Other receivables include PJM receivables resulting from transmission and wholesale sales. FirstEnergy’s uncollectible risk on PJM receivables is minimal due to the nature of PJM’s settlement process whereby members of PJM legally agree to share the cost of defaults and as a result there is no allowance for doubtful accounts. VARIABLE INTEREST ENTITIES FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has: (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance; and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary. In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregates variable interests into categories based on similar risk characteristics and significance. Consolidated VIEs VIEs in which FirstEnergy is the primary beneficiary consist of the following (included in FirstEnergy’s consolidated financial statements): • Ohio Securitization - In June 2013, SPEs formed by the Ohio Companies issued approximately $445 million of pass-through trust certificates supported by phase-in recovery bonds to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. • MP and PE Environmental Funding Companies - Bankruptcy remote, special purpose limited liability companies that are indirect subsidiaries of MP and PE which issued environmental control bonds. See Note 9, “Capitalization,” for additional information on securitized bonds. Unconsolidated VIEs FirstEnergy is not the primary beneficiary of the following VIEs: • Global Holding - FEV holds |
REVENUE
REVENUE | 12 Months Ended |
Dec. 31, 2021 | |
Revenue from Contract with Customer [Abstract] | |
REVENUE | REVENUE FirstEnergy accounts for revenues from contracts with customers under ASC 606, “ Revenue from Contracts with Customers. ” Revenue from leases, financial instruments, other contractual rights or obligations and other revenues that are not from contracts with customers are outside the scope of the standard and accounted for under other existing GAAP. FirstEnergy has elected to exclude sales taxes and other similar taxes collected on behalf of third parties from revenue as prescribed in the standard. As a result, tax collections and remittances are excluded from recognition in the income statement and instead recorded through the balance sheet. Excise and gross receipts taxes that are assessed on FirstEnergy are not subject to the election and are included in revenue. FirstEnergy has elected the optional invoice practical expedient for most of its revenues and utilizes the optional short-term contract exemption for transmission revenues due to the annual establishment of revenue requirements, which eliminates the need to provide certain revenue disclosures regarding unsatisfied performance obligations. FirstEnergy’s revenues are primarily derived from electric service provided by the Utilities and Transmission Companies. The following represents a disaggregation of revenue from contracts with customers for the year ended December 31, 2021: Revenues by Type of Service Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments (1) Total (In millions) Distribution services (2)(4) $ 5,433 $ — $ (104) $ 5,329 Retail generation 3,730 — (50) 3,680 Wholesale sales 362 — 14 376 Transmission (2) — 1,608 — 1,608 Other 119 — — 119 Total revenues from contracts with customers $ 9,644 $ 1,608 $ (140) $ 11,112 ARP (3) (27) — — (27) Other revenue unrelated to contracts with customers 94 10 (57) 47 Total revenues $ 9,711 $ 1,618 $ (197) $ 11,132 (1) Includes eliminations and reconciling adjustments of inter-segment revenues. (2) Includes reductions to revenue related to amounts subject to refund resulting from the Tax Act ($3 million at Regulated Distribution and $(2) million at Regulated Transmission). (3) Reflects amounts the Ohio Companies refunded to customers that was previously collected under decoupling mechanisms, with interest. See Note 12, “Regulatory Matters,” for further discussion on Ohio decoupling rates. (4) Includes $38 million of customer refunds associated with the Ohio Stipulation that became effective in December 2021. See Note 12, “Regulatory Matters,” for additional information. The following represents a disaggregation of revenue from contracts with customers for the year ended December 31, 2020: Revenues by Type of Service Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments (1) Total (In millions) Distribution services (2) $ 5,259 $ — $ (88) $ 5,171 Retail generation 3,577 — (60) 3,517 Wholesale sales 251 — 9 260 Transmission (2) — 1,613 — 1,613 Other 140 — — 140 Total revenues from contracts with customers $ 9,227 $ 1,613 $ (139) $ 10,701 ARP (3) 43 — — 43 Other revenue unrelated to contracts with customers 93 17 (64) 46 Total revenues $ 9,363 $ 1,630 $ (203) $ 10,790 (1) Includes eliminations and reconciling adjustments of inter-segment revenues. (2) Includes reductions to revenue related to amounts subject to refund resulting from the Tax Act ($2 million at Regulated Distribution and $7 million at Regulated Transmission). (3) ARP revenue for the year ended December 31, 2020, is primarily related to shared savings revenue in Ohio. The following represents a disaggregation of revenue from contracts with customers for the year ended December 31, 2019: Revenues by Type of Service Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments (1) Total (In millions) Distribution services (2) $ 5,133 $ — $ (83) $ 5,050 Retail generation 3,727 — (57) 3,670 Wholesale sales (2) 411 — 12 423 Transmission (2) — 1,510 — 1,510 Other 150 — 2 152 Total revenues from contracts with customers $ 9,421 $ 1,510 $ (126) $ 10,805 ARP (3) 181 — — 181 Other revenue unrelated to contracts with customers 96 16 (63) 49 Total revenues $ 9,698 $ 1,526 $ (189) $ 11,035 (1) Includes eliminations and reconciling adjustments of inter-segment revenues. (2) Includes reductions to revenue related to amounts subject to refund resulting from the Tax Act ($16 million at Regulated Distribution and $19 million at Regulated Transmission). (3) ARP revenue for the year ended December 31, 2019, includes DMR revenue, lost distribution and shared savings revenue in Ohio. Other revenue unrelated to contracts with customer s includes revenue from late payment charges of $36 million, $31 million and $37 million, respectively, for the years ended December 31, 2021, 2020 and 2019. Other revenue unrelated to contracts with customer s also includes revenue from derivatives of $11 million, $14 million and $8 million, respectively, for the years ended December 31, 2021, 2020 and 2019. Regulated Distribution The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies and also controls 3,580 MWs of regulated electric generation capacity located primarily in West Virginia and Virginia. Each of the Utilities earns revenue from state-regulated rate tariffs under which it provides distribution services to residential, commercial and industrial customers in its service territory. The Utilities are obligated under the regulated construct to deliver power to customers reliably, as it is needed, which creates an implied monthly contract with the end-use customer. See Note 12, “Regulatory Matters,” for additional information on rate recovery mechanisms. Distribution and electric revenues are recognized over time as electricity is distributed and delivered to the customer and the customers consume the electricity immediately as delivery occurs. Retail generation sales relate to POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland, as well as generation sales in West Virginia that are regulated by the WVPSC. Certain of the Utilities have default service obligations to provide power to non-shopping customers who have elected to continue to receive service under regulated retail tariffs. The volume of these sales varies depending on the level of shopping that occurs. Supply plans vary by state and by service territory. Default service for the Ohio Companies, Pennsylvania Companies, JCP&L and PE’s Maryland jurisdiction are provided through a competitive procurement process approved by each state’s respective commission. Retail generation revenues are recognized over time as electricity is delivered and consumed immediately by the customer. The following table represents a disaggregation of the Regulated Distribution segment revenue from contracts with distribution service and retail generation customers for the years ended December 31, 2021, 2020 and 2019 by class: For the Years Ended December 31, Revenues by Customer Class 2021 2020 2019 (In millions) Residential $ 5,713 $ 5,539 $ 5,412 Commercial 2,284 2,140 2,252 Industrial 1,091 1,076 1,106 Other 75 81 90 Total $ 9,163 $ 8,836 $ 8,860 Wholesale sales primarily consist of generation and capacity sales into the PJM market from FirstEnergy’s regulated electric generation capacity and NUGs. Certain of the Utilities may also purchase power in the PJM markets to supply power to their customers. Generally, these power sales from generation and purchases to serve load are netted hourly and reported as either revenues or purchased power on the Consolidated Statements of Income based on whether the entity was a net seller or buyer each hour. Capacity revenues are recognized ratably over the PJM planning year at prices cleared in the annual PJM Reliability Pricing Model Base Residual Auction and Incremental Auctions. Capacity purchases and sales through PJM capacity auctions are reported within revenues on the Consolidated Statements of Income. Certain capacity income (bonuses) and charges (penalties) related to the availability of units that have cleared in the auctions are unknown and not recorded in revenue until, and unless, they occur. The Utilities’ distribution customers are metered on a cycle basis. An estimate of unbilled revenues is calculated to recognize electric service provided from the last meter reading through the end of the month. This estimate includes many factors, among which are historical customer usage, load profiles, estimated weather impacts, customer shopping activity and prices in effect for each class of customer. In each accounting period, the Utilities accrue the estimated unbilled amount as revenue and reverse the related prior period estimate. Customer payments vary by state but are generally due within 30 days. ASC 606 excludes industry-specific accounting guidance for recognizing revenue from ARPs as these programs represent contracts between the utility and its regulators, as opposed to customers. Therefore, revenues from these programs are not within the scope of ASC 606 and regulated utilities are permitted to continue to recognize such revenues in accordance with existing practice but are presented separately from revenue arising from contracts with customers. FirstEnergy had ARPs in Ohio primarily for shared savings in 2020, and has reflected refunds of decoupling revenue owed to customers as reductions to ARPs in 2021. See Note 12, “Regulatory Matters,” for further discussion on decoupling revenues in Ohio. Regulated Transmission The Regulated Transmission segment provides transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment's revenues are derived from forward-looking formula rates. See Note 12, “Regulatory Matters,” for additional information. Forward-looking formula rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. Revenues and cash receipts for the stand-ready obligation of providing transmission service are recognized ratably over time. The following table represents a disaggregation of revenue from contracts with regulated transmission customers for the years ended December 31, 2021, 2020 and 2019: For the Years Ended December 31, Transmission Owner 2021 2020 2019 (In millions) ATSI $ 799 $ 804 $ 754 TrAIL 233 247 242 MAIT 288 250 224 JCP&L 164 178 160 MP, PE and WP 124 134 130 Total Revenues $ 1,608 $ 1,613 $ 1,510 |
ACCUMULATED OTHER COMPREHENSIVE
ACCUMULATED OTHER COMPREHENSIVE INCOME | 12 Months Ended |
Dec. 31, 2021 | |
Equity [Abstract] | |
ACCUMULATED OTHER COMPREHENSIVE INCOME | ACCUMULATED OTHER COMPREHENSIVE INCOME The changes in AOCI for the years ended December 31, 2021, 2020 and 2019, for FirstEnergy are shown in the following table: Gains & Losses on Cash Flow Hedges (1) Defined Benefit Pension & OPEB Plans Total (In millions) AOCI Balance, January 1, 2019 $ (11) $ 52 $ 41 Other comprehensive income before reclassifications — (2) (2) Amounts reclassified from AOCI 2 (29) (27) Other comprehensive income (loss) 2 (31) (29) Income tax (benefits) on other comprehensive income (loss) — (8) (8) Other comprehensive income (loss), net of tax 2 (23) (21) AOCI Balance, December 31, 2019 $ (9) $ 29 $ 20 Amounts reclassified from AOCI 1 (34) (33) Other comprehensive income (loss) 1 (34) (33) Income tax (benefits) on other comprehensive income (loss) — (8) (8) Other comprehensive income (loss), net of tax 1 (26) (25) AOCI Balance, December 31, 2020 $ (8) $ 3 $ (5) Amounts reclassified from AOCI 1 (14) (13) Other comprehensive income (loss) 1 (14) (13) Income tax (benefits) on other comprehensive income (loss) — (3) (3) Other comprehensive income (loss), net of tax 1 (11) (10) AOCI Balance, December 31, 2021 $ (7) $ (8) $ (15) (1) Relates to previous cash flow hedges used to hedge fixed rate long-term debt securities prior to their issuance. The following amounts were reclassified from AOCI for FirstEnergy in the years ended December 31, 2021, 2020 and 2019: For the Years Ended December 31, Affected Line Item in Consolidated Statements of Income Reclassifications from AOCI (1) 2021 2020 2019 (In millions) Gains & losses on cash flow hedges Long-term debt $ 1 $ 1 $ 2 Interest expense $ 1 $ 1 $ 2 Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (14) $ (34) $ (29) (2) 3 8 8 Income taxes $ (11) $ (26) $ (21) Net of tax (1) Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI. (2) Prior-service costs are reported within Miscellaneous income, net within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income. Components are included in the computation of net periodic cost (credits), see Note 4, "Pension and Other Postemployment Benefits," for additional details. |
PENSION AND OTHER POST-EMPLOYME
PENSION AND OTHER POST-EMPLOYMENT BENEFITS | 12 Months Ended |
Dec. 31, 2021 | |
Retirement Benefits [Abstract] | |
PENSION AND OTHER POST-EMPLOYMENT BENEFITS | PENSION AND OTHER POST-EMPLOYMENT BENEFITS FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels. Under the cash-balance portion of the pension plan (for employees hired on or after January 1, 2014), FirstEnergy makes contributions to eligible employee retirement accounts based on a pay credit and an interest credit. In addition, FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension and OPEB to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits. FirstEnergy’s pension and OPEB funding policy is based on actuarial computations using the projected unit credit method. On March 11, 2021, President Biden signed into law the American Rescue Plan Act of 2021, which, among other things, extended shortfall amortization periods and modification of the interest rate stabilization rules for single-employer plans thereby impacting funding requirements. As a result, FirstEnergy does not currently expect to have a required contribution to the pension plan based on various assumptions including annual expected rate of returns for assets of 7.50%. However, FirstEnergy may elect to contribute to the pension plan voluntarily. Pension and OPEB costs are affected by employee demographics (including age, compensation levels and employment periods), the level of contributions made to the plans and earnings on plan assets. Pension and OPEB costs may also be affected by changes in key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. FirstEnergy uses a December 31 measurement date for its pension and OPEB plans. The fair value of the plan assets represents the actual market value as of the measurement date. Discount Rate - In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and OPEB obligations. The assumed rates of return on plan assets consider historical market returns and economic forecasts for the types of investments held by FirstEnergy’s pension trusts. The long-term rate of return is developed considering the portfolio’s asset allocation strategy. FirstEnergy utilizes a spot rate approach in the estimation of the components of benefit cost by applying specific spot rates along the full yield curve to the relevant projected cash flows. Expected Return on Plan Assets - FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by the pension trusts. In 2021, FirstEnergy’s qualified pension and OPEB plan assets experienced gains of $689 million or 7.9%, compared to gains of $1,225 million, or 14.7% in 2020, and losses of $1,492 million, or 20.2% in 2019 and assumed a 7.50% rate of return on plan assets in 2021, 2020 and 2019, which generated $688 million, $651 million and $569 million of expected returns on plan assets, respectively. The expected return on pension and OPEB assets is based on input from investment consultants, including the trusts’ asset allocation targets and the historical performance of risk-based and fixed income securities. The gains or losses generated as a result of the difference between expected and actual returns on plan assets is recognized as a pension and OPEB mark-to-market adjustment in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for remeasurement. Mortality Rates - During 2021, the Society of Actuaries published new mortality tables that include more current data than the RP-2014 tables as well as new improvement scales. An analysis of plan mortality data indicated the use of the Pri-2012 mortality table with projection scale MP-2021, actuarially adjusted to reflect increased mortality rates due to COVID-19 based on mortality experience reported by the Center for Disease and Control Prevention in 2020 and 2021, was most appropriate and such was utilized to determine the 2021 benefit cost and obligation as of December 31, 2021, for the FirstEnergy pension and OPEB plans. The impact of using the Pri-2012 mortality table with projection scale MP-2021 (adjusted by FirstEnergy's actuary for COVID-19 impacts) resulted in a decrease to the projected benefit obligation of approximately $32 million and $2 million for the pension and OPEB plans, respectively, and was included in the 2021 pension and OPEB mark-to-market adjustment. Net Periodic Benefit Costs - In addition to service costs, interest on obligations, expected return on plan assets, and prior service costs, FirstEnergy recognizes in net periodic benefit costs a pension and OPEB mark-to-market adjustment for the change in the fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. Service costs, net of capitalization, are reported within Other operating expenses on FirstEnergy’s Consolidated Statements of Income. Non-service costs, other than the pension and OPEB mark-to-market adjustment, which is separately shown, are reported within Miscellaneous income, net, within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income. Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December (1) Pension OPEB 2021 2020 2019 2021 2020 2019 Service cost weighted-average discount rate (2) 3.10 % 3.60%/3.24% 4.66 % 3.03 % 3.63%/3.29% 4.67 % Interest cost weighted-average discount rate (3) 2.58 % 3.27%/2.90% 4.37 % 1.66 % 2.71%/2.30% 3.89 % Expected return on plan assets 7.50 % 7.50 % 7.50 % 7.50 % 7.50 % 7.50 % Rate of compensation increase 4.10 % 4.10 % 4.10 % N/A N/A N/A (1) Excludes impact of pension and OPEB mark-to-market adjustment. (2) Weighted-average discount rates effect from January 1, 2020, through February 26, 2020, were 3.60% and 3.63% for pension and OPEB service cost, respectively. Discount rates were 3.24% and 3.29% for pension and OPEB service cost, respectively, for the period February 27, 2020 through December 31, 2020. (3) Weighted-average discount rates in effect from January 1, 2020, through February 26, 2020, were 3.27% and 2.71% for pension and OPEB interest cost, respectively. Discount rates were 2.90% and 2.30% for pension and OPEB interest cost, respectively, for the period February 27, 2020, through December 31, 2020. Components of Net Periodic Benefit Costs (Credits) for the Years Ended December 31, Pension OPEB 2021 2020 2019 2021 2020 2019 (In millions) Service cost $ 195 $ 194 $ 193 $ 4 $ 4 $ 3 Interest cost 226 287 373 11 15 22 Expected return on plan assets (652) (618) (540) (36) (33) (29) Amortization of prior service costs (credits) (1) 3 12 7 (17) (46) (36) Special termination costs (2) — — 14 — — — One-time termination benefits (3) — 8 — — — — Pension & OPEB mark-to-market (4) (253) 463 656 (129) 14 20 Net periodic benefit costs (credits) $ (481) $ 346 $ 703 $ (167) $ (46) $ (20) (1) 2020 includes the acceleration of approximately $18 million in net credits as a result of the FES Debtors’ emergence during the first quarter of 2020 and is a component of discontinued operations in FirstEnergy’s Consolidated Statements of Income. (2) Subject to a cap, FirstEnergy agreed to fund a pension enhancement through its pension plan, for voluntary enhanced retirement packages offered to certain FES employees, as well as offer certain other employee benefits. The costs are a component of discontinued operations in FirstEnergy’s Consolidated Statements of Income. (3) Costs represent additional benefits provided to FES and FENOC employees under the approved settlement agreement and are a component of discontinued operations. (4) Of the total Pension and OPEB mark-to-market adjustment for 2019, approximately $2 million is included in discontinued operations. The annual pension and OPEB mark-to-market adjustments, (gains) or losses, for the years ended December 31, 2021, 2020, and 2019 were $(382) million, $477 million (including $423 million in the first quarter of 2020), and $676 million, respectively. Of these annual pension and OPEB mark-to-market amounts, approximately $(31) million, $40 million and $47 million were allocated to the Transmission Companies and certain of FirstEnergy's utilities under forward-looking formula rates, and expected to be refunded or recovered through formula transmission rates, respectively. The 2021 pension and OPEB mark-to-market adjustment primarily reflects an approximate 35 bps increase in the discount rate used to measure pension benefit obligations. Under the approved bankruptcy settlement agreement, upon emergence, FES and FENOC employees ceased earning years of service under the FirstEnergy pension and OPEB plans. The emergence on February 27, 2020, triggered a remeasurement of the affected pension and OPEB plans and as a result, FirstEnergy recognized a non-cash, pre-tax pension and OPEB mark-to-market adjustment of approximately $423 million in the first quarter of 2020. In the fourth quarter 2020, FirstEnergy recognized a $54 million pension and OPEB mark-to-market adjustment. Pension OPEB Obligations and Funded Status - Qualified and Non-Qualified Plans 2021 2020 2021 2020 (In millions) Change in benefit obligation: Benefit obligation as of January 1 $ 11,935 $ 11,050 $ 676 $ 654 Service cost 195 194 4 4 Interest cost 226 287 11 15 Plan participants’ contributions — — 4 4 Plan amendments — 9 — — Medicare retiree drug subsidy — — 1 1 Actuarial loss (gain) (280) 1,011 (101) 41 Benefits paid (597) (616) (46) (43) Benefit obligation as of December 31 $ 11,479 $ 11,935 $ 549 $ 676 Change in fair value of plan assets: Fair value of plan assets as of January 1 $ 8,968 $ 8,395 $ 502 $ 458 Actual return on plan assets 625 1,165 64 60 Company contributions 24 24 24 23 Plan participants’ contributions — — 4 4 Benefits paid (597) (616) (46) (43) Fair value of plan assets as of December 31 $ 9,020 $ 8,968 $ 548 $ 502 Funded Status: Qualified plan $ (1,974) $ (2,500) $ — $ — Non-qualified plans (485) (467) — — Funded Status (Net liability as of December 31) $ (2,459) $ (2,967) $ (1) $ (174) Accumulated benefit obligation $ 10,927 $ 11,376 $ — $ — Amounts Recognized in AOCI: Prior service cost (credit) $ 9 $ 12 $ (21) $ (39) Assumptions Used to Determine Benefit Obligations (as of December 31) Discount rate 3.02 % 2.67 % 2.84 % 2.45 % Rate of compensation increase 4.10 % 4.10 % N/A N/A Cash balance weighted average interest crediting rate 2.57 % 2.57 % N/A N/A Assumed Health Care Cost Trend Rates (as of December 31) Health care cost trend rate assumed (pre/post-Medicare) N/A N/A 5.75%-5.25% 6.0%-5.5% Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) N/A N/A 4.5 % 4.5 % Year that the rate reaches the ultimate trend rate N/A N/A 2028 2028 The following tables set forth pension financial assets that are accounted for at fair value by level within the fair value hierarchy. See Note 8, "Fair Value Measurements," for a description of each level of the fair value hierarchy. There were no significant transfers between levels during 2021 and 2020. December 31, 2021 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 746 $ — $ 746 8 % Public equity 2,867 286 — 3,153 35 % Fixed income — 2,453 — 2,453 27 % Derivatives 20 — — 20 — % Total (1) $ 2,887 $ 3,485 $ — $ 6,372 70 % Private - equity and debt funds (2) 811 9 % Insurance-linked securities (2) 320 4 % Hedge funds (2) 678 7 % Real estate funds (2) 886 10 % Total Investments $ 9,067 100 % (1) Excludes $(47) million as of December 31, 2021, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. (2) Net Asset Value used as a practical expedient to approximate fair value. December 31, 2020 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 1,493 $ — $ 1,493 17 % Public equity 1,903 162 — 2,065 23 % Fixed income — 3,059 — 3,059 35 % Derivatives (13) — — (13) — % Total (1) $ 1,890 $ 4,714 $ — $ 6,604 75 % Private - equity and debt funds (2) 465 5 % Insurance-linked securities (2) 323 4 % Hedge funds (3) 645 7 % Real estate funds (2) 815 9 % Total Investments $ 8,852 100 % (1) Excludes $116 million as of December 31, 2020, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. (2) Net Asset Value used as a practical expedient to approximate fair value. As of December 31, 2021, and 2020, the OPEB trust investments measured at fair value were as follows: December 31, 2021 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 95 $ — $ 95 17 % Public equity 278 — — 278 51 % Fixed income — 175 — 175 32 % Total $ 278 $ 270 $ — $ 548 100 % December 31, 2020 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 84 $ — $ 84 17 % Public equity 283 — — 283 55 % Fixed income: — 145 — 145 28 % Total (1) $ 283 $ 229 $ — $ 512 100 % (1) Excludes $(10) million as of December 31, 2020, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. FirstEnergy follows a total return investment approach using a mix of equities, fixed income and other available investments while taking into account the pension plan liabilities to optimize the long-term return on plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalization funds. Other assets such as real estate and private equity are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements and periodic asset/liability studies. FirstEnergy’s target asset allocations for its pension and OPEB trust portfolios for 2021 and 2020 are shown in the following table: Target Asset Allocations 2021 2020 Equities 38 % 38 % Fixed income 30 % 30 % Hedge funds 8 % 8 % Real estate 10 % 10 % Alternative investments 8 % 8 % Cash and short-term securities 6 % 6 % 100 % 100 % Taking into account estimated employee future service, FirstEnergy expects to make the following benefit payments from plan assets and other payments, net of participant contributions: OPEB Pension Benefit Payments Subsidy Receipts (In millions) 2022 $ 566 $ 44 $ (1) 2023 575 41 (1) 2024 581 39 (1) 2025 590 38 — 2026 598 37 — Years 2027-2030 3,075 164 (2) |
STOCK-BASED COMPENSATION PLANS
STOCK-BASED COMPENSATION PLANS | 12 Months Ended |
Dec. 31, 2021 | |
Share-based Payment Arrangement [Abstract] | |
STOCK-BASED COMPENSATION PLANS | STOCK-BASED COMPENSATION PLANS FirstEnergy grants stock-based awards through the ICP 2020, primarily in the form of restricted stock and performance-based restricted stock units. There are also awards currently outstanding issued through the ICP 2015 primarily in the form of restricted stock and performance-based restricted stock units. The ICP 2020 and ICP 2015 include shareholder authorization to each issue 10 million shares of common stock or their equivalent. As of December 31, 2021, approximately 12.7 million shares were available for future grants under the ICP 2020 assuming maximum performance metrics are achieved for the outstanding cycles of restricted stock units. No shares are available for future grants under ICP 2015. Shares not issued due to forfeitures or cancellations originally granted through the ICP 2015 may be added back to the ICP 2020. Shares granted under the ICP 2020 and ICP 2015 are issued from authorized but unissued common stock. Vesting periods for stock-based awards range from two to ten years, with the majority of awards having a vesting period of three years. FirstEnergy also issues stock through its 401(k) Savings Plan, EDCP, and DCPD. Currently, FirstEnergy records the compensation costs for stock-based compensation awards that will be paid in stock over the vesting period based on the fair value on the grant date. FirstEnergy accounts for forfeitures as they occur. FirstEnergy adjusts the compensation costs for stock-based compensation awards that will be paid in cash based on changes in the fair value of the award as of each reporting date. FirstEnergy records the actual tax benefit realized from tax deductions when awards are exercised or settled. Actual income tax benefits realized during the years ended December 31, 2021, 2020 and 2019, were $10 million, $20 million and $24 million, respectively. The income tax effects of awards are recognized in the income statement when the awards vest, are settled or are forfeited. Stock-based compensation costs and the amount of stock-based compensation costs capitalized related to FirstEnergy plans for the years ended December 31, 2021, 2020 and 2019, are included in the following tables: For the Years Ended December 31, Stock-based Compensation Plan 2021 2020 2019 (In millions) Restricted Stock Units $ 40 $ 22 $ 73 Restricted Stock 2 1 1 401(k) Savings Plan 35 33 33 EDCP & DCPD 13 (5) 9 Total $ 90 $ 51 $ 116 Stock-based compensation costs capitalized $ 47 $ 26 $ 54 Income tax benefits associated with stock-based compensation plan expense were $5 million, $3 million and $10 million for the years ended December 31, 2021, 2020 and 2019, respectively. Restricted Stock Units Beginning with the performance-based restricted stock units granted in 2015, two-thirds of each award will be paid in stock and one-third will be paid in cash. Restricted stock units payable in stock provide the participant the right to receive, at the end of the period of restriction, a number of shares of common stock equal to the number of stock units set forth in the agreement, subject to adjustment based on FirstEnergy's performance relative to financial and operational performance targets applicable to each award. The grant date fair value of the stock portion of the restricted stock unit award is measured based on the average of the high and low prices of FE common stock on the date of grant. Beginning with awards granted in 2018, restricted stock units include a performance metric consisting of a relative total shareholder return modifier utilizing the S&P 500 Utility Index as a comparator group. The estimated grant date fair value for these awards is calculated using the Monte Carlo simulation method . Restricted stock units payable in cash provide the participant the right to receive cash based on the number of stock units set forth in the agreement and value of the equivalent number of shares of FE common stock as of the vesting date. The cash portion of the restricted stock unit award is considered a liability award, which is remeasured each period based on FE's stock price and projected performance adjustments. The liability recorded for the portion of performance-based restricted stock units payable in cash in the future as of December 31, 2021, was $24 million. During 2021, approximately $11 million was paid in relation to the cash portion of restricted stock unit obligations that vested in 2021. The vesting period for the performance-based restricted stock unit awards granted in 2019, 2020 and 2021, were each three years. Dividend equivalents are received on the restricted stock units and are reinvested in additional restricted stock units and subject to the same performance conditions as the underlying award. Restricted stock unit activity for the year ended December 31, 2021, was as follows: Restricted Stock Unit Activity Shares (in millions) Weighted-Average Grant Date Fair Value (per share) Nonvested as of January 1, 2021 1.8 $ 40.25 Granted in 2021 1.3 35.50 Forfeited in 2021 (0.3) 40.08 Vested in 2021 (1) (1.0) 33.73 Nonvested as of December 31, 2021 1.8 $ 41.89 (1) Excludes dividend equivalents of approximately 130 thousand shares earned during vesting period. The weighted-average fair value of awards granted in 2021, 2020 and 2019 was $35.50, $44.42 and $41.23 per share, respectively. For the years ended December 31, 2021, 2020, and 2019, the fair value of restricted stock units vested was $34 million, $80 million, and $91 million, respectively. As of December 31, 2021, there was approximately $29 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted for restricted stock units, which is expected to be recognized over a period of approximately three years. Restricted Stock Certain employees receive awards of FE restricted stock (as opposed to "units" with the right to receive shares at the end of the restriction period) subject to restrictions that lapse over a defined period of time or upon achieving performance results. The fair value of restricted stock is measured based on the average of the high and low prices of FE common stock on the date of grant. Dividends are received on the restricted stock and are reinvested in additional shares of restricted stock, subject to the vesting conditions of the underlying award. Restricted stock activity for the year ended December 31, 2021, was not material. 401(k) Savings Plan In 2021 and 2020, approximately 1 million shares of FE common stock, respectively, were issued and contributed to participants' accounts. EDCP Under the EDCP, certain employees can defer a portion of their compensation, including base salary, annual incentive awards and/or long-term incentive awards, into unfunded accounts. Annual incentive and long-term incentive awards may be deferred in FE stock accounts. Base salary and annual incentive awards may be deferred into a retirement cash account which earns interest. Dividends are calculated quarterly on stock units outstanding and are credited in the form of additional stock units. The form of payout as stock or cash vary depending upon the form of the award, the duration of the deferral and other factors. Awards deferred into a retirement stock account will pay out in cash upon separation from service, death or disability. Interest accrues on the cash allocated to the retirement cash account and the balance will pay out in cash over a time period as elected by the participant. DCPD Under the DCPD, members of the FE Board can elect to defer all or a portion of their equity retainers to a deferred stock account and their cash retainers to deferred stock or deferred cash accounts. The net liability recognized for DCPD of approximately $9 million and $7 million as of December 31, 2021 and 2020, respectively, is included in “Retirement benefits,” on the Consolidated Balance Sheets. |
TAXES
TAXES | 12 Months Ended |
Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |
TAXES | TAXES FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled. FE and its subsidiaries are party to an intercompany income tax allocation agreement that provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FE, excluding any tax benefits derived from certain interest expense, are generally reallocated to the subsidiaries of FE that have taxable income. That allocation is accounted for as a capital contribution to the company receiving the tax benefit. On April 9, 2021, West Virginia enacted legislation changing the state’s corporate income tax apportionment rules, including adopting a single sales factor formula and market-based sourcing for sales of services and intangibles, effective for taxable years beginning on or after January 1, 2022. Enactment of this law triggered a remeasurement of state deferred income taxes for entities included in FirstEnergy’s West Virginia combined unitary return, resulting in a net impact of approximately $9 million in additional tax expense in 2021. For the Years Ended December 31, INCOME TAXES (1) 2021 2020 2019 (In millions) Currently payable (receivable)- Federal (2) $ 2 $ (14) $ (16) State 21 21 24 23 7 8 Deferred, net- Federal (3) 174 171 150 State (4) 127 (38) 60 301 133 210 Investment tax credit amortization (4) (14) (5) Total income taxes $ 320 $ 126 $ 213 (1) Income Taxes on Income from Continuing Operations. (2) Excludes $2 million of federal tax benefit and $6 million of federal tax expense associated with discontinued operations for the years ended December 31, 2021 and 2020 respectively. (3) Excludes $46 million, $66 million and $9 million of federal tax benefits associated with discontinued operations for the years ended December 31, 2021, 2020 and 2019, respectively. (4) Excludes $1 million and $4 million of state tax expense associated with discontinued operations for the years ended December 31, 2020 and 2019, respectively. FirstEnergy tax rates are affected by permanent items, such as AFUDC equity and other flow-through items, as well as discrete items that may occur in any given period but are not consistent from period to period. The following tables provide a reconciliation of federal income tax expense (benefit) at the federal statutory rate to the total income taxes (benefits) for the years ended December 31, 2021, 2020 and 2019: For the Years Ended December 31, 2021 2020 2019 (In millions) Income from Continuing Operations, before income taxes $ 1,559 $ 1,129 $ 1,117 Federal income tax expense at statutory rate (21%) $ 327 $ 237 $ 235 Increases (reductions) in taxes resulting from- State income taxes, net of federal tax benefit 122 75 96 AFUDC equity and other flow-through (29) (38) (36) Amortization of investment tax credits (4) (14) (5) Federal tax credits claimed (34) — — Nondeductible DPA monetary penalty 52 — — Excess deferred tax amortization due to the Tax Act (54) (56) (74) TMI-2 reversal of tax regulatory liabilities — (40) — Uncertain tax positions (82) (1) (11) Valuation allowances 17 (49) 5 Other, net 5 12 3 Total income taxes $ 320 $ 126 $ 213 Effective income tax rate 20.5 % 11.2 % 19.1 % FirstEnergy's effective tax rate on continuing operations for 2021 and 2020 was 20.5% and 11.2%, respectively. The increase in effective tax rate was primarily due to: • The non-deductibility of the DPA monetary penalty; • The absence of a $52 million benefit for reduction in valuation allowances in 2020 from the recognition of deferred gains on prior intercompany generation asset transfers triggered by the FES Debtors’ emergence from bankruptcy and deconsolidation from FirstEnergy’s consolidated federal income tax group; • Lower amortization of investment tax credits due to the absence of a $10 million benefit from accelerated amortization of certain investment credits in 2020; • The absence of a $40 million benefit related to reversals of certain tax regulatory liabilities resulting from the transfer of TMI-2 in 2020; • Additional tax expense of $9 million as a result of the West Virginia legislation that changed income tax apportionment rules discussed above; • Partially offset by a net $81 million increase in uncertain tax position benefits primarily related to reserves on the worthless stock deduction, nondeductible interest under Section 163(j), and certain federal tax credits, discussed below; and • A $34 million benefit in federal tax credits claimed on FirstEnergy’s federal income tax return in 2021. Accumulated deferred income taxes as of December 31, 2021 and 2020, are as follows: As of December 31, 2021 2020 (In millions) Property basis differences $ 5,670 $ 5,396 Pension and OPEB (570) (769) AROs (21) (28) Regulatory asset/liability 322 440 Deferred compensation (155) (165) Loss carryforwards and tax credits (2,040) (1,995) Valuation reserve 484 496 All other (253) (280) Net deferred income tax liability $ 3,437 $ 3,095 FirstEnergy has recorded as deferred income tax assets the effect of Federal NOLs and tax credits that will more likely than not be realized through future operations and through the reversal of existing temporary differences. As of December 31, 2021, FirstEnergy's loss carryforwards primarily consisted of $6.9 billion ($1.5 billion, net of tax) of Federal NOL carryforwards that will begin to expire in 2031. The table below summarizes pre-tax NOL carryforwards and their respective anticipated expirations for state and local income tax purposes of approximately $11.9 billion ($544 million, net of tax) for FirstEnergy, of which approximately $2.7 billion ($136 million, net of tax) is expected to be utilized based on current estimates and assumptions. The ultimate utilization of these NOLs may be impacted by statutory limitations on the use of NOLs imposed by state and local tax jurisdictions, changes in statutory tax rates, and changes in business which, among other things, impact both future profitability and the manner in which future taxable income is apportioned to various state and local tax jurisdictions. Expiration Period State Local (In millions) 2022-2026 $ 2,603 $ 3,783 2027-2031 1,390 — 2032-2036 992 — 2037-2041 959 — Indefinite 2,157 — $ 8,101 $ 3,783 The following table summarizes the changes in valuation allowances on federal, state and local DTAs related to disallowed interest and certain employee remuneration, in addition to state and local NOLs discussed above for the years ended December 31, 2021, 2020 and 2019: (In millions) 2021 2020 2019 Beginning of year balance $ 496 $ 441 $ 394 Charged to income (12) 55 47 Charged to other accounts — — — Write-offs — — — End of year balance $ 484 $ 496 $ 441 FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. A recognition threshold and measurement attribute are utilized for financial statement recognition and measurement of tax positions taken or expected to be taken on the tax return. As of December 31, 2021 and 2020, FirstEnergy's total unrecognized income tax benefits were approximately $47 million and $139 million, respectively. The $92 million net decrease in unrecognized income tax benefits is primarily due to: • Decreases of $68 million for reserves related to the worthless stock deduction (see Note 14, "Discontinued Operations," for further discussion) and $29 million for reserves attributable to nondeductible interest under Section 163(j), both of which were effectively settled with federal taxing authorities; • Decrease of $7 million to the reserve due to the remeasurement of certain positions for the change in West Virginia deferred taxes resulting from a state law change discussed above and $1 million due to other state tax rate changes; • Decrease of $2 million due to the lapse in statue in certain state taxing jurisdictions; • Partially offset by an increase of $15 million for reserves related to certain federal tax credits claimed on FirstEnergy's federal income tax return in 2021. If ultimately recognized in future years, approximately $39 million of unrecognized income tax benefits would impact the effective tax rate. As of December 31, 2021, it is reasonably possible that approximately $31 million of unrecognized tax benefits may be resolved during 2022 as a result of settlements with taxing authorities or the statute of limitations expiring, of which $24 million would ultimately affect FirstEnergy's effective tax rate. The following table summarizes the changes in unrecognized tax positions for the years ended December 31, 2021, 2020 and 2019: (In millions) Balance, January 1, 2019 $ 158 Current year increases 22 Prior year decreases (12) Decrease for lapse in statute (4) Balance, December 31, 2019 $ 164 Current year increases 7 Prior year decreases (28) Decrease for lapse in statute (2) Effectively settled with taxing authorities (2) Balance, December 31, 2020 $ 139 Current year increases 15 Prior years decreases (8) Effectively settled with taxing authorities (97) Decrease for lapse in statute (2) Balance, December 31, 2021 $ 47 FirstEnergy recognizes interest expense or income and penalties related to uncertain tax positions in income taxes by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken, or expected to be taken, on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes. FirstEnergy's recognition of net interest associated with unrecognized tax benefits in 2021, 2020 and 2019, was not material. For the years ended December 31, 2021 and 2020, the cumulative net interest payable recorded by FirstEnergy was not material. IRS review of FirstEnergy’s federal income tax returns is complete through the 2020 tax year with no pending adjustments. FirstEnergy’s tax returns for some state jurisdictions are open from tax years 2009 to 2020. General Taxes General tax expense for the years ended December 31, 2021, 2020 and 2019, recognized in continuing operations is summarized as follows: For the Years Ended December 31, 2021 2020 2019 (In millions) KWH excise $ 189 $ 183 $ 191 State gross receipts 190 182 185 Real and personal property 571 541 504 Social security and unemployment 103 112 100 Other 20 28 28 Total general taxes $ 1,073 $ 1,046 $ 1,008 |
LEASES
LEASES | 12 Months Ended |
Dec. 31, 2021 | |
Leases [Abstract] | |
LEASES | LEASES FirstEnergy primarily leases vehicles as well as building space, office equipment, and other property and equipment under cancellable and non-cancelable leases. FirstEnergy does not have any material leases in which it is the lessor. FirstEnergy accounts for leases under, "Leases (Topic 842)". Leases with an initial term of 12 months or less are recognized as lease expense on a straight-line basis over the lease term and not recorded on the balance sheet. Most leases include one or more options to renew, with renewal terms that can extend the lease term from 1 to 40 years, and certain leases include options to terminate. The exercise of lease renewal options is at FirstEnergy’s sole discretion. Renewal options are included within the lease liability if they are reasonably certain based on various factors relative to the contract. Certain leases also include options to purchase the leased property. The depreciable life of leased assets and leasehold improvements are limited by the expected lease term unless there is a transfer of title or purchase option reasonably certain of exercise. FirstEnergy’s lease agreements do not contain any material restrictive covenants. FirstEnergy has elected a policy to not separate lease components from non-lease components for all asset classes. For vehicles leased under certain master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, FirstEnergy is committed to pay the difference in the actual fair value and the residual value guarantee. FirstEnergy does not believe it is probable that it will be required to pay anything pertaining to the residual value guarantee, and the lease liabilities and right-of-use assets are measured accordingly. Finance leases for assets used in regulated operations are recognized in FirstEnergy’s Consolidated Statements of Income such that amortization of the right-of-use asset and interest on lease liabilities equals the expense allowed for ratemaking purposes. Finance leases for regulated and non-regulated operations are accounted for as if the assets were owned and financed, with associated expense recognized in Interest expense and Provision for depreciation on FirstEnergy’s Consolidated Statements of Income, while all operating lease expenses are recognized in Other operating expense. The components of lease expense were as follows: For the Year Ended December 31, 2021 (In millions) Vehicles Buildings Other Total Operating lease costs (1) $ 44 $ 9 $ 18 $ 71 Finance lease costs: Amortization of right-of-use assets 12 1 1 14 Interest on lease liabilities 1 3 — 4 Total finance lease cost 13 4 1 18 Total lease cost $ 57 $ 13 $ 19 $ 89 (1) Includes $21 million of short-term lease costs. For the Year Ended December 31, 2020 (In millions) Vehicles Buildings Other Total Operating lease costs (1) $ 35 $ 8 $ 17 $ 60 Finance lease costs: Amortization of right-of-use assets 14 — 1 15 Interest on lease liabilities 2 3 — 5 Total finance lease cost 16 3 1 20 Total lease cost $ 51 $ 11 $ 18 $ 80 (1) Includes $17 million of short-term lease costs. For the Year Ended December 31, 2019 (In millions) Vehicles Buildings Other Total Operating lease costs (1) $ 28 $ 9 $ 12 $ 49 Finance lease costs: Amortization of right-of-use assets 15 1 1 17 Interest on lease liabilities 3 3 — 6 Total finance lease cost 18 4 1 23 Total lease cost $ 46 $ 13 $ 13 $ 72 (1) Includes $13 million of short-term lease costs. Supplemental cash flow information related to leases was as follows: For the Years Ended December 31, (In millions) 2021 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 64 $ 44 $ 29 Operating cash flows from finance leases 4 4 5 Finance cash flows from finance leases 13 15 25 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 60 $ 67 $ 83 Finance leases 5 — 3 Lease terms and discount rates were as follows: As of December 31, 2021 2020 2019 Weighted-average remaining lease terms (years) Operating leases 7.97 8.55 9.42 Finance leases 8.12 7.74 4.62 Weighted-average discount rate (1) Operating leases 4.16 % 4.21 % 4.51 % Finance leases 12.22 % 11.58 % 10.45 % (1) When an implicit rate is not readily determinable, an incremental borrowing rate is utilized, determining the present value of lease payments. The rate is determined based on expected term and information available at the commencement date. Supplemental balance sheet information related to leases was as follows: As of December 31, (In millions) Financial Statement Line Item 2021 2020 Assets Operating lease (1) Deferred charges and other assets $ 279 $ 265 Finance lease (2) Property, plant and equipment 48 57 Total leased assets $ 327 $ 322 Liabilities Current: Operating Other current liabilities $ 39 $ 42 Finance Currently payable long-term debt 13 14 Noncurrent: Operating Other noncurrent liabilities 271 263 Finance Long-term debt and other long-term obligations 23 31 Total leased liabilities $ 346 $ 350 (1) Operating lease assets are recorded net of accumulated amortization of $79 million and $51 million as of December 31, 2021 and 2020, respectively. (2) Finance lease assets are recorded net of accumulated amortization of $95 million and $96 million as of December 31, 2021 and 2020, respectively. Maturities of lease liabilities as of December 31, 2021, were as follows: (In millions) Operating Leases Finance Leases Total 2022 $ 54 $ 16 $ 70 2023 54 9 63 2024 48 5 53 2025 45 5 50 2026 41 5 46 Thereafter 133 8 141 Total lease payments (1) 375 48 423 Less imputed interest 65 12 77 Total net present value $ 310 $ 36 $ 346 (1) Operating lease payments for certain leases are offset by sublease receipts of $10 million over 11 years. |
LEASES | LEASES FirstEnergy primarily leases vehicles as well as building space, office equipment, and other property and equipment under cancellable and non-cancelable leases. FirstEnergy does not have any material leases in which it is the lessor. FirstEnergy accounts for leases under, "Leases (Topic 842)". Leases with an initial term of 12 months or less are recognized as lease expense on a straight-line basis over the lease term and not recorded on the balance sheet. Most leases include one or more options to renew, with renewal terms that can extend the lease term from 1 to 40 years, and certain leases include options to terminate. The exercise of lease renewal options is at FirstEnergy’s sole discretion. Renewal options are included within the lease liability if they are reasonably certain based on various factors relative to the contract. Certain leases also include options to purchase the leased property. The depreciable life of leased assets and leasehold improvements are limited by the expected lease term unless there is a transfer of title or purchase option reasonably certain of exercise. FirstEnergy’s lease agreements do not contain any material restrictive covenants. FirstEnergy has elected a policy to not separate lease components from non-lease components for all asset classes. For vehicles leased under certain master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, FirstEnergy is committed to pay the difference in the actual fair value and the residual value guarantee. FirstEnergy does not believe it is probable that it will be required to pay anything pertaining to the residual value guarantee, and the lease liabilities and right-of-use assets are measured accordingly. Finance leases for assets used in regulated operations are recognized in FirstEnergy’s Consolidated Statements of Income such that amortization of the right-of-use asset and interest on lease liabilities equals the expense allowed for ratemaking purposes. Finance leases for regulated and non-regulated operations are accounted for as if the assets were owned and financed, with associated expense recognized in Interest expense and Provision for depreciation on FirstEnergy’s Consolidated Statements of Income, while all operating lease expenses are recognized in Other operating expense. The components of lease expense were as follows: For the Year Ended December 31, 2021 (In millions) Vehicles Buildings Other Total Operating lease costs (1) $ 44 $ 9 $ 18 $ 71 Finance lease costs: Amortization of right-of-use assets 12 1 1 14 Interest on lease liabilities 1 3 — 4 Total finance lease cost 13 4 1 18 Total lease cost $ 57 $ 13 $ 19 $ 89 (1) Includes $21 million of short-term lease costs. For the Year Ended December 31, 2020 (In millions) Vehicles Buildings Other Total Operating lease costs (1) $ 35 $ 8 $ 17 $ 60 Finance lease costs: Amortization of right-of-use assets 14 — 1 15 Interest on lease liabilities 2 3 — 5 Total finance lease cost 16 3 1 20 Total lease cost $ 51 $ 11 $ 18 $ 80 (1) Includes $17 million of short-term lease costs. For the Year Ended December 31, 2019 (In millions) Vehicles Buildings Other Total Operating lease costs (1) $ 28 $ 9 $ 12 $ 49 Finance lease costs: Amortization of right-of-use assets 15 1 1 17 Interest on lease liabilities 3 3 — 6 Total finance lease cost 18 4 1 23 Total lease cost $ 46 $ 13 $ 13 $ 72 (1) Includes $13 million of short-term lease costs. Supplemental cash flow information related to leases was as follows: For the Years Ended December 31, (In millions) 2021 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 64 $ 44 $ 29 Operating cash flows from finance leases 4 4 5 Finance cash flows from finance leases 13 15 25 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 60 $ 67 $ 83 Finance leases 5 — 3 Lease terms and discount rates were as follows: As of December 31, 2021 2020 2019 Weighted-average remaining lease terms (years) Operating leases 7.97 8.55 9.42 Finance leases 8.12 7.74 4.62 Weighted-average discount rate (1) Operating leases 4.16 % 4.21 % 4.51 % Finance leases 12.22 % 11.58 % 10.45 % (1) When an implicit rate is not readily determinable, an incremental borrowing rate is utilized, determining the present value of lease payments. The rate is determined based on expected term and information available at the commencement date. Supplemental balance sheet information related to leases was as follows: As of December 31, (In millions) Financial Statement Line Item 2021 2020 Assets Operating lease (1) Deferred charges and other assets $ 279 $ 265 Finance lease (2) Property, plant and equipment 48 57 Total leased assets $ 327 $ 322 Liabilities Current: Operating Other current liabilities $ 39 $ 42 Finance Currently payable long-term debt 13 14 Noncurrent: Operating Other noncurrent liabilities 271 263 Finance Long-term debt and other long-term obligations 23 31 Total leased liabilities $ 346 $ 350 (1) Operating lease assets are recorded net of accumulated amortization of $79 million and $51 million as of December 31, 2021 and 2020, respectively. (2) Finance lease assets are recorded net of accumulated amortization of $95 million and $96 million as of December 31, 2021 and 2020, respectively. Maturities of lease liabilities as of December 31, 2021, were as follows: (In millions) Operating Leases Finance Leases Total 2022 $ 54 $ 16 $ 70 2023 54 9 63 2024 48 5 53 2025 45 5 50 2026 41 5 46 Thereafter 133 8 141 Total lease payments (1) 375 48 423 Less imputed interest 65 12 77 Total net present value $ 310 $ 36 $ 346 (1) Operating lease payments for certain leases are offset by sublease receipts of $10 million over 11 years. |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 12 Months Ended |
Dec. 31, 2021 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS RECURRING FAIR VALUE MEASUREMENTS Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy and a description of the valuation techniques are as follows: Level 1 - Quoted prices for identical instruments in active market Level 2 - Quoted prices for similar instruments in active market - Quoted prices for identical or similar instruments in markets that are not active - Model-derived valuations for which all significant inputs are observable market data Models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 - Valuation inputs are unobservable and significant to the fair value measurement FirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market conditions change. When underlying prices are not observable, prices from the long-term price forecast are used to measure fair value. FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term PJM auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs' carrying values are periodically adjusted to fair value using a mark-to-model methodology, which approximates market. The primary inputs into the model, which are generally less observable than objective sources, are the most recent PJM auction clearing prices and the FTRs' remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. Significant increases or decreases in inputs in isolation may have resulted in a higher or lower fair value measurement. NUG contracts represent PPAs with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. NUG contract carrying values are recorded at fair value and adjusted periodically using a mark-to-model methodology, which approximates market. The primary unobservable inputs into the model are regional power prices and generation MWH. Pricing for the NUG contracts is a combination of market prices for the current year and next two years based on observable data and internal models using historical trends and market data for the remaining years under contract. The internal models use forecasted energy purchase prices as an input when prices are not defined by the contract. Forecasted market prices are based on Intercontinental Exchange, Inc. quotes and management assumptions. Generation MWH reflects data provided by contractual arrangements and historical trends. The model calculates the fair value by multiplying the prices by the generation MWH. Significant increases or decreases in inputs in isolation may have resulted in a higher or lower fair value measurement. For investments reported at NAV where there is no readily determinable fair value, a practical expedient is available that allows the NAV to approximate fair value. Investments that use NAV as a practical expedient are excluded from the requirement to be categorized within the fair value hierarchy tables. Instead, these investments are reported outside of the fair value hierarchy tables to assist in the reconciliation of investment balances reported in the tables to the balance sheet. FirstEnergy has elected the NAV practical expedient for investments in private equity funds, insurance-linked securities, hedge funds (absolute return) and real estate funds held within the pension plan. See Note 4, "Pension And Other Post-Employment Benefits" for the pension financial assets accounted for at fair value by level within the fair value hierarchy. FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were no changes in valuation methodologies used as of December 31, 2021, from those used as of December 31, 2020. The determination of the fair value measures takes into consideration various factors, including but not limited to, nonperformance risk, counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of these forms of risk was not significant to the fair value measurements. The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy: December 31, 2021 December 31, 2020 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Derivative assets FTRs (1) $ — $ — $ 9 $ 9 $ — $ — $ 3 $ 3 Equity securities 2 — — 2 2 — — 2 U.S. state debt securities — 273 — 273 — 276 — 276 Cash, cash equivalents and restricted cash (2) 1,511 — — 1,511 1,801 — — 1,801 Other (3) — 42 — 42 — 41 — 41 Total assets $ 1,513 $ 315 $ 9 $ 1,837 $ 1,803 $ 317 $ 3 $ 2,123 Liabilities Derivative liabilities FTRs (1) $ — $ — $ (1) $ (1) $ — $ — $ — $ — Total liabilities $ — $ — $ (1) $ (1) $ — $ — $ — $ — Net assets (liabilities) (4) $ 1,513 $ 315 $ 8 $ 1,836 $ 1,803 $ 317 $ 3 $ 2,123 (1) Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. (2) Restricted cash of $49 million and $67 million as of December 31, 2021 and 2020 respectively, primarily relates to cash collected from JCP&L, MP, PE and the Ohio Companies' customers that is specifically used to service debt of their respective funding companies. (3) Primarily consists of short-term investments. (4) Excludes $1 million as of December 31, 2020, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. Rollforward of Level 3 Measurements The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the years ended December 31, 2021 and 2020: NUG Contracts (1) FTRs (1) Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net (In millions) January 1, 2020 Balance $ — $ (16) $ (16) $ 4 $ (1) $ 3 Unrealized gain (loss) — (3) (3) (3) — (3) Purchases — — — 7 (2) 5 Settlements — 19 19 (5) 3 (2) December 31, 2020 Balance $ — $ — $ — $ 3 $ — $ 3 Unrealized gain (loss) — — — 7 — 7 Purchases — — — 5 (2) 3 Settlements — — — (6) 1 (5) December 31, 2021 Balance $ — $ — $ — $ 9 $ (1) $ 8 (1) Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. Level 3 Quantitative Information The following table provides quantitative information for FTRs contracts that are classified as Level 3 in the fair value hierarchy for the year ended December 31, 2021: Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ 8 Model RTO auction clearing prices $1.10 to $4.60 $1.80 Dollars/MWH INVESTMENTS All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include AFS debt securities and other investments. FirstEnergy has no debt securities held for trading purposes. Generally, unrealized gains and losses on equity securities are recognized in income whereas unrealized gains and losses on AFS debt securities are recognized in AOCI. However, the JCP&L spent nuclear fuel disposal trusts are subject to regulatory accounting with all gains and losses on equity and AFS debt securities offset against regulatory assets. On October 15, 2019, JCP&L, ME, PN and GPUN executed an asset purchase and sale agreement with TMI-2 Solutions, LLC, a subsidiary of EnergySolutions, LLC, concerning the transfer and dismantlement of TMI-2. With the receipt of all required regulatory approvals, the transaction was consummated, including the transfer of external trusts for the decommissioning and environmental remediation of TMI-2, on December 18, 2020. Spent Nuclear Fuel Disposal Trusts JCP&L holds debt securities within the spent nuclear fuel disposal trust, which are classified as AFS securities, recognized at fair market value. The trust is intended for funding spent nuclear fuel disposal fees to the DOE associated with the previously owned Oyster Creek and TMI-1 nuclear power plants. The following table summarizes the amortized cost basis, unrealized gains, unrealized losses and fair values of investments held in nuclear fuel disposal trusts as of December 31, 2021 and 2020: December 31, 2021 (1) December 31, 2020 (2) Cost Basis Unrealized Gains Unrealized Losses Fair Value Cost Basis Unrealized Gains Unrealized Losses Fair Value (In millions) Debt securities $ 280 $ 2 $ (9) $ 273 $ 275 $ 7 $ (6) $ 276 (1) Excludes short-term cash investments of $11 million. (2) Excludes short-term cash investments of $9 million. Proceeds from the sale of investments in AFS debt securities, realized gains and losses on those sales and interest and dividend income for the years ended December 31, 2021, 2020 and 2019, were as follows: For the Years Ended December 31, 2021 2020 (1) 2019 (1) (In millions) Sale Proceeds $ 48 $ 186 $ 1,637 Realized Gains — 12 98 Realized Losses (3) (8) (31) Interest and Dividend Income 11 22 38 (1) Includes amounts associated with NDTs that were previously held by JCP&L, ME, and PN. See above for additional information. Other Investments Other investments include employee benefit trusts, which are primarily invested in corporate-owned life insurance policies, and equity method investments. Other investments were $371 million and $322 million as of December 31, 2021 and 2020, respectively, and are excluded from the amounts reported above. LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported as Short-term borrowings on the Consolidated Balance Sheets at cost. Since these borrowings are short-term in nature, FirstEnergy believes that their costs approximate their fair market value. The following table provides the approximate fair value and related carrying amounts of long-term debt, which excludes finance lease obligations and net unamortized debt issuance costs, unamortized fair value adjustments, premiums and discounts as of December 31, 2021 and 2020: As of December 31, 2021 2020 (In millions) Carrying Value $ 23,946 $ 22,377 Fair Value 27,043 25,465 The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy. FirstEnergy classified short-term borrowings, long-term debt and other long-term obligations as Level 2 in the fair value hierarchy as of December 31, 2021 and 2020. See Note 9, "Capitalization," for further information on long-term debt issued during the twelve months ended December 31, 2021. |
CAPITALIZATION
CAPITALIZATION | 12 Months Ended |
Dec. 31, 2021 | |
Capitalization, Long-term Debt and Equity [Abstract] | |
CAPITALIZATION | CAPITALIZATION COMMON STOCK Retained Earnings and Dividends As of December 31, 2021, FirstEnergy had an accumulated deficit of $1.6 billion. Dividends declared in 2021 and 2020 totaled $1.56 per share in each period. Dividends of $0.39 per share were paid in the first, second, third and fourth quarters in 2021 and 2020, respectively. On December 21, 2021, the FE Board declared a quarterly dividend of $0.39 per share to be paid from OPIC in the first quarter of 2022. The amount and timing of all dividend declarations are subject to the discretion of the FE Board and its consideration of business conditions, results of operations, financial condition, risks and uncertainties of the government investigations, and other factors. In addition to paying dividends from retained earnings, the Ohio Companies, Penn, JCP&L, ME and PN have authorization from FERC to pay cash dividends to FE from paid-in capital accounts, as long as their FERC-defined equity-to-total-capitalization ratio remains above 35%. In addition, AGC has authorization from FERC to pay cash dividends to its parent, MP, from paid-in capital accounts, as long as its FERC-defined equity-to-total-capitalization ratio remains above 45%. The articles of incorporation, indentures, regulatory limitations, FET P&SA, and various other agreements, including those relating to the long-term debt of certain FirstEnergy subsidiaries contain provisions that could further restrict the payment of dividends on their common stock. None of these provisions materially restricted FirstEnergy subsidiaries’ abilities to pay cash dividends to FE as of December 31, 2021. Common Stock Issuance FE issued approximately 1 million shares of common stock in 2021, 2 million shares of common stock in 2020 and 3 million shares of common stock in 2019 to registered shareholders and its directors and the employees of its subsidiaries under its Stock Investment Plan and certain share-based benefit plans. On November 6, 2021, FE entered into a Common Stock Purchase Agreement with BIP Securities II-B L.P., an affiliate of Blackstone Infrastructure Partners L.P., for the private placement of 25,588,535 shares of FE common stock, par value $0.10 per share, at a price of $39.08 per share, representing an investment of $1.0 billion. The transaction settled on December 13, 2021. Issuance costs associated with the transaction were approximately $26 million as of December 31, 2021. PREFERRED AND PREFERENCE STOCK FirstEnergy and the Utilities were authorized to issue preferred stock and preference stock as of December 31, 2021, as follows: Preferred Stock Preference Stock Shares Authorized Par Value Shares Authorized Par Value FE 5,000,000 $ 100 OE 6,000,000 $ 100 8,000,000 no par OE 8,000,000 $ 25 Penn 1,200,000 $ 100 CEI 4,000,000 no par 3,000,000 no par TE 3,000,000 $ 100 5,000,000 $ 25 TE 12,000,000 $ 25 JCP&L 15,600,000 no par ME 10,000,000 no par PN 11,435,000 no par MP 940,000 $ 100 PE 10,000,000 $ 0.01 WP 32,000,000 no par As of December 31, 2021 and 2020, there were no preferred stock or preference stock outstanding. Preferred Stock Issuance In January of 2018, FE entered into a Preferred Stock Purchase Agreement for the private placement of 1,616,000 shares of mandatorily convertible preferred stock, designated as the Series A Convertible Preferred Stock, par value $100 per share, representing an investment of nearly $1.62 billion ($162 million of mandatorily convertible preferred stock and $1.46 billion of OPIC). During 2018, 911,411 shares of preferred stock were converted into 33,238,910 shares of common stock at the option of the preferred stockholders. During 2019, the remaining 704,589 shares of preferred stock were converted into 25,696,168 shares of common stock at the option of the preferred stockholders. LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS The following tables present outstanding long-term debt and finance lease obligations for FirstEnergy as of December 31, 2021 and 2020: As of December 31, 2021 As of December 31, (Dollar amounts in millions) Maturity Date Interest Rate 2021 2020 FMBs and secured notes - fixed rate 2022-2059 2.650% - 8.250% $ 5,021 $ 4,802 Unsecured notes - fixed rate 2022-2050 1.600% - 7.375% 18,925 17,575 Finance lease obligations 36 45 Unamortized debt discounts (8) (34) Unamortized debt issuance costs (126) (118) Unamortized fair value adjustments 6 7 Currently payable long-term debt (1,606) (146) Total long-term debt and other long-term obligations $ 22,248 $ 22,131 See Note 7, "Leases," for additional information related to finance leases. During the twelve months ended December 31, 2021, the following long-term debt was issued: Company Issuance Date Interest Rate Maturity Amount Issuance Type Use of Proceeds FET 3/19/2021 2.87% 2028 $500 million Unsecured Notes Repay short-term borrowings under the former FET Revolving Facility. MP 4/9/2021 3.55% (1) 2027 $200 million FMB Fund MP’s ongoing capital expenditures, for working capital needs and for other general corporate purposes. TE 5/6/2021 2.65% 2028 $150 million Senior Secured Notes Repay short-term borrowings, fund TE’s ongoing capital expenditures and for other general corporate purposes. MAIT 5/24/2021 4.10% (2) 2028 $150 million Unsecured Notes Repay borrowings outstanding under FirstEnergy’s regulated company money pool, fund MAIT’s ongoing capital expenditures, to fund working capital and for other general corporate purposes. JCP&L 6/10/2021 2.75% 2032 $500 million Unsecured Notes Repay $450 million of short-term debt under the former FE Revolving Facility, storm recovery and restoration costs and expenses, to fund JCP&L’s ongoing capital expenditures, working capital requirements and for other general corporate purposes. ATSI 12/1/2021 2.65% 2032 $600 million Unsecured Notes Repay outstanding notes and short-term borrowings, to fund ATSI's ongoing capital expenditures, working capital requirements and for other general corporate purposes. (1) New debt was issued at a premium under a previously issued bond series, resulting in an effective interest rate of 2.06%. (2) New debt was issued at a premium under a previously issued note series, resulting in an effective interest rate of 2.55%. In December 2021, notice of redemption was provided for all remaining $850 million of FE's 4.25% Notes, Series B, due 2023, which was completed on January 20, 2022, and with a make-whole premium of approximately $38 million. Due to the redemption, the $850 million in notes is included within currently payable long-term debt on the Consolidated Balance Sheets as of December 31, 2021. On January 27, 2022, CEI instructed its indenture trustee to provide notice of redemption for all remaining $150 million of CEI's 2.77% Senior Notes, Series A, due 2034, for redemption to occur on March 14, 2022. Also on January 27, 2022, TE instructed its indenture trustee to provide notice of partial redemption for $25 million of TE's 2.65% Senior Secured Notes, due 2028, for partial redemption which occurred on February 11, 2022. The following table presents scheduled debt repayments or debt that has been noticed for redemption for outstanding long-term debt, excluding finance leases, fair value purchase accounting adjustments and unamortized debt discounts and premiums, for the next five years as of December 31, 2021. Year (In millions) 2022 $ 1,593 2023 344 2024 1,246 2025 2,023 2026 1,076 Securitized Bonds Environmental Control Bonds The consolidated financial statements of FirstEnergy include environmental control bonds issued by two bankruptcy remote, special purpose limited liability companies that are indirect subsidiaries of MP and PE. Proceeds from the bonds were used to construct environmental control facilities. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. Creditors of FirstEnergy, other than the limited liability company SPEs, have no recourse to any assets or revenues of the special purpose limited liability companies. As of December 31, 2021 and 2020, $274 million and $300 million of environmental control bonds were outstanding, respectively. Phase-In Recovery Bonds In June 2013, the SPEs formed by the Ohio Companies issued approximately $445 million of pass-through trust certificates supported by phase-in recovery bonds to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds are payable only from, and secured by, phase in recovery property owned by the SPEs. The bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and administers the phase in recovery property including the billing, collection and remittance of usage-based charges payable by retail electric customers. In the aggregate, the Ohio Companies are entitled to annual servicing fees of $445 thousand that are recoverable through the usage-based charges. The SPEs are considered VIEs and each one is consolidated into its applicable utility. As of December 31, 2021 and 2020, $222 million and $245 million of the phase-in recovery bonds were outstanding, respectively. FMBs The Ohio Companies and Penn each have a first mortgage indenture under which they can issue FMBs secured by a direct first mortgage lien on substantially all of their property and franchises, other than specifically excepted property. Debt Covenant Default Provisions FirstEnergy has various debt covenants under certain financing arrangements, including its revolving credit facilities and term loans. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on such debt and the maintenance of certain financial ratios. The failure by FirstEnergy to comply with the covenants contained in its financing arrangements could result in an event of default, which may have an adverse effect on its financial condition. As of December 31, 2021, FirstEnergy remains in compliance with all debt covenant provisions. Additionally, there are cross-default provisions in a number of the financing arrangements. These provisions generally trigger a default in the applicable financing arrangement of an entity if it, or any of its significant subsidiaries, default under another financing arrangement in excess of a certain principal amount, typically $100 million. Such defaults by any of the Utilities or Transmission Companies would cross-default certain FE financing arrangements containing these provisions, and a certain FET Financing arrangement, with respect to the Transmission Companies only, such defaults by AE Supply would not cross-default to applicable financing arrangements of FE. Also, defaults by FE would generally not cross-default applicable financing arrangements of any of FE’s subsidiaries. Cross-default provisions are not typically found in any of the senior notes or FMBs of FE or its subsidiaries. |
SHORT-TERM BORROWINGS AND BANK
SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT | 12 Months Ended |
Dec. 31, 2021 | |
Debt Disclosure [Abstract] | |
SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT | SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT FirstEnergy had no outstanding short-term borrowings as of December 31, 2021 and $2.2 billion of outstanding short-term borrowings as of December 31, 2020. On November 23, 2020, JCP&L, ME, Penn, TE and WP, borrowed $950 million in the aggregate under the former FE Revolving Facility, bringing the outstanding principal balance to $1.2 billion, with $1.3 billion of remaining availability. On November 23, 2020, FET and ATSI borrowed $1 billion in the aggregate under the former FET Revolving Facility, bringing the outstanding principal balance to $1 billion, with no remaining availability. FE, FET and certain of their respective subsidiaries increased their borrowings under the former Revolving Facilities as a proactive measure to increase their respective cash positions and preserve financial flexibility. These borrowings were repaid in full during 2021. On October 18, 2021, FE, FET, the Utilities, and the Transmission Companies entered into the 2021 Credit Facilities, which were six separate senior unsecured five-year syndicated revolving credit facilities with JPMorgan Chase Bank, N.A., Mizuho Bank, Ltd. and PNC Bank, National Association that replaced the FE Revolving Facility and the FET Revolving Facility, and provide for aggregate commitments of $4.5 billion. The 2021 Credit Facilities are available until October 18, 2026, as follows: • FE and FET, $1.0 billion revolving credit facility; • Ohio Companies, $800 million revolving credit facility; • Pennsylvania Companies, $950 million revolving credit facility; • JCP&L, $500 million revolving credit facility; • MP and PE, $400 million revolving credit facility; and • Transmission Companies, $850 million revolving credit facility. Under the 2021 Credit Facilities, an aggregate amount of $4.5 billion is available to be borrowed, repaid and reborrowed, subject to each borrower's respective sublimit under the respective facilities. These new credit facilities provide substantial liquidity to support the Regulated Distribution and Regulated Transmission businesses, and each of the operating companies within the businesses. As of December 31, 2021, available liquidity under the 2021 Credit Facilities was $4.5 billion. Borrowings under the 2021 Credit Facilities may be used for working capital and other general corporate purposes. Generally, borrowings under each of the credit facilities are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Each of the 2021 Credit Facilities contain financial covenants requiring each borrower, with the exception of FE, to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the 2021 Credit Facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter. FE is required under its 2021 Credit Facility to maintain a consolidated interest coverage ratio of not less than 2.50 times, measured at the end of each fiscal quarter for the last four fiscal quarters beginning with the quarter ending December 31, 2021. Subject to each borrower's sublimit, the amounts noted below are available for the issuance of LOCs (subject to borrowings drawn under the 2021 Credit Facilities) expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under each of the 2021 Credit Facilities and against the applicable borrower's borrowing sublimit. As of December 31, 2021, FirstEnergy had $4 million in outstanding LOCs. The 2021 Credit Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances in the event of any change in credit ratings of the borrowers. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the 2021 Credit Facilities are related to the credit ratings of the company borrowing the funds. Additionally, borrowings under each of the 2021 Credit Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of $100 million. As of December 31, 2021, the borrowers were in compliance with the applicable interest coverage and debt-to-total-capitalization ratio covenants in each case as defined under the respective 2021 Credit Facilities. FirstEnergy Money Pools FirstEnergy’s utility operating subsidiary companies also have the ability to borrow from each other and FE to meet their short-term working capital requirements. Similar but separate arrangements exist among FirstEnergy’s unregulated companies with AE Supply, FE, FET, FEV and certain other unregulated subsidiaries. FESC administers these money pools and tracks surplus funds of FE and the respective regulated and unregulated subsidiaries, as the case may be, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in 2021 was 1.01% per annum for the regulated companies’ money pool and 0.60% per annum for the unregulated companies’ money pool. Weighted Average Interest Rates |
