Cover Page
Cover Page - USD ($) | 12 Months Ended | ||
Dec. 31, 2022 | Jan. 31, 2023 | Jun. 30, 2022 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2022 | ||
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 Public Float | $ 21,916,076,568 | ||
Entity Common Stock Shares Outstanding | 572,245,184 | ||
Documents Incorporated by Reference | Documents Incorporated By Reference PART OF FORM 10-K INTO WHICH DOCUMENT DOCUMENT IS INCORPORATED Proxy Statement for 2023 Annual Meeting of Shareholders of FirstEnergy Corp. to be held May 24, 2023 Part III | ||
Entity Central Index Key | 0001031296 | ||
Document Fiscal Year Focus | 2022 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Shell Company | false |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2022 | |
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, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | ||
REVENUES: | ||||
Total revenues | [1] | $ 12,459 | $ 11,132 | $ 10,790 |
OPERATING EXPENSES: | ||||
Fuel | 730 | 481 | 369 | |
Purchased power | 3,863 | 2,964 | 2,701 | |
Other operating expenses | 3,817 | 3,196 | 3,291 | |
Provision for depreciation | 1,375 | 1,302 | 1,274 | |
Amortization (deferral) of regulatory assets, net | (365) | 269 | (53) | |
General taxes | 1,129 | 1,073 | 1,046 | |
DPA penalty (Note 13) | 0 | 230 | 0 | |
Gain on sale of Yards Creek (Note 14) | 0 | (109) | 0 | |
Total operating expenses | 10,549 | 9,406 | 8,628 | |
OPERATING INCOME | 1,910 | 1,726 | 2,162 | |
OTHER INCOME (EXPENSE): | ||||
Debt redemption costs (Note 10) | (171) | (2) | 0 | |
Equity method investment earnings (Note 1) | 168 | 31 | 2 | |
Miscellaneous income, net | 415 | 486 | 430 | |
Pension and OPEB mark-to-market adjustment | 72 | 382 | (477) | |
Interest expense | (1,039) | (1,139) | (1,065) | |
Capitalized financing costs | 84 | 75 | 77 | |
Total other expense | (471) | (167) | (1,033) | |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | 1,439 | 1,559 | 1,129 | |
INCOME TAXES | 1,000 | 320 | 126 | |
INCOME FROM CONTINUING OPERATIONS | 439 | |||
Discontinued operations (Note 15) | [2] | 0 | 44 | 76 |
NET INCOME | 439 | 1,283 | 1,079 | |
Income attributable to noncontrolling interest (continuing operations) | 33 | 0 | 0 | |
EARNINGS ATTRIBUTABLE TO FIRSTENERGY CORP. | $ 406 | $ 1,283 | $ 1,079 | |
EARNINGS PER SHARE ATTRIBUTABLE TO FIRSTENERGY CORP. | ||||
Basic - Income from continuing operations, basic (in dollars per share) | $ 0.71 | $ 2.27 | $ 1.85 | |
Basic - Discontinued operations, basic (in dollars per share) | 0 | 0.08 | 0.14 | |
Basic - EPS (in dollars per share) | 0.71 | 2.35 | 1.99 | |
Diluted - Income from continuing operations, diluted (in dollars per share) | 0.71 | 2.27 | 1.85 | |
Diluted - Discontinued operations, diluted (in dollars per share) | 0 | 0.08 | 0.14 | |
Diluted - EPS (in dollars per share) | $ 0.71 | $ 2.35 | $ 1.99 | |
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING: | ||||
Weighted average number of basic shares outstanding (in shares) | 571 | 545 | 542 | |
Weighted average number of diluted shares outstanding (in shares) | 572 | 546 | 543 | |
Distribution services and retail generation | ||||
REVENUES: | ||||
Total revenues | $ 9,916 | $ 9,009 | $ 8,688 | |
Transmission | ||||
REVENUES: | ||||
Total revenues | 1,863 | 1,608 | 1,613 | |
Other | ||||
REVENUES: | ||||
Total revenues | $ 680 | $ 515 | $ 489 | |
[1]Includes excise and gross receipts tax collections of $406 million, $374 million and $362 million in 2022, 2021 and 2020, respectively.[2]Net of income tax benefit of $48 million and $59 million in 2021 and 2020, respectively. |
Consolidated Statements of In_2
Consolidated Statements of Income (Loss) (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Income Statement [Abstract] | |||
Excise tax collections included in Revenue | $ 406 | $ 374 | $ 362 |
Income tax benefit | $ 48 | $ 59 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Statement of Comprehensive Income [Abstract] | |||
NET INCOME | $ 439 | $ 1,283 | $ 1,079 |
OTHER COMPREHENSIVE INCOME (LOSS): | |||
Pension and OPEB prior service costs | (9) | (14) | (34) |
Amortized losses on derivative hedges | 9 | 1 | 1 |
Other comprehensive loss | 0 | (13) | (33) |
Income tax benefits on other comprehensive loss | (1) | (3) | (8) |
Other comprehensive income (loss), net of tax | 1 | (10) | (25) |
COMPREHENSIVE INCOME | 440 | 1,273 | 1,054 |
Income attributable to noncontrolling interest (continuing operations) | 33 | 0 | 0 |
COMPREHENSIVE INCOME ATTRIBUTABLE TO FIRSTENERGY CORP. | $ 407 | $ 1,273 | $ 1,054 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
CURRENT ASSETS: | ||
Cash and cash equivalents | $ 160 | $ 1,462 |
Restricted cash | 46 | 49 |
Receivables- | ||
Customers | 1,455 | 1,192 |
Less — Allowance for uncollectible customer receivables | 137 | 159 |
Current accounts receivable | 1,318 | 1,033 |
Other, net of allowance for uncollectible accounts of $11 in 2022 and $10 in 2021 | 253 | 246 |
Materials and supplies, at average cost | 421 | 260 |
Prepaid taxes and other | 217 | 187 |
Total current assets | 2,415 | 3,237 |
PROPERTY, PLANT AND EQUIPMENT: | ||
In service | 47,850 | 46,002 |
Less — Accumulated provision for depreciation | 13,258 | 12,672 |
Net Plant | 34,592 | 33,330 |
Construction work in progress | 1,693 | 1,414 |
Total | 36,285 | 34,744 |
INVESTMENTS AND OTHER NONCURRENT ASSETS | ||
Goodwill | 5,618 | 5,618 |
Investments (Note 9) | 622 | 655 |
Regulatory assets | 33 | 71 |
Other | 1,135 | 1,107 |
Total deferred charges and other assets | 7,408 | 7,451 |
Total assets | 46,108 | 45,432 |
CURRENT LIABILITIES: | ||
Currently payable long-term debt | 351 | 1,606 |
Short-term borrowings | 100 | 0 |
Accounts payable | 1,503 | 943 |
Accrued interest | 254 | 283 |
Accrued taxes | 668 | 647 |
Accrued compensation and benefits | 272 | 313 |
Dividends payable (Note 10) | 223 | 222 |
Customer deposits | 223 | 214 |
Other | 364 | 188 |
Total current liabilities | 3,958 | 4,416 |
Stockholders’ equity- | ||
Common Stock, Value, Outstanding | 57 | 57 |
Other paid-in capital | 11,322 | 10,238 |
Accumulated other comprehensive loss | (14) | (15) |
Accumulated deficit | (1,199) | (1,605) |
Total common stockholders' equity | 10,166 | 8,675 |
Noncontrolling interest | 477 | 0 |
Total equity | 10,643 | 8,675 |
Long-term debt and other long-term obligations | 21,203 | 22,248 |
Total capitalization | 31,846 | 30,923 |
NONCURRENT LIABILITIES: | ||
Accumulated deferred income taxes | 4,202 | 3,437 |
Retirement benefits | 2,335 | 2,669 |
Regulatory liabilities | 1,847 | 2,124 |
Other | 1,920 | 1,863 |
Total noncurrent liabilities | 10,304 | 10,093 |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 13) | ||
Total liabilities and capitalization | 46,108 | 45,432 |
Customer | ||
Receivables- | ||
Customers | 1,455 | 1,192 |
Less — Allowance for uncollectible customer receivables | 137 | 159 |
Current accounts receivable | $ 1,318 | $ 1,033 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Receivables- | ||
Allowance for uncollectible accounts | $ 137 | $ 159 |
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) | 572,130,932 | 570,261,104 |
Other | ||
Receivables- | ||
Allowance for uncollectible accounts | $ 11 | $ 10 |
Consolidated Statements of Stoc
Consolidated Statements of Stockholders' Equity - USD ($) $ in Millions | Total | Total Common Stockholders' Equity | Common Stock | OPIC | AOCI | Accumulated Deficit | NCI | |
Beginning Balance (in shares) at Dec. 31, 2019 | 541,000,000 | |||||||
Beginning Balance at Dec. 31, 2019 | $ 6,975 | $ 6,975 | $ 54 | $ 10,868 | $ 20 | $ (3,967) | $ 0 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
NET INCOME | 1,079 | 1,079 | 1,079 | |||||
Other comprehensive loss, net of tax | (25) | (25) | (25) | |||||
Cash dividends declared on common stock | [1] | (846) | (846) | (846) | ||||
Stock Investment Plan and share-based benefit plans (in shares) | 2,000,000 | |||||||
Stock Investment Plan and share-based benefit plans | 54 | 54 | 54 | |||||
Ending Balance (in shares) at Dec. 31, 2020 | 543,000,000 | |||||||
Ending Balance at Dec. 31, 2020 | 7,237 | 7,237 | $ 54 | 10,076 | (5) | (2,888) | 0 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
NET INCOME | 1,283 | 1,283 | 1,283 | |||||