ASSET RETIREMENT OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS | 12 Months Ended |
Dec. 31, 2021 | |
Asset Retirement Obligation [Abstract] | |
ASSET RETIREMENT OBLIGATIONS | ASSET RETIREMENT OBLIGATIONS FirstEnergy has recognized applicable legal obligations for AROs and their associated cost, including reclamation of sludge disposal ponds, closure of coal ash disposal sites, underground and above-ground storage tanks and wastewater treatment lagoons. In addition, FirstEnergy has recognized conditional retirement obligations, primarily for asbestos remediation. The following table summarizes the changes to the ARO balances during 2021 and 2020: ARO Reconciliation (In millions) Balance, January 1, 2020 $ 856 Liabilities settled (1) (744) Accretion 47 Balance, December 31, 2020 $ 159 Changes in timing and amount of estimated cash flows 8 Liabilities settled (1) Accretion 13 Balance, December 31, 2021 $ 179 (1) Includes $726 million related to the closing of the asset purchase and sale agreement with TMI-2 Solutions, LLC, a subsidiary of Energy Solutions |
REGULATORY MATTERS
REGULATORY MATTERS | 12 Months Ended |
Dec. 31, 2021 | |
Regulated Operations [Abstract] | |
REGULATORY MATTERS | REGULATORY MATTERS STATE REGULATION Each of the Utilities' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia, ATSI in Ohio, and the Transmission Companies in Pennsylvania are subject to certain regulations of the VSCC, PUCO and PPUC, respectively. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission facility. The following table summarizes the key terms of base distribution rate orders in effect for the Utilities as of December 31, 2021: Company Rates Effective For Customers Allowed Debt/Equity Allowed ROE CEI May 2009 51% /49% 10.5% ME (1) January 2017 48.8% / 51.2% Settled (2) MP February 2015 54% / 46% Settled (2) JCP&L November 2021 (3) 48.6% / 51.4% 9.6% OE January 2009 51% /49% 10.5% PE (West Virginia) February 2015 54% / 46% Settled (2) PE (Maryland) March 2019 47% / 53% 9.65% PN (1) January 2017 47.4% /52.6% Settled (2) Penn (1) January 2017 49.9% / 50.1% Settled (2) TE January 2009 51% / 49% 10.5% WP (1) January 2017 49.7% / 50.3% Settled (2) (1) Reflects filed debt/equity as final settlement/orders do not specifically include capital structure. (2) Commission-approved settlement agreements did not disclose ROE rates. (3) On October 28, 2020, the NJBPU approved JCP&L's distribution rate case settlement with an allowed ROE of 9.6% and a 48.6% debt / 51.4% equity capital structure. Rates are effective for customers on November 1, 2021, but beginning January 1, 2021, JCP&L offset the impact to customers' bills by amortizing an $86 million regulatory liability. MARYLAND PE operates under MDPSC approved base rates that were effective as of March 23, 2019. PE also provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third-party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS. The EmPOWER Maryland program requires each electric utility to file a plan to reduce electric consumption and demand 0.2% per year, up to the ultimate goal of 2% annual savings, for the duration of the 2021-2023 EmPOWER Maryland program cycles to the extent the MDPSC determines that cost-effective programs and services are available. PE's approved 2021-2023 EmPOWER Maryland plan continues and expands upon prior years' programs for a projected total investment of approximately $148 million over the three-year period. PE recovers program investments with a return through an annually reconciled surcharge, with most costs subject to recovery over a five-year period with a return on the unamortized balance. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding, and to date, such recovery has not been sought or obtained by PE. In 2019, MDPSC issued an order approving PE’s 2018 base rate case filing, which among other things, approved an annual rate increase of $6.2 million, approved three of the four EDIS programs for four years to fund enhanced service reliability programs, directed PE to file a new depreciation study within 18 months, and ordered the filing of a new base rate case in four years to correspond to the ending of the approved EDIS programs. Following the filing of PE’s depreciation study and subsequent filings by the Maryland Office of the People’s Counsel and the staff of the MDPSC, the public utility law judge issued a proposed order reducing PE’s base rates by $2.1 million. The MDPSC denied PE’s appeal of the proposed order on October 26, 2021, and the proposed order was affirmed. On April 9, 2020, the MDPSC issued an order allowing utilities to track and create a regulatory asset for future recovery of all prudently incurred incremental costs arising from the COVID-19 pandemic, including incremental uncollectible expense, incurred from the date of the Governor’s order (or earlier if the utility could show that the expenses related to suspension of service terminations). On June 16, 2021, the MDPSC provided PE with approximately $4 million of COVID-19 relief funds that was allocated by the Maryland General Assembly to be used to reduce certain residential customer utility account receivable arrearages. NEW JERSEY J CP&L operates under NJBPU approved rates that were effective for customers as of November 1, 2021. JCP&L provides BGS for retail customers who do not choose a third-party EGS and for customers of third-party EGSs that fail to provide the contracted service. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates. In December 2017, the NJBPU issued proposed rules to modify its current CTA policy in base rate cases to: (i) calculate savings using a five-year look back from the beginning of the test year; (ii) allocate savings with 75% retained by the company and 25% allocated to customers; and (iii) exclude transmission assets of electric distribution companies in the savings calculation. On January 17, 2019, the NJBPU approved the proposed CTA rules with no changes. On May 17, 2019, the NJ Rate Counsel filed an appeal with the Appellate Division of the Superior Court of New Jersey and on June 7, 2021, the Superior Court issued an order reversing the NJBPU’s CTA rules and remanded the case back to the NJBPU. Specifically, the Court’s ruling requires 100% of the CTA savings to be credited to customers in lieu of the NJBPU’s current policy requiring 25%. On December 6, 2021, the NJBPU issued proposed amended rules modifying its current CTA policy in base rate cases consistent with the Superior Court’s June 7, 2021 order. Once the proposed rules are final, they will be applied on a prospective basis in a future base rate case, however, it is not expected to have a material adverse effect on FirstEnergy’s results or financial condition. On February 18, 2020, JCP&L submitted a filing with the NJBPU requesting a distribution base rate increase. On October 28, 2020, the NJBPU approved a stipulated settlement between JCP&L and various parties, providing for, among other things, a $94 million annual base distribution revenues increase for JCP&L based on an ROE of 9.6%, which became effective for customers on November 1, 2021. Between January 1, 2021 and October 31, 2021, JCP&L amortized an existing regulatory liability totaling approximately $86 million to offset the base rate increase that otherwise would have occurred in this period. The parties also agreed that the actual net gain from the sale of JCP&L’s interest in the Yards Creek pumped-storage hydro generation facility in New Jersey (210 MWs), as further discussed below, be applied to reduce JCP&L’s existing regulatory asset for previously deferred storm costs. Lastly, the parties agreed that approximately $95 million of Reliability Plus capital investment for projects through December 31, 2020, is included in rate base effective December 31, 2020. Included in the NJBPU approved-settlement in JCP&L’s distribution rate case on October 28, 2020, was that JCP&L will be subject to a management audit. The management audit began at the end of May 2021 and is currently ongoing. On April 6, 2020, JCP&L signed an asset purchase agreement with Yards Creek Energy, LLC, a subsidiary of LS Power to sell its 50% interest in the Yards Creek pumped-storage hydro generation facility. Subject to terms and conditions of the agreement, the base purchase price is $155 million. As of December 31, 2020, assets held for sale on FirstEnergy’s Consolidated Balance Sheets associated with the transaction consist of property, plant and equipment of $45 million, which is included in the regulated distribution segment. On July 31, 2020, FERC approved the transfer of JCP&L’s interest in the hydroelectric operating license. On October 8, 2020, FERC issued an order authorizing the transfer of JCP&L’s ownership interest in the hydroelectric facilities. On October 28, 2020, the NJBPU approved the sale of Yards Creek. With the receipt of all required regulatory approvals, the transaction was consummated on March 5, 2021 and resulted in a $109 million gain within the regulated distribution segment. As further discussed above, the gain from the transaction was applied against and reduced JCP&L’s existing regulatory asset for previously deferred storm costs and, as a result, was offset by expense in the “Amortization of regulatory assets, net”, line on the Consolidated Statements of Income, resulting in no earnings impact to FirstEnergy or JCP&L. On August 27, 2020, JCP&L filed an AMI Program with the NJBPU, which proposed the deployment of approximately 1.2 million advanced meters over a three-year period beginning on January 1, 2023, at a total cost of approximately $418 million, including the pre-deployment phase. The then proposed 3-year deployment was part of the 20-year AMI Program that was projected to cost approximately $732 million and proposed a cost recovery mechanism through a separate AMI tariff rider. On September 14, 2021, JCP&L submitted a supplemental filing, which reflected increases in the AMI Program’s costs. Under the revised AMI Program, during the first six years of the AMI Program from 2022 through 2027, JCP&L estimates costs of $494 million, consisting of capital expenditures of approximately $390 million, incremental operations and maintenance expenses of approximately $73 million and cost of removal of $31 million. On February 8, 2022, JCP&L filed with the NJBPU a stipulation entered into with the NJBPU staff, NJ Rate Counsel and others, that, pending NJBPU approval, would affirm the terms of the revised AMI Program. JCP&L expects a NJBPU order by the end of the first quarter of 2022. The Stipulation also provided that the revised AMI Program-related capital costs, the legacy meter stranded costs, and the operations and maintenance expense will be deferred and placed in regulatory assets, with such amounts sought to be recovered in the JCP&L’s subsequent base rate cases. On June 10, 2020, the NJBPU issued an order establishing a framework for the filing of utility-run energy efficiency and peak demand reduction programs in accordance with the New Jersey Clean Energy Act. Under the established framework, JCP&L will recover its program investments with a return over a ten-year amortization period and its operations and maintenance expenses on an annual basis, be eligible to receive lost revenues on energy savings that resulted from its programs and be eligible for incentives or subject to penalties based on its annual program performance, beginning in the fifth year of its program offerings. On September 25, 2020, JCP&L filed its energy efficiency and peak demand reduction program, which consists of 11 energy efficiency and peak demand reduction programs and subprograms to be run from July 1, 2021, through June 30, 2024. On April 23, 2021, JCP&L filed a Stipulation of Settlement with the NJBPU for approval of recovery of lost revenues resulting from the programs and a three-year plan including total program costs of $203 million, of which $158 million of investment is recovered over a ten-year amortization period with a return as well as operations and maintenance expenses and financing costs of $45 million recovered on an annual basis. On April 27, 2021, the NJBPU issued an Order approving the Stipulation of Settlement. On July 2, 2020, the NJBPU issued an order allowing New Jersey utilities to track and create a regulatory asset for future recovery of all prudently incurred incremental costs arising from the COVID-19 pandemic beginning March 9, 2020 and continuing until the New Jersey Governor issues an order stating that the COVID-19 pandemic is no longer in effect. New Jersey utilities can request recovery of such regulatory asset in a stand-alone COVID-19 regulatory asset filing or future base rate case. On October 28, 2020, the NJBPU issued an order expanding the scope of the proceeding to examine all pandemic issues, including recovery of the COVID-19 regulatory assets, by way of a generic proceeding. Through various executive orders issued by the New Jersey Governor, the moratorium period was extended to December 31, 2021. On December 21, 2021, the moratorium on residential disconnections for certain entities providing utility service was extended until March 15, 2022. The moratorium on residential disconnections was not extended for investor-owned electric utilities such as JCP&L, but does require that investor-owned electric public utilities offer qualifying residential customers deferred payment arrangements meeting certain minimum criteria prior to disconnecting service. Credit rating actions taken by S&P and Fitch on October 28, 2020 triggered a requirement from various NJBPU orders that JCP&L file a mitigation plan, which was filed on November 5, 2020, to demonstrate that JCP&L has sufficient liquidity to meet its BGS obligations. On December 11, 2020, the NJBPU held a public hearing on the mitigation plan. Written comments on JCP&L’s mitigation plan were submitted on January 8, 2021. Pursuant to an NJBPU order requiring all New Jersey electric distribution companies to file electric vehicle programs, JCP&L filed its program on March 1, 2021. JCP&L’s proposed electric vehicle program consisted of six sub-programs, including a consumer education and outreach initiative that would begin on January 1, 2022, and continue over a four-year period. The total proposed budget for the electric vehicle program is approximately $50 million, of which $16 million is capital expenditures and $34 million is for operations and maintenance expenses. JCP&L is proposing to recover the electric vehicle program costs via a non-bypassable rate clause applicable to all distribution customer rate classes, which became effective on January 1, 2022. On May 26, 2021, a procedural schedule was set to include evidentiary hearings the week of October 18, 2021. On July 16, 2021, the procedural schedule was extended by thirty days as requested by JCP&L to continue settlement discussions. On August 19, 2021, the presiding commissioner issued an order modifying the procedural schedule by extending the procedural schedule by ninety days as requested by JCP&L to continue settlement discussions. On November 12, 2021, JCP&L filed a letter with the presiding commissioner requesting a suspension of the procedural schedule in order to allow the parties to continue settlement discussion. On November 23, 2021, the presiding commissioner entered an order suspending the procedural schedule. JCP&L expects an order from the NJBPU by the end of the first quarter of 2022. OHIO The Ohio Companies operate under PUCO approved base distribution rates that became effective in 2009. The Ohio Companies currently operate under ESP IV, effective June 1, 2016 and continuing through May 31, 2024, that continues the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continues the Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024. In addition, ESP IV includes: (1) continuation of a base distribution rate freeze through May 31, 2024; (2) a goal across FirstEnergy to reduce CO 2 emissions by 90% below 2005 levels by 2045; and (3) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio. ESP IV further provided for the Ohio Companies to collect DMR revenues, but the SCOH reversed the PUCO’s decision to include DMR in ESP IV. Subsequently, the PUCO entered an order directing the Ohio Companies to cease further collection through the DMR and credit back to customers a refund of the DMR funds collected since July 2, 2019. On December 1, 2020, the SCOH reversed the PUCO’s exclusion of the DMR revenues from the determination of the existence of significantly excessive earnings under ESP IV for OE for calendar year 2017, and remanded the case to the PUCO with instructions to conduct new proceedings which include the DMR revenues in the analysis, determine the threshold against which the earned return is measured, and make other necessary determinations. As further described below, the Ohio Stipulation resolves the Ohio Companies’ 2017 SEET proceeding. On July 23, 2019, Ohio enacted HB 6, which included provisions supporting nuclear energy, authorizing a decoupling mechanism for Ohio electric utilities and ending current energy efficiency program mandates. Under HB 6, the energy efficiency program mandates, as well as Ohio electric utilities’ energy efficiency and peak demand reduction cost recovery riders, ended on December 31, 2020, subject to final reconciliation. Third-parties have challenged the Ohio Companies’ authorization to recover all lost distribution revenue under energy efficiency and peak demand reduction cost recovery riders. The Ohio Stipulation resolves the issues related to lost distribution revenue with no financial impact to the Ohio Companies. On March 31, 2021, the Ohio Governor signed HB 128, which, among other things, repealed parts of HB 6, the legislation that established support for nuclear energy supply in Ohio, provided for a decoupling mechanism for Ohio electric utilities, and provided for the ending of current energy efficiency program mandates. HB 128 was effective June 30, 2021. As FirstEnergy would not have financially benefited from the mechanism to provide support to nuclear energy in Ohio, there is no expected additional impact to FirstEnergy due to the repeal of that provision in HB 6. As further discussed below, in connection with a partial settlement with the OAG and other parties, the Ohio Companies filed an application with the PUCO on February 1, 2021, to set the respective decoupling riders (CSR) to zero. On February 2, 2021, the PUCO approved the application. While the partial settlement with the OAG focused specifically on decoupling, the Ohio Companies elected to forego recovery of lost distribution revenue. FirstEnergy also committed to pursuing an open dialogue with stakeholders in an appropriate manner with respect to the numerous regulatory proceedings then underway as further discussed herein. As a result of the partial settlement, and the decision to not seek lost distribution revenue, FirstEnergy recognized a $108 million pre-tax charge ($84 million after-tax) in the fourth quarter of 2020, and $77 million (pre-tax) of which is associated with forgoing collection of lost distribution revenue. The Ohio Stipulation affirms the Ohio Companies’ commitment to not seek recovery of lost distribution revenue through the end of its ESP IV in May 2024. On March 31, 2021, FirstEnergy announced that the Ohio Companies would refund to customers amounts previously collected under decoupling, with interest, totaling approximately $27 million. On July 7, 2021, the PUCO issued an order approving the Ohio Companies’ modified application to refund such amounts to customers and directed that all funds collected through CSR be refunded to customers over a single billing cycle beginning August 1, 2021. In connection with the audit of the Ohio Companies’ Rider DCR for 2017, the PUCO issued an order on June 16, 2021, directing the Ohio Companies to prospectively discontinue capitalizing certain vegetation management costs and reduce the 2017 Rider DCR revenue requirement by $3.7 million associated with these costs. On September 8, 2020, the OCC filed motions in the Ohio Companies’ corporate separation audit and DMR audit dockets, requesting the PUCO to open an investigation and management audit, hire an independent auditor, and require FirstEnergy to show it did not improperly use money collected from consumers or violate any utility regulatory laws, rules or orders in its activities regarding HB 6. On December 30, 2020, in response to the OCC's motion, the PUCO reopened the DMR audit docket, and directed PUCO staff to solicit a third-party auditor and conduct a full review of the DMR to ensure funds collected from customers through the DMR were only used for the purposes established in ESP IV. On June 2, 2021, the PUCO selected an auditor. The auditor filed the final audit report on January 14, 2022, which made findings and recommendations. The report found that spending of DMR revenues was not required to be tracked, and that DMR revenues, like all rider revenues, are placed into the regulated money pool as a matter of routine, where the funds lose their identify. Therefore, the report could not suggest that DMR funds were used definitively for direct or indirect support for grid modernization. The report also concluded that there was no documented evidence that ties revenues from the DMR to lobbying for the passage of HB 6, but also could not rule out with certainty uses of DMR funds to support the passage of HB 6. The report further recommended that the regulated companies' money pool be audited more frequently and the Ohio Companies adopt formal dividend policies. On September 15, 2020, the PUCO opened a new proceeding to review the political and charitable spending by the Ohio Companies in support of HB 6 and the subsequent referendum effort, and directing the Ohio Companies to show cause, demonstrating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by customers. The Ohio Companies initially filed a response stating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by customers, but on August 6, 2021, filed a supplemental response explaining that, in light of the facts set forth in the DPA and the findings of the Rider DCR audit report further discussed below, political or charitable spending in support of HB 6, or the subsequent referendum effort, affected pole attachment rates paid by approximately $15 thousand. On October 26, 2021, the OCC filed a motion requesting the PUCO to order an independent external audit to investigate FE’s political and charitable spending related to HB 6, and to appoint an independent review panel to retain and oversee the auditor. In November and December 2021, parties filed comments and reply comments regarding the Ohio Companies’ original and supplemental responses to the PUCO’s September 15, 2020, show cause directive. In connection with an ongoing audit of the Ohio Companies’ policies and procedures relating to the code of conduct rules between affiliates, on November 4, 2020, the PUCO initiated an additional corporate separation audit as a result of the FirstEnergy leadership transition announcement made on October 29, 2020, as further discussed below. The additional audit is to ensure compliance by the Ohio Companies and their affiliates with corporate separation laws and the Ohio Companies’ corporate separation plan. The additional audit is for the period from November 2016 through October 2020. The final audit report was filed on September 13, 2021. The audit report makes no findings of major non-compliance with Ohio corporate separation requirements, minor non-compliance with eight requirements, and findings of compliance with 23 requirements. Parties filed comments and reply comments on the audit report, and a PUCO attorney examiner has issued a procedural schedule setting an evidentiary hearing on May 9, 2022. In the fourth quarter of 2020, motions were filed with the PUCO requesting that the PUCO amend the Ohio Companies’ riders for collecting the OVEC related charges required by HB 6, which the Ohio Companies are further required to remit to other Ohio electric distribution utilities or to the State Treasurer, to provide for refunds in the event such provisions of HB 6 are repealed. The Ohio Companies contested the motions, which are pending before the PUCO. On December 7, 2020, the Citizens’ Utility Board of Ohio filed a complaint with the PUCO against the Ohio Companies. The complaint alleges that the Ohio Companies’ new charges resulting from HB 6, and any increased rates resulting from proceedings over which the former PUCO Chairman presided, are unjust and unreasonable, and that the Ohio Companies violated Ohio corporate separation laws by failing to operate separately from unregulated affiliates. The complaint requests, among other things, that any rates authorized by HB 6 or authorized by the PUCO in a proceeding over which the former Chairman presided be made refundable; that the Ohio Companies be required to file a new distribution rate case at the earliest possible date; and that the Ohio Companies’ corporate separation plans be modified to introduce institutional controls. The Ohio Companies are contesting the complaint. On December 21, 2021, the Citizens’ Utility Board of Ohio filed a notice of voluntary dismissal of its complaint without prejudice. The PUCO dismissed the complaint without prejudice on January 12, 2022. On November 1, 2021, the Ohio Companies, together with the OCC, PUCO Staff, and several other signatories, entered into an Ohio Stipulation with the intent of resolving the ongoing energy efficiency rider audits, various SEET, proceedings, including the Ohio Companies’ 2017 SEET proceeding, and the Ohio Companies’ quadrennial ESP review, each of which was pending before the PUCO. Specifically, the Ohio Stipulation provides that the Ohio Companies’ current ESP IV passes the required statutory test for their prospective SEET review as part of the Quadrennial Review of ESP IV, and except for limited circumstances, the signatory parties have agreed not to challenge the Ohio Companies’ SEET return on equity calculation methodology for their 2021-2024 SEET proceedings. The Ohio Stipulation additionally affirms that: (i) the Ohio Companies’ ESP IV shall continue through its previously authorized term of May 31, 2024; and (ii) the Ohio Companies will file their next base rate case in May 2024, and further, no signatory party will seek to adjust the Ohio Companies’ base distribution rates before that time, except in limited circumstances. The Ohio Companies further agreed to refund $96 million to customers in connection with the 2017-2019 SEET cases, and to provide $210 million in future rate reductions for all customers, including $80 million in 2022, $60 million in 2023, $45 million in 2024, and $25 million in 2025. The PUCO approved the 2017-2019 SEET refunds and 2022 rate reductions December 1, 2021, and refunds began in January 2022. As a result of the PUCO approval, FirstEnergy recognized a $96 million pre-tax charge in the fourth quarter of 2021 at the regulated distribution segment within Amortization (deferral) of Regulatory Assets, net, on the Consolidated Statements of Income associated with the refund. The future rate reductions will be recognized as a reduction to regulated distribution segment’s revenue in the Consolidated Statements of Income as they are provided to the Ohio Companies’ customers. In connection with an ongoing annual audit of the Ohio Companies’ Rider DCR for 2020, and as a result of disclosures in FirstEnergy’s Form 10-K for the year ended December 31, 2020 (filed on February 18, 2021), the PUCO expanded the scope of the audit on March 10, 2021, to include a review of certain transactions that were either improperly classified, misallocated, or lacked supporting documentation, and to determine whether funds collected from customers were used to pay the vendors, and if so, whether or not the funds associated with those payments should be returned to customers through Rider DCR or through an alternative proceeding. On August 3, 2021, the auditor filed its final report on this phase of the audit, and the parties submitted comments and reply comments on this audit report in October 2021. Additionally, on September 29, 2021, the PUCO expanded the scope of the audit in this proceeding to determine if the costs of the naming rights for FirstEnergy Stadium have been recovered from the Ohio Companies’ customers. On November 19, 2021, the auditor filed its final report, in which the auditor concluded that the FirstEnergy Stadium naming rights expenses were not recovered from Ohio customers. On December 15, 2021, the PUCO further expanded the scope of the audit to include an investigation into an apparent nondisclosure of a side agreement in the Ohio Companies’ ESP IV settlement proceedings, but stayed its expansion of the audit until otherwise ordered by the PUCO. See Note 13, "Commitments, Guarantees and Contingencies" below for additional details on the government investigations and subsequent litigation surrounding the investigation of HB 6. PENNSYLVANIA The Pennsylvania Companies operate under rates approved by the PPUC, effective as of January 27, 2017. On November 18, 2021, the PPUC issued orders to each of the Pennsylvania Companies directing they operate under DSPs for the June 1, 2019 through May 31, 2023 delivery period, which DSPs provide for the competitive procurement of generation supply for customers who do not receive service from an alternative EGS. Under the 2019-2023 DSPs, supply will be provided by wholesale suppliers through a mix of 3, 12 and 24-month energy contracts, as well as two RFPs for 2-year SREC contracts for ME, PN and Penn. On December 14, 2021, the Pennsylvania Companies filed proposed DSPs for provision of generation for the June 1, 2023 through May 31, 2027 delivery period, to be sourced through competitive procurements for customers who do not receive service from an alternative EGS. Under the 2023-2027 DSPs, supply is proposed to be provided through a mix of 12 and 24-month energy contracts, as well as long-term solar PPAs. In March 2018, the PPUC approved adjusted customer rates of the Pennsylvania Companies to reflect the net impact of the Tax Act. As a result, the Pennsylvania Companies established riders that, beginning July 1, 2018, refunded to customers tax savings attributable to the Tax Act as compared to the amounts established in their most recent base rate proceedings on a current and going forward basis. The amounts recorded as savings for the total period of January 1 through June 30, 2018, were tracked and were to be addressed for treatment in a future proceeding. On May 17, 2021, the Pennsylvania Companies filed petitions with the PPUC proposing to refund the net savings for the January through June 2018 period to customers beginning January 1, 2022. On November 18, 2021, the PPUC approved the Pennsylvania Companies' proposed refunds, but also revised a previous methodology for calculating the net tax savings, which resulted in additional tax savings attributable to the Tax Act to be refunded to customers and directed the Pennsylvania Companies to file new petitions to propose the timing and methodology to provide these additional refunds to customers. The Pennsylvania Companies recalculated the net impact for 2018 through 2021 under the revised PPUC methodology in comparison to amounts already refunded to customers under the existing riders, which resulted in an additional $61 million in savings, with interest, to be provided to customers. As a result, FirstEnergy recognized a pre |
COMMITMENTS, GUARANTEES AND CON
COMMITMENTS, GUARANTEES AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2021 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS, GUARANTEES AND CONTINGENCIES | COMMITMENTS, GUARANTEES AND CONTINGENCIES GUARANTEES AND OTHER ASSURANCES FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. As of December 31, 2021, outstanding guarantees and other assurances aggregated approximately $1.1 billion, consisting of parental guarantees on behalf of its consolidated subsidiaries ($0.6 billion) and other assurances ($0.5 billion). COLLATERAL AND CONTINGENT-RELATED FEATURES In the normal course of business, FE and its subsidiaries may enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain agreements contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE's or its subsidiaries' credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of December 31, 2021, $55 million of collateral has been posted by FE or its subsidiaries and is included in Prepaid taxes and other current assets on FirstEnergy's Consolidated Balance Sheets. These credit-risk-related contingent features stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of December 31, 2021: Potential Collateral Obligations Utilities FE Total (In millions) Contractual Obligations for Additional Collateral Upon Further Downgrade $ 44 $ — $ 44 Surety Bonds (collateralized amount) (1) 57 258 315 Total Exposure from Contractual Obligations $ 101 $ 258 $ 359 (1) Surety Bonds are not tied to a credit rating. Surety Bonds' impact assumes maximum contractual obligations, which is ordinarily 100% of the face amount of the surety bond except with respect to $39 million of surety obligations for which the collateral obligation is capped at 60% of the face amount, and typical obligations require 30 days to cure. OTHER COMMITMENTS AND CONTINGENCIES FE was previously a guarantor under a $120 million syndicated senior secured term loan facility due November 12, 2024, which Global Holding repaid during the fourth quarter of 2021, and as a result, FirstEnergy’s guarantee is no longer in effect. ENVIRONMENTAL MATTERS Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. While FirstEnergy’s environmental policies and procedures are designed to achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and potential revision by the implementing agencies. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof may materially impact its business, results of operations, cash flows and financial condition. Clean Air Act FirstEnergy complies with SO 2 and NOx emission reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls and/or using emission allowances. CSAPR requires reductions of NOx and SO 2 emissions in two phases (2015 and 2017), ultimately capping SO 2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO 2 emission allowances between power plants located in the same state and interstate trading of NOx and SO 2 emission allowances with some restrictions. On July 28, 2015, the D.C. Circuit ordered the EPA to reconsider the CSAPR caps on NOx and SO 2 emissions from power plants in 13 states, including West Virginia. This followed the 2014 U.S. Supreme Court ruling generally upholding the EPA’s regulatory approach under CSAPR but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR Update on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR Update to the D.C. Circuit in November and December 2016. On September 13, 2019, the D.C. Circuit remanded the CSAPR Update to the EPA citing that the rule did not eliminate upwind states’ significant contributions to downwind states’ air quality attainment requirements within applicable attainment deadlines. Also, during this time, in March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from nine states (including West Virginia) significantly contribute to New York’s inability to attain the ozone NAAQS. The petition sought suitable emission rate limits for large stationary sources that are allegedly affecting New York’s air quality within the three years allowed by CAA Section 126. On September 20, 2019, the EPA denied New York’s CAA Section 126 petition. On October 29, 2019, the State of New York appealed the denial of its petition to the D.C. Circuit. On July 14, 2020, the D.C. Circuit reversed and remanded the New York petition to the EPA for further consideration. On March 15, 2021, the EPA issued a revised CSAPR Update that addresses, among other things, the remands of the CSAPR Update and the New York Section 126 Petition. Depending on the outcome of any appeals and how the EPA and the states ultimately implement the revised CSAPR Update, the future cost of compliance may materially impact FirstEnergy's operations, cash flows and financial condition. In February 2019, the EPA announced its final decision to retain without changes the NAAQS for SO 2 , specifically retaining the 2010 primary (health-based) 1-hour standard of 75 PPB. As of March 31, 2020, FirstEnergy has no power plants operating in areas designated as non-attainment by the EPA. Climate Change There are several initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation. In September 2016, the U.S. joined in adopting the agreement reached on December 12, 2015, at the United Nations Framework Convention on Climate Change meetings in Paris to reduce GHGs. The Paris Agreement’s non-binding obligations to limit global warming to below two degrees Celsius became effective on November 4, 2016. On June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the Paris Agreement. On January 20, 2021, President Biden signed an executive order re-adopting the agreement on behalf of the U.S. In November 2020, FirstEnergy published its Climate Story which includes its climate position and strategy, as well as a new comprehensive and ambitious GHG emission goal. FirstEnergy pledged to achieve carbon neutrality by 2050 and set an interim goal for a 30% reduction in GHGs within FirstEnergy’s direct operational control by 2030, based on 2019 levels. Future resource plans to achieve carbon reductions, including any determination of retirement dates of the regulated coal-fired generation, will be developed by working collaboratively with regulators in West Virginia. Determination of the useful life of the regulated coal-fired generation could result in changes in depreciation, and/or continued collection of net plant in rates after retirement, securitization, sale, impairment, or regulatory disallowances. If MP is unable to recover these costs, it could have a material adverse effect on FirstEnergy’s and/or MP’s financial condition, results of operations, and cash flow. Furthermore, FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO 2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for GHGs under the Clean Air Act,” concluding that concentrations of several key GHGs constitute an "endangerment" and may be regulated as "air pollutants" under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. Subsequently, the EPA released its final CPP regulations in August 2015 to reduce CO 2 emissions from existing fossil fuel-fired EGUs and finalized separate regulations imposing CO 2 emission limits for new, modified, and reconstructed fossil fuel-fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court. On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On June 19, 2019, the EPA repealed the CPP and replaced it with the ACE rule that established guidelines for states to develop standards of performance to address GHG emissions from existing coal-fired generation. On January 19, 2021, the D.C. Circuit vacated and remanded the ACE rule declaring that the EPA was “arbitrary and capricious” in its rule making and, as such, the ACE rule is no longer in effect and all actions thus far taken by states to implement the federally mandated rule are now null and void. The D.C. Circuit decision is subject to legal challenge. Depending on the outcomes of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material. Clean Water Act Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy’s facilities. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy’s operations. On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations were to phase-in as permits are renewed on a five-year cycle from 2018 to 2023. However, on April 13, 2017, the EPA granted a Petition for Reconsideration and on September 18, 2017, the EPA postponed certain compliance deadlines for two years. On August 31, 2020, the EPA issued a final rule revising the effluent limits for discharges from wet scrubber systems, retaining the zero-discharge standard for ash transport water, (with some limited discharge allowances), and extending the deadline for compliance to December 31, 2025 for both. In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system, and unit retirement date. The EPA is reconsidering the ELG rule with a publicly announced target of issuing a proposed revised rule in the Fall of 2022 and a final rule by the Spring of 2023. In the interim, the rule issued on August 31, 2020, remains in effect. Depending on the outcome of appeals and how final rules are ultimately implemented, the compliance with these standards, could require additional capital expenditures or changes in operations at Ft. Martin and Harrison power stations from what was filed with the WVPSC in December 2021 that seeks approval of environmental compliance projects to comply with the EPA’s ELG. After the completion of a negotiated settlement, a complaint was filed by the EPA and PA DEP on January 10, 2022 in Federal District Court for the Western District of Pennsylvania, alleging, among other things, that WP violated the CWA in connection with past boron exceedances at WP’s Springdale and Mingo landfills. On January 11, 2022, WP entered into a consent decree with the EPA and PA DEP resolving the matters addressed in the complaint, which, among other things, requires a civil penalty of $610 thousand. The consent decree is subject to final approval by the District Court pending public comment. Regulation of Waste Disposal Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act. Certain CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation. In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 29, 2020, the EPA published a final rule again revising the date that certain CCR impoundments must cease accepting waste and initiate closure to April 11, 2021. The final rule also allows for an extension of the closure deadline based on meeting proscribed site-specific criteria. On November 30, 2020, AE Supply submitted a closure deadline extension request to the EPA seeking to extend the closure date of McElroy's Run CCR impoundment facility until 2024, which request is pending technical review by the EPA. AE Supply continues to operate McElroy’s Run as a disposal facility for FG’s Pleasants Power Station. FE or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of December 31, 2021, based on estimates of the total costs of cleanup, FirstEnergy’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $105 million have been accrued through December 31, 2021, of which, approximately $70 million are for environmental remediation of former MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. FE or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time. OTHER LEGAL PROCEEDINGS United States v. Larry Householder, et al. On July 21, 2020, a complaint and supporting affidavit containing federal criminal allegations were unsealed against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. Also, on July 21, 2020, and in connection with the investigation, FirstEnergy received subpoenas for records from the U.S. Attorney’s Office for the S.D. Ohio. FirstEnergy was not aware of the criminal allegations, affidavit or subpoenas before July 21, 2020. On July 21, 2021, FE entered into a three-year DPA with the U.S. Attorney’s Office that, subject to court proceedings, resolves this matter. Under the DPA, FE has agreed to the filing of a criminal information charging FE with one count of conspiracy to commit honest services wire fraud. The DPA requires that FirstEnergy, among other obligations: (i) continue to cooperate with the U.S. Attorney’s Office in all matters relating to the conduct described in the DPA and other conduct under investigation by the U.S. government; (ii) pay a criminal monetary penalty totaling $230 million within sixty days, which shall consist of (x) $115 million paid by FE to the United States Treasury and (y) $115 million paid by FE to the ODSA to fund certain assistance programs, as determined by the ODSA, for the benefit of low-income Ohio electric utility customers; (iii) publish a list of all payments made in 2021 to either 501(c)(4) entities or to entities known by FirstEnergy to be operating for the benefit of a public official, either directly or indirectly, and update the same on a quarterly basis during the term of the DPA; (iv) issue a public statement, as dictated in the DPA, regarding FE’s use of 501(c)(4) entities; and (v) continue to implement and review its compliance and ethics program, internal controls, policies and procedures designed, implemented and enforced to prevent and detect violations of the U.S. laws throughout its operations, and to take certain related remedial measures. The $230 million payment will neither be recovered in rates or charged to FirstEnergy customers nor will FirstEnergy seek any tax deduction related to such payment. The entire amount of the monetary penalty was recognized as expense in the second quarter of 2021, and paid in the third quarter of 2021. Under the terms of the DPA, the criminal information will be dismissed after FirstEnergy fully complies with its obligations under the DPA. Legal Proceedings Relating to United States v. Larry Householder, et al. On August 10, 2020, the SEC, through its Division of Enforcement, issued an order directing an investigation of possible securities laws violations by FE, and on September 1, 2020, issued subpoenas to FE and certain FE officers. On April 28, 2021, the SEC issued an additional subpoena to FE. While no contingency has been reflected in its consolidated financial statements, FE believes that it is probable that it will incur a loss in connection with the resolution of the SEC investigation. Given the ongoing nature and complexity of the review, inquiries and investigations, FE cannot yet reasonably estimate a loss or range of loss that may arise from the resolution of the SEC investigation. In addition to the subpoenas referenced above under “—United States v. Larry Householder, et. al.” and the SEC investigation, certain FE stockholders and FirstEnergy customers filed several lawsuits against FirstEnergy and certain current and former directors, officers and other employees, and the complaints in each of these suits is related to allegations in the complaint and supporting affidavit relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. The plaintiffs in each of the below cases seek, among other things, to recover an unspecified amount of damages (unless otherwise noted). Unless otherwise indicated, no contingency has been reflected in FirstEnergy’s consolidated financial statements with respect to these lawsuits as a loss is neither probable, nor is a loss or range of a loss reasonably estimable. • In re FirstEnergy Corp. Securities Litigation (Federal District Court, S.D. Ohio); on July 28, 2020 and August 21, 2020, purported stockholders of FE filed putative class action lawsuits alleging violations of the federal securities laws. Those actions have been consolidated and a lead plaintiff, the Los Angeles County Employees Retirement Association, has been appointed by the court. A consolidated complaint was filed on February 26, 2021. The consolidated complaint alleges, on behalf of a proposed class of persons who purchased FE securities between February 21, 2017 and July 21, 2020, that FE and certain current or former FE officers violated Sections 10(b) and 20(a) of the Exchange Act by issuing misrepresentations or omissions concerning FE’s business and results of operations. The consolidated complaint also alleges that FE, certain current or former FE officers and directors, and a group of underwriters violated Sections 11, 12(a)(2) and 15 of the Securities Act of 1933 as a result of alleged misrepresentations or omissions in connection with offerings of senior notes by FE in February and June 2020. FE believes that it is probable that it will incur a loss in connection with the resolution of this lawsuit. Given the ongoing nature and complexity of such litigation, FE cannot yet reasonably estimate a loss or range of loss. • MFS Series Trust I, et al. v. FirstEnergy Corp., et al. (Federal District Court, S.D. Ohio) on December 17, 2021, purported stockholders of FE filed a complaint against FE, certain current and former officers, and certain current and former officers of EH. The complaint alleges that the defendants violated Sections 10(b) and 20(a) of the Exchange Act by issuing alleged misrepresentations or omissions regarding FE’s business and its results of operations, and seeks the same relief as the In re FirstEnergy Corp. Securities Litigation described above. FE believes that it is probable that it will incur a loss in connection with the resolution of this lawsuit. Given the ongoing nature and complexity of such litigation, FE cannot yet reasonably estimate a loss or range of loss. • State of Ohio ex rel. Dave Yost, Ohio Attorney General v. FirstEnergy Corp., et al. and City of Cincinnati and City of Columbus v. FirstEnergy Corp. (Common Pleas Court, Franklin County, OH, all actions have been consolidated); on September 23, 2020 and October 27, 2020, the OAG and the cities of Cincinnati and Columbus, respectively, filed complaints against several parties including FE (the OAG also named FES as a defendant), each alleging civil violations of the Ohio Corrupt Activity Act in connection with the passage of HB 6. On January 13, 2021, the OAG filed a motion for a temporary restraining order and preliminary injunction against FirstEnergy seeking to enjoin FirstEnergy from collecting the Ohio Companies' decoupling rider. On January 31, 2021, FE reached a partial settlement with the OAG and the cities of Cincinnati and Columbus with respect to the temporary restraining order and preliminary injunction request and related issues. In connection with the partial settlement, the Ohio Companies filed an application on February 1, 2021, with the PUCO to set their respective decoupling riders (CSR) to zero. On February 2, 2021, the PUCO approved the application of the Ohio Companies setting the rider to zero and no additional customer bills will include new decoupling rider charges after February 8, 2021. The cases are stayed pending final resolution of the United States v. Larry Householder, et al. criminal proceeding described above, although on August 13, 2021, new defendants were added to the complaint, including two former officers of FirstEnergy. On November 9, 2021, the OAG filed a motion to lift the agreed-upon stay, which FE opposed on November 19, 2021; the motion remains pending. On December 2, 2021, the cities and FE entered a stipulated dismissal with prejudice of the cities’ suit. • Smith v. FirstEnergy Corp. et al., Buldas v. FirstEnergy Corp. et al., and Hudock and Cameo Countertops, Inc. v. FirstEnergy Corp. et al. (Federal District Court, S.D. Ohio, all actions have been consolidated); on July 27, 2020, July 31, 2020, and August 5, 2020, respectively, purported customers of FE filed putative class action lawsuits against FE and FESC, as well as certain current and former FE officers, alleging civil Racketeer Influenced and Corrupt Organizations Act violations and related state law claims. The court denied FE’s motions to dismiss and stay discovery on February 10 and 11, 2021, respectively, and the defendants submitted answers to the complaint on March 10, 2021. The plaintiffs moved to certify the case as a class action on June 28, 2021, and moved for leave to amend the complaint to add FES as a defendant on September 27, 2021. The court granted the motion to amend on November 10, 2021. On November 9, 2021, the court issued an order granting Plaintiffs' motion for class certification, but vacated that order on November 19, 2021, to allow defendants to take the named plaintiffs’ depositions and to file an opposition to the motion, which they filed on December 14, 2021. On November 19, 2021, FE and FESC moved for judgment on the pleadings. One of the individual defendants moved to dismiss the amended complaint on November 24, 2021. On December 28, 2021, the parties jointly moved the court to stay consideration of the pending motions for class certification, to dismiss, and for judgment on the pleadings for 45 days. The court granted the motion on December 29, 2021, and the cases are currently stayed. FE is engaged with the parties in settlement discussions, and believes that it is probable that it will incur a loss in connection with the resolution of these lawsuits. As a result, FirstEnergy recognized in the fourth quarter of 2021 a pre-tax reserve of $37.5 million in the aggregate with respect to these lawsuits and the Emmons lawsuit below. • Emmons v. FirstEnergy Corp. et al. (Common Pleas Court, Cuyahoga County, OH); on August 4, 2020, a purported customer of FirstEnergy filed a putative class action lawsuit against FE, FESC, the Ohio Companies, along with FES, alleging several causes of action, including negligence and/or gross negligence, breach of contract, unjust enrichment, and unfair or deceptive consumer acts or practices. On October 1, 2020, plaintiffs filed a First Amended Complaint, adding as a plaintiff a purported customer of FirstEnergy and alleging a civil violation of the Ohio Corrupt Activity Act and civil conspiracy against FE, FESC and FES. On May 4, 2021, the court granted the defendants’ motion to dismiss plaintiffs’ breach of contract claims and denied the remainder of the motions to dismiss. The defendants submitted answers to the complaint on June 1, 2021. Discovery is proceeding. On December 30, 2021, the plaintiff filed a Second Amended Complaint removing one of the named plaintiffs and updating the class definition. FE is engaged with the parties in settlement discussions, and believes that it is probable that it will incur a loss in connection with the resolution of these lawsuits. As a result, FirstEnergy recognized in the fourth quarter of 2021 a pre-tax reserve of $37.5 million in the aggregate with respect to this lawsuit and the lawsuits above consolidated with Smith in the S.D. Ohio alleging, among other things, civil violations of the Racketeer Influenced and Corrupt Organizations Act. On February 9, 2022, FE, acting through the SLC, agreed to a settlement term sheet to resolve the following shareholder derivative lawsuits relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder that were filed in the S.D. Ohio, the N.D. Ohio, and the Ohio Court of Common Pleas, Summit County: • Gendrich v. Anderson, et al. and Sloan v. Anderson, et al. (Common Pleas Court, Summit County, OH, all actions have been consolidated); on July 26, 2020 and July 31, 2020, respectively, purported stockholders of FE filed shareholder derivative action lawsuits against certain FE directors and officers, alleging, among other things, breaches of fiduciary duty. • Miller v. Anderson, et al. (Federal District Court, N.D. Ohio); Bloom, et al. v. Anderson, et al.; Employees Retirement System of the City of St. Louis v. Jones, et al.; Electrical Workers Pension Fund, Local 103, I.B.E.W. v. Anderson et al.; Massachusetts Laborers Pension Fund v. Anderson et al.; The City of Philadelphia Board of Pensions and Retirement v. Anderson et al.; Atherton v. Dowling et al.; Behar v. Anderson, et al. (Federal District Court, S.D. Ohio, all actions have been consolidated); beginning on August 7, 2020, purported stockholders of FE filed shareholder derivative actions alleging the FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act. The proposed settlement, which is subject to court approval, will fully resolve the shareholder derivative lawsuits above and stipulates a series of corporate governance enhancements, that is expected to result in the following: • Six members of the FE Board, Messrs. Michael J. Anderson, Donald T. Misheff, Thomas N. Mitchell, Christopher D. Pappas and Luis A. Reyes, and Ms. Julia L. Johnson will not stand for re-election at FE’s 2022 annual shareholder meeting; • A special FE Board committee of at least three recently appointed independent directors will be formed to initiate a review process of the current senior executive team, to begin within 30 days of the 2022 annual shareholder meeting; • The FE Board will oversee FE’s lobbying and political activities, including periodically reviewing and approving political and lobbying action plans prepared by management; • The FE Board will form another committee of recently appointed independent directors to oversee the implementation and third-party audits of the FE Board-approved action plans with respect to political and lobbying activities; • FE will implement enhanced disclosure to shareholders of political and lobbying activities, including enhanced disclosure in its annual proxy statement; and • FE will further align financial incentives of senior executives to proactive compliance with legal and ethical obligations. The settlement also includes a payment to FirstEnergy of $180 million, to be paid by insurance after court approval, less any court-ordered attorney’s fees awarded to plaintiffs. In letters dated January 26, and February 22, 2021, staff of FERC's Division of Investigations notified FirstEnergy that the Division is conducting an investigation of FirstEnergy’s lobbying and governmental affairs activities concerning HB 6, and staff directed FirstEnergy to preserve and maintain all documents and information related to the same as such have been developed as part of an ongoing non-public audit being conducted by FERC's Division of Audits and Accounting. While no contingency has been reflected in the consolidated financial statements, FirstEnergy believes that it is probable that it will incur a loss in connection with the resolution of the FERC investigation. Given the ongoing nature and complexity of the review, inquiries and investigations, FirstEnergy cannot yet reasonably estimate a loss or range of loss that may arise from the resolution of the FERC investigation. The outcome of any of these lawsuits, governmental investigations and audit is uncertain and could have a material adverse effect on FE’s or its subsidiaries’ reputation, business, financial condition, results of operations, liquidity, and cash flows. Other Legal Matters There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to FE or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 12, “Regulatory Matters.” |
DISCONTINUED OPERATIONS
DISCONTINUED OPERATIONS | 12 Months Ended |
Dec. 31, 2021 | |
Discontinued Operations and Disposal Groups [Abstract] | |
DISCONTINUED OPERATIONS | DISCONTINUED OPERATIONS On March 31, 2018, the FES Debtors announced that, in order to facilitate an orderly financial restructuring, they filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code with the Bankruptcy Court. On February 27, 2020, the FES Debtors effectuated their plan, emerged from bankruptcy and FirstEnergy tendered the bankruptcy court approved settlement payments totaling $853 million and a $125 million tax sharing payment to the FES Debtors. The FES Bankruptcy settlement was conditioned on the FES Debtors confirming and effectuating a plan of reorganization acceptable to FirstEnergy. As contemplated under the FES Bankruptcy settlement agreement, AE Supply entered into an agreement on December 31, 2018, to transfer the 1,300 MW Pleasants Power Station and related assets to FG, while retaining certain specified liabilities. Under the terms of the agreement, FG acquired the economic interests in Pleasants as of January 1, 2019, and AE Supply operated Pleasants until ownership was transferred on January 30, 2020. AE Supply will continue to provide access to the McElroy's Run CCR impoundment facility, which was not transferred, and FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR impoundment facility. During the first quarter of 2020, FG paid AE Supply approximately $65 million of cash for related materials and supplies (at book value) and the settlement of FG’s economic interest in Pleasants. By eliminating a significant portion of its competitive generation fleet with the deconsolidation of the FES Debtors, FirstEnergy has concluded the FES Debtors meet the criteria for discontinued operations, as this represents a significant event in management’s strategic review to exit commodity-exposed generation and transition to a fully regulated company. Income Taxes As a result of the FES Debtors’ tax return deconsolidation, FirstEnergy recognized a worthless stock deduction, of approximately $4.9 billion, net of unrecognized tax benefits of $316 million, for the remaining tax basis in the stock of the FES Debtors. Based upon completion of the IRS’s review of the 2020 federal income tax return during fourth quarter 2021, FirstEnergy recognized the full tax benefit of the worthless stock deduction of approximately $5.2 billion, or $1.1 billion on a tax-effected basis, net of valuation allowances recorded against the state tax benefit ($21 million), eliminating associated uncertain tax position reserves. Upon emergence, FirstEnergy paid the FES Debtors $125 million to settle all reconciliations under the Intercompany Tax Allocation Agreement for 2018, 2019 and 2020 tax years, including all issues regarding nondeductible interest. In conjunction with filing the 2020 consolidated federal income tax return during the third quarter of 2021, FirstEnergy computed a final federal NOL allocation between the FES Debtors and FirstEnergy consolidated that resulted in FirstEnergy recording an increase to the consolidated NOL carryforward of approximately $289 million ($61 million tax-effected). Summarized Results of Discontinued Operations Summarized results of discontinued operations for the years ended December 31, 2021, 2020, and 2019 were as follows: For the Years Ended December 31, (In millions) 2021 2020 2019 Revenues $ — $ 7 $ 188 Fuel — (6) (140) Other operating expenses — (6) (63) General taxes — — (14) Pleasants economic interest (1) — 5 27 Other expense, net (4) — (2) Loss from discontinued operations, before tax (4) — (4) Income tax expense (benefit) (1) — 47 Loss from discontinued operations, net of tax (3) — (51) Settlement consideration and services credit — (1) 7 Accelerated net pension and OPEB prior service credits — 18 — Gain on disposal of FES and FENOC, before tax — 17 7 Income tax benefits, including worthless stock deduction (47) (59) (52) Gain on disposal of FES and FENOC, net of tax 47 76 59 Income from discontinued operations $ 44 $ 76 $ 8 (1) Reflects the estimated amounts owed from FG for its economic interests in Pleasants effective January 1, 2019. As discussed above, settlement of the economic interests occurred during the first quarter of 2020. FirstEnergy's Consolidated Statements of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. The following table summarizes the major classes of cash flow items from discontinued operations for the years ended December 31, 2021, 2020 and 2019: For the Years Ended December 31, (In millions) 2021 2020 2019 CASH FLOWS FROM OPERATING ACTIVITIES: Income from discontinued operations $ 44 $ 76 $ 8 Gain on disposal, net of tax (47) (76) (59) Deferred income taxes and investment tax credits, net — — 47 |
SEGMENT INFORMATION
SEGMENT INFORMATION | 12 Months Ended |
Dec. 31, 2021 | |
Segment Reporting [Abstract] | |
SEGMENT INFORMATION | SEGMENT INFORMATION FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity through its reportable segments, Regulated Distribution and Regulated Transmission. The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey, and Maryland. This segment also controls 3,580 MWs of regulated electric generation capacity located primarily in West Virginia and Virginia. The segment's results reflect the costs of securing and delivering electric generation from transmission facilities to customers, including the deferral and amortization of certain related costs. The transaction to transfer TMI-2 to TMI-2 Solutions, LLC was consummated on December 18, 2020, and as a result, during the fourth quarter of 2020 FirstEnergy recognized an after-tax gain of approximately $33 million, primarily associated with the write-off of a tax related regulatory liability. Included within the segment is $45 million of assets classified as held for sale as of December 31, 2020 associated with the asset purchase agreement with Yards Creek; see Note 12, "Regulatory Matters," for additional information. The Regulated Transmission segment provides transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment's revenues are primarily derived from forward-looking formula rates. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual rate base and costs. The segment's results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy's transmission facilities. On November 6, 2021, FirstEnergy, along with FET, entered into the FET P&SA, with Brookfield and Brookfield Guarantors pursuant to which FET agreed to issue and sell to Brookfield at the closing, and Brookfield agreed to purchase from FET, certain newly issued membership interests of FET, such that Brookfield will own 19.9% of the issued and outstanding membership interests of FET, for a purchase price of $2.375 billion. The transaction is subject to customary closing conditions, including approval from the FERC and review by the CFIUS. KATCo, which is currently a subsidiary of FET, will become a wholly owned subsidiary of FE prior to the closing of the transaction and will remain in the Regulated Transmission segment. Corporate/Other reflects corporate support and other costs not charged or attributable to the Utilities or Transmission Companies, including FE's retained Pension and OPEB assets and liabilities of the FES Debtors, interest expense on FE’s holding company debt and other businesses that do not constitute an operating segment. Reconciling adjustments for the elimination of inter-segment transaction are shown separately in the following table of Segment Financial Information. As of December 31, 2021, 67 MWs of electric generating capacity, representing AE Supply's OVEC capacity entitlement, is included in Corporate/Other. As of December 31, 2021, Corporate/Other had approximately $7.9 billion of FE holding company debt. Financial information for each of FirstEnergy’s business segments and reconciliations to consolidated amounts is presented in the tables below. FirstEnergy evaluates segment performance based on Income (loss) from continuing operations. Segment Financial Information For the Years Ended Regulated Distribution Regulated Transmission Corporate/ Other Reconciling Adjustments FirstEnergy Consolidated (In millions) December 31, 2021 External revenues $ 9,510 $ 1,608 $ 14 $ — $ 11,132 Internal revenues 201 10 — (211) — Total revenues 9,711 1,618 14 (211) 11,132 Provision for depreciation 911 325 3 63 1,302 Amortization of regulatory assets, net 260 9 — — 269 DPA penalty — — 230 — 230 Miscellaneous income (expense), net 399 41 89 (12) 517 Interest expense 523 248 382 (12) 1,141 Income taxes (benefits) 364 127 (171) — 320 Income (loss) from continuing operations 1,288 408 (457) — 1,239 Property additions $ 1,395 $ 958 $ 92 $ — $ 2,445 December 31, 2020 External revenues $ 9,168 $ 1,613 $ 9 $ — $ 10,790 Internal revenues 195 17 — (212) — Total revenues 9,363 1,630 9 (212) 10,790 Provision for depreciation 896 313 4 61 1,274 Amortization (deferral) of regulatory assets, net (64) 11 — — (53) Miscellaneous income (expense), net 332 30 83 (13) 432 Interest expense 501 219 358 (13) 1,065 Income taxes (benefits) 113 138 (125) — 126 Income (loss) from continuing operations 959 464 (420) — 1,003 Property additions $ 1,514 $ 1,067 $ 76 $ — $ 2,657 December 31, 2019 External revenues $ 9,511 $ 1,510 $ 14 $ — $ 11,035 Internal revenues 187 16 — (203) — Total revenues 9,698 1,526 14 (203) 11,035 Provision for depreciation 863 284 5 68 1,220 Amortization (deferral) of regulatory assets, net (89) 10 — — (79) Miscellaneous income (expense), net 174 15 80 (26) 243 Interest expense 495 192 372 (26) 1,033 Income taxes 271 113 (171) — 213 Income (loss) from continuing operations 1,076 447 (619) — 904 Property additions $ 1,473 $ 1,090 $ 102 $ — $ 2,665 As of December 31, 2021 Total assets $ 30,812 $ 13,237 $ 1,383 $ — $ 45,432 Total goodwill $ 5,004 $ 614 $ — $ — $ 5,618 As of December 31, 2020 Total assets $ 30,855 $ 12,592 $ 1,017 $ — $ 44,464 Total goodwill $ 5,004 $ 614 $ — $ — $ 5,618 |
ORGANIZATION AND BASIS OF PRE_2
ORGANIZATION AND BASIS OF PRESENTATION (Policies) | 12 Months Ended |
Dec. 31, 2021 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Accounting | FE and its subsidiaries follow GAAP and comply with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not necessarily indicative of results of operations for any future period. FE and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued. |
Consolidation | FE and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation as appropriate and permitted pursuant to GAAP. As further discussed below, FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary. Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but do not have a controlling financial interest, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage of FE's ownership share of the entity’s earnings is reported in the Consolidated Statements of Income and Comprehensive Income. Certain prior year amounts have been reclassified to conform to the current year presentation. |
Accounting for the Effects of Regulation | ACCOUNTING FOR THE EFFECTS OF REGULATION FirstEnergy’s Regulated Distribution and Regulated Transmission segments are subject to regulation that sets the prices (rates) the Utilities and the Transmission Companies are permitted to charge customers based on costs that the regulatory agencies determine are permitted to be recovered. At times, regulatory agencies permit the future recovery of costs that would be currently charged to expense by an unregulated company. The ratemaking process results in the recording of regulatory assets and liabilities based on anticipated future cash inflows and outflows. FirstEnergy reviews the probability of recovery of regulatory assets, and settlement of regulatory liabilities, at each balance sheet date and whenever new events occur. Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory commission order, or passage of new legislation. Upon material changes to these factors, where applicable, FirstEnergy will record new regulatory assets or liabilities and will assess whether it is probable that currently recorded regulatory assets and liabilities will be recovered or settled in future rates. If recovery of a regulatory asset is no longer probable, FirstEnergy will write off that regulatory asset as a charge against earnings. FirstEnergy considers the entire regulatory asset balance as the unit of account for the purposes of balance sheet classification rather than the next years recovery and as such net regulatory assets and liabilities are presented in the non-current section on the FirstEnergy Consolidated Balance Sheets. See Note 12, "Regulatory Matters," of the Notes to Consolidated Financial Statements for additional information. |
Derivatives | DERIVATIVES FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, coal and energy transmission. To manage the volatility related to these exposures, FirstEnergy’s Risk Policy Committee, comprised of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Risk Policy Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. FirstEnergy may use a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. |
Earnings Per Share of Common Stock | EARNINGS PER SHARE OF COMMON STOCK Basic EPS available to common stockholders is computed using the weighted average number of common shares outstanding during the relevant period as the denominator. The denominator for diluted EPS of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. During 2019, EPS was computed using the two-class method required for participating securities. The convertible preferred stock issued in January 2018 were considered participating securities since the shares participated in dividends on common stock on an “as-converted” basis. All convertible preferred stock outstanding was converted to common stock during 2019. The two-class method uses an earnings allocation formula that treats participating securities as having rights to earnings that otherwise would have been available only to common stockholders. Under the two-class method, net income attributable to common stockholders is derived by subtracting the following from income from continuing operations: • preferred stock dividends; • deemed dividends for the amortization of the beneficial conversion feature recognized at issuance of the preferred stock (if any); and • an allocation of undistributed earnings between the common stock and the participating securities (convertible preferred stock) based on their respective rights to receive dividends. Net losses were not allocated to the convertible preferred stock as they did not have a contractual obligation to share in the losses of FirstEnergy. FirstEnergy allocated undistributed earnings based upon income from continuing operations. |
Goodwill | GOODWILL In a business combination, the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed is recognized as goodwill. FirstEnergy evaluates goodwill for impairment annually on July 31 and more frequently if indicators of impairment arise. In evaluating goodwill for impairment, FirstEnergy assesses qualitative factors to determine whether it is more likely than not (that is, likelihood of more than 50%) that the fair value of a reporting unit is less than its carrying value (including goodwill). If FirstEnergy concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then no further testing is required. However, if FirstEnergy concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying value or bypasses the qualitative assessment, then the quantitative goodwill impairment test is performed to identify a potential goodwill impairment and measure the amount of impairment to be recognized, if any. |
Inventory | INVENTORY Materials and supplies inventory includes fuel inventory and the distribution, transmission and generation plant materials, net of reserve for excess and obsolete inventory. Materials charged to inventory are at weighted average cost when purchased and expensed or capitalized, as appropriate, when used or installed. Fuel inventory is accounted for at weighted average cost when purchased and recorded to fuel expense when consumed. |
Property, Plant and Equipment | PROPERTY, PLANT AND EQUIPMENTProperty, plant and equipment reflects original cost (net of any impairments recognized), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and financing costs incurred to place the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. FirstEnergy recognizes liabilities for planned major maintenance projects as they are incurred. |
Asset Retirement Obligations | Asset Retirement Obligations FirstEnergy recognizes an ARO for its legal obligation to perform asset retirement activities associated with its long-lived assets. The ARO liability represents an estimate of the fair value of FirstEnergy's current obligation such that the ARO is accreted monthly to reflect the time value of money. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FirstEnergy uses an expected cash flow approach to measure the fair value of the remediation AROs, considering the expected timing of settlement of the ARO based on the expected economic useful life of associated asset and/or regulatory requirements. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related asset. In certain circumstances, FirstEnergy has recovery of asset retirement costs and, as such, certain accretion and depreciation is offset against regulatory assets. Conditional retirement obligations associated with tangible long-lived assets are recognized at fair value in the period in which they are incurred if a reasonable estimate can be made, even though there may be uncertainty about timing or method of settlement. When settlement is conditional on a future event occurring, it is reflected in the measurement of the liability, not the timing of the liability recognition. |
Asset Impairments | Asset Impairments FirstEnergy evaluates long-lived assets classified as held and used for impairment when events or changes in circumstances indicate the carrying value of the long-lived assets may not be recoverable. First, the estimated undiscounted future cash flows attributable to the assets is compared with the carrying value of the assets. If the carrying value is greater than the undiscounted future cash flows, an impairment charge is recognized equal to the amount the carrying value of the assets exceeds its estimated fair value. |
Receivables | RECEIVABLES Receivables from customers include retail electric sales and distribution deliveries to residential, commercial and industrial customers of the Utilities. There was no material concentration of receivables as of December 31, 2021 and 2020, with respect to any particular segment of FirstEnergy’s customers. Billed and unbilled customer receivables as of December 31, 2021 and 2020, are included below. As of December 31, Customer Receivables 2021 2020 (In millions) Billed (1) $ 616 $ 800 Unbilled 576 567 1,192 1,367 Less: Uncollectible Reserve 159 164 Total Customer Receivables $ 1,033 $ 1,203 (1) Includes approximately $318 million and $349 million as of December 31, 2021, 2020, respectively, that are past due by greater than 30 days. Activity in the allowance for uncollectible accounts on receivables for the years ended December 31, 2021, 2020 and 2019 are as follows: (In millions) 2021 2020 2019 Customer Receivables Beginning of year balance $ 164 $ 46 $ 50 Charged to income (1) 54 174 81 Charged to other accounts (2) 42 46 47 Write-offs (101) (102) (132) End of year balance $ 159 $ 164 $ 46 Other Receivables Beginning of year balance $ 26 $ 21 $ 2 Charged to income 3 7 27 Charged to other accounts (2) 3 10 1 Write-offs (22) (12) (9) End of year balance $ 10 $ 26 $ 21 Affiliated Companies Receivables (3) Beginning of year balance $ — $ 1,063 $ 920 Charged to income — — 143 Charged to other accounts (2) — — — Write-offs — (1,063) — End of year balance $ — $ — $ 1,063 (1) Customer receivable amounts charged to income for the years ended December 31, 2021, 2020 and 2019 include approximately $12 million, $103 million, and $25 million respectively, deferred for future recovery. (2) Represents recoveries and reinstatements of accounts previously written off for uncollectible accounts. (3) Amounts relate to the FES Debtors and are included in discontinued operations. Write-off of $1.1 billion in 2020 was recognized upon their emergence in February 2020. The allowance for uncollectible customer receivables is based on historical loss information comprised of a rolling 36-month average net write-off percentage of revenues, in conjunction with a qualitative assessment of elements that impact the collectability of receivables to determine if allowances for uncollectible accounts should be further adjusted in accordance with the accounting guidance for credit losses. Management contemplates available current information such as changes in economic factors, regulatory matters, industry trends, customer credit factors, amount of receivable balances that are past-due, payment options and programs available to customers, and the methods that the Utilities are able to utilize to ensure payment. FirstEnergy reviews its allowance for uncollectible customer receivables utilizing a quantitative and qualitative assessment, which includes consideration of the outbreak of COVID-19 and the impact on customer receivable balances outstanding and write-offs since the pandemic began. Beginning March 13, 2020, FirstEnergy temporarily suspended customer disconnections for nonpayment and ceased collection activities as a result of the ongoing COVID-19 pandemic and in accordance with state regulatory requirements. The temporary suspension of disconnections for nonpayment and ceasing of collection activities extended into the fourth quarter of 2020 but resumed for many customers before the end of 2020, except in New Jersey where the moratorium was extended until the end of 2021. Customers are subject to each state's applicable regulations on winter moratoriums. See Note 12, “Regulatory Matters,” for further discussion on applicable regulations that may alter customer disconnections and collection activity as well as regulatory recovery. During 2020, FirstEnergy analyzed the likelihood of loss based on increases in customer accounts in arrears since the pandemic began in mid-March 2020 as well as what collection methods at the time were suspended, and historically been utilized to ensure payment. Based on this assessment, and consideration of other qualitative factors described above, FirstEnergy recognized incremental uncollectible expense of $121 million in the year 2020, of which approximately $90 million was not being collected through rates and as a result was deferred for future recovery under regulatory mechanisms. During 2021, arrears levels continue to be elevated above 2019 pre-pandemic levels. Various regulatory actions have impacted the growth and recovery of past due balances including extensions on moratoriums, significant restrictions regarding disconnections, and extended installment plans. FirstEnergy has experienced a reduction in the amount of receivables that are past due by greater than 30 days since the end of 2020. While total customer arrears balances continue to decrease in 2021, balances that are over 120 days past due continue to be elevated. FirstEnergy considered other factors as part of its qualitative assessment, such as certain federal stimulus and state funding being made available to assist with past due utility bills. As a result of this qualitative analysis, FirstEnergy did not recognize any incremental uncollectible expense for the twelve months ended December 31, 2021. Additionally, as a result of the pandemic-related moratoriums and certain customer installment or extended payment plans offered, the allowance for uncollectible accounts on receivables in 2021 and 2020 are elevated due to the extension of when certain write-offs would have otherwise occurred. Other receivables include PJM receivables resulting from transmission and wholesale sales. FirstEnergy’s uncollectible risk on PJM receivables is minimal due to the nature of PJM’s settlement process whereby members of PJM legally agree to share the cost of defaults and as a result there is no allowance for doubtful accounts. |