Other comprehensive loss, net of tax | (10) | (10) | (10) | |||||
Cash dividends declared on common stock | [1] | (859) | (859) | (859) | ||||
Common Stock issuance (Note 10) (in shares) | 26,000,000 | |||||||
Common stock issuance (Note 10) | 974 | 974 | $ 3 | 971 | ||||
Stock Investment Plan and share-based benefit plans (in shares) | 1,000,000 | |||||||
Stock Investment Plan and share-based benefit plans | $ 50 | 50 | 50 | |||||
Ending Balance (in shares) at Dec. 31, 2021 | 570,261,104 | 570,000,000 | ||||||
Ending Balance at Dec. 31, 2021 | $ 8,675 | 8,675 | $ 57 | 10,238 | (15) | (1,605) | 0 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
NET INCOME | 439 | 406 | 406 | 33 | ||||
Other comprehensive loss, net of tax | 1 | 1 | 1 | |||||
Cash dividends declared on common stock | [1] | (892) | (892) | (892) | ||||
Stock Investment Plan and share-based benefit plans (in shares) | 2,000,000 | |||||||
Stock Investment Plan and share-based benefit plans | 98 | 98 | 98 | |||||
FET minority interest sale, net of transaction costs (Note 1) | 2,338 | 1,887 | 1,887 | 451 | ||||
Distribution to FET minority interest | (21) | (21) | ||||||
Capital contribution from FET minority interest | 9 | 9 | ||||||
Consolidated tax benefit allocation | 0 | (5) | (5) | 5 | ||||
Other | $ (4) | (4) | (4) | |||||
Ending Balance (in shares) at Dec. 31, 2022 | 572,130,932 | 572,000,000 | ||||||
Ending Balance at Dec. 31, 2022 | $ 10,643 | $ 10,166 | $ 57 | $ 11,322 | $ (14) | $ (1,199) | $ 477 | |
[1]Dividends declared for each share of common stock were $1.56 during 2022, 2021 and 2020. |
Consolidated Statements of St_2
Consolidated Statements of Stockholders' Equity (Parenthetical) - $ / shares | 12 Months Ended | |||
Dec. 13, 2022 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Statement of Stockholders' Equity [Abstract] | ||||
Dividends declared (in dollars per share) | $ 0.39 | $ 1.56 | $ 1.56 | $ 1.56 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
NET INCOME | $ 439 | $ 1,283 | $ 1,079 |
Adjustments to reconcile net income to net cash from operating activities- | |||
Depreciation, amortization, and impairments | 1,317 | 1,664 | 1,199 |
Retirement benefits, net of payments | (378) | (417) | (301) |
Pension and OPEB mark-to-market adjustments | (72) | (382) | 477 |
Deferred income taxes and investment tax credits, net | 989 | 297 | 113 |
Transmission revenue collections, net | 79 | 182 | (32) |
Gain on sale of Yards Creek (Note 14) | 0 | (109) | 0 |
Settlement agreement and tax sharing payments to the FES Debtors | 0 | 0 | (978) |
Gain on disposal, net of tax (Note 15) | 0 | (47) | (76) |
Changes in current assets and liabilities- | |||
Receivables | (292) | 160 | (129) |
Materials and supplies | (161) | 57 | (32) |
Prepaid taxes and other current assets | (28) | 18 | 6 |
Accounts payable | 560 | 117 | (138) |
Accrued taxes | 22 | 7 | 159 |
Accrued interest | (29) | 0 | 33 |
Other current liabilities | 21 | (52) | 81 |
Cash collateral, net | 111 | 31 | (12) |
Other | 105 | 2 | (26) |
Net cash provided from operating activities | 2,683 | 2,811 | 1,423 |
New financing- | |||
Long-term debt | 700 | 2,100 | 3,425 |
Short-term borrowings, net | 100 | 0 | 1,200 |
Common stock issuance | 0 | 1,000 | 0 |
Redemptions and repayments- | |||
Long-term debt | (3,005) | (532) | (1,114) |
Short-term borrowings, net | 0 | (2,200) | 0 |
Discounts (premiums) on debt issuances and redemptions, net | (151) | 27 | (4) |
Proceeds from FET minority interest sale, net of transaction costs | 2,348 | 0 | 0 |
Distributions to FET minority interest | (21) | 0 | 0 |
Capital contributions from FET minority interest | 9 | 0 | 0 |
Common stock dividend payments | (891) | (849) | (845) |
Other | (1) | (88) | (55) |
Net cash provided from (used for) financing activities | (912) | (542) | 2,607 |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Property additions | (2,756) | (2,445) | (2,657) |
Proceeds from sale of Yards Creek | 0 | 155 | 0 |
Sales of investment securities held in trusts | 48 | 48 | 186 |
Purchases of investment securities held in trusts | (59) | (59) | (208) |
Asset removal costs | (213) | (226) | (224) |
Other | (96) | (32) | (5) |
Net cash used for investing activities | (3,076) | (2,559) | (2,908) |
Net change in cash, cash equivalents and restricted cash | (1,305) | (290) | 1,122 |
Cash, cash equivalents, and restricted cash at beginning of period | 1,511 | 1,801 | 679 |
Cash, cash equivalents, and restricted cash at end of period | 206 | 1,511 | 1,801 |
SUPPLEMENTAL CASH FLOW INFORMATION: | |||
Interest (net of amounts capitalized) | 1,021 | 1,085 | 970 |
Income taxes, net of refunds | $ 21 | $ (7) | $ 6 |
ORGANIZATION AND BASIS OF PRESE
ORGANIZATION AND BASIS OF PRESENTATION | 12 Months Ended |
Dec. 31, 2022 | |
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 FEV which currently 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. 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. PN and Tri-County Rural Electric Cooperative have jointly decided not to move forward with the transfer. As a result, on September 30, 2022 both parties notified the NYPSC that the transaction would not occur. The accompanying consolidated financial statements have been prepared in accordance with GAAP and the rules and regulations of the SEC. 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. Economic Conditions Economic conditions following the global pandemic, have increased lead times across numerous material categories, with some as much as doubling from pre-pandemic lead times. Some key suppliers have struggled with labor shortages and raw material availability, which along with increasing inflationary pressure, have increased costs and decreased the availability of certain materials, equipment and contractors. FirstEnergy has taken steps to mitigate these risks and does not currently expect service disruptions or any material impact on its capital spending plan. However, the situation remains fluid and a prolonged continuation or further increase in supply chain disruptions could have an adverse effect on FirstEnergy’s results of operations, cash flow and financial condition. Sale of Minority Equity Interest in FirstEnergy Transmission, LLC On February 2, 2023, FE, along with FET, entered into the FET P&SA II with Brookfield and the Brookfield Guarantors, pursuant to which FE agreed to sell to Brookfield at the closing, and Brookfield agreed to purchase from FE, an incremental 30% equity interest in FET for a purchase price of $3.5 billion. The purchase price will be payable in part by the issuance of a promissory note expected to be in the principal amount of $1.75 billion. The remaining $1.75 billion of the purchase price will be payable in cash at the closing. As a result of the consummation of the transaction, Brookfield’s interest in FET will increase from 19.9% to 49.9%, while FE will retain the remaining 50.1% ownership interests of FET. The transaction is subject to customary closing conditions, including approval from the FERC and certain state utility commissions, and completion of review by the CFIUS. In addition, pursuant to the FET P&SA II, FirstEnergy has agreed to make the necessary filings with the applicable regulatory authorities for the PA Consolidation. The FET Minority Equity Interest Sale is expected to close by early 2024. Upon closing, FET will continue to be consolidated in FirstEnergy’s GAAP financial statements. Pursuant to the terms of the FET P&SA II, in connection with the closing, Brookfield, FET and FE will enter into the A&R FET LLC Agreement, which will amend and restate in its entirety the current limited liability company agreement of FET. The A&R 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 A&R FET LLC Agreement, at the closing, the FET Board will consist of five directors, two appointed by Brookfield and three appointed by FE. Each of Brookfield’s and FE’s respective appointment rights are subject to such party maintaining certain minimum ownership percentages. The A&R 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 A&R FET LLC Agreement, for so long as Brookfield holds at least a 30.0% interest in FET, Brookfield’s consent is required for FET or any of its subsidiaries to, among other