Variable Interest Entities | VARIABLE INTEREST ENTITIES FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has: (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance; and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary. In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregates variable interests into categories based on similar risk characteristics and significance. Consolidated VIEs VIEs in which FirstEnergy is the primary beneficiary consist of the following (included in FirstEnergy’s consolidated financial statements): • Ohio Securitization - In June 2013, SPEs formed by the Ohio Companies issued approximately $445 million of pass-through trust certificates supported by phase-in recovery bonds to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. • MP and PE Environmental Funding Companies - Bankruptcy remote, special purpose limited liability companies that are indirect subsidiaries of MP and PE which issued environmental control bonds. See Note 9, “Capitalization,” for additional information on securitized bonds. Unconsolidated VIEs FirstEnergy is not the primary beneficiary of the following VIEs: • Global Holding - FEV holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales in U.S. and international markets. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint ventures economic performance. FEV's ownership interest is subject to the equity method of accounting. As of December 31, 2021, the carrying value of the equity method investment was $59 million. • PATH WV - PATH, a proposed transmission line from West Virginia through Virginia into Maryland which PJM cancelled in 2012, is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of FE owns 100% of the Allegheny Series (PATH-Allegheny) and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of PATH-WV. FirstEnergy's ownership interest in PATH-WV is subject to the equity method of accounting. As of December 31, 2021, the carrying value of the equity method investment was $18 million. • Purchase Power Agreements - FirstEnergy evaluated its PPAs and determined that certain NUG entities at its Regulated Distribution segment may be VIEs to the extent that they own a plant that sells substantially all of its output to the applicable utilities and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy maintains six long-term PPAs with NUG entities that were entered into pursuant to PURPA. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, any of these entities. FirstEnergy has determined that for all but one of these NUG entities, it does not have a variable interest, or the entities do not meet the criteria to be considered a VIE. FirstEnergy may hold a variable interest in the remaining one entity; however, it applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities. Because FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred at its Regulated Distribution segment to be recovered from customers. Purchased power costs related to the contract that may contain a variable interest were $111 million and $113 million, respectively, during the years ended December 31, 2021 and 2020. |
New Accounting Pronouncements | NEW ACCOUNTING PRONOUNCEMENTS Recently Adopted Pronouncements ASU 2019-12, " Simplifying the Accounting for Income Taxes" (Issued in December 2019): ASU 2019-12 enhances and simplifies various aspects of the income tax accounting guidance, including the elimination of certain exceptions related to the approach for intra-period tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. The new guidance also simplifies aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. FirstEnergy adopted the guidance as of January 1, 2021, with no material impact to the financial statements. Recently Issued Pronouncements - FirstEnergy has assessed new authoritative accounting guidance issued by the FASB that has not yet been adopted and none are currently expected to have a material impact to the financial statements. |
Pension and Other Postretirement Plans | PENSION AND OTHER POST-EMPLOYMENT BENEFITS FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels. Under the cash-balance portion of the pension plan (for employees hired on or after January 1, 2014), FirstEnergy makes contributions to eligible employee retirement accounts based on a pay credit and an interest credit. In addition, FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension and OPEB to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits. FirstEnergy’s pension and OPEB funding policy is based on actuarial computations using the projected unit credit method. On March 11, 2021, President Biden signed into law the American Rescue Plan Act of 2021, which, among other things, extended shortfall amortization periods and modification of the interest rate stabilization rules for single-employer plans thereby impacting funding requirements. As a result, FirstEnergy does not currently expect to have a required contribution to the pension plan based on various assumptions including annual expected rate of returns for assets of 7.50%. However, FirstEnergy may elect to contribute to the pension plan voluntarily. Pension and OPEB costs are affected by employee demographics (including age, compensation levels and employment periods), the level of contributions made to the plans and earnings on plan assets. Pension and OPEB costs may also be affected by changes in key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. FirstEnergy uses a December 31 measurement date for its pension and OPEB plans. The fair value of the plan assets represents the actual market value as of the measurement date. Discount Rate - In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and OPEB obligations. The assumed rates of return on plan assets consider historical market returns and economic forecasts for the types of investments held by FirstEnergy’s pension trusts. The long-term rate of return is developed considering the portfolio’s asset allocation strategy. FirstEnergy utilizes a spot rate approach in the estimation of the components of benefit cost by applying specific spot rates along the full yield curve to the relevant projected cash flows. Expected Return on Plan Assets - FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by the pension trusts. In 2021, FirstEnergy’s qualified pension and OPEB plan assets experienced gains of $689 million or 7.9%, compared to gains of $1,225 million, or 14.7% in 2020, and losses of $1,492 million, or 20.2% in 2019 and assumed a 7.50% rate of return on plan assets in 2021, 2020 and 2019, which generated $688 million, $651 million and $569 million of expected returns on plan assets, respectively. The expected return on pension and OPEB assets is based on input from investment consultants, including the trusts’ asset allocation targets and the historical performance of risk-based and fixed income securities. The gains or losses generated as a result of the difference between expected and actual returns on plan assets is recognized as a pension and OPEB mark-to-market adjustment in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for remeasurement. Mortality Rates - During 2021, the Society of Actuaries published new mortality tables that include more current data than the RP-2014 tables as well as new improvement scales. An analysis of plan mortality data indicated the use of the Pri-2012 mortality table with projection scale MP-2021, actuarially adjusted to reflect increased mortality rates due to COVID-19 based on mortality experience reported by the Center for Disease and Control Prevention in 2020 and 2021, was most appropriate and such was utilized to determine the 2021 benefit cost and obligation as of December 31, 2021, for the FirstEnergy pension and OPEB plans. The impact of using the Pri-2012 mortality table with projection scale MP-2021 (adjusted by FirstEnergy's actuary for COVID-19 impacts) resulted in a decrease to the projected benefit obligation of approximately $32 million and $2 million for the pension and OPEB plans, respectively, and was included in the 2021 pension and OPEB mark-to-market adjustment. Net Periodic Benefit Costs - In addition to service costs, interest on obligations, expected return on plan assets, and prior service costs, FirstEnergy recognizes in net periodic benefit costs a pension and OPEB mark-to-market adjustment for the change in the fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. Service costs, net of capitalization, are reported within Other operating expenses on FirstEnergy’s Consolidated Statements of Income. Non-service costs, other than the pension and OPEB mark-to-market adjustment, which is separately shown, are reported within Miscellaneous income, net, within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income. Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December (1) Pension OPEB 2021 2020 2019 2021 2020 2019 Service cost weighted-average discount rate (2) 3.10 % 3.60%/3.24% 4.66 % 3.03 % 3.63%/3.29% 4.67 % Interest cost weighted-average discount rate (3) 2.58 % 3.27%/2.90% 4.37 % 1.66 % 2.71%/2.30% 3.89 % Expected return on plan assets 7.50 % 7.50 % 7.50 % 7.50 % 7.50 % 7.50 % Rate of compensation increase 4.10 % 4.10 % 4.10 % N/A N/A N/A (1) Excludes impact of pension and OPEB mark-to-market adjustment. (2) Weighted-average discount rates effect from January 1, 2020, through February 26, 2020, were 3.60% and 3.63% for pension and OPEB service cost, respectively. Discount rates were 3.24% and 3.29% for pension and OPEB service cost, respectively, for the period February 27, 2020 through December 31, 2020. (3) Weighted-average discount rates in effect from January 1, 2020, through February 26, 2020, were 3.27% and 2.71% for pension and OPEB interest cost, respectively. Discount rates were 2.90% and 2.30% for pension and OPEB interest cost, respectively, for the period February 27, 2020, through December 31, 2020. Components of Net Periodic Benefit Costs (Credits) for the Years Ended December 31, Pension OPEB 2021 2020 2019 2021 2020 2019 (In millions) Service cost $ 195 $ 194 $ 193 $ 4 $ 4 $ 3 Interest cost 226 287 373 11 15 22 Expected return on plan assets (652) (618) (540) (36) (33) (29) Amortization of prior service costs (credits) (1) 3 12 7 (17) (46) (36) Special termination costs (2) — — 14 — — — One-time termination benefits (3) — 8 — — — — Pension & OPEB mark-to-market (4) (253) 463 656 (129) 14 20 Net periodic benefit costs (credits) $ (481) $ 346 $ 703 $ (167) $ (46) $ (20) (1) 2020 includes the acceleration of approximately $18 million in net credits as a result of the FES Debtors’ emergence during the first quarter of 2020 and is a component of discontinued operations in FirstEnergy’s Consolidated Statements of Income. (2) Subject to a cap, FirstEnergy agreed to fund a pension enhancement through its pension plan, for voluntary enhanced retirement packages offered to certain FES employees, as well as offer certain other employee benefits. The costs are a component of discontinued operations in FirstEnergy’s Consolidated Statements of Income. (3) Costs represent additional benefits provided to FES and FENOC employees under the approved settlement agreement and are a component of discontinued operations. (4) Of the total Pension and OPEB mark-to-market adjustment for 2019, approximately $2 million is included in discontinued operations. The annual pension and OPEB mark-to-market adjustments, (gains) or losses, for the years ended December 31, 2021, 2020, and 2019 were $(382) million, $477 million (including $423 million in the first quarter of 2020), and $676 million, respectively. Of these annual pension and OPEB mark-to-market amounts, approximately $(31) million, $40 million and $47 million were allocated to the Transmission Companies and certain of FirstEnergy's utilities under forward-looking formula rates, and expected to be refunded or recovered through formula transmission rates, respectively. The 2021 pension and OPEB mark-to-market adjustment primarily reflects an approximate 35 bps increase in the discount rate used to measure pension benefit obligations. |
Share-based Compensation | Shares granted under the ICP 2020 and ICP 2015 are issued from authorized but unissued common stock. Vesting periods for stock-based awards range from two to ten years, with the majority of awards having a vesting period of three years. FirstEnergy also issues stock through its 401(k) Savings Plan, EDCP, and DCPD. Currently, FirstEnergy records the compensation costs for stock-based compensation awards that will be paid in stock over the vesting period based on the fair value on the grant date. FirstEnergy accounts for forfeitures as they occur. FirstEnergy adjusts the compensation costs for stock-based compensation awards that will be paid in cash based on changes in the fair value of the award as of each reporting date. FirstEnergy records the actual tax benefit realized from tax deductions when awards are exercised or settled |
Income Taxes | FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled. FE and its subsidiaries are party to an intercompany income tax allocation agreement that provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FE, excluding any tax benefits derived from certain interest expense, are generally reallocated to the subsidiaries of FE that have taxable income. That allocation is accounted for as a capital contribution to the company receiving the tax benefit. |
Fair Value Measurement | Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy and a description of the valuation techniques are as follows: Level 1 - Quoted prices for identical instruments in active market Level 2 - Quoted prices for similar instruments in active market - Quoted prices for identical or similar instruments in markets that are not active - Model-derived valuations for which all significant inputs are observable market data Models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 - Valuation inputs are unobservable and significant to the fair value measurement FirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market conditions change. When underlying prices are not observable, prices from the long-term price forecast are used to measure fair value. FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term PJM auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs' carrying values are periodically adjusted to fair value using a mark-to-model methodology, which approximates market. The primary inputs into the model, which are generally less observable than objective sources, are the most recent PJM auction clearing prices and the FTRs' remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. Significant increases or decreases in inputs in isolation may have resulted in a higher or lower fair value measurement. NUG contracts represent PPAs with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. NUG contract carrying values are recorded at fair value and adjusted periodically using a mark-to-model methodology, which approximates market. The primary unobservable inputs into the model are regional power prices and generation MWH. Pricing for the NUG contracts is a combination of market prices for the current year and next two years based on observable data and internal models using historical trends and market data for the remaining years under contract. The internal models use forecasted energy purchase prices as an input when prices are not defined by the contract. Forecasted market prices are based on Intercontinental Exchange, Inc. quotes and management assumptions. Generation MWH reflects data provided by contractual arrangements and historical trends. The model calculates the fair value by multiplying the prices by the generation MWH. Significant increases or decreases in inputs in isolation may have resulted in a higher or lower fair value measurement. |
ORGANIZATION AND BASIS OF PRE_3
ORGANIZATION AND BASIS OF PRESENTATION (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Regulatory assets on the Balance Sheets | The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2021 and 2020, and the changes during the year ended December 31, 2021: As of December 31, Net Regulatory Assets (Liabilities) by Source 2021 2020 Change (In millions) Customer payables for future income taxes $ (2,345) $ (2,369) $ 24 Spent nuclear fuel disposal costs (101) (102) 1 Asset removal costs (646) (721) 75 Deferred transmission costs (3) 319 (322) Deferred generation costs 118 17 101 Deferred distribution costs 49 79 (30) Contract valuations 7 41 (34) Storm-related costs 660 748 (88) Uncollectible and COVID-19 related costs 56 97 (41) Energy efficiency program costs 47 42 5 New Jersey societal benefit costs 109 112 (3) Regulatory transition costs (18) (20) 2 Vegetation management 33 22 11 Other (19) (9) (10) Net Regulatory Liabilities included on the Consolidated Balance Sheets $ (2,053) $ (1,744) $ (309) The following table provides information about the composition of net regulatory assets that do not earn a current return as of December 31, 2021 and 2020, of which approximately $228 million and $195 million, respectively, are currently being recovered through rates over varying periods, through 2068, depending on the nature of the deferral and the jurisdiction: Regulatory Assets by Source Not Earning a As of December 31, Current Return 2021 2020 Change (in millions) Deferred transmission costs $ 13 $ 17 $ (4) Deferred generation costs 50 5 45 Storm-related costs 549 654 (105) COVID-19 related costs 65 66 (1) Regulatory transition costs 13 16 (3) Vegetation management 31 22 9 Other 11 9 2 Regulatory Assets Not Earning a Current Return $ 732 $ 789 $ (57) |
Reconciliation of basic and diluted earnings per share | For the Years Ended December 31, Reconciliation of Basic and Diluted EPS of Common Stock 2021 2020 2019 (In millions, except per share amounts) EPS of Common Stock Income from continuing operations $ 1,239 $ 1,003 $ 904 Less: Preferred dividends N/A N/A (3) Less: Undistributed earnings allocated to preferred stockholders N/A N/A (1) Income from continuing operations available to common stockholders 1,239 1,003 900 Discontinued operations, net of tax 44 76 8 Less: Undistributed earnings allocated to preferred stockholders N/A N/A — Income from discontinued operations available to common stockholders 44 76 8 Income attributable to common stockholders, basic $ 1,283 $ 1,079 $ 908 Income allocated to preferred stockholders, preferred dilutive N/A N/A 4 Income attributable to common stockholders, dilutive $ 1,283 $ 1,079 $ 912 Share Count information: Weighted average number of basic shares outstanding 545 542 535 Assumed exercise of dilutive share based awards 1 1 3 Assumed conversion of preferred stock N/A N/A 4 Weighted average number of diluted shares outstanding 546 543 542 Income attributable to common stockholders, per common share: Income from continuing operations, basic $ 2.27 $ 1.85 $ 1.69 Discontinued operations, basic 0.08 0.14 0.01 Income attributable to common stockholders, basic $ 2.35 $ 1.99 $ 1.70 Income from continuing operations, diluted $ 2.27 $ 1.85 $ 1.67 Discontinued operations, diluted 0.08 0.14 0.01 Income attributable to common stockholders, diluted $ 2.35 $ 1.99 $ 1.68 |
Schedule of Goodwill | The following table presents goodwill by reporting unit as of December 31, 2021: (In millions) Regulated Distribution Regulated Transmission Consolidated Goodwill $ 5,004 $ 614 $ 5,618 |
Property, plant and equipment balances | Property, plant and equipment balances by segment as of December 31, 2021 and 2020, were as follows: December 31, 2021 Property, Plant and Equipment In Service (1) Accum. Depr. Net Plant CWIP Total (In millions) Regulated Distribution $ 31,154 $ (9,284) $ 21,870 $ 774 $ 22,644 Regulated Transmission 13,744 (2,789) 10,955 580 11,535 Corporate/Other 1,104 (599) 505 60 565 Total $ 46,002 $ (12,672) $ 33,330 $ 1,414 $ 34,744 December 31, 2020 Property, Plant and Equipment In Service (1) Accum. Depr. Net Plant CWIP Total (In millions) Regulated Distribution $ 29,775 $ (8,800) $ 20,975 $ 841 $ 21,816 Regulated Transmission 12,912 (2,609) 10,303 671 10,974 Corporate/Other 1,039 (556) 483 66 549 Total $ 43,726 $ (11,965) $ 31,761 $ 1,578 $ 33,339 (1) Includes finance leases of $143 million and $153 million as of December 31, 2021 and 2020, respectively. |
Receivables from customers | Billed and unbilled customer receivables as of December 31, 2021 and 2020, are included below. As of December 31, Customer Receivables 2021 2020 (In millions) Billed (1) $ 616 $ 800 Unbilled 576 567 1,192 1,367 Less: Uncollectible Reserve 159 164 Total Customer Receivables $ 1,033 $ 1,203 (1) Includes approximately $318 million and $349 million as of December 31, 2021, 2020, respectively, that are past due by greater than 30 days. |
Accounts receivable, allowance for credit loss | Activity in the allowance for uncollectible accounts on receivables for the years ended December 31, 2021, 2020 and 2019 are as follows: (In millions) 2021 2020 2019 Customer Receivables Beginning of year balance $ 164 $ 46 $ 50 Charged to income (1) 54 174 81 Charged to other accounts (2) 42 46 47 Write-offs (101) (102) (132) End of year balance $ 159 $ 164 $ 46 Other Receivables Beginning of year balance $ 26 $ 21 $ 2 Charged to income 3 7 27 Charged to other accounts (2) 3 10 1 Write-offs (22) (12) (9) End of year balance $ 10 $ 26 $ 21 Affiliated Companies Receivables (3) Beginning of year balance $ — $ 1,063 $ 920 Charged to income — — 143 Charged to other accounts (2) — — — Write-offs — (1,063) — End of year balance $ — $ — $ 1,063 (1) Customer receivable amounts charged to income for the years ended December 31, 2021, 2020 and 2019 include approximately $12 million, $103 million, and $25 million respectively, deferred for future recovery. (2) Represents recoveries and reinstatements of accounts previously written off for uncollectible accounts. |
REVENUE (Tables)
REVENUE (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The following represents a disaggregation of revenue from contracts with customers for the year ended December 31, 2021: Revenues by Type of Service Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments (1) Total (In millions) Distribution services (2)(4) $ 5,433 $ — $ (104) $ 5,329 Retail generation 3,730 — (50) 3,680 Wholesale sales 362 — 14 376 Transmission (2) — 1,608 — 1,608 Other 119 — — 119 Total revenues from contracts with customers $ 9,644 $ 1,608 $ (140) $ 11,112 ARP (3) (27) — — (27) Other revenue unrelated to contracts with customers 94 10 (57) 47 Total revenues $ 9,711 $ 1,618 $ (197) $ 11,132 (1) Includes eliminations and reconciling adjustments of inter-segment revenues. (2) Includes reductions to revenue related to amounts subject to refund resulting from the Tax Act ($3 million at Regulated Distribution and $(2) million at Regulated Transmission). (3) Reflects amounts the Ohio Companies refunded to customers that was previously collected under decoupling mechanisms, with interest. See Note 12, “Regulatory Matters,” for further discussion on Ohio decoupling rates. (4) Includes $38 million of customer refunds associated with the Ohio Stipulation that became effective in December 2021. See Note 12, “Regulatory Matters,” for additional information. The following represents a disaggregation of revenue from contracts with customers for the year ended December 31, 2020: Revenues by Type of Service Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments (1) Total (In millions) Distribution services (2) $ 5,259 $ — $ (88) $ 5,171 Retail generation 3,577 — (60) 3,517 Wholesale sales 251 — 9 260 Transmission (2) — 1,613 — 1,613 Other 140 — — 140 Total revenues from contracts with customers $ 9,227 $ 1,613 $ (139) $ 10,701 ARP (3) 43 — — 43 Other revenue unrelated to contracts with customers 93 17 (64) 46 Total revenues $ 9,363 $ 1,630 $ (203) $ 10,790 (1) Includes eliminations and reconciling adjustments of inter-segment revenues. (2) Includes reductions to revenue related to amounts subject to refund resulting from the Tax Act ($2 million at Regulated Distribution and $7 million at Regulated Transmission). (3) ARP revenue for the year ended December 31, 2020, is primarily related to shared savings revenue in Ohio. The following represents a disaggregation of revenue from contracts with customers for the year ended December 31, 2019: Revenues by Type of Service Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments (1) Total (In millions) Distribution services (2) $ 5,133 $ — $ (83) $ 5,050 Retail generation 3,727 — (57) 3,670 Wholesale sales (2) 411 — 12 423 Transmission (2) — 1,510 — 1,510 Other 150 — 2 152 Total revenues from contracts with customers $ 9,421 $ 1,510 $ (126) $ 10,805 ARP (3) 181 — — 181 Other revenue unrelated to contracts with customers 96 16 (63) 49 Total revenues $ 9,698 $ 1,526 $ (189) $ 11,035 (1) Includes eliminations and reconciling adjustments of inter-segment revenues. (2) Includes reductions to revenue related to amounts subject to refund resulting from the Tax Act ($16 million at Regulated Distribution and $19 million at Regulated Transmission). (3) ARP revenue for the year ended December 31, 2019, includes DMR revenue, lost distribution and shared savings revenue in Ohio. The following table represents a disaggregation of the Regulated Distribution segment revenue from contracts with distribution service and retail generation customers for the years ended December 31, 2021, 2020 and 2019 by class: For the Years Ended December 31, Revenues by Customer Class 2021 2020 2019 (In millions) Residential $ 5,713 $ 5,539 $ 5,412 Commercial 2,284 2,140 2,252 Industrial 1,091 1,076 1,106 Other 75 81 90 Total $ 9,163 $ 8,836 $ 8,860 The following table represents a disaggregation of revenue from contracts with regulated transmission customers for the years ended December 31, 2021, 2020 and 2019: For the Years Ended December 31, Transmission Owner 2021 2020 2019 (In millions) ATSI $ 799 $ 804 $ 754 TrAIL 233 247 242 MAIT 288 250 224 JCP&L 164 178 160 MP, PE and WP 124 134 130 Total Revenues $ 1,608 $ 1,613 $ 1,510 |
ACCUMULATED OTHER COMPREHENSI_2
ACCUMULATED OTHER COMPREHENSIVE INCOME (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Equity [Abstract] | |
Schedule of Accumulated Other Comprehensive Income | The changes in AOCI for the years ended December 31, 2021, 2020 and 2019, for FirstEnergy are shown in the following table: Gains & Losses on Cash Flow Hedges (1) Defined Benefit Pension & OPEB Plans Total (In millions) AOCI Balance, January 1, 2019 $ (11) $ 52 $ 41 Other comprehensive income before reclassifications — (2) (2) Amounts reclassified from AOCI 2 (29) (27) Other comprehensive income (loss) 2 (31) (29) Income tax (benefits) on other comprehensive income (loss) — (8) (8) Other comprehensive income (loss), net of tax 2 (23) (21) AOCI Balance, December 31, 2019 $ (9) $ 29 $ 20 Amounts reclassified from AOCI 1 (34) (33) Other comprehensive income (loss) 1 (34) (33) Income tax (benefits) on other comprehensive income (loss) — (8) (8) Other comprehensive income (loss), net of tax 1 (26) (25) AOCI Balance, December 31, 2020 $ (8) $ 3 $ (5) Amounts reclassified from AOCI 1 (14) (13) Other comprehensive income (loss) 1 (14) (13) Income tax (benefits) on other comprehensive income (loss) — (3) (3) Other comprehensive income (loss), net of tax 1 (11) (10) AOCI Balance, December 31, 2021 $ (7) $ (8) $ (15) (1) |
Reclassification out of Accumulated Other Comprehensive Income | The following amounts were reclassified from AOCI for FirstEnergy in the years ended December 31, 2021, 2020 and 2019: For the Years Ended December 31, Affected Line Item in Consolidated Statements of Income Reclassifications from AOCI (1) 2021 2020 2019 (In millions) Gains & losses on cash flow hedges Long-term debt $ 1 $ 1 $ 2 Interest expense $ 1 $ 1 $ 2 Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (14) $ (34) $ (29) (2) 3 8 8 Income taxes $ (11) $ (26) $ (21) Net of tax (1) Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI. (2) Prior-service costs are reported within Miscellaneous income, net within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income. Components are included in the computation of net periodic cost (credits), see Note 4, "Pension and Other Postemployment Benefits," for additional details. |
PENSION AND OTHER POST-EMPLOY_2
PENSION AND OTHER POST-EMPLOYMENT BENEFITS (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Assumptions Used to Determine Net Periodic Benefit Cost | Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December (1) Pension OPEB 2021 2020 2019 2021 2020 2019 Service cost weighted-average discount rate (2) 3.10 % 3.60%/3.24% 4.66 % 3.03 % 3.63%/3.29% 4.67 % Interest cost weighted-average discount rate (3) 2.58 % 3.27%/2.90% 4.37 % 1.66 % 2.71%/2.30% 3.89 % Expected return on plan assets 7.50 % 7.50 % 7.50 % 7.50 % 7.50 % 7.50 % Rate of compensation increase 4.10 % 4.10 % 4.10 % N/A N/A N/A (1) Excludes impact of pension and OPEB mark-to-market adjustment. (2) Weighted-average discount rates effect from January 1, 2020, through February 26, 2020, were 3.60% and 3.63% for pension and OPEB service cost, respectively. Discount rates were 3.24% and 3.29% for pension and OPEB service cost, respectively, for the period February 27, 2020 through December 31, 2020. |
Components of Net Periodic Benefit Costs | Components of Net Periodic Benefit Costs (Credits) for the Years Ended December 31, Pension OPEB 2021 2020 2019 2021 2020 2019 (In millions) Service cost $ 195 $ 194 $ 193 $ 4 $ 4 $ 3 Interest cost 226 287 373 11 15 22 Expected return on plan assets (652) (618) (540) (36) (33) (29) Amortization of prior service costs (credits) (1) 3 12 7 (17) (46) (36) Special termination costs (2) — — 14 — — — One-time termination benefits (3) — 8 — — — — Pension & OPEB mark-to-market (4) (253) 463 656 (129) 14 20 Net periodic benefit costs (credits) $ (481) $ 346 $ 703 $ (167) $ (46) $ (20) (1) 2020 includes the acceleration of approximately $18 million in net credits as a result of the FES Debtors’ emergence during the first quarter of 2020 and is a component of discontinued operations in FirstEnergy’s Consolidated Statements of Income. (2) Subject to a cap, FirstEnergy agreed to fund a pension enhancement through its pension plan, for voluntary enhanced retirement packages offered to certain FES employees, as well as offer certain other employee benefits. The costs are a component of discontinued operations in FirstEnergy’s Consolidated Statements of Income. (3) Costs represent additional benefits provided to FES and FENOC employees under the approved settlement agreement and are a component of discontinued operations. (4) Of the total Pension and OPEB mark-to-market adjustment for 2019, approximately $2 million is included in discontinued operations. |
Obligations and Funded Status | Pension OPEB Obligations and Funded Status - Qualified and Non-Qualified Plans 2021 2020 2021 2020 (In millions) Change in benefit obligation: Benefit obligation as of January 1 $ 11,935 $ 11,050 $ 676 $ 654 Service cost 195 194 4 4 Interest cost 226 287 11 15 Plan participants’ contributions — — 4 4 Plan amendments — 9 — — Medicare retiree drug subsidy — — 1 1 Actuarial loss (gain) (280) 1,011 (101) 41 Benefits paid (597) (616) (46) (43) Benefit obligation as of December 31 $ 11,479 $ 11,935 $ 549 $ 676 Change in fair value of plan assets: Fair value of plan assets as of January 1 $ 8,968 $ 8,395 $ 502 $ 458 Actual return on plan assets 625 1,165 64 60 Company contributions 24 24 24 23 Plan participants’ contributions — — 4 4 Benefits paid (597) (616) (46) (43) Fair value of plan assets as of December 31 $ 9,020 $ 8,968 $ 548 $ 502 Funded Status: Qualified plan $ (1,974) $ (2,500) $ — $ — Non-qualified plans (485) (467) — — Funded Status (Net liability as of December 31) $ (2,459) $ (2,967) $ (1) $ (174) Accumulated benefit obligation $ 10,927 $ 11,376 $ — $ — Amounts Recognized in AOCI: Prior service cost (credit) $ 9 $ 12 $ (21) $ (39) Assumptions Used to Determine Benefit Obligations (as of December 31) Discount rate 3.02 % 2.67 % 2.84 % 2.45 % Rate of compensation increase 4.10 % 4.10 % N/A N/A Cash balance weighted average interest crediting rate 2.57 % 2.57 % N/A N/A Assumed Health Care Cost Trend Rates (as of December 31) Health care cost trend rate assumed (pre/post-Medicare) N/A N/A 5.75%-5.25% 6.0%-5.5% Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) N/A N/A 4.5 % 4.5 % Year that the rate reaches the ultimate trend rate N/A N/A 2028 2028 |
Target asset allocations for pension and OPEB portfolio | FirstEnergy’s target asset allocations for its pension and OPEB trust portfolios for 2021 and 2020 are shown in the following table: Target Asset Allocations 2021 2020 Equities 38 % 38 % Fixed income 30 % 30 % Hedge funds 8 % 8 % Real estate 10 % 10 % Alternative investments 8 % 8 % Cash and short-term securities 6 % 6 % 100 % 100 % |
Estimated Future Benefit Payments | Taking into account estimated employee future service, FirstEnergy expects to make the following benefit payments from plan assets and other payments, net of participant contributions: OPEB Pension Benefit Payments Subsidy Receipts (In millions) 2022 $ 566 $ 44 $ (1) 2023 575 41 (1) 2024 581 39 (1) 2025 590 38 — 2026 598 37 — Years 2027-2030 3,075 164 (2) |
Pension | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Pension investments measured at fair value | The following tables set forth pension financial assets that are accounted for at fair value by level within the fair value hierarchy. See Note 8, "Fair Value Measurements," for a description of each level of the fair value hierarchy. There were no significant transfers between levels during 2021 and 2020. December 31, 2021 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 746 $ — $ 746 8 % Public equity 2,867 286 — 3,153 35 % Fixed income — 2,453 — 2,453 27 % Derivatives 20 — — 20 — % Total (1) $ 2,887 $ 3,485 $ — $ 6,372 70 % Private - equity and debt funds (2) 811 9 % Insurance-linked securities (2) 320 4 % Hedge funds (2) 678 7 % Real estate funds (2) 886 10 % Total Investments $ 9,067 100 % (1) Excludes $(47) million as of December 31, 2021, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. (2) Net Asset Value used as a practical expedient to approximate fair value. December 31, 2020 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 1,493 $ — $ 1,493 17 % Public equity 1,903 162 — 2,065 23 % Fixed income — 3,059 — 3,059 35 % Derivatives (13) — — (13) — % Total (1) $ 1,890 $ 4,714 $ — $ 6,604 75 % Private - equity and debt funds (2) 465 5 % Insurance-linked securities (2) 323 4 % Hedge funds (3) 645 7 % Real estate funds (2) 815 9 % Total Investments $ 8,852 100 % (1) Excludes $116 million as of December 31, 2020, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. (2) Net Asset Value used as a practical expedient to approximate fair value. |
OPEB | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Pension investments measured at fair value | As of December 31, 2021, and 2020, the OPEB trust investments measured at fair value were as follows: December 31, 2021 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 95 $ — $ 95 17 % Public equity 278 — — 278 51 % Fixed income — 175 — 175 32 % Total $ 278 $ 270 $ — $ 548 100 % December 31, 2020 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 84 $ — $ 84 17 % Public equity 283 — — 283 55 % Fixed income: — 145 — 145 28 % Total (1) $ 283 $ 229 $ — $ 512 100 % (1) Excludes $(10) million as of December 31, 2020, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. |
STOCK-BASED COMPENSATION PLANS
STOCK-BASED COMPENSATION PLANS (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Share-based Payment Arrangement [Abstract] | |
Schedule of Stock-based Compensation Expense | Stock-based compensation costs and the amount of stock-based compensation costs capitalized related to FirstEnergy plans for the years ended December 31, 2021, 2020 and 2019, are included in the following tables: For the Years Ended December 31, Stock-based Compensation Plan 2021 2020 2019 (In millions) Restricted Stock Units $ 40 $ 22 $ 73 Restricted Stock 2 1 1 401(k) Savings Plan 35 33 33 EDCP & DCPD 13 (5) 9 Total $ 90 $ 51 $ 116 Stock-based compensation costs capitalized $ 47 $ 26 $ 54 |
Schedule of Nonvested Restricted Stock Units Activity | Restricted stock unit activity for the year ended December 31, 2021, was as follows: Restricted Stock Unit Activity Shares (in millions) Weighted-Average Grant Date Fair Value (per share) Nonvested as of January 1, 2021 1.8 $ 40.25 Granted in 2021 1.3 35.50 Forfeited in 2021 (0.3) 40.08 Vested in 2021 (1) (1.0) 33.73 Nonvested as of December 31, 2021 1.8 $ 41.89 (1) |
TAXES (Tables)
TAXES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |
Provision for income taxes (benefits) | For the Years Ended December 31, INCOME TAXES (1) 2021 2020 2019 (In millions) Currently payable (receivable)- Federal (2) $ 2 $ (14) $ (16) State 21 21 24 23 7 8 Deferred, net- Federal (3) 174 171 150 State (4) 127 (38) 60 301 133 210 Investment tax credit amortization (4) (14) (5) Total income taxes $ 320 $ 126 $ 213 (1) Income Taxes on Income from Continuing Operations. (2) Excludes $2 million of federal tax benefit and $6 million of federal tax expense associated with discontinued operations for the years ended December 31, 2021 and 2020 respectively. (3) Excludes $46 million, $66 million and $9 million of federal tax benefits associated with discontinued operations for the years ended December 31, 2021, 2020 and 2019, respectively. (4) Excludes $1 million and $4 million of state tax expense associated with discontinued operations for the years ended December 31, 2020 and 2019, respectively. |
Reconciliation of federal income tax expense at the federal statutory rate to the total provision for income taxes | The following tables provide a reconciliation of federal income tax expense (benefit) at the federal statutory rate to the total income taxes (benefits) for the years ended December 31, 2021, 2020 and 2019: For the Years Ended December 31, 2021 2020 2019 (In millions) Income from Continuing Operations, before income taxes $ 1,559 $ 1,129 $ 1,117 Federal income tax expense at statutory rate (21%) $ 327 $ 237 $ 235 Increases (reductions) in taxes resulting from- State income taxes, net of federal tax benefit 122 75 96 AFUDC equity and other flow-through (29) (38) (36) Amortization of investment tax credits (4) (14) (5) Federal tax credits claimed (34) — — Nondeductible DPA monetary penalty 52 — — Excess deferred tax amortization due to the Tax Act (54) (56) (74) TMI-2 reversal of tax regulatory liabilities — (40) — Uncertain tax positions (82) (1) (11) Valuation allowances 17 (49) 5 Other, net 5 12 3 Total income taxes $ 320 $ 126 $ 213 Effective income tax rate 20.5 % 11.2 % 19.1 % |
Accumulated deferred income taxes | Accumulated deferred income taxes as of December 31, 2021 and 2020, are as follows: As of December 31, 2021 2020 (In millions) Property basis differences $ 5,670 $ 5,396 Pension and OPEB (570) (769) AROs (21) (28) Regulatory asset/liability 322 440 Deferred compensation (155) (165) Loss carryforwards and tax credits (2,040) (1,995) Valuation reserve 484 496 All other (253) (280) Net deferred income tax liability $ 3,437 $ 3,095 |
Pre-tax net operating loss expiration period | Expiration Period State Local (In millions) 2022-2026 $ 2,603 $ 3,783 2027-2031 1,390 — 2032-2036 992 — 2037-2041 959 — Indefinite 2,157 — $ 8,101 $ 3,783 |
Valuation allowance roll forward | The following table summarizes the changes in valuation allowances on federal, state and local DTAs related to disallowed interest and certain employee remuneration, in addition to state and local NOLs discussed above for the years ended December 31, 2021, 2020 and 2019: (In millions) 2021 2020 2019 Beginning of year balance $ 496 $ 441 $ 394 Charged to income (12) 55 47 Charged to other accounts — — — Write-offs — — — End of year balance $ 484 $ 496 $ 441 |
Changes in unrecognized tax benefits | The following table summarizes the changes in unrecognized tax positions for the years ended December 31, 2021, 2020 and 2019: (In millions) Balance, January 1, 2019 $ 158 Current year increases 22 Prior year decreases (12) Decrease for lapse in statute (4) Balance, December 31, 2019 $ 164 Current year increases 7 Prior year decreases (28) Decrease for lapse in statute (2) Effectively settled with taxing authorities (2) Balance, December 31, 2020 $ 139 Current year increases 15 Prior years decreases (8) Effectively settled with taxing authorities (97) Decrease for lapse in statute (2) Balance, December 31, 2021 $ 47 |
Details of general taxes | General tax expense for the years ended December 31, 2021, 2020 and 2019, recognized in continuing operations is summarized as follows: For the Years Ended December 31, 2021 2020 2019 (In millions) KWH excise $ 189 $ 183 $ 191 State gross receipts 190 182 185 Real and personal property 571 541 504 Social security and unemployment 103 112 100 Other 20 28 28 Total general taxes $ 1,073 $ 1,046 $ 1,008 |
LEASES (Tables)
LEASES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Leases [Abstract] | |
Components of Lease Expense | The components of lease expense were as follows: For the Year Ended December 31, 2021 (In millions) Vehicles Buildings Other Total Operating lease costs (1) $ 44 $ 9 $ 18 $ 71 Finance lease costs: Amortization of right-of-use assets 12 1 1 14 Interest on lease liabilities 1 3 — 4 Total finance lease cost 13 4 1 18 Total lease cost $ 57 $ 13 $ 19 $ 89 (1) Includes $21 million of short-term lease costs. For the Year Ended December 31, 2020 (In millions) Vehicles Buildings Other Total Operating lease costs (1) $ 35 $ 8 $ 17 $ 60 Finance lease costs: Amortization of right-of-use assets 14 — 1 15 Interest on lease liabilities 2 3 — 5 Total finance lease cost 16 3 1 20 Total lease cost $ 51 $ 11 $ 18 $ 80 (1) Includes $17 million of short-term lease costs. For the Year Ended December 31, 2019 (In millions) Vehicles Buildings Other Total Operating lease costs (1) $ 28 $ 9 $ 12 $ 49 Finance lease costs: Amortization of right-of-use assets 15 1 1 17 Interest on lease liabilities 3 3 — 6 Total finance lease cost 18 4 1 23 Total lease cost $ 46 $ 13 $ 13 $ 72 (1) Includes $13 million of short-term lease costs. Supplemental cash flow information related to leases was as follows: For the Years Ended December 31, (In millions) 2021 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 64 $ 44 $ 29 Operating cash flows from finance leases 4 4 5 Finance cash flows from finance leases 13 15 25 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 60 $ 67 $ 83 Finance leases 5 — 3 Maturities of lease liabilities as of December 31, 2021, were as follows: (In millions) Operating Leases Finance Leases Total 2022 $ 54 $ 16 $ 70 2023 54 9 63 2024 48 5 53 2025 45 5 50 2026 41 5 46 Thereafter 133 8 141 Total lease payments (1) 375 48 423 Less imputed interest 65 12 77 Total net present value $ 310 $ 36 $ 346 (1) Operating lease payments for certain leases are offset by sublease receipts of $10 million over 11 years. |
Assets and Liabilities, Lessee | Lease terms and discount rates were as follows: As of December 31, 2021 2020 2019 Weighted-average remaining lease terms (years) Operating leases 7.97 8.55 9.42 Finance leases 8.12 7.74 4.62 Weighted-average discount rate (1) Operating leases 4.16 % 4.21 % 4.51 % Finance leases 12.22 % 11.58 % 10.45 % (1) When an implicit rate is not readily determinable, an incremental borrowing rate is utilized, determining the present value of lease payments. The rate is determined based on expected term and information available at the commencement date. Supplemental balance sheet information related to leases was as follows: As of December 31, (In millions) Financial Statement Line Item 2021 2020 Assets Operating lease (1) Deferred charges and other assets $ 279 $ 265 Finance lease (2) Property, plant and equipment 48 57 Total leased assets $ 327 $ 322 Liabilities Current: Operating Other current liabilities $ 39 $ 42 Finance Currently payable long-term debt 13 14 Noncurrent: Operating Other noncurrent liabilities 271 263 Finance Long-term debt and other long-term obligations 23 31 Total leased liabilities $ 346 $ 350 (1) Operating lease assets are recorded net of accumulated amortization of $79 million and $51 million as of December 31, 2021 and 2020, respectively. |
Maturity of Operating Lease Liabilities | Maturities of lease liabilities as of December 31, 2021, were as follows: (In millions) Operating Leases Finance Leases Total 2022 $ 54 $ 16 $ 70 2023 54 9 63 2024 48 5 53 2025 45 5 50 2026 41 5 46 Thereafter 133 8 141 Total lease payments (1) 375 48 423 Less imputed interest 65 12 77 Total net present value $ 310 $ 36 $ 346 (1) Operating lease payments for certain leases are offset by sublease receipts of $10 million over 11 years. |
Maturity of Finance Lease Liabilities | Maturities of lease liabilities as of December 31, 2021, were as follows: (In millions) Operating Leases Finance Leases Total 2022 $ 54 $ 16 $ 70 2023 54 9 63 2024 48 5 53 2025 45 5 50 2026 41 5 46 Thereafter 133 8 141 Total lease payments (1) 375 48 423 Less imputed interest 65 12 77 Total net present value $ 310 $ 36 $ 346 (1) Operating lease payments for certain leases are offset by sublease receipts of $10 million over 11 years. |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Fair Value Disclosures [Abstract] | |
Assets and liabilities measured on recurring basis | The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy: December 31, 2021 December 31, 2020 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Derivative assets FTRs (1) $ — $ — $ 9 $ 9 $ — $ — $ 3 $ 3 Equity securities 2 — — 2 2 — — 2 U.S. state debt securities — 273 — 273 — 276 — 276 Cash, cash equivalents and restricted cash (2) 1,511 — — 1,511 1,801 — — 1,801 Other (3) — 42 — 42 — 41 — 41 Total assets $ 1,513 $ 315 $ 9 $ 1,837 $ 1,803 $ 317 $ 3 $ 2,123 Liabilities Derivative liabilities FTRs (1) $ — $ — $ (1) $ (1) $ — $ — $ — $ — Total liabilities $ — $ — $ (1) $ (1) $ — $ — $ — $ — Net assets (liabilities) (4) $ 1,513 $ 315 $ 8 $ 1,836 $ 1,803 $ 317 $ 3 $ 2,123 (1) Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. (2) Restricted cash of $49 million and $67 million as of December 31, 2021 and 2020 respectively, primarily relates to cash collected from JCP&L, MP, PE and the Ohio Companies' customers that is specifically used to service debt of their respective funding companies. (3) Primarily consists of short-term investments. (4) Excludes $1 million as of December 31, 2020, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. |
Reconciliation of changes in the fair value roll forward of level 3 measurements of NUG contracts | The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the years ended December 31, 2021 and 2020: NUG Contracts (1) FTRs (1) Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net (In millions) January 1, 2020 Balance $ — $ (16) $ (16) $ 4 $ (1) $ 3 Unrealized gain (loss) — (3) (3) (3) — (3) Purchases — — — 7 (2) 5 Settlements — 19 19 (5) 3 (2) December 31, 2020 Balance $ — $ — $ — $ 3 $ — $ 3 Unrealized gain (loss) — — — 7 — 7 Purchases — — — 5 (2) 3 Settlements — — — (6) 1 (5) December 31, 2021 Balance $ — $ — $ — $ 9 $ (1) $ 8 (1) Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. |
Quantitative information for level 3 valuation | The following table provides quantitative information for FTRs contracts that are classified as Level 3 in the fair value hierarchy for the year ended December 31, 2021: Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ 8 Model RTO auction clearing prices $1.10 to $4.60 $1.80 Dollars/MWH |
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities | The following table summarizes the amortized cost basis, unrealized gains, unrealized losses and fair values of investments held in nuclear fuel disposal trusts as of December 31, 2021 and 2020: December 31, 2021 (1) December 31, 2020 (2) Cost Basis Unrealized Gains Unrealized Losses Fair Value Cost Basis Unrealized Gains Unrealized Losses Fair Value (In millions) Debt securities $ 280 $ 2 $ (9) $ 273 $ 275 $ 7 $ (6) $ 276 (1) Excludes short-term cash investments of $11 million. (2) Excludes short-term cash investments of $9 million. |
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income | Proceeds from the sale of investments in AFS debt securities, realized gains and losses on those sales and interest and dividend income for the years ended December 31, 2021, 2020 and 2019, were as follows: For the Years Ended December 31, 2021 2020 (1) 2019 (1) (In millions) Sale Proceeds $ 48 $ 186 $ 1,637 Realized Gains — 12 98 Realized Losses (3) (8) (31) Interest and Dividend Income 11 22 38 (1) Includes amounts associated with NDTs that were previously held by JCP&L, ME, and PN. See above for additional information. |
Fair value and related carrying amounts of long-term debt and other long-term obligations | The following table provides the approximate fair value and related carrying amounts of long-term debt, which excludes finance lease obligations and net unamortized debt issuance costs, unamortized fair value adjustments, premiums and discounts as of December 31, 2021 and 2020: As of December 31, 2021 2020 (In millions) Carrying Value $ 23,946 $ 22,377 Fair Value 27,043 25,465 |
CAPITALIZATION (Tables)
CAPITALIZATION (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Capitalization, Long-term Debt and Equity [Abstract] | |
Preferred stock and preference stock authorizations | FirstEnergy and the Utilities were authorized to issue preferred stock and preference stock as of December 31, 2021, as follows: Preferred Stock Preference Stock Shares Authorized Par Value Shares Authorized Par Value FE 5,000,000 $ 100 OE 6,000,000 $ 100 8,000,000 no par OE 8,000,000 $ 25 Penn 1,200,000 $ 100 CEI 4,000,000 no par 3,000,000 no par TE 3,000,000 $ 100 5,000,000 $ 25 TE 12,000,000 $ 25 JCP&L 15,600,000 no par ME 10,000,000 no par PN 11,435,000 no par MP 940,000 $ 100 PE 10,000,000 $ 0.01 WP 32,000,000 no par |
Outstanding consolidated long-term debt and other long-term obligations | The following tables present outstanding long-term debt and finance lease obligations for FirstEnergy as of December 31, 2021 and 2020: As of December 31, 2021 As of December 31, (Dollar amounts in millions) Maturity Date Interest Rate 2021 2020 FMBs and secured notes - fixed rate 2022-2059 2.650% - 8.250% $ 5,021 $ 4,802 Unsecured notes - fixed rate 2022-2050 1.600% - 7.375% 18,925 17,575 Finance lease obligations 36 45 Unamortized debt discounts (8) (34) Unamortized debt issuance costs (126) (118) Unamortized fair value adjustments 6 7 Currently payable long-term debt (1,606) (146) Total long-term debt and other long-term obligations $ 22,248 $ 22,131 During the twelve months ended December 31, 2021, the following long-term debt was issued: Company Issuance Date Interest Rate Maturity Amount Issuance Type Use of Proceeds FET 3/19/2021 2.87% 2028 $500 million Unsecured Notes Repay short-term borrowings under the former FET Revolving Facility. MP 4/9/2021 3.55% (1) 2027 $200 million FMB Fund MP’s ongoing capital expenditures, for working capital needs and for other general corporate purposes. TE 5/6/2021 2.65% 2028 $150 million Senior Secured Notes Repay short-term borrowings, fund TE’s ongoing capital expenditures and for other general corporate purposes. MAIT 5/24/2021 4.10% (2) 2028 $150 million Unsecured Notes Repay borrowings outstanding under FirstEnergy’s regulated company money pool, fund MAIT’s ongoing capital expenditures, to fund working capital and for other general corporate purposes. JCP&L 6/10/2021 2.75% 2032 $500 million Unsecured Notes Repay $450 million of short-term debt under the former FE Revolving Facility, storm recovery and restoration costs and expenses, to fund JCP&L’s ongoing capital expenditures, working capital requirements and for other general corporate purposes. ATSI 12/1/2021 2.65% 2032 $600 million Unsecured Notes Repay outstanding notes and short-term borrowings, to fund ATSI's ongoing capital expenditures, working capital requirements and for other general corporate purposes. (1) New debt was issued at a premium under a previously issued bond series, resulting in an effective interest rate of 2.06%. (2) New debt was issued at a premium under a previously issued note series, resulting in an effective interest rate of 2.55%. |
Schedule of Maturities of Long-term Debt | The following table presents scheduled debt repayments or debt that has been noticed for redemption for outstanding long-term debt, excluding finance leases, fair value purchase accounting adjustments and unamortized debt discounts and premiums, for the next five years as of December 31, 2021. Year (In millions) 2022 $ 1,593 2023 344 2024 1,246 2025 2,023 2026 1,076 |
ASSET RETIREMENT OBLIGATIONS (T
ASSET RETIREMENT OBLIGATIONS (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Asset Retirement Obligation [Abstract] | |
Changes to the asset retirement obligations | The following table summarizes the changes to the ARO balances during 2021 and 2020: ARO Reconciliation (In millions) Balance, January 1, 2020 $ 856 Liabilities settled (1) (744) Accretion 47 Balance, December 31, 2020 $ 159 Changes in timing and amount of estimated cash flows 8 Liabilities settled (1) Accretion 13 Balance, December 31, 2021 $ 179 (1) Includes $726 million related to the closing of the asset purchase and sale agreement with TMI-2 Solutions, LLC, a subsidiary of Energy Solutions |
REGULATORY MATTERS (Tables)
REGULATORY MATTERS (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Regulated Operations [Abstract] | |
Distribution Rate Orders | The following table summarizes the key terms of base distribution rate orders in effect for the Utilities as of December 31, 2021: Company Rates Effective For Customers Allowed Debt/Equity Allowed ROE CEI May 2009 51% /49% 10.5% ME (1) January 2017 48.8% / 51.2% Settled (2) MP February 2015 54% / 46% Settled (2) JCP&L November 2021 (3) 48.6% / 51.4% 9.6% OE January 2009 51% /49% 10.5% PE (West Virginia) February 2015 54% / 46% Settled (2) PE (Maryland) March 2019 47% / 53% 9.65% PN (1) January 2017 47.4% /52.6% Settled (2) Penn (1) January 2017 49.9% / 50.1% Settled (2) TE January 2009 51% / 49% 10.5% WP (1) January 2017 49.7% / 50.3% Settled (2) (1) Reflects filed debt/equity as final settlement/orders do not specifically include capital structure. (2) Commission-approved settlement agreements did not disclose ROE rates. (3) On October 28, 2020, the NJBPU approved JCP&L's distribution rate case settlement with an allowed ROE of 9.6% and a 48.6% debt / 51.4% equity capital structure. Rates are effective for customers on November 1, 2021, but beginning January 1, 2021, JCP&L offset the impact to customers' bills by amortizing an $86 million regulatory liability. The following table summarizes the key terms of rate orders in effect for transmission customer billings for FirstEnergy's transmission owner entities as of December 31, 2021: Company Rates Effective Capital Structure Allowed ROE ATSI January 1, 2015 Actual (13-month average) 10.38% JCP&L January 1, 2020 Actual (13-month average) 10.20% MP January 1, 2021 (1)(2) Actual (13-month average) (1) 11.35% (1) PE January 1, 2021 (1)(2) Actual (13-month average) (1) 11.35% (1) WP January 1, 2021 (1)(2) Actual (13-month average) (1) 11.35% (1) MAIT July 1, 2017 Lower of Actual (13-month average) or 60% 10.3% TrAIL July 1, 2008 Actual (year-end) 12.7%(TrAIL the Line & Black Oak SVC) 11.7% (All other projects) (1) Effective on January 1, 2021, MP, PE, and WP have implemented a forward-looking formula rate, which has been accepted by FERC, subject to refund, pending further hearing and settlement procedures. (2) See FERC Action on Tax Act below. |
COMMITMENTS, GUARANTEES AND C_2
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Guarantor Obligations | The following table discloses the potential additional credit rating contingent contractual collateral obligations as of December 31, 2021: Potential Collateral Obligations Utilities FE Total (In millions) Contractual Obligations for Additional Collateral Upon Further Downgrade $ 44 $ — $ 44 Surety Bonds (collateralized amount) (1) 57 258 315 Total Exposure from Contractual Obligations $ 101 $ 258 $ 359 |
DISCONTINUED OPERATIONS (Tables
DISCONTINUED OPERATIONS (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Disposal Groups, Including Discontinued Operations | Summarized results of discontinued operations for the years ended December 31, 2021, 2020, and 2019 were as follows: For the Years Ended December 31, (In millions) 2021 2020 2019 Revenues $ — $ 7 $ 188 Fuel — (6) (140) Other operating expenses — (6) (63) General taxes — — (14) Pleasants economic interest (1) — 5 27 Other expense, net (4) — (2) Loss from discontinued operations, before tax (4) — (4) Income tax expense (benefit) (1) — 47 Loss from discontinued operations, net of tax (3) — (51) Settlement consideration and services credit — (1) 7 Accelerated net pension and OPEB prior service credits — 18 — Gain on disposal of FES and FENOC, before tax — 17 7 Income tax benefits, including worthless stock deduction (47) (59) (52) Gain on disposal of FES and FENOC, net of tax 47 76 59 Income from discontinued operations $ 44 $ 76 $ 8 (1) Reflects the estimated amounts owed from FG for its economic interests in Pleasants effective January 1, 2019. As discussed above, settlement of the economic interests occurred during the first quarter of 2020. FirstEnergy's Consolidated Statements of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. The following table summarizes the major classes of cash flow items from discontinued operations for the years ended December 31, 2021, 2020 and 2019: For the Years Ended December 31, (In millions) 2021 2020 2019 CASH FLOWS FROM OPERATING ACTIVITIES: Income from discontinued operations $ 44 $ 76 $ 8 Gain on disposal, net of tax (47) (76) (59) Deferred income taxes and investment tax credits, net — — 47 |
SEGMENT INFORMATION (Tables)
SEGMENT INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Segment Reporting [Abstract] | |
Segment Financial Information | Segment Financial Information For the Years Ended Regulated Distribution Regulated Transmission Corporate/ Other Reconciling Adjustments FirstEnergy Consolidated (In millions) December 31, 2021 External revenues $ 9,510 $ 1,608 $ 14 $ — $ 11,132 Internal revenues 201 10 — (211) — Total revenues 9,711 1,618 14 (211) 11,132 Provision for depreciation 911 325 3 63 1,302 Amortization of regulatory assets, net 260 9 — — 269 DPA penalty — — 230 — 230 Miscellaneous income (expense), net 399 41 89 (12) 517 Interest expense 523 248 382 (12) 1,141 Income taxes (benefits) 364 127 (171) — 320 Income (loss) from continuing operations 1,288 408 (457) — 1,239 Property additions $ 1,395 $ 958 $ 92 $ — $ 2,445 December 31, 2020 External revenues $ 9,168 $ 1,613 $ 9 $ — $ 10,790 Internal revenues 195 17 — (212) — Total revenues 9,363 1,630 9 (212) 10,790 Provision for depreciation 896 313 4 61 1,274 Amortization (deferral) of regulatory assets, net (64) 11 — — (53) Miscellaneous income (expense), net 332 30 83 (13) 432 Interest expense 501 219 358 (13) 1,065 Income taxes (benefits) 113 138 (125) — 126 Income (loss) from continuing operations 959 464 (420) — 1,003 Property additions $ 1,514 $ 1,067 $ 76 $ — $ 2,657 December 31, 2019 External revenues $ 9,511 $ 1,510 $ 14 $ — $ 11,035 Internal revenues 187 16 — (203) — Total revenues 9,698 1,526 14 (203) 11,035 Provision for depreciation 863 284 5 68 1,220 Amortization (deferral) of regulatory assets, net (89) 10 — — (79) Miscellaneous income (expense), net 174 15 80 (26) 243 Interest expense 495 192 372 (26) 1,033 Income taxes 271 113 (171) — 213 Income (loss) from continuing operations 1,076 447 (619) — 904 Property additions $ 1,473 $ 1,090 $ 102 $ — $ 2,665 As of December 31, 2021 Total assets $ 30,812 $ 13,237 $ 1,383 $ — $ 45,432 Total goodwill $ 5,004 $ 614 $ — $ — $ 5,618 As of December 31, 2020 Total assets $ 30,855 $ 12,592 $ 1,017 $ — $ 44,464 Total goodwill $ 5,004 $ 614 $ — $ — $ 5,618 |
ORGANIZATION AND BASIS OF PRE_4
ORGANIZATION AND BASIS OF PRESENTATION - Narrative (Details) customer in Thousands | Apr. 30, 2022USD ($) | Dec. 31, 2021USD ($)mi²transmissionCenteragreemententitycompanycustomerMW | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | Jun. 30, 2022director |
Regulatory Assets [Line Items] | |||||
Number of regional transmission centers | transmissionCenter | 2 | ||||
Regulatory assets currently being recovered through deferred returns | $ 228,000,000 | $ 195,000,000 | |||
Annual composite depreciation rate | 2.70% | 2.70% | 2.70% | ||
Capitalized financing costs | $ 48,000,000 | $ 49,000,000 | $ 45,000,000 | ||
Interest costs capitalized | 27,000,000 | 28,000,000 | 26,000,000 | ||
Property, plant and equipment | 34,744,000,000 | 33,294,000,000 | |||
Concentration of risk of accounts receivable | $ 0 | 0 | |||
Increase (decrease) in allowance for credit loss, | 121,000,000 | ||||
Number of contracts that may contain variable interest | entity | 1 | ||||
Purchased power | $ 2,964,000,000 | 2,701,000,000 | $ 2,927,000,000 | ||
Power Purchase Agreements | |||||
Regulatory Assets [Line Items] | |||||
Ownership interest | 0.00% | ||||
Number of long term power purchase agreements maintained by parent company with Non utility generation entities | agreement | 6 | ||||
Global Holding | |||||
Regulatory Assets [Line Items] | |||||
Equity method investments | $ 59,000,000 | ||||
Path-WV | Variable Interest Entity, Not Primary Beneficiary | |||||
Regulatory Assets [Line Items] | |||||
Equity method investments | $ 18,000,000 | ||||
Percentage of high-voltage transmission line project owned by subsidiary of FE on the Allegheny Series | 100.00% | ||||
Percentage of high-voltage transmission line project owned by subsidiary of AE on the West Virginia Series | 50.00% | ||||
FEV | Signal Peak | Global Holding | |||||
Regulatory Assets [Line Items] | |||||
Ownership interest | 33.33% | ||||
Other FE subsidiaries | Power Purchase Agreements | |||||
Regulatory Assets [Line Items] | |||||
Purchased power | $ 111,000,000 | 113,000,000 | |||
FET | Forecast | |||||
Regulatory Assets [Line Items] | |||||
Number of directors | director | 5 | ||||
Debt covenants minimum ownership interest percentage | 9.90% | ||||
Debt-to-Capital terms included in sale for the first 5 years | 65.00% | ||||
Debt-to-Capital terms included in sale for thereafter | 70.00% | ||||
FET | North American Transmission Company II LLC | Forecast | |||||
Regulatory Assets [Line Items] | |||||
Sale of ownership interest by parent | 19.90% | ||||
Sale of ownership interest by parent | $ 2,375,000,000 | ||||
Number of directors | director | 1 | ||||
FET | FE | Forecast | |||||
Regulatory Assets [Line Items] | |||||
Number of directors | director | 4 | ||||
Bath County, Virginia | |||||
Regulatory Assets [Line Items] | |||||
Plant generation capacity (in MW's) | MW | 3,003 | ||||
Bath County, Virginia | AGC | |||||
Regulatory Assets [Line Items] | |||||
Plant generation capacity (in MW's) | MW | 487 | ||||
Proportionate ownership share | 16.25% | ||||
Property, plant and equipment | $ 153,000,000 | ||||
Bath County, Virginia | Virginia Electric and Power Company | |||||
Regulatory Assets [Line Items] | |||||
Proportionate ownership share | 60.00% | ||||
Waverly, New York | PN | |||||
Regulatory Assets [Line Items] | |||||
Number of customers served by utility operating companies | customer | 4 | ||||
Regulated Distribution | |||||
Regulatory Assets [Line Items] | |||||
Number of existing utility operating companies | company | 10 | ||||
Number of customers served by utility operating companies | customer | 6,000 | ||||
Service Area | mi² | 65,000 | ||||
Plant generation capacity (in MW's) | MW | 3,580 | ||||
Property, plant and equipment, net | $ 2,100,000,000 | ||||
Regulated Transmission | |||||
Regulatory Assets [Line Items] | |||||
Service Area | mi² | 24,500 | ||||
Disposal Group, Held-for-sale | Yard Creek Generating Facility | Regulated Distribution | |||||
Regulatory Assets [Line Items] | |||||
Assets held-for-sale | 45,000,000 | ||||
Future Recovery of Incremental Costs | |||||
Regulatory Assets [Line Items] | |||||
Increase (decrease) in allowance for credit loss, | $ 90,000,000 |
ORGANIZATION AND BASIS OF PRE_5
ORGANIZATION AND BASIS OF PRESENTATION - Regulatory Assets on the Balance Sheet (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Regulatory assets on the Balance Sheets | ||
Regulatory Liability | $ (2,124) | $ (1,826) |
Regulatory Assets | 71 | 82 |
Net Regulatory Liabilities included on the Consolidated Balance Sheets | (2,053) | (1,744) |
Change | (309) | |
Current Return | 732 | 789 |
Change | (57) | |
Customer payables for future income taxes | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Liability | (2,345) | (2,369) |
Change | 24 | |
Spent nuclear fuel disposal costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Liability | (101) | (102) |
Change | 1 | |
Asset removal costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Liability | (646) | (721) |
Change | 75 | |
Deferred transmission costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | (3) | 319 |
Change | (322) | |
Current Return | 13 | 17 |
Change | (4) | |
Deferred generation costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 118 | 17 |
Change | 101 | |
Current Return | 50 | 5 |
Change | 45 | |
Deferred distribution costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 49 | 79 |
Change | (30) | |
Contract valuations | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 7 | 41 |
Change | (34) | |
Storm-related costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 660 | 748 |
Change | (88) | |
Current Return | 549 | 654 |
Change | (105) | |
Uncollectible and COVID-19 related costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 56 | 97 |
Change | (41) | |
Current Return | 65 | 66 |
Change | (1) | |
Energy efficiency program costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 47 | 42 |
Change | 5 | |
New Jersey societal benefit costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 109 | 112 |
Change | (3) | |
Regulatory transition costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Liability | (18) | (20) |
Change | 2 | |
Current Return | 13 | 16 |
Change | (3) | |
Vegetation management | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 33 | 22 |
Change | 11 | |
Current Return | 31 | 22 |
Change | 9 | |
Other | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Liability | (19) | (9) |
Change | (10) | |
Current Return | 11 | $ 9 |
Change | $ 2 |
ORGANIZATION AND BASIS OF PRE_6
ORGANIZATION AND BASIS OF PRESENTATION - Reconciliation of Basic and Diluted Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions | 12 Months Ended | |||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | ||
EPS of Common Stock | ||||
Income from continuing operations | $ 1,239 | $ 1,003 | $ 904 | |
Less: Preferred dividends | (3) | |||
Less: Undistributed earnings allocated to preferred shareholders | (1) | |||
Income from continuing operations available to common stockholders | 1,239 | 1,003 | 900 | |
Discontinued operations, net of tax | [1] | 44 | 76 | 8 |
Less: Undistributed earnings allocated to preferred shareholders | 0 | |||
Income from discontinued operations available to common stockholders | 44 | 76 | 8 | |
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS | 1,283 | 1,079 | 908 | |
Income allocated to preferred shareholders, preferred dilutive | 4 | |||
Income attributable to common stockholders, dilutive | $ 1,283 | $ 1,079 | $ 912 | |
Share Count information: | ||||
Weighted average number of basic shares outstanding (in shares) | 545,000 | 542,000 | 535,000 | |
Assumed exercise of dilutive stock options and awards (in shares) | 1,000 | 1,000 | 3,000 | |
Assumed conversion of preferred stock (in shares) | 4,000 | |||
Weighted average number of diluted shares outstanding (in shares) | 546,000 | 543,000 | 542,000 | |
Income attributable to common stockholders, per common share: | ||||
Income from continuing operations, basic (in dollars per share) | $ 2.27 | $ 1.85 | $ 1.69 | |
Discontinued operations, basic (in dollars per share) | 0.08 | 0.14 | 0.01 | |
Basic - Net Income Attributable to Common Stockholders (in dollars per share) | 2.35 | 1.99 | 1.70 | |
Income from continuing operations, diluted (in dollars per share) | 2.27 | 1.85 | 1.67 | |
Discontinued operations, diluted (in dollars per share) | 0.08 | 0.14 | 0.01 | |
Diluted - Net Income Attributable to Common Stockholders (in dollars per share) | $ 2.35 | $ 1.99 | $ 1.68 | |
Antidilutive securities excluded from computation of EPS (in shares) | 0 | 0 | 0 | |
[1] | Net of income tax benefit of $48 million, $59 million, and $5 million in 2021, 2020 and 2019, respectively. |
ORGANIZATION AND BASIS OF PRE_7
ORGANIZATION AND BASIS OF PRESENTATION - Summary of Changes in Goodwill (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Goodwill [Line Items] | ||
Goodwill | $ 5,618 | $ 5,618 |
Regulated Distribution | ||
Goodwill [Line Items] | ||
Goodwill | 5,004 | |
Regulated Transmission | ||
Goodwill [Line Items] | ||
Goodwill | $ 614 |
ORGANIZATION AND BASIS OF PRE_8
ORGANIZATION AND BASIS OF PRESENTATION - Property, Plant and Equipment Balances (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Property, Plant and Equipment | ||
In Service | $ 46,002 | $ 43,726 |
Accum. Depr. | (12,672) | (11,965) |
Net Plant | 33,330 | 31,761 |
CWIP | 1,414 | 1,578 |
Total | 34,744 | 33,339 |
Finance leases | 36 | 45 |
Finance leases | 143 | 153 |
Regulated Distribution | ||
Property, Plant and Equipment | ||
In Service | 31,154 | 29,775 |
Accum. Depr. | (9,284) | (8,800) |
Net Plant | 21,870 | 20,975 |
CWIP | 774 | 841 |
Total | 22,644 | 21,816 |
Regulated Transmission | ||
Property, Plant and Equipment | ||
In Service | 13,744 | 12,912 |
Accum. Depr. | (2,789) | (2,609) |
Net Plant | 10,955 | 10,303 |
CWIP | 580 | 671 |
Total | 11,535 | 10,974 |
Corporate/Other | ||
Property, Plant and Equipment | ||
In Service | 1,104 | 1,039 |
Accum. Depr. | (599) | (556) |
Net Plant | 505 | 483 |
CWIP | 60 | 66 |
Total | $ 565 | $ 549 |
ORGANIZATION AND BASIS OF PRE_9
ORGANIZATION AND BASIS OF PRESENTATION - Receivables from Customers (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Receivables from customers | ||
Customer receivables | $ 1,192 | $ 1,367 |
Less — Allowance for uncollectible customer receivables | 159 | 164 |
Current accounts receivable | 1,033 | 1,203 |
Billed Revenues | ||
Receivables from customers | ||
Customer receivables | 616 | 800 |
Billed Revenues | Financial Asset, Greater than 30 Days Past Due | ||
Receivables from customers | ||
Customer receivables | 318 | 349 |
Unbilled Revenues | ||
Receivables from customers | ||
Customer receivables | $ 576 | $ 567 |
ORGANIZATION AND BASIS OF PR_10
ORGANIZATION AND BASIS OF PRESENTATION - Accounts Receivable (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Feb. 29, 2020 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||||
Deferred for recovery | $ 12 | $ 103 | $ 25 | |
Customer Receivables | ||||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||||
Beginning balance | 164 | 46 | 50 | |
Charged to income | 54 | 174 | 81 | |
Charged to other accounts | 42 | 46 | 47 | |
Write-offs | (101) | (102) | (132) | |
Ending balance | 159 | 164 | 46 | |
Other Receivables | ||||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||||
Beginning balance | 26 | 21 | 2 | |
Charged to income | 3 | 7 | 27 | |
Charged to other accounts | 3 | 10 | 1 | |
Write-offs | (22) | (12) | (9) | |
Ending balance | 10 | 26 | 21 | |
Affiliated companies | ||||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||||
Beginning balance | 0 | 1,063 | 920 | |
Charged to income | 0 | 0 | 143 | |
Charged to other accounts | 0 | 0 | 0 | |
Write-offs | 0 | (1,063) | 0 | |
Ending balance | $ 0 | $ 0 | $ 1,063 | |
Affiliated companies | FES | ||||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||||
Write-offs | $ (1,100) |
REVENUE (Details)
REVENUE (Details) $ in Millions | 12 Months Ended | |||
Dec. 31, 2021USD ($)companyMW | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | ||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | $ 11,112 | $ 10,701 | $ 10,805 | |
Total revenues | [1] | $ 11,132 | 10,790 | 11,035 |
Utility customer payment period | 30 days | |||
Other Non-Customer Revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Late payment charges | $ 36 | 31 | 37 | |
Distribution services | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 5,329 | 5,171 | 5,050 | |
Total revenues | 9,009 | 8,688 | 8,720 | |
Retail generation | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 3,680 | 3,517 | 3,670 | |
Wholesale sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 376 | 260 | 423 | |
Transmission | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 1,608 | 1,613 | 1,510 | |
Total revenues | 1,608 | 1,613 | 1,510 | |
Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 119 | 140 | 152 | |
Total revenues | 515 | 489 | 805 | |
ARP | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | (27) | 43 | 181 | |
Other revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 47 | 46 | 49 | |
Derivative Revenue | Other Non-Customer Revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | $ 11 | 14 | 8 | |
Regulated Distribution | ||||
Disaggregation of Revenue [Line Items] | ||||
Number of existing utility operating companies | company | 10 | |||
Megawatts of net demonstrated capacity of competitive segment (in MW's) | MW | 3,580 | |||
Regulated Distribution | Retail generation | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | $ 9,163 | 8,836 | 8,860 | |
Regulated Distribution | Retail generation | Residential | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 5,713 | 5,539 | 5,412 | |
Regulated Distribution | Retail generation | Commercial | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 2,284 | 2,140 | 2,252 | |
Regulated Distribution | Retail generation | Industrial | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 1,091 | 1,076 | 1,106 | |
Regulated Distribution | Retail generation | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 75 | 81 | 90 | |
Regulated Transmission | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 1,608 | 1,613 | 1,510 | |
Regulated Transmission | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 124 | 134 | 130 | |
Regulated Transmission | ATSI | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 799 | 804 | 754 | |
Regulated Transmission | TrAIL | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 233 | 247 | 242 | |
Regulated Transmission | MAIT | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 288 | 250 | 224 | |
Regulated Transmission | JCP&L | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 164 | 178 | 160 | |
Operating Segments | Regulated Distribution | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 9,644 | 9,227 | 9,421 | |
Total revenues | 9,711 | 9,363 | 9,698 | |
Reduction in revenue | 3 | 2 | 16 | |
Operating Segments | Regulated Distribution | Distribution services | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 5,433 | 5,259 | 5,133 | |
Operating Segments | Regulated Distribution | Distribution services | Ohio Stipulation | ||||
Disaggregation of Revenue [Line Items] | ||||
Rate refunds | 38 | |||
Operating Segments | Regulated Distribution | Retail generation | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 3,730 | 3,577 | 3,727 | |
Operating Segments | Regulated Distribution | Wholesale sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 362 | 251 | 411 | |
Operating Segments | Regulated Distribution | Transmission | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 0 | 0 | 0 | |
Operating Segments | Regulated Distribution | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 119 | 140 | 150 | |
Operating Segments | Regulated Distribution | ARP | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | (27) | 43 | 181 | |
Operating Segments | Regulated Distribution | Other revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 94 | 93 | 96 | |
Operating Segments | Regulated Transmission | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 1,608 | 1,613 | 1,510 | |
Total revenues | 1,618 | 1,630 | 1,526 | |
Reduction in revenue | (2) | 7 | 19 | |
Operating Segments | Regulated Transmission | Distribution services | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 0 | 0 | 0 | |
Operating Segments | Regulated Transmission | Retail generation | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 0 | 0 | 0 | |
Operating Segments | Regulated Transmission | Wholesale sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 0 | 0 | 0 | |
Operating Segments | Regulated Transmission | Transmission | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 1,608 | 1,613 | 1,510 | |
Operating Segments | Regulated Transmission | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 0 | 0 | 0 | |
Operating Segments | Regulated Transmission | ARP | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 0 | 0 | 0 | |
Operating Segments | Regulated Transmission | Other revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 10 | 17 | 16 | |
Corporate/Other and Reconciling Adjustments | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | (140) | (139) | (126) | |
Total revenues | (197) | (203) | (189) | |
Corporate/Other and Reconciling Adjustments | Distribution services | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | (104) | (88) | (83) | |
Corporate/Other and Reconciling Adjustments | Retail generation | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | (50) | (60) | (57) | |
Corporate/Other and Reconciling Adjustments | Wholesale sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 14 | 9 | 12 | |
Corporate/Other and Reconciling Adjustments | Transmission | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 0 | 0 | 0 | |
Corporate/Other and Reconciling Adjustments | Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 0 | 0 | 2 | |
Reconciling Adjustments | ARP | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 0 | 0 | 0 | |
Reconciling Adjustments | Other revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | $ (57) | $ (64) | $ (63) | |
[1] | Includes excise and gross receipts tax collections of $374 million, $362 million and $373 million in 2021, 2020 and 2019, respectively. |
ACCUMULATED OTHER COMPREHENSI_3
ACCUMULATED OTHER COMPREHENSIVE INCOME- Components of AOCI (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
Beginning Balance | $ 7,237 | $ 6,975 | $ 6,814 |
Other comprehensive income before reclassifications | (2) | ||
Amounts reclassified from AOCI | (13) | (33) | (27) |
Other comprehensive loss | (13) | (33) | (29) |
Income tax benefits on other comprehensive loss | (3) | (8) | (8) |
Other comprehensive loss, net of tax | (10) | (25) | (21) |
Ending Balance | 8,675 | 7,237 | 6,975 |
Accumulated Other Comprehensive Income | |||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
Beginning Balance | (5) | 20 | 41 |
Other comprehensive loss, net of tax | (10) | (25) | (21) |
Ending Balance | (15) | (5) | 20 |
Gains & Losses on Cash Flow Hedges | |||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
Beginning Balance | (8) | (9) | (11) |
Other comprehensive income before reclassifications | 0 | ||
Amounts reclassified from AOCI | 1 | 1 | 2 |
Other comprehensive loss | 1 | 1 | 2 |
Income tax benefits on other comprehensive loss | 0 | 0 | 0 |
Other comprehensive loss, net of tax | 1 | 1 | 2 |
Ending Balance | (7) | (8) | (9) |
Defined Benefit Pension & OPEB Plans | |||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
Beginning Balance | 3 | 29 | 52 |
Other comprehensive income before reclassifications | (2) | ||
Amounts reclassified from AOCI | (14) | (34) | (29) |
Other comprehensive loss | (14) | (34) | (31) |
Income tax benefits on other comprehensive loss | (3) | (8) | (8) |
Other comprehensive loss, net of tax | (11) | (26) | (23) |
Ending Balance | $ (8) | $ 3 | $ 29 |
ACCUMULATED OTHER COMPREHENSI_4
ACCUMULATED OTHER COMPREHENSIVE INCOME - Reclassifications (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||
Interest expense | $ (1,141) | $ (1,065) | $ (1,033) |
Income taxes | (320) | (126) | (213) |
Net income (loss) attributable to common stockholders | 1,283 | 1,079 | 908 |
Reclassifications from AOCI | Gains & losses on cash flow hedges | |||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||
Net income (loss) attributable to common stockholders | 1 | 1 | 2 |
Reclassifications from AOCI | Gains & losses on cash flow hedges | Long-term debt | |||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||
Interest expense | 1 | 1 | 2 |
Reclassifications from AOCI | Defined benefit pension and OPEB plans | |||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||
Prior-service costs | (14) | (34) | (29) |
Income taxes | 3 | 8 | 8 |
Net income (loss) attributable to common stockholders | $ (11) | $ (26) | $ (21) |
PENSION AND OTHER POST-EMPLOY_3
PENSION AND OTHER POST-EMPLOYMENT BENEFITS - Narrative (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2020 | Mar. 31, 2020 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Defined Benefit Plan Disclosure [Line Items] | |||||
Mark-to-market adjustment, net of capitalized amounts | $ 54 | $ 423 | $ (382) | $ 477 | $ 676 |
Increase in discount rate | 0.35% | ||||
Pensions and OPEB | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Actual return on plan assets | $ 689 | $ 1,225 | $ 1,492 | ||
Actual return on plan assets (percent) | 7.90% | 14.70% | 20.20% | ||
Expected return on plan assets | $ 688 | $ 651 | $ 569 | ||
Pension | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Expected return on plan assets | 7.50% | 7.50% | 7.50% | ||
Actual return on plan assets | $ 625 | $ 1,165 | |||
Expected return on plan assets | 652 | 618 | $ 540 | ||
Increase in benefit obligation due to RP2014 mortality table | 32 | ||||
Company contributions | $ 24 | $ 24 | |||
OPEB | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Expected return on plan assets | 7.50% | 7.50% | 7.50% | ||
Actual return on plan assets | $ 64 | $ 60 | |||
Expected return on plan assets | 36 | 33 | $ 29 | ||
Increase in benefit obligation due to RP2014 mortality table | 2 | ||||
Company contributions | 24 | 23 | |||
OPEB | Regulated Transmission | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Mark-to-market adjustment, net of capitalized amounts | $ (31) | $ 40 | $ 47 |
PENSION AND OTHER POST-EMPLOY_4
PENSION AND OTHER POST-EMPLOYMENT BENEFITS - Assumptions Used to Determine Net Periodic Benefit Cost (Details) | 2 Months Ended | 10 Months Ended | 12 Months Ended | ||
Feb. 26, 2020 | Dec. 31, 2020 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Pension | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Expected return on plan assets | 7.50% | 7.50% | 7.50% | ||
Rate of compensation increase | 4.10% | 4.10% | 4.10% | ||
Pension | Service Cost | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Weighted-average discount rate | 3.60% | 3.24% | 3.10% | 4.66% | |
Pension | Interest Cost | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Weighted-average discount rate | 3.27% | 2.90% | 2.58% | 4.37% | |
OPEB | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Expected return on plan assets | 7.50% | 7.50% | 7.50% | ||
OPEB | Service Cost | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Weighted-average discount rate | 3.63% | 3.29% | 3.03% | 4.67% | |
OPEB | Interest Cost | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Weighted-average discount rate | 2.71% | 2.30% | 1.66% | 3.89% |
PENSION AND OTHER POST-EMPLOY_5
PENSION AND OTHER POST-EMPLOYMENT BENEFITS - Components of Net Periodic Benefit Costs (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2020 | Mar. 31, 2020 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Mark-to-market adjustment, net of capitalized amounts | $ 54 | $ 423 | $ (382) | $ 477 | $ 676 |
Discontinued Operations | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Mark-to-market adjustment, net of capitalized amounts | 2 | ||||
Pension | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Service cost | 195 | 194 | 193 | ||
Interest cost | 226 | 287 | 373 | ||
Expected return on plan assets | (652) | (618) | (540) | ||
Amortization of prior service costs (credits) | 3 | 12 | 7 | ||
Special termination costs | 0 | 0 | 14 | ||
One-time termination benefits | 0 | 8 | 0 | ||
Pension & OPEB mark-to-market Adjustment | (253) | 463 | 656 | ||
Net periodic benefit costs (credits) | (481) | 346 | 703 | ||
Net accelerated credits | $ 18 | ||||
OPEB | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Service cost | 4 | 4 | 3 | ||
Interest cost | 11 | 15 | 22 | ||
Expected return on plan assets | (36) | (33) | (29) | ||
Amortization of prior service costs (credits) | (17) | (46) | (36) | ||
Special termination costs | 0 | 0 | 0 | ||
One-time termination benefits | 0 | 0 | 0 | ||
Pension & OPEB mark-to-market Adjustment | (129) | 14 | 20 | ||
Net periodic benefit costs (credits) | $ (167) | $ (46) | $ (20) |
PENSION AND OTHER POST-EMPLOY_6
PENSION AND OTHER POST-EMPLOYMENT BENEFITS - Obligations and Funded Status (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Pension | |||
Change in benefit obligation: | |||
Benefit obligation as of January 1 | $ 11,935 | $ 11,050 | |
Service cost | 195 | 194 | $ 193 |
Interest cost | 226 | 287 | 373 |
Plan participants’ contributions | 0 | 0 | |
Plan amendments | 0 | 9 | |
Medicare retiree drug subsidy | 0 | 0 | |
Actuarial loss (gain) | (280) | 1,011 | |
Benefits paid | (597) | (616) | |
Benefit obligation as of December 31 | 11,479 | 11,935 | 11,050 |
Change in fair value of plan assets: | |||
Fair value of plan assets as of January 1 | 8,968 | 8,395 | |
Actual return on plan assets | 625 | 1,165 | |
Company contributions | 24 | 24 | |
Plan participants’ contributions | 0 | 0 | |
Benefits paid | (597) | (616) | |
Fair value of plan assets as of December 31 | 9,020 | 8,968 | 8,395 |
Funded Status: | |||
Funded Status (Net liability as of December 31) | (2,459) | (2,967) | |
Accumulated benefit obligation | 10,927 | 11,376 | |
Amounts Recognized in AOCI: | |||
Prior service cost (credit) | $ 9 | $ 12 | |
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | |||
Discount rate | 3.02% | 2.67% | |
Rate of compensation increase | 4.10% | 4.10% | |
Cash balance weighted average interest crediting rate | 2.57% | 2.57% | |
Pension | Qualified plan | |||
Funded Status: | |||
Funded Status (Net liability as of December 31) | $ (1,974) | $ (2,500) | |
Pension | Non-qualified plans | |||
Funded Status: | |||
Funded Status (Net liability as of December 31) | (485) | (467) | |
OPEB | |||
Change in benefit obligation: | |||
Benefit obligation as of January 1 | 676 | 654 | |
Service cost | 4 | 4 | 3 |
Interest cost | 11 | 15 | 22 |
Plan participants’ contributions | 4 | 4 | |
Plan amendments | 0 | 0 | |
Medicare retiree drug subsidy | 1 | 1 | |
Actuarial loss (gain) | (101) | 41 | |
Benefits paid | (46) | (43) | |
Benefit obligation as of December 31 | 549 | 676 | 654 |
Change in fair value of plan assets: | |||
Fair value of plan assets as of January 1 | 502 | 458 | |
Actual return on plan assets | 64 | 60 | |
Company contributions | 24 | 23 | |
Plan participants’ contributions | 4 | 4 | |
Benefits paid | (46) | (43) | |
Fair value of plan assets as of December 31 | 548 | 502 | $ 458 |
Funded Status: | |||
Funded Status (Net liability as of December 31) | (1) | (174) | |
Accumulated benefit obligation | 0 | 0 | |
Amounts Recognized in AOCI: | |||
Prior service cost (credit) | $ (21) | $ (39) | |
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | |||
Discount rate | 2.84% | 2.45% | |
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) | 4.50% | 4.50% | |
OPEB | Pre Medicare | |||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | |||
Health care cost trend rate assumed (pre/post-Medicare) | 5.75% | 6.00% | |
OPEB | Post Medicare | |||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | |||
Health care cost trend rate assumed (pre/post-Medicare) | 5.25% | 5.50% | |
OPEB | Qualified plan | |||
Funded Status: | |||
Funded Status (Net liability as of December 31) | $ 0 | $ 0 | |
OPEB | Non-qualified plans | |||
Funded Status: | |||
Funded Status (Net liability as of December 31) | $ 0 | $ 0 |
PENSION AND OTHER POST-EMPLOY_7
PENSION AND OTHER POST-EMPLOYMENT BENEFITS - Pension Investments Measured at Fair Value (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Pension | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 9,067 | $ 8,852 |
Asset Allocation | 100.00% | 100.00% |
Excluded from total investments | $ (47) | $ 116 |
Pension | Investments Excluding in Investments at NAV | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 6,372 | $ 6,604 |
Asset Allocation | 70.00% | 75.00% |
Pension | Cash and short-term securities | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 746 | $ 1,493 |
Asset Allocation | 8.00% | 17.00% |
Pension | Public equity | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 3,153 | $ 2,065 |
Asset Allocation | 35.00% | 23.00% |
Pension | Fixed income | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 2,453 | $ 3,059 |
Asset Allocation | 27.00% | 35.00% |
Pension | Derivatives | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 20 | $ (13) |
Asset Allocation | 0.00% | 0.00% |
Pension | Private equity and debt funds | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 811 | $ 465 |
Asset Allocation | 9.00% | 5.00% |
Pension | Insurance-linked securities | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 320 | $ 323 |
Asset Allocation | 4.00% | 4.00% |
Pension | Hedge funds | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 678 | $ 645 |
Asset Allocation | 7.00% | 7.00% |
Pension | Real estate funds | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 886 | $ 815 |
Asset Allocation | 10.00% | 9.00% |
Pension | Level 1 | Investments Excluding in Investments at NAV | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 2,887 | $ 1,890 |
Pension | Level 1 | Cash and short-term securities | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
Pension | Level 1 | Public equity | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 2,867 | 1,903 |
Pension | Level 1 | Fixed income | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
Pension | Level 1 | Derivatives | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 20 | (13) |
Pension | Level 2 | Investments Excluding in Investments at NAV | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 3,485 | 4,714 |
Pension | Level 2 | Cash and short-term securities | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 746 | 1,493 |
Pension | Level 2 | Public equity | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 286 | 162 |
Pension | Level 2 | Fixed income | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 2,453 | 3,059 |
Pension | Level 2 | Derivatives | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
Pension | Level 3 | Investments Excluding in Investments at NAV | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
Pension | Level 3 | Cash and short-term securities | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
Pension | Level 3 | Public equity | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
Pension | Level 3 | Fixed income | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
Pension | Level 3 | Derivatives | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
OPEB | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 548 | $ 512 |
Asset Allocation | 100.00% | 100.00% |
Excluded from total investments | $ (10) | |
OPEB | Cash and short-term securities | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 95 | $ 84 |
Asset Allocation | 17.00% | 17.00% |
OPEB | Public equity | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 278 | $ 283 |
Asset Allocation | 51.00% | 55.00% |
OPEB | Fixed income | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 175 | $ 145 |
Asset Allocation | 32.00% | 28.00% |
OPEB | Level 1 | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 278 | $ 283 |
OPEB | Level 1 | Cash and short-term securities | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
OPEB | Level 1 | Public equity | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 278 | 283 |
OPEB | Level 1 | Fixed income | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
OPEB | Level 2 | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 270 | 229 |
OPEB | Level 2 | Cash and short-term securities | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 95 | 84 |
OPEB | Level 2 | Public equity | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
OPEB | Level 2 | Fixed income | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 175 | 145 |
OPEB | Level 3 | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
OPEB | Level 3 | Cash and short-term securities | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
OPEB | Level 3 | Public equity | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
OPEB | Level 3 | Fixed income | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 0 | $ 0 |
PENSION AND OTHER POST-EMPLOY_8
PENSION AND OTHER POST-EMPLOYMENT BENEFITS - Target Asset Allocations for Pension and OPEB Portfolio (Details) | Dec. 31, 2021 | Dec. 31, 2020 |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Target Asset Allocations | 100.00% | 100.00% |
Equities | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Target Asset Allocations | 38.00% | 38.00% |
Fixed income | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Target Asset Allocations | 30.00% | 30.00% |
Hedge funds | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Target Asset Allocations | 8.00% | 8.00% |
Real estate | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Target Asset Allocations | 10.00% | 10.00% |
Alternative investments | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Target Asset Allocations | 8.00% | 8.00% |
Cash and short-term securities | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Target Asset Allocations | 6.00% | 6.00% |
PENSION AND OTHER POST-EMPLOY_9
PENSION AND OTHER POST-EMPLOYMENT BENEFITS - Estimated Future Benefit Payments (Details) $ in Millions | Dec. 31, 2021USD ($) |
Pension | |
Estimated Future Benefit Payments | |
2022 | $ 566 |
2023 | 575 |
2024 | 581 |
2025 | 590 |
2026 | 598 |
Years 2027-2030 | 3,075 |
OPEB | |
Estimated Future Benefit Payments | |
2022 | 44 |
2023 | 41 |
2024 | 39 |
2025 | 38 |
2026 | 37 |
Years 2027-2030 | 164 |
Subsidy Receipts | |
2022 | (1) |
2023 | (1) |
2024 | (1) |
2025 | 0 |
2026 | 0 |
Years 2027-2030 | $ (2) |
STOCK-BASED COMPENSATION PLAN_2
STOCK-BASED COMPENSATION PLANS - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Realized tax benefits | $ 10 | $ 20 | $ 24 |
Tax benefit associated with stock-based compensation expense | 5 | 3 | 10 |
Cash portion of RSU paid | 11 | ||
Fair value of restricted stock units vested | 34 | 80 | $ 91 |
DCPD | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Net liability recognized | $ 9 | $ 7 | |
Restricted Stock Units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unrecognized cost, period for recognition | 3 years | 3 years | 3 years |
Granted (in dollars per share) | $ 35.50 | $ 44.42 | $ 41,230,000 |
Unrecognized cost | $ 29 | ||
Performance-based Restricted Stock Units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Award paid in stock (percent) | 66.67% | ||
Award paid in cash (percent) | 33.33% | ||
Liability recognized | $ 24 | ||
Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation award vesting period | 2 years | ||
Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation award vesting period | 10 years | ||
ICP 2020 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Maximum limit of total stock awards (in shares) | 10,000,000 | ||
Stock-based compensation award number of shares available for future | 12,700,000 | ||
ICP 2015 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Maximum limit of total stock awards (in shares) | 10,000,000 | ||
Stock-based compensation award number of shares available for future | 0 | ||
401(k) Savings Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares authorized for issuance | 1,000,000 | 1,000,000 |
STOCK-BASED COMPENSATION PLAN_3
STOCK-BASED COMPENSATION PLANS - Schedule of Stock-Based Compensation Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | $ 90 | $ 51 | $ 116 |
Stock-based compensation costs capitalized | 47 | 26 | 54 |
Incentive Plans | Restricted Stock Units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | 40 | 22 | 73 |
Incentive Plans | Restricted Stock | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | 2 | 1 | 1 |
401(k) Savings Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | 35 | 33 | 33 |
EDCP & DCPD | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | $ 13 | $ (5) | $ 9 |
STOCK-BASED COMPENSATION PLAN_4
STOCK-BASED COMPENSATION PLANS - Schedule of Nonvested Restricted Stock Units Activity (Details) - $ / shares shares in Thousands | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Weighted-Average Grant Date Fair Value (per share) | |||
Dividend shares earned during period, number of shares | 130 | ||
Restricted Stock Units | |||
Shares (in millions) | |||
Nonvested, beginning balance (shares) | 1,800 | ||
Granted (shares) | 1,300 | ||
Forfeited (shares) | (300) | ||
Vested (shares) | (1,000) | ||
Nonvested, ending balance (shares) | 1,800 | 1,800 | |
Weighted-Average Grant Date Fair Value (per share) | |||
Beginning balance (in dollars per share) | $ 40.25 | ||
Granted (in dollars per share) | 35.50 | $ 44.42 | $ 41,230,000 |
Forfeited (in dollars per share) | 40.08 | ||
Vested (in dollars per share) | 33.73 | ||
Ending balance (in dollars per share) | $ 41.89 | $ 40.25 |
TAXES - Narrative (Details)
TAXES - Narrative (Details) - USD ($) $ in Millions | Feb. 27, 2020 | Jun. 30, 2021 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Income Taxes (Textuals) [Abstract] | ||||||
Excess deferred tax amortization due to the Tax Act | $ (54) | $ (56) | $ (74) | |||
Effective income tax rate (percent) | 20.50% | 11.20% | 19.10% | |||
Nondeductible DPA monetary penalty | $ 52 | $ 0 | $ 0 | |||
Decrease in amortization benefit | 10 | |||||
TMI-2 reversal of tax regulatory liabilities | 0 | 40 | 0 | |||
Unrecognized tax benefits from worthless stock deduction | $ 316 | 81 | ||||
Federal tax credits claimed | 34 | 0 | 0 | |||
Operating loss carryforwards, subject to expiration | 6,900 | |||||
Operating loss carryforwards, subject to expiration, net of tax | 1,500 | |||||
Operating loss carryforwards, not subject to expiration | 11,900 | |||||
Operating loss carryforwards, not subject to expiration, net of tax | 544 | |||||
Pre-tax net operating loss carryforwards expected to utilized | 2,700 | |||||
Operating loss carryforwards expected to utilized, net of tax | 136 | |||||
Unrecognized tax benefits | 47 | 139 | 164 | $ 158 | ||
Decrease in unrecognized tax benefits | 92 | |||||
Decrease resulting from change in worthless stock deduction | 68 | |||||
Decrease resulting from nondeductible interest | 29 | |||||
Decreases resulting from prior positions | 8 | 28 | 12 | |||
Decrease from tax rate changes | 1 | |||||
Decrease for lapse in statute | 2 | $ 2 | $ 4 | |||
Increase resulting related to federal positions | 15 | |||||
Unrecognized tax benefits that would impact future tax rates | 39 | |||||
Unrecognized tax benefits, portion expected to be resolved in the next fiscal year | 31 | |||||
Unrecognized tax benefits that would impact effective tax rate | 24 | |||||
West Virginia | ||||||
Income Taxes (Textuals) [Abstract] | ||||||
Decreases resulting from prior positions | 7 | |||||
State and Local | West Virginia | ||||||
Income Taxes (Textuals) [Abstract] | ||||||
Excess deferred tax amortization due to the Tax Act | $ 9 | 9 | ||||
FES | ||||||
Income Taxes (Textuals) [Abstract] | ||||||
Nondeductible DPA monetary penalty | $ 52 |
TAXES - Provision for Income Ta
TAXES - Provision for Income Taxes (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Currently payable (receivable)- | |||
Federal | $ 2 | $ (14) | $ (16) |
State | 21 | 21 | 24 |
Currently payable (receivable) Total | 23 | 7 | 8 |
Deferred, net- | |||
Federal | 174 | 171 | 150 |
State | 127 | (38) | 60 |
Deferred Tax Total | 301 | 133 | 210 |
Investment tax credit amortization | (4) | (14) | (5) |
Total income taxes | 320 | 126 | 213 |
Federal | |||
Deferred, net- | |||
Income tax expense (benefit), continuing operations, discontinued operations | 2 | 6 | |
Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC | Federal | |||
Deferred, net- | |||
Federal | $ 46 | 66 | 9 |
Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC | State and Local | |||
Deferred, net- | |||
Federal | $ 1 | $ 4 |
TAXES - Reconciliation of Feder
TAXES - Reconciliation of Federal Income Tax Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Reconciliation of federal income tax expense at the federal statutory rate to the total provision for income taxes | |||
Income from Continuing Operations, before income taxes | $ 1,559 | $ 1,129 | $ 1,117 |
Federal income tax expense at statutory rate (21%) | 327 | 237 | 235 |
Increases (reductions) in taxes resulting from- | |||
State income taxes, net of federal tax benefit | 122 | 75 | 96 |
AFUDC equity and other flow-through | (29) | (38) | (36) |
Amortization of investment tax credits | (4) | (14) | (5) |
Federal tax credits claimed | (34) | 0 | 0 |
Nondeductible DPA monetary penalty | 52 | 0 | 0 |
Excess deferred tax amortization due to the Tax Act | (54) | (56) | (74) |
TMI-2 reversal of tax regulatory liabilities | 0 | (40) | 0 |
Uncertain tax positions | 82 | 1 | 11 |
Valuation allowances | 17 | (49) | 5 |
Other, net | 5 | 12 | 3 |
Total income taxes | $ 320 | $ 126 | $ 213 |
Effective income tax rate (percent) | 20.50% | 11.20% | 19.10% |
TAXES - Accumulated Deferred In
TAXES - Accumulated Deferred Income Taxes (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Accumulated deferred income taxes | ||||
Property basis differences | $ 5,670 | $ 5,396 | ||
Pension and OPEB | (570) | (769) | ||
AROs | (21) | (28) | ||
Regulatory asset/liability | 322 | 440 | ||
Deferred compensation | (155) | (165) | ||
Loss carryforwards and tax credits | (2,040) | (1,995) | ||
Valuation reserve | 484 | 496 | $ 441 | $ 394 |
All other | (253) | (280) | ||
Net deferred income tax liability | $ 3,437 | $ 3,095 |
TAXES - Pre-tax Net Operating L
TAXES - Pre-tax Net Operating Loss Expiration Period (Details) $ in Millions | Dec. 31, 2021USD ($) |
State | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | $ 8,101 |
State | 2022-2026 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 2,603 |
State | 2027-2031 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 1,390 |
State | 2032-2036 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 992 |
State | 2037-2041 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 959 |
State | Indefinite | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 2,157 |
Local | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 3,783 |
Local | 2022-2026 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 3,783 |
Local | 2027-2031 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 0 |
Local | 2032-2036 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 0 |
Local | 2037-2041 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 0 |
Local | Indefinite | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | $ 0 |
TAXES - Changes in Valuation Al
TAXES - Changes in Valuation Allowances (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Loss Carry Forward Valuation Reserve | |||
Beginning of year balance | $ 496 | $ 441 | $ 394 |
Charged to income | (12) | 55 | 47 |
Charged to other accounts | 0 | 0 | 0 |
Write-offs | 0 | 0 | 0 |
End of year balance | $ 484 | $ 496 | $ 441 |
TAXES - Changes in Unrecognized
TAXES - Changes in Unrecognized Tax Benefits (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Changes in unrecognized tax benefits | |||
Beginning balance | $ 139 | $ 164 | $ 158 |
Current year increases | 15 | 7 | 22 |
Prior year decreases | (8) | (28) | (12) |
Decrease for lapse in statute | (2) | (2) | (4) |
Decrease for lapse in statute | (97) | (2) | |
Ending balance | $ 47 | $ 139 | $ 164 |
TAXES - Details of General Taxe
TAXES - Details of General Taxes (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
General Taxes | |||
KWH excise | $ 189 | $ 183 | $ 191 |
State gross receipts | 190 | 182 | 185 |
Real and personal property | 571 | 541 | 504 |
Social security and unemployment | 103 | 112 | 100 |
Other | 20 | 28 | 28 |
Total general taxes | $ 1,073 | $ 1,046 | $ 1,008 |
LEASES -Narrative (Details)
LEASES -Narrative (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2021USD ($) | |
Lessor, Lease, Description [Line Items] | |
Amount of leases not yet commenced | $ 5 |
Expected commencement period | 18 months |
Minimum | |
Lessor, Lease, Description [Line Items] | |
Renewal term of lease yet to be commenced | 1 year |
Operating lease renewal term | 2 years |
Maximum | |
Lessor, Lease, Description [Line Items] | |
Renewal term of lease yet to be commenced | 40 years |
Operating lease renewal term | 10 years |
LEASES - Components of Lease Ex
LEASES - Components of Lease Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Lessee, Lease, Description [Line Items] | |||
Operating lease costs | $ 71 | $ 60 | $ 49 |
Amortization of right-of-use assets | 14 | 15 | 17 |
Interest on lease liabilities | 4 | 5 | 6 |
Total finance lease cost | 18 | 20 | 23 |
Total lease cost | 89 | 80 | 72 |
Short-term lease costs | 21 | 17 | 13 |
Cash paid for amounts included in the measurement of lease liabilities: | |||
Operating cash flows from operating leases | 64 | 44 | 29 |
Operating cash flows from finance leases | 4 | 4 | 5 |
Finance cash flows from finance leases | 13 | 15 | 25 |
Right-of-use assets obtained in exchange for lease obligations: | |||
Operating leases | 60 | 67 | 83 |
Finance leases | 5 | 0 | 3 |
Vehicles | |||
Lessee, Lease, Description [Line Items] | |||
Operating lease costs | 44 | 35 | 28 |
Amortization of right-of-use assets | 12 | 14 | 15 |
Interest on lease liabilities | 1 | 2 | 3 |
Total finance lease cost | 13 | 16 | 18 |
Total lease cost | 57 | 51 | 46 |
Buildings | |||
Lessee, Lease, Description [Line Items] | |||
Operating lease costs | 9 | 8 | 9 |
Amortization of right-of-use assets | 1 | 0 | 1 |
Interest on lease liabilities | 3 | 3 | 3 |
Total finance lease cost | 4 | 3 | 4 |
Total lease cost | 13 | 11 | 13 |
Other | |||
Lessee, Lease, Description [Line Items] | |||
Operating lease costs | 18 | 17 | 12 |
Amortization of right-of-use assets | 1 | 1 | 1 |
Interest on lease liabilities | 0 | 0 | 0 |
Total finance lease cost | 1 | 1 | 1 |
Total lease cost | $ 19 | $ 18 | $ 13 |
LEASES - Assets and Liabilities
LEASES - Assets and Liabilities, Lessee (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Weighted-average remaining lease terms (years) | |||
Operating leases | 7 years 11 months 19 days | 8 years 6 months 18 days | 9 years 5 months 1 day |
Finance leases | 8 years 1 month 13 days | 7 years 8 months 26 days | 4 years 7 months 13 days |
Weighted-average discount rate | |||
Operating leases | 4.16% | 4.21% | 4.51% |
Finance leases | 12.22% | 11.58% | 10.45% |
Assets | |||
Operating lease | $ 279 | $ 265 | |
Finance lease | 48 | 57 | |
Total leased assets | 327 | 322 | |
Current: | |||
Operating | 39 | 42 | |
Finance | 13 | 14 | |
Noncurrent: | |||
Operating | 271 | 263 | |
Finance lease obligations | 23 | 31 | |
Total leased liabilities | 346 | 350 | |
Operating lease assets, accumulated amortization | 79 | 51 | |
Financing lease, accumulated amortization | $ 95 | $ 96 | |
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List] | Other Assets, Noncurrent | Other Assets, Noncurrent | |
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] | Property, plant and equipment | Property, plant and equipment | |
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List] | Other Liabilities, Current | Other Liabilities, Current | |
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration] | Long-term Debt and Lease Obligation, Current | Long-term Debt and Lease Obligation, Current | |
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List] | Other Liabilities, Noncurrent | Other Liabilities, Noncurrent | |
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration] | Total long-term debt and other long-term obligations | Total long-term debt and other long-term obligations | |
Operating cash flows from operating leases | $ 64 | $ 44 | $ 29 |
Operating cash flows from finance leases | 4 | 4 | 5 |
Finance cash flows from finance leases | 13 | 15 | 25 |
Operating leases | 60 | 67 | 83 |
Finance leases | $ 5 | $ 0 | $ 3 |
LEASES - Maturity of Operating
LEASES - Maturity of Operating and Finance Lease Liabilities (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Operating Leases | ||
2022 | $ 54 | |
2023 | 54 | |
2024 | 48 | |
2025 | 45 | |
2026 | 41 | |
Thereafter | 133 | |
Total lease payments | 375 | |
Less imputed interest | 65 | |
Total net present value | 310 | |
Finance Leases | ||
2022 | 16 | |
2023 | 9 | |
2024 | 5 | |
2025 | 5 | |
2026 | 5 | |
Thereafter | 8 | |
Total lease payments | 48 | |
Less imputed interest | 12 | |
Finance leases | 36 | $ 45 |
Total | ||
2022 | 70 | |
2023 | 63 | |
2024 | 53 | |
2025 | 50 | |
2026 | 46 | |
Thereafter | 141 | |
Total lease payments | 423 | |
Less imputed interest | 77 | |
Total net present value | 346 | |
Sublease income | $ 10 | |
Sublease income term | 11 years |
FAIR VALUE MEASUREMENTS - Narra
FAIR VALUE MEASUREMENTS - Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments not required to be disclosed | $ 371 | $ 322 |
NUG contracts | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Period of future observable data to determine contract price | 2 years |
FAIR VALUE MEASUREMENTS - Recur
FAIR VALUE MEASUREMENTS - Recurring Assets and Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Liabilities | ||
Restricted cash | $ 49 | $ 67 |
Investment excludes receivables, payables and accrued income | 1 | |
Recurring | ||
Assets | ||
Fair value, assets | 1,837 | 2,123 |
Liabilities | ||
Fair value, liabilities | (1) | 0 |
Net assets (liabilities) | 1,836 | 2,123 |
Recurring | FTRs | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | (1) | 0 |
Recurring | FTRs | Derivative Assets | ||
Assets | ||
Fair value, assets | 9 | 3 |
Recurring | Equity securities | ||
Assets | ||
Fair value, assets | 2 | 2 |
Recurring | Cash, cash equivalents and restricted cash | ||
Assets | ||
Fair value, assets | 1,511 | 1,801 |
Recurring | U.S. state debt securities | ||
Assets | ||
Fair value, assets | 273 | 276 |
Recurring | Other | ||
Assets | ||
Fair value, assets | 42 | 41 |
Recurring | Level 1 | ||
Assets | ||
Fair value, assets | 1,513 | 1,803 |
Liabilities | ||
Fair value, liabilities | 0 | 0 |
Net assets (liabilities) | 1,513 | 1,803 |
Recurring | Level 1 | FTRs | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | 0 | 0 |
Recurring | Level 1 | FTRs | Derivative Assets | ||
Assets | ||
Fair value, assets | 0 | 0 |
Recurring | Level 1 | Equity securities | ||
Assets | ||
Fair value, assets | 2 | 2 |
Recurring | Level 1 | Cash, cash equivalents and restricted cash | ||
Assets | ||
Fair value, assets | 1,511 | 1,801 |
Recurring | Level 1 | U.S. state debt securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Recurring | Level 1 | Other | ||
Assets | ||
Fair value, assets | 0 | 0 |
Recurring | Level 2 | ||
Assets | ||
Fair value, assets | 315 | 317 |
Liabilities | ||
Fair value, liabilities | 0 | 0 |
Net assets (liabilities) | 315 | 317 |
Recurring | Level 2 | FTRs | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | 0 | 0 |
Recurring | Level 2 | FTRs | Derivative Assets | ||
Assets | ||
Fair value, assets | 0 | 0 |
Recurring | Level 2 | Equity securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Recurring | Level 2 | Cash, cash equivalents and restricted cash | ||
Assets | ||
Fair value, assets | 0 | 0 |
Recurring | Level 2 | U.S. state debt securities | ||
Assets | ||
Fair value, assets | 273 | 276 |
Recurring | Level 2 | Other | ||
Assets | ||
Fair value, assets | 42 | 41 |
Recurring | Level 3 | ||
Assets | ||
Fair value, assets | 9 | 3 |
Liabilities | ||
Fair value, liabilities | (1) | 0 |
Net assets (liabilities) | 8 | 3 |
Recurring | Level 3 | FTRs | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | (1) | 0 |
Recurring | Level 3 | FTRs | Derivative Assets | ||
Assets | ||
Fair value, assets | 9 | 3 |
Recurring | Level 3 | Equity securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Recurring | Level 3 | Cash, cash equivalents and restricted cash | ||
Assets | ||
Fair value, assets | 0 | 0 |
Recurring | Level 3 | U.S. state debt securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Recurring | Level 3 | Other | ||
Assets | ||
Fair value, assets | $ 0 | $ 0 |
FAIR VALUE MEASUREMENTS - Level
FAIR VALUE MEASUREMENTS - Level 3 Rollforward (Details) - Level 3 - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
NUG contracts | ||
Reconciliation of changes in the fair value of NUG contracts | ||
Beginning Balance, Derivative Assets | $ 0 | $ 0 |
Beginning Balance, Derivative Liabilities | 0 | (16) |
Beginning Balance, Net | 0 | (16) |
Unrealized gain (loss), Derivative Assets | 0 | 0 |
Unrealized gain (loss), Derivative Liabilities | 0 | (3) |
Unrealized gain (loss), Net | 0 | (3) |
Purchases, Derivative Assets | 0 | 0 |
Purchases, Derivative Liabilities | 0 | 0 |
Purchases, Net | 0 | 0 |
Settlements, Derivative Assets | 0 | 0 |
Settlements, Derivative Liabilities | 0 | 19 |
Settlements, Net | 0 | 19 |
Ending Balance, Derivative Assets | 0 | 0 |
Ending Balance, Derivative Liabilities | 0 | 0 |
Ending Balance, Net | 0 | 0 |
FTRs | ||
Reconciliation of changes in the fair value of NUG contracts | ||
Beginning Balance, Derivative Assets | 3 | 4 |
Beginning Balance, Derivative Liabilities | 0 | (1) |
Beginning Balance, Net | 3 | 3 |
Unrealized gain (loss), Derivative Assets | 7 | (3) |
Unrealized gain (loss), Derivative Liabilities | 0 | 0 |
Unrealized gain (loss), Net | 7 | (3) |
Purchases, Derivative Assets | 5 | 7 |
Purchases, Derivative Liabilities | (2) | (2) |
Purchases, Net | 3 | 5 |
Settlements, Derivative Assets | (6) | (5) |
Settlements, Derivative Liabilities | 1 | 3 |
Settlements, Net | (5) | (2) |
Ending Balance, Derivative Assets | 9 | 3 |
Ending Balance, Derivative Liabilities | (1) | 0 |
Ending Balance, Net | $ 8 | $ 3 |
FAIR VALUE MEASUREMENTS - Lev_2
FAIR VALUE MEASUREMENTS - Level 3 Quantitative Information (Details) - Level 3 - FTRs $ in Millions | 12 Months Ended | ||
Dec. 31, 2021USD ($)$ / MWh | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | |
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value | $ | $ 8 | $ 3 | $ 3 |
Model | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value | $ | $ 8 | ||
Model | Minimum | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH) | 1,100,000 | ||
Model | Maximum | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH) | 4,600,000 | ||
Model | Weighted Average | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH) | 1,800,000 |
FAIR VALUE MEASUREMENTS - Inves
FAIR VALUE MEASUREMENTS - Investments Held in Trusts (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Debt Securities, Available-for-sale [Abstract] | ||
Short-term cash investments | $ 11 | $ 9 |
Debt Securities | ||
Debt Securities, Available-for-sale [Abstract] | ||
Cost Basis | 280 | 275 |
Unrealized Gains | 2 | 7 |
Unrealized Losses | (9) | (6) |
Fair Value | $ 273 | $ 276 |
FAIR VALUE MEASUREMENTS - Proce
FAIR VALUE MEASUREMENTS - Proceeds from the Sale of Investments (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Fair Value Disclosures [Abstract] | |||
Sale Proceeds | $ 48 | $ 186 | $ 1,637 |
Realized Gains | 0 | 12 | 98 |
Realized Losses | (3) | (8) | (31) |
Interest and Dividend Income | $ 11 | $ 22 | $ 38 |
FAIR VALUE MEASUREMENTS - Carry
FAIR VALUE MEASUREMENTS - Carrying Amounts of Long-term Debt (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Carrying Value | ||
Fair value and related carrying amounts of long-term debt and other long-term obligations | ||
Long-term debt and other long-term obligations | $ 23,946 | $ 22,377 |
Fair Value | ||
Fair value and related carrying amounts of long-term debt and other long-term obligations | ||
Long-term debt and other long-term obligations | $ 27,043 | $ 25,465 |
CAPITALIZATION - Narrative (Det
CAPITALIZATION - Narrative (Details) | Jan. 27, 2022USD ($) | Jan. 20, 2022USD ($) | Dec. 21, 2021$ / shares | Nov. 06, 2021USD ($)$ / sharesshares | Dec. 31, 2021USD ($)$ / sharesshares | Dec. 31, 2021USD ($)$ / sharesshares | Sep. 30, 2021$ / shares | Jun. 30, 2021$ / shares | Mar. 31, 2021$ / shares | Dec. 31, 2020USD ($)$ / sharesshares | Sep. 30, 2020$ / shares | Jun. 30, 2020$ / shares | Mar. 31, 2020$ / shares | Dec. 31, 2021USD ($)subsidiary$ / sharesshares | Dec. 31, 2020USD ($)$ / sharesshares | Dec. 31, 2019USD ($)$ / sharesshares | Dec. 31, 2018shares | Jan. 31, 2018USD ($)$ / sharesshares | Jun. 30, 2013USD ($) |
Debt Instrument [Line Items] | |||||||||||||||||||
Retained earnings (accumulated deficit) | $ (1,605,000,000) | $ (1,605,000,000) | $ (2,888,000,000) | $ (1,605,000,000) | $ (2,888,000,000) | ||||||||||||||
Dividends declared (in dollars per share) | $ / shares | $ 0.39 | $ 1.56 | $ 1.56 | $ 1.53 | |||||||||||||||
Common stock dividends per share paid, in dollars per share | $ / shares | $ 0.39 | $ 0.39 | $ 0.39 | $ 0.39 | $ 0.39 | $ 0.39 | $ 0.39 | $ 0.39 | |||||||||||
FERC-defined equity to total capitalization ratio | 35.00% | ||||||||||||||||||
Common stock, par value (in dollars per share) | $ / shares | $ 0.10 | $ 0.10 | $ 0.10 | $ 0.10 | $ 0.10 | ||||||||||||||
Preferred shares, outstanding (in shares) | shares | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Preference shares outstanding (in shares) | shares | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Preferred stock, par value (in dollars per share) | $ / shares | $ 100 | $ 100 | $ 100 | ||||||||||||||||
Repayments of debt | $ 532,000,000 | $ 1,114,000,000 | $ 789,000,000 | ||||||||||||||||
Number of subsidiaries that issued environmental control bonds | subsidiary | 2 | ||||||||||||||||||
Environmental control bonds outstanding | $ 274,000,000 | $ 274,000,000 | $ 300,000,000 | $ 274,000,000 | $ 300,000,000 | ||||||||||||||
Principal default amount specified in debt covenants | $ 100,000,000 | ||||||||||||||||||
Series A Convertible Preferred Stock | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Preferred stock shares issued (in shares) | shares | 1,616,000 | ||||||||||||||||||
Preferred stock, par value (in dollars per share) | $ / shares | $ 100 | ||||||||||||||||||
Amount of preferred stock investment | $ 1,620,000,000 | ||||||||||||||||||
Common Stock Purchase Agreement | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Number of shares issued in transaction | shares | 25,588,535 | ||||||||||||||||||
Common stock, par value (in dollars per share) | $ / shares | $ 0.10 | ||||||||||||||||||
Sale of stock, price per share (in dollars per share) | $ / shares | $ 39.08 | ||||||||||||||||||
Investment amount | $ 1,000,000,000 | ||||||||||||||||||
Transaction costs | 26,000,000 | ||||||||||||||||||
Registered Shareholders, Directors and Employees of Subsidiaries | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Share-based benefit plans (in shares) | shares | 1,000,000 | 2,000,000 | 3,000,000 | ||||||||||||||||
Phase In Recovery Bonds | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Long-term debt and other long-term obligations | 222,000,000 | 222,000,000 | $ 245,000,000 | $ 222,000,000 | $ 245,000,000 | ||||||||||||||
Senior Notes | 4.25% Series B Senior Notes Due 2023 | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Face amount of loan | 850,000,000 | 850,000,000 | 850,000,000 | ||||||||||||||||
Debt premium | $ 38,000,000 | $ 38,000,000 | $ 38,000,000 | ||||||||||||||||
Interest rate (percent) | 4.25% | 4.25% | 4.25% | ||||||||||||||||
Senior Notes | 4.25% Series B Senior Notes Due 2023 | Subsequent Event | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Repayments of debt | $ 850,000,000 | ||||||||||||||||||
Common Stock | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Share-based benefit plans (in shares) | shares | 1,000,000 | ||||||||||||||||||
Number of shares issued | shares | 25,696,168 | 33,238,910 | |||||||||||||||||
Preferred Stock | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Number of shares converted | shares | 704,589 | 911,411 | |||||||||||||||||
Preferred Stock | Series A Convertible Preferred Stock | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Amount of preferred stock investment | 162,000,000 | ||||||||||||||||||
OPIC | Series A Convertible Preferred Stock | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Amount of preferred stock investment | $ 1,460,000,000 | ||||||||||||||||||
Ohio Funding Companies | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Aggregate annual servicing fees receivable for phase-in recovery bonds | $ 445,000 | ||||||||||||||||||
Ohio Funding Companies | Phase In Recovery Bonds | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Face amount of loan | $ 445,000,000 | ||||||||||||||||||
AGC | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
FERC-defined equity to total capitalization ratio | 45.00% | ||||||||||||||||||
CEI | Senior Notes | 2.77% Series A Senior Notes Due 2034 | Subsequent Event | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Face amount of loan | $ 150,000,000 | ||||||||||||||||||
Interest rate (percent) | 2.77% | ||||||||||||||||||
TE | Senior Notes | 2.65%, 150 Million Notes Maturing 2028 | Subsequent Event | |||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||
Prepayments of debt | $ 25,000,000 | ||||||||||||||||||
Interest rate (percent) | 2.65% |
CAPITALIZATION - Preferred and
CAPITALIZATION - Preferred and Preference Stock (Details) - $ / shares | Dec. 31, 2021 | Jan. 31, 2018 |
Preferred stock and preference stock authorizations | ||
Shares Authorized (in shares) | 5,000,000 | |
Par Value (in dollars per share) | $ 100 | |
Penn | ||
Preferred stock and preference stock authorizations | ||
Shares Authorized (in shares) | 1,200,000 | |
Par Value (in dollars per share) | $ 100 | |
CEI | ||
Preferred stock and preference stock authorizations | ||
Shares Authorized (in shares) | 4,000,000 | |
JCP&L | ||
Preferred stock and preference stock authorizations | ||
Shares Authorized (in shares) | 15,600,000 | |
ME | ||
Preferred stock and preference stock authorizations | ||
Shares Authorized (in shares) | 10,000,000 | |
PN | ||
Preferred stock and preference stock authorizations | ||
Shares Authorized (in shares) | 11,435,000 | |
PE | ||
Preferred stock and preference stock authorizations | ||
Shares Authorized (in shares) | 10,000,000 | |
Par Value (in dollars per share) | $ 0.01 | |
WP | ||
Preferred stock and preference stock authorizations | ||
Shares Authorized (in shares) | 32,000,000 | |
Preferred Stock With Par Value $100 | OE | ||
Preferred stock and preference stock authorizations | ||
Shares Authorized (in shares) | 6,000,000 | |
Par Value (in dollars per share) | $ 100 | |
Preferred Stock With Par Value $100 | TE | ||
Preferred stock and preference stock authorizations | ||
Shares Authorized (in shares) | 3,000,000 | |
Par Value (in dollars per share) | $ 100 | |
Preferred Stock With Par Value $100 | MP | ||
Preferred stock and preference stock authorizations | ||
Shares Authorized (in shares) | 940,000 | |
Par Value (in dollars per share) | $ 100 | |
Preferred Stock With Par Value $25 | OE | ||
Preferred stock and preference stock authorizations | ||
Shares Authorized (in shares) | 8,000,000 | |
Par Value (in dollars per share) | $ 25 | |
Preferred Stock With Par Value $25 | TE | ||
Preferred stock and preference stock authorizations | ||
Shares Authorized (in shares) | 12,000,000 | |
Par Value (in dollars per share) | $ 25 | |
Preference Stock | OE | ||
Preferred stock and preference stock authorizations | ||
Preference Shares Authorized (in shares) | 8,000,000 | |
Preference Stock | CEI | ||
Preferred stock and preference stock authorizations | ||
Preference Shares Authorized (in shares) | 3,000,000 | |
Preference Stock | TE | ||
Preferred stock and preference stock authorizations | ||
Preference Shares Authorized (in shares) | 5,000,000 | |
Preference Stock Par Value (in dollars per share) | $ 25 | |
Series A Convertible Preferred Stock | ||
Preferred stock and preference stock authorizations | ||
Par Value (in dollars per share) | $ 100 |
CAPITALIZATION - Long-term Debt
CAPITALIZATION - Long-term Debt and Other Long-term Obligations (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Schedule of Capitalization [Line Items] | ||
Finance leases | $ 36 | $ 45 |
Unamortized debt discounts | (8) | (34) |
Unamortized debt issuance costs | (126) | (118) |
Unamortized fair value adjustments | 6 | 7 |
Currently payable long-term debt | (1,606) | (146) |
Total long-term debt and other long-term obligations | 22,248 | 22,131 |
FMBs and secured notes - fixed rate | ||
Schedule of Capitalization [Line Items] | ||
FMBs and secured notes - fixed rate | $ 5,021 | 4,802 |
FMBs and secured notes - fixed rate | Minimum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 2.65% | |
FMBs and secured notes - fixed rate | Maximum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 8.25% | |
Unsecured notes - fixed rate | ||
Schedule of Capitalization [Line Items] | ||
Unsecured notes - fixed rate | $ 18,925 | $ 17,575 |
Unsecured notes - fixed rate | Minimum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 1.60% | |
Unsecured notes - fixed rate | Maximum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 7.375% |
CAPITALIZATION - Schedule of Lo
CAPITALIZATION - Schedule of Long Term Debt (Details) | 12 Months Ended |
Dec. 31, 2021USD ($) | |
Line of Credit | Jersey Central Power and Light Company | Revolving Credit Facility | |
Debt Instrument [Line Items] | |
Long-term Line of Credit | $ 450,000,000 |
2.866%, 500 Million Notes Maturing 2028 | Promissory Notes | FET | |
Debt Instrument [Line Items] | |
Interest rate (percent) | 2.87% |
Face amount of loan | $ 500,000,000 |
3.55%, 200 Million Notes Maturing 2027 | Promissory Notes | MP | |
Debt Instrument [Line Items] | |
Interest rate (percent) | 3.55% |
Face amount of loan | $ 200,000,000 |
Effective interest rate | 2.06% |
2.65%, 150 Million Notes Maturing 2028 | Promissory Notes | TE | |
Debt Instrument [Line Items] | |
Interest rate (percent) | 2.65% |
Face amount of loan | $ 150,000,000 |
4.10%, 150 Million Notes Maturing 2028 | Promissory Notes | MAIT | |
Debt Instrument [Line Items] | |
Interest rate (percent) | 4.10% |
Face amount of loan | $ 150,000,000 |
Effective interest rate | 2.55% |
2.75%, 500 Million Notes Maturing 2032 | Promissory Notes | Jersey Central Power and Light Company | |
Debt Instrument [Line Items] | |
Interest rate (percent) | 2.75% |
Face amount of loan | $ 500,000,000 |
2.65%, 600 Million Notes Maturing 2032 | Promissory Notes | ATSI | |
Debt Instrument [Line Items] | |
Interest rate (percent) | 2.65% |
Face amount of loan | $ 600,000,000 |
CAPITALIZATION - Sinking Fund R
CAPITALIZATION - Sinking Fund Requirements (Details) $ in Millions | Dec. 31, 2021USD ($) |
Capitalization, Long-term Debt and Equity [Abstract] | |
2022 | $ 1,593 |
2023 | 344 |
2024 | 1,246 |
2025 | 2,023 |
2026 | $ 1,076 |
SHORT-TERM BORROWINGS AND BAN_2
SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT - Narrative (Details) | Oct. 18, 2021USD ($)agreement | Nov. 23, 2020USD ($) | Dec. 31, 2021USD ($) | Dec. 31, 2020USD ($) |
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Short-term borrowings | $ 0 | $ 2,200,000,000 | ||
Average interest rate for borrowings | 2.42% | 1.86% | ||
Revolving Credit Facility | Line of Credit | ||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Line of credit facility, remaining borrowing capacity | $ 4,500,000,000 | |||
Number of agreements | agreement | 6 | |||
Maximum amount borrowed under revolving credit facility | $ 4,500,000,000 | |||
Revolving Credit Facility | Parent, FET, the Utilities and the Transmission Companies | Line of Credit | ||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Term of revolving credit facility | 5 years | |||
Revolving Credit Facility | Parent, FET, the Utilities and the Transmission Companies | Line of Credit | Maximum | ||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Term of revolving credit facility | 364 days | |||
Revolving Credit Facility | Parent and FET | Line of Credit | ||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Maximum amount borrowed under revolving credit facility | $ 1,000,000,000 | |||
Revolving Credit Facility | Ohio Companies | Line of Credit | ||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Maximum amount borrowed under revolving credit facility | 800,000,000 | |||
Revolving Credit Facility | Pennsylvania Companies | Line of Credit | ||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Maximum amount borrowed under revolving credit facility | 950,000,000 | |||
Revolving Credit Facility | JCP&L | Line of Credit | ||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Maximum amount borrowed under revolving credit facility | 500,000,000 | |||
Revolving Credit Facility | MP and PE | Line of Credit | ||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Maximum amount borrowed under revolving credit facility | 400,000,000 | |||
Revolving Credit Facility | Transmission companies | Line of Credit | ||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Maximum amount borrowed under revolving credit facility | $ 850,000,000 | |||
Revolving Credit Facility | FET, the Utilities and the Transmission Companies | Line of Credit | ||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Coverage ratio | 250.00% | |||
Revolving Credit Facility | FET, the Utilities and the Transmission Companies | Line of Credit | Minimum | ||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Consolidated debt to total capitalization ratio (percent) | 65.00% | |||
Revolving Credit Facility | FET, the Utilities and the Transmission Companies | Line of Credit | Maximum | ||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Consolidated debt to total capitalization ratio (percent) | 75.00% | |||
Revolving Credit Facility | FET | Line of Credit | ||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Line of credit facility, remaining borrowing capacity | $ 0 | |||
Revolving Credit Facility | FE and the regulated distribution subsidiaries | Line of Credit | ||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Proceeds from lines of credit | 950,000,000 | |||
Line of Credit | Letter of Credit | ||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Term of revolving credit facility | 1 year | |||
Money Pool | Maximum | ||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Term of revolving credit facility | 364 days | |||
Money Pool | Regulated Companies | ||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Average interest rate for borrowings | 1.01% | |||
Money Pool | Unregulated Companies | ||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Average interest rate for borrowings | 0.60% | |||
Available for Issuance of Letters of Credit | Minimum | ||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Cross-default provision for other indebtedness | $ 100,000,000 | |||
FE | Revolving Credit Facility | Line of Credit | ||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Outstanding borrowings | 1,200,000,000 | |||
Line of credit facility, remaining borrowing capacity | 1,300,000,000 | |||
FE | Line of Credit | Letter of Credit | ||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Outstanding borrowings | $ 4,000,000 | |||
FET Sub-limits | Revolving Credit Facility | Line of Credit | ||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||
Outstanding borrowings | 1,000,000,000 | |||
Proceeds from lines of credit | $ 1,000,000,000 |
ASSET RETIREMENT OBLIGATIONS -
ASSET RETIREMENT OBLIGATIONS - Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Changes to the asset retirement obligations | ||
Beginning Balance | $ 159 | $ 856 |
Liabilities settled | (1) | (744) |
Changes in timing and amount of estimated cash flows | 8 | |
Accretion | 13 | 47 |
Ending Balance | $ 179 | 159 |
TMI-2 | ||
Changes to the asset retirement obligations | ||
Decrease in asset retirement obligation | $ 726 |
REGULATORY MATTERS - Distributi
REGULATORY MATTERS - Distribution Rate Orders (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Jan. 01, 2021 | |
CEI | ||
Public Utilities, General Disclosures [Line Items] | ||
Allowed Debt | 51.00% | |
Allowed Equity | 49.00% | |
Approved ROE | 10.50% | |
ME | ||
Public Utilities, General Disclosures [Line Items] | ||
Allowed Debt | 48.80% | |
Allowed Equity | 51.20% | |
MP | ||
Public Utilities, General Disclosures [Line Items] | ||
Allowed Debt | 54.00% | |
Allowed Equity | 46.00% | |
JCP&L | ||
Public Utilities, General Disclosures [Line Items] | ||
Allowed Debt | 48.60% | |
Allowed Equity | 51.40% | |
Approved ROE | 9.60% | |
Regulatory liabilities | $ 86 | |
OE | ||
Public Utilities, General Disclosures [Line Items] | ||
Allowed Debt | 51.00% | |
Allowed Equity | 49.00% | |
Approved ROE | 10.50% | |
PE | West Virginia | ||
Public Utilities, General Disclosures [Line Items] | ||
Allowed Debt | 54.00% | |
Allowed Equity | 46.00% | |
PE | Maryland | ||
Public Utilities, General Disclosures [Line Items] | ||
Allowed Debt | 47.00% | |
Allowed Equity | 53.00% | |
Approved ROE | 9.65% | |
PN | ||
Public Utilities, General Disclosures [Line Items] | ||
Allowed Debt | 47.40% | |
Allowed Equity | 52.60% | |
Penn | ||
Public Utilities, General Disclosures [Line Items] | ||
Allowed Debt | 49.90% | |
Allowed Equity | 50.10% | |
TE | ||
Public Utilities, General Disclosures [Line Items] | ||
Allowed Debt | 51.00% | |
Allowed Equity | 49.00% | |
Approved ROE | 10.50% | |
WP | ||
Public Utilities, General Disclosures [Line Items] | ||
Allowed Debt | 49.70% | |
Allowed Equity | 50.30% |
REGULATORY MATTERS - Maryland a
REGULATORY MATTERS - Maryland and New Jersey (Details) meter in Millions, $ in Millions | Sep. 14, 2021USD ($) | May 26, 2021USD ($) | Apr. 23, 2021USD ($) | Mar. 05, 2021USD ($) | Mar. 01, 2021USD ($)program | Oct. 28, 2020USD ($)MW | Sep. 25, 2020program | Aug. 27, 2020USD ($)meter | Jun. 10, 2020 | Apr. 06, 2020USD ($) | Mar. 22, 2019 | Jul. 16, 2015 | Oct. 31, 2021USD ($) | Dec. 31, 2021USD ($)MW | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($)program | Dec. 31, 2020USD ($) |
Regulatory Matters [Line Items] | |||||||||||||||||
Gain on sale of property | $ 109 | $ 0 | $ 0 | ||||||||||||||
Regulated Distribution | |||||||||||||||||
Regulatory Matters [Line Items] | |||||||||||||||||
Plant generation capacity (in MW's) | MW | 3,580 | ||||||||||||||||
PE | Maryland | |||||||||||||||||
Regulatory Matters [Line Items] | |||||||||||||||||
Incremental energy savings goal per year (percent) | 0.20% | ||||||||||||||||
Incremental energy savings goal thereafter (percent) | 2.00% | ||||||||||||||||
PE | Maryland | MDPSC | |||||||||||||||||
Regulatory Matters [Line Items] | |||||||||||||||||
Requested increase (decrease) in revenues | $ 6.2 | ||||||||||||||||
Number of approved ESR programs | program | 3 | ||||||||||||||||
ESR program term | 4 years | ||||||||||||||||
Period to file new depreciation study | 18 months | ||||||||||||||||
ESER Program rate case renewal period | 4 years | ||||||||||||||||
JCP&L | New Jersey | Yard's Creek Energy, LLC Hydro Generation Facility | |||||||||||||||||
Regulatory Matters [Line Items] | |||||||||||||||||
Plant generation capacity (in MW's) | MW | 210 | ||||||||||||||||
Consideration transferred | $ 155 | ||||||||||||||||
JCP&L | New Jersey | Yard's Creek Energy, LLC Hydro Generation Facility | Regulated Distribution | |||||||||||||||||
Regulatory Matters [Line Items] | |||||||||||||||||
Assets acquired | $ 45 | ||||||||||||||||
Gain on sale of property | $ 109 | ||||||||||||||||
JCP&L | New Jersey | NJBPU | |||||||||||||||||
Regulatory Matters [Line Items] | |||||||||||||||||
Settled amount of increase in revenue | $ 94 | ||||||||||||||||
Requested ROE | 9.60% | ||||||||||||||||
Settled decrease in regulatory liability | $ 86 | ||||||||||||||||
JCP&L | New Jersey | NJBPU | Yard's Creek Energy, LLC Hydro Generation Facility | |||||||||||||||||
Regulatory Matters [Line Items] | |||||||||||||||||
Ownership interest acquired | 50.00% | ||||||||||||||||
JCP&L Reliability Plus | JCP&L | New Jersey | NJBPU | |||||||||||||||||
Regulatory Matters [Line Items] | |||||||||||||||||
Approved amount included in rate base | $ 95 | $ 95 | |||||||||||||||
2021-2023 EmPOWER Program Cycle | PE | Maryland | |||||||||||||||||
Regulatory Matters [Line Items] | |||||||||||||||||
Expenditures for cost recovery program | $ 148 | ||||||||||||||||
Recovery period for expenditures for cost recovery program | 3 years | ||||||||||||||||
Amortization period for expenditures for cost recovery program | 5 years | ||||||||||||||||
Advanced metering infrastructure | JCP&L | New Jersey | Regulated Distribution | |||||||||||||||||
Regulatory Matters [Line Items] | |||||||||||||||||
Requested rate increase (decrease) | $ (732) | ||||||||||||||||
Advanced metering infrastructure | JCP&L | New Jersey | NJBPU | Regulated Distribution | |||||||||||||||||
Regulatory Matters [Line Items] | |||||||||||||||||
Number of meters to be deployed | meter | 1.2 | ||||||||||||||||
Deployment period | 3 years | ||||||||||||||||
Expected cost of the program | $ 418 | ||||||||||||||||
Meter deployment program period | 20 years | ||||||||||||||||
Energy Efficiency and Peak Demand Reduction | JCP&L | New Jersey | NJBPU | Regulated Distribution | |||||||||||||||||
Regulatory Matters [Line Items] | |||||||||||||||||
Amortization period for expenditures for cost recovery program | 10 years | 10 years | |||||||||||||||
Number of programs | program | 11 | ||||||||||||||||
Depreciation Study | PE | Maryland | Maryland Office of People's Counsel | |||||||||||||||||
Regulatory Matters [Line Items] | |||||||||||||||||
Requested increase (decrease) in revenues | $ (2.1) | ||||||||||||||||
Advanced Metering Infrastructure Supplemental Filing | JCP&L | New Jersey | Regulated Distribution | |||||||||||||||||
Regulatory Matters [Line Items] | |||||||||||||||||
Meter program period | 6 years | ||||||||||||||||
Requested rate increase due to costs associated with program | $ 494 | ||||||||||||||||
Requested increase due to capital expenditures | 390 | ||||||||||||||||
Requested increase due to maintenance expense | 73 | ||||||||||||||||
Cost of removal | $ 31 | ||||||||||||||||
Energy Efficiency and Peak Demand Reduction Stipulation Settlement | JCP&L | New Jersey | NJBPU | Regulated Distribution | |||||||||||||||||
Regulatory Matters [Line Items] | |||||||||||||||||
Requested rate increase (decrease) | $ (203) | ||||||||||||||||
Approved rate plan period | 3 years | ||||||||||||||||
Approved amount of investment recovery over amortization period | $ 158 | ||||||||||||||||
Approved amount of operation costs and maintenance recovery | $ 45 | ||||||||||||||||
Electrical Vehicle Program | JCP&L | New Jersey | NJBPU | Regulated Distribution | |||||||||||||||||
Regulatory Matters [Line Items] | |||||||||||||||||
Requested rate increase (decrease) | $ (50) | ||||||||||||||||
Number of programs | program | 6 | ||||||||||||||||
Electric vehicle program period | 4 years | ||||||||||||||||
Requested ROE | $ 16 | ||||||||||||||||
Apportioned for operations and maintenance expense amount | $ 34 |
REGULATORY MATTERS - Ohio (Deta
REGULATORY MATTERS - Ohio (Details) - Ohio - PUCO $ in Millions | Nov. 01, 2021USD ($) | Jun. 16, 2021USD ($) | Jun. 01, 2016USD ($) | Dec. 31, 2021USD ($) | Dec. 31, 2021USD ($) | Sep. 13, 2021requirement | Feb. 01, 2021USD ($) |
Regulatory Matters [Line Items] | |||||||
Proposed reduction in power plants carbon pollution (percent) | 90.00% | ||||||
DCR Rider | |||||||
Regulatory Matters [Line Items] | |||||||
Revenue cap for Rider for years 3-6 | $ 20 | ||||||
Revenue cap for Rider for years 6-8 | 15 | ||||||
Ohio Stipulation | |||||||
Regulatory Matters [Line Items] | |||||||
Rate refunds | $ 210 | ||||||
Rate refund in 2022 | 80 | ||||||
Rate refund in 2023 | 60 | ||||||
Rate refund in 2024 | 45 | ||||||
Rate refund in 2025 | 25 | ||||||
Ohio Stipulation | Regulated Distribution | |||||||
Regulatory Matters [Line Items] | |||||||
Pre-tax charges | $ 96 | ||||||
Energy Conservation, Economic Development and Job Retention | |||||||
Regulatory Matters [Line Items] | |||||||
Contribution amount | $ 51 | ||||||
Ohio Companies | Rider CSR | |||||||
Regulatory Matters [Line Items] | |||||||
Regulatory asset balance | $ 0 | ||||||
Pre-tax impairment of regulatory asset | 108 | $ 108 | |||||
Impairment of regulatory asset, net | 84 | 84 | |||||
Lost distribution revenue | $ 77 | 77 | |||||
Ohio Companies | Decoupling Rider | |||||||
Regulatory Matters [Line Items] | |||||||
Proposed penalty | $ 27 | ||||||
Ohio Companies | Rider Delivery Capital Recovery | |||||||
Regulatory Matters [Line Items] | |||||||
Approved amount of rate increase (decrease) | $ (3.7) | ||||||
Ohio Companies | Rider Delivery Capital Recovery Audit Report | |||||||
Regulatory Matters [Line Items] | |||||||
Number of minor non-compliance with requirements | requirement | 8 | ||||||
Number of requirements were in compliance | requirement | 23 | ||||||
Ohio Companies | SEET 2017-2019 Cases | |||||||
Regulatory Matters [Line Items] | |||||||
Rate refunds | $ 96 |
REGULATORY MATTERS - Pennsylvan
REGULATORY MATTERS - Pennsylvania and West Virginia (Details) $ in Millions | Dec. 29, 2021USD ($) | Dec. 27, 2021USD ($) | Dec. 17, 2021USD ($) | Nov. 22, 2021USD ($)plantMW | Nov. 18, 2021USD ($) | Aug. 27, 2021USD ($) | Dec. 30, 2020USD ($) | Aug. 30, 2019USD ($) | Jun. 01, 2019proposalMW | Mar. 31, 2016USD ($) | Dec. 31, 2021USD ($) | Jun. 18, 2020 |
Pennsylvania | PPUC | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Revised requested rate increase | $ 61 | |||||||||||
Pennsylvania | PPUC | Utilities and FET | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Pre-tax charges | $ 61 | |||||||||||
Pennsylvania | PPUC | Penn | ENEC Phase IV | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Approved demand reduction targets | 2.00% | |||||||||||
Approved energy consumption reduction targets | 2.70% | |||||||||||
Pennsylvania | PPUC | WP | ENEC Phase IV | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Approved demand reduction targets | 2.50% | |||||||||||
Approved energy consumption reduction targets | 2.40% | |||||||||||
Pennsylvania | PPUC | Pennsylvania Companies | DSP | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Number of RFP's | proposal | 2 | |||||||||||
Project term | 2 years | |||||||||||
New hourly priced default service threshold (in MW's) | MW | 0.1 | |||||||||||
Pennsylvania | PPUC | Pennsylvania Companies | DSP | 3 Month Period | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Energy contract term | 3 months | |||||||||||
Pennsylvania | PPUC | Pennsylvania Companies | DSP | 12 Month Period | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Energy contract term | 12 months | |||||||||||
Pennsylvania | PPUC | Pennsylvania Companies | DSP | 24 Month Period | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Energy contract term | 24 months | |||||||||||
Pennsylvania | PPUC | Pennsylvania Companies | EE&C | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Approved amount of rate increase (decrease) | $ 390 | |||||||||||
Pennsylvania | PPUC | Pennsylvania Companies | New LTIP's | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Cost recovery period | 5 years | |||||||||||
Requested rate increase (decrease) | $ 572 | |||||||||||
Pennsylvania | PPUC | PN | ENEC Phase IV | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Approved demand reduction targets | 3.30% | |||||||||||
Approved energy consumption reduction targets | 3.00% | |||||||||||
Pennsylvania | PPUC | ME | ENEC Phase IV | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Approved demand reduction targets | 2.90% | |||||||||||
Approved energy consumption reduction targets | 3.10% | |||||||||||
West Virginia | WVPSC | MP and PE | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Number of solar generation sites | plant | 5 | |||||||||||
Solar generation plant capacity (in MW's) | MW | 50 | |||||||||||
West Virginia | WVPSC | MP and PE | Ft. Martin and Harrison Power Stations | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Requested rate increase (decrease) | $ 142 | |||||||||||
Requested annual rate increase | $ 3 | |||||||||||
West Virginia | WVPSC | MP and PE | Solar Generation Project | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Expected cost of the program | $ 100 | |||||||||||
West Virginia | WVPSC | MP and PE | ENEC | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Approved amount of rate increase (decrease) | $ (7.7) | |||||||||||
Requested rate increase (decrease) | $ 19.6 | $ (2.6) | ||||||||||
Requested rate increase (decrease) (percent) | 1.50% | |||||||||||
Supplemental requested decrease | $ (7.7) | |||||||||||
Approved amount of rate offset | $ 2.9 | |||||||||||
West Virginia | WVPSC | MP and PE | Integrated Resource Plan | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Approved amount of rate increase (decrease) | $ 19.6 | |||||||||||
West Virginia | WVPSC | MP and PE | Vegetation Management Surcharge Rates | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Approved amount of rate increase (decrease) | $ 16 | |||||||||||
Requested rate increase (decrease) | $ 16 | |||||||||||
Surcharge period | 2 years |
REGULATORY MATTERS - Reliabilit
REGULATORY MATTERS - Reliability and FERC Matters (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2021USD ($) | |
FERC | FE | Other Nonoperating Income (Expense) | Transmission Related Vegetation Management Programs | |
Regulatory Matters [Line Items] | |
Pre-tax impairment of regulatory asset | $ 21 |
ATSI | Regulated Transmission | |
Regulatory Matters [Line Items] | |
Approved ROE | 10.38% |
ATSI | Regulated Transmission | FERC | Transmission Related Vegetation Management Programs | |
Regulatory Matters [Line Items] | |
Pre-tax impairment of regulatory asset | $ 48 |
ATSI | Regulated Distribution | FERC | Transmission Related Vegetation Management Programs | |
Regulatory Matters [Line Items] | |
Pre-tax impairment of regulatory asset | $ 27 |
JCP&L | |
Regulatory Matters [Line Items] | |
Allowed Debt | 48.60% |
Approved ROE | 9.60% |
JCP&L | Regulated Transmission | |
Regulatory Matters [Line Items] | |
Approved ROE | 10.20% |
MAIT | Regulated Transmission | |
Regulatory Matters [Line Items] | |
Allowed Debt | 60.00% |
Approved ROE | 10.30% |
TrAIL | Regulated Transmission | TrAIL the Line and Black Oak SVC | |
Regulatory Matters [Line Items] | |
Approved ROE | 12.70% |
TrAIL | Regulated Transmission | All Other Projects | |
Regulatory Matters [Line Items] | |
Approved ROE | 11.70% |
MP | |
Regulatory Matters [Line Items] | |
Allowed Debt | 54.00% |
MP | Regulated Transmission | |
Regulatory Matters [Line Items] | |
Approved ROE | 11.35% |
PE | Regulated Transmission | |
Regulatory Matters [Line Items] | |
Approved ROE | 11.35% |
WP | |
Regulatory Matters [Line Items] | |
Allowed Debt | 49.70% |
WP | Regulated Transmission | |
Regulatory Matters [Line Items] | |
Approved ROE | 11.35% |
COMMITMENTS, GUARANTEES AND C_3
COMMITMENTS, GUARANTEES AND CONTINGENCIES - Schedule of Guarantor Obligations (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2021USD ($) | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | $ 359 |
Percent of face amount of debt | 100.00% |
Curing period | 30 days |
Utilities and FET | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | $ 101 |
FE | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 258 |
Upon Further Downgrade | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 44 |
Upon Further Downgrade | Utilities and FET | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 44 |
Upon Further Downgrade | FE | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 0 |
Surety Bond | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | $ 315 |
Percent of face amount of debt | 60.00% |
Capped portion of surety bond obligations | $ 39 |
Surety Bond | Utilities and FET | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 57 |
Surety Bond | FE | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | $ 258 |
COMMITMENTS, GUARANTEES AND C_4
COMMITMENTS, GUARANTEES AND CONTINGENCIES - Nuclear Insurance, Commitments and Collateral (Details) | Dec. 31, 2021USD ($) |
Loss Contingencies [Line Items] | |
Outstanding guarantees and other assurances aggregated | $ 1,100,000,000 |
Company posted collateral related to net liability positions | 55,000,000 |
Subsidiaries' Guarantees | |
Loss Contingencies [Line Items] | |
Outstanding guarantees and other assurances aggregated | 600,000,000 |
Other Assurances | |
Loss Contingencies [Line Items] | |
Outstanding guarantees and other assurances aggregated | 500,000,000 |
Term Loan Facility Due November 2024 | Line of Credit | Global Holding | |
Loss Contingencies [Line Items] | |
Face amount of loan | $ 120,000,000 |
COMMITMENTS, GUARANTEES AND C_5
COMMITMENTS, GUARANTEES AND CONTINGENCIES - Climate Change, Clean Water Act, Regulation of Waste Disposal and Other Legal Proceedings (Details) $ in Thousands | Feb. 09, 2022USD ($) | Jul. 21, 2021USD ($) | Feb. 20, 2018USD ($) | Dec. 31, 2021USD ($) | Oct. 29, 2020director |
Loss Contingencies [Line Items] | |||||
Number of additional executives terminated | director | 2 | ||||
Climate change | |||||
Loss Contingencies [Line Items] | |||||
Proposed reduction in power plants carbon pollution (percent) | 30.00% | ||||
Smith v FirstEnergy Corp et al., Buldas v FirstEnergy Corp. et al., and Hudock and Cameo Countertops, Inc. v. FirstEnergy Corp. et al. | |||||
Loss Contingencies [Line Items] | |||||
Loss contingency accrual | $ 37,500 | ||||
Emmons v. FirstEnergy Corp. et al. | |||||
Loss Contingencies [Line Items] | |||||
Loss contingency accrual | 37,500 | ||||
Shareholder Derivative Lawsuit | Subsequent Event | |||||
Loss Contingencies [Line Items] | |||||
Settlement payment awarded | $ 180,000 | ||||
U.S. Attorney's Office | United States v. Householder, et al. | |||||
Loss Contingencies [Line Items] | |||||
Term of DPA | 3 years | ||||
Loss in period | $ 230,000 | ||||
Term of payments | 60 days | ||||
United States Treasury | United States v. Householder, et al. | |||||
Loss Contingencies [Line Items] | |||||
Proposed penalty | $ 115,000 | ||||
Ohio Development Service | United States v. Householder, et al. | |||||
Loss Contingencies [Line Items] | |||||
Proposed penalty | $ 115,000 | ||||
Clean Water Act | EPA | |||||
Loss Contingencies [Line Items] | |||||
Proposed penalty | $ 610 | ||||
Regulation of Waste Disposal | |||||
Loss Contingencies [Line Items] | |||||
Accrual for environmental loss contingencies | 110,000 | ||||
Environmental liabilities former gas facilities | $ 70,000 |
DISCONTINUED OPERATIONS - Narra
DISCONTINUED OPERATIONS - Narrative (Details) $ in Millions | Feb. 27, 2020USD ($) | Sep. 30, 2018USD ($) | Dec. 31, 2021USD ($) | Sep. 30, 2021USD ($) | Mar. 31, 2021USD ($) | Dec. 31, 2021USD ($) | Dec. 31, 2019MW |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||
Worthless stock deduction | $ 4,900 | $ 5,200 | |||||
Unrecognized tax benefits from worthless stock deduction | 316 | $ 81 | |||||
Worthless stock deduction, net of tax | 1,100 | ||||||
Increase in NOL allocation | $ 289 | ||||||
Increase in NOL allocation tax effected | 61 | ||||||
State and Local | |||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||
Worthless stock deduction, net of tax | $ 21 | ||||||
Disposal Group, Disposed of by Sale | |||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||
Proceeds from asset sales | $ 65 | ||||||
AE Supply | Purchase Agreement with Subsidiary of LS Power | Pleasants Power Station | |||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||
Plant generation capacity (in MW's) | MW | 1,300 | ||||||
IT Access Agreement | Affiliated companies | FES | |||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||
Amount paid to settle claims | $ 125 | ||||||
FES Key Creditor Groups | Affiliated companies | FES | |||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||
Settlement of claims upon emergence | $ 853 |
DISCONTINUED OPERATIONS - Summa
DISCONTINUED OPERATIONS - Summarized Results of Discontinued Operations (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Income tax expense (benefit) | $ (48) | $ (59) | $ (5) | |
Income from discontinued operations | [1] | 44 | 76 | 8 |
FES and FENOC | Discontinued Operations, Disposed of by Means Other than Sale | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Revenues | 0 | 7 | 188 | |
Fuel | 0 | (6) | (140) | |
Other operating expenses | 0 | (6) | (63) | |
General taxes | 0 | 0 | (14) | |
Pleasants economic interest | 0 | 5 | 27 | |
Other expense, net | (4) | 0 | (2) | |
Loss from discontinued operations, before tax | (4) | 0 | (4) | |
Income tax expense (benefit) | (1) | 0 | 47 | |
Loss from discontinued operations, net of tax | (3) | 0 | (51) | |
Settlement consideration and services credit | 0 | (1) | 7 | |
Accelerated net pension and OPEB prior service credits | 0 | 18 | 0 | |
Gain on disposal of FES and FENOC, before tax | 0 | 17 | 7 | |
Income tax benefits, including worthless stock deduction | (47) | (59) | (52) | |
Gain on disposal of FES and FENOC, net of tax | 47 | 76 | 59 | |
Income from discontinued operations | $ 44 | $ 76 | $ 8 | |
[1] | Net of income tax benefit of $48 million, $59 million, and $5 million in 2021, 2020 and 2019, respectively. |
DISCONTINUED OPERATIONS - Major
DISCONTINUED OPERATIONS - Major Classes of Cash Flow Items from Discontinued Operations (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | ||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||
Income from discontinued operations | [1] | $ 44 | $ 76 | $ 8 |
Gain on disposal, net of tax | (47) | (76) | (59) | |
Deferred income taxes and investment tax credits, net | 297 | 113 | 252 | |
FES and FENOC | Discontinued Operations, Disposed of by Means Other than Sale | ||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||
Income from discontinued operations | 44 | 76 | 8 | |
Gain on disposal, net of tax | (47) | (76) | (59) | |
Deferred income taxes and investment tax credits, net | $ 0 | $ 0 | $ 47 | |
[1] | Net of income tax benefit of $48 million, $59 million, and $5 million in 2021, 2020 and 2019, respectively. |
SEGMENT INFORMATION - Narrative
SEGMENT INFORMATION - Narrative (Details) mi² in Thousands, customer in Millions, $ in Millions | Apr. 30, 2022USD ($) | Dec. 31, 2021USD ($)mi²companyMW | Dec. 31, 2021USD ($)mi²companycustomerMW | Dec. 31, 2020USD ($) |
FET | North American Transmission Company II LLC | Forecast | ||||
Segment Reporting Information [Line Items] | ||||
Sale of ownership interest by parent | 19.90% | |||
Sale of ownership interest by parent | $ 2,375 | |||
Regulated Distribution | ||||
Segment Reporting Information [Line Items] | ||||
Number of existing utility operating companies | company | 10 | 10 | ||
Number of customers served by utility operating companies | customer | 6 | |||
Number of square miles in service area | mi² | 65 | 65 | ||
Megawatts of net demonstrated capacity of competitive segment (in MW's) | MW | 3,580 | 3,580 | ||
Regulated Distribution | Disposal Group, Held-for-sale | Yard Creek Generating Facility | ||||
Segment Reporting Information [Line Items] | ||||
Assets held-for-sale | $ 45 | |||
Regulated Distribution | Disposal Group, Disposed of by Sale | TMI-2 | ||||
Segment Reporting Information [Line Items] | ||||
Gain on disposal of discontinued operation, net of tax | $ 33 | |||
Other/Corporate | OVEC | ||||
Segment Reporting Information [Line Items] | ||||
Megawatts of net demonstrated capacity of competitive segment (in MW's) | MW | 67 | 67 | ||
FE | Other/Corporate | ||||
Segment Reporting Information [Line Items] | ||||
Long-term debt and other long-term obligations | $ 7,900 | $ 7,900 |
SEGMENT INFORMATION (Details)
SEGMENT INFORMATION (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | ||
Segment Financial Information | ||||
Total revenues | [1] | $ 11,132 | $ 10,790 | $ 11,035 |
Provision for depreciation | 1,302 | 1,274 | 1,220 | |
Amortization (deferral) of regulatory assets, net | 269 | (53) | (79) | |
DPA penalty (Note 13) | 230 | 0 | 0 | |
Miscellaneous income (expense), net | 517 | 432 | 243 | |
Interest expense | 1,141 | 1,065 | 1,033 | |
Income taxes (benefits) | 320 | 126 | 213 | |
Income (loss) from continuing operations | 1,239 | 1,003 | 904 | |
Property additions | 2,445 | 2,657 | 2,665 | |
Total assets | 45,432 | 44,464 | ||
Total goodwill | 5,618 | 5,618 | ||
External revenues | ||||
Segment Financial Information | ||||
Total revenues | 11,132 | 10,790 | 11,035 | |
Internal revenues | ||||
Segment Financial Information | ||||
Total revenues | 0 | 0 | 0 | |
Regulated Distribution | ||||
Segment Financial Information | ||||
Total goodwill | 5,004 | |||
Regulated Transmission | ||||
Segment Financial Information | ||||
Total revenues | 1,608 | 1,613 | 1,510 | |
Operating Segments | Regulated Distribution | ||||
Segment Financial Information | ||||
Total revenues | 9,711 | 9,363 | 9,698 | |
Provision for depreciation | 911 | 896 | 863 | |
Amortization (deferral) of regulatory assets, net | 260 | (64) | (89) | |
DPA penalty (Note 13) | 0 | |||
Miscellaneous income (expense), net | 399 | 332 | 174 | |
Interest expense | 523 | 501 | 495 | |
Income taxes (benefits) | 364 | 113 | 271 | |
Income (loss) from continuing operations | 1,288 | 959 | 1,076 | |
Property additions | 1,395 | 1,514 | 1,473 | |
Total assets | 30,812 | 30,855 | ||
Total goodwill | 5,004 | 5,004 | ||
Operating Segments | Regulated Distribution | External revenues | ||||
Segment Financial Information | ||||
Total revenues | 9,510 | 9,168 | 9,511 | |
Operating Segments | Regulated Distribution | Internal revenues | ||||
Segment Financial Information | ||||
Total revenues | 201 | 195 | 187 | |
Operating Segments | Regulated Transmission | ||||
Segment Financial Information | ||||
Total revenues | 1,618 | 1,630 | 1,526 | |
Provision for depreciation | 325 | 313 | 284 | |
Amortization (deferral) of regulatory assets, net | 9 | 11 | 10 | |
DPA penalty (Note 13) | 0 | |||
Miscellaneous income (expense), net | 41 | 30 | 15 | |
Interest expense | 248 | 219 | 192 | |
Income taxes (benefits) | 127 | 138 | 113 | |
Income (loss) from continuing operations | 408 | 464 | 447 | |
Property additions | 958 | 1,067 | 1,090 | |
Total assets | 13,237 | 12,592 | ||
Total goodwill | 614 | 614 | ||
Operating Segments | Regulated Transmission | External revenues | ||||
Segment Financial Information | ||||
Total revenues | 1,608 | 1,613 | 1,510 | |
Operating Segments | Regulated Transmission | Internal revenues | ||||
Segment Financial Information | ||||
Total revenues | 10 | 17 | 16 | |
Corporate/ Other | ||||
Segment Financial Information | ||||
Total revenues | 14 | 9 | 14 | |
Provision for depreciation | 3 | 4 | 5 | |
Amortization (deferral) of regulatory assets, net | 0 | 0 | 0 | |
DPA penalty (Note 13) | 230 | |||
Miscellaneous income (expense), net | 89 | 83 | 80 | |
Interest expense | 382 | 358 | 372 | |
Income taxes (benefits) | (171) | (125) | (171) | |
Income (loss) from continuing operations | (457) | (420) | (619) | |
Property additions | 92 | 76 | 102 | |
Total assets | 1,383 | 1,017 | ||
Total goodwill | 0 | 0 | ||
Corporate/ Other | External revenues | ||||
Segment Financial Information | ||||
Total revenues | 14 | 9 | 14 | |
Corporate/ Other | Internal revenues | ||||
Segment Financial Information | ||||
Total revenues | 0 | 0 | 0 | |
Reconciling Adjustments | ||||
Segment Financial Information | ||||
Total revenues | (211) | (212) | (203) | |
Provision for depreciation | 63 | 61 | 68 | |
Amortization (deferral) of regulatory assets, net | 0 | 0 | 0 | |
DPA penalty (Note 13) | 0 | |||
Miscellaneous income (expense), net | (12) | (13) | (26) | |
Interest expense | (12) | (13) | (26) | |
Income taxes (benefits) | 0 | 0 | 0 | |
Income (loss) from continuing operations | 0 | 0 | 0 | |
Property additions | 0 | 0 | 0 | |
Total assets | 0 | 0 | ||
Total goodwill | 0 | 0 | ||
Reconciling Adjustments | External revenues | ||||
Segment Financial Information | ||||
Total revenues | 0 | 0 | 0 | |
Reconciling Adjustments | Internal revenues | ||||
Segment Financial Information | ||||
Total revenues | $ (211) | $ (212) | $ (203) | |
[1] | Includes excise and gross receipts tax collections of $374 million, $362 million and $373 million in 2021, 2020 and 2019, respectively. |