things, undertake certain acquisitions or dispositions in excess of certain dollar thresholds, establish or amend the annual budget, incur cost overruns on certain capital expenditures projects during any fiscal year in excess of a certain percentage overage of the budgeted amounts or incur cost overruns on the aggregate capital expenditure budget of FET’s subsidiaries during any fiscal year in excess of a certain percentage overage of the aggregated budgeted amount, make material decisions relating to litigation where either the potential liability exposure is in excess of a certain threshold dollar amount or such proceeding would reasonably be expected to have an adverse effect on Brookfield or FET, make certain material regulatory filings, incur or refinance indebtedness by FET or its subsidiaries, which, in the case of its subsidiaries, would reasonably be expected to cause such subsidiary to deviate from its targeted capital structure, enter into joint ventures, appoint or replace any member of its transmission leadership team, amend the accounting policies of FET or its subsidiaries (but only if FirstEnergy Corp is no longer the majority owner of FET), take any action that would reasonably be expected to cause a default or breach of any material contract of FET or any of its subsidiaries, create certain material liens (excluding certain permitted liens), or cause any reorganization of FET or any of its subsidiaries. The A&R FET LLC Agreement also includes provisions relating to the resolution of disputes and to address deadlocks. Consolidation of Pennsylvania Companies FirstEnergy is proceeding with the consolidation of the Pennsylvania Companies into a new, single operating entity. The PA Consolidation will require, among other steps: (a) the transfer of certain Pennsylvania-based transmission assets owned by WP to KATCo, (b) the transfer of Class B equity interests of MAIT currently held by PN and ME to FE (and ultimately transferred to FET as part of the FET Minority Equity Interest Sale), (c) the formation of PA NewCo and (d) the merger of each of the Pennsylvania Companies with and into PA NewCo, with PA NewCo surviving such mergers as the successor-in-interest to all assets and liabilities of the Pennsylvania Companies. Following completion of the PA Consolidation, PA NewCo will be FE’s only regulated utility in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies. Consummation of the PA Consolidation is contingent upon numerous conditions, including the approval of NYPSC, PPUC and FERC. Subject to receipt of such regulatory approvals, FirstEnergy expects that the PA Consolidation will close by early 2024. 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, 2022 and 2021, and the changes during the year ended December 31, 2022: As of December 31, Net Regulatory Assets (Liabilities) by Source 2022 2021 Change (In millions) Customer payables for future income taxes $ (2,463) $ (2,345) $ (118) Spent nuclear fuel disposal costs (83) (101) 18 Asset removal costs (675) (646) (29) Deferred transmission costs 50 (3) 53 Deferred generation costs 235 118 117 Deferred distribution costs 164 49 115 Storm-related costs 683 660 23 Uncollectible and pandemic-related costs 63 56 7 Energy efficiency program costs 94 47 47 New Jersey societal benefit costs 94 109 (15) Vegetation management 63 33 30 Other (39) (30) (9) Net Regulatory Liabilities included on the Consolidated Balance Sheets $ (1,814) $ (2,053) $ 239 The following table provides information about the composition of net regulatory assets that do not earn a current return as of December 31, 2022 and 2021, of which approximately $511 million and $228 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 2022 2021 Change (In millions) Deferred transmission costs $ 8 $ 13 $ (5) Deferred generation costs 262 63 199 Deferred distribution costs 27 2 25 Storm-related costs 568 549 19 Pandemic-related costs 70 65 5 Vegetation management 52 31 21 Other 10 9 1 Regulatory Assets Not Earning a Current Return $ 997 $ 732 $ 265 DERIVATIVES FirstEnergy is exposed to limited 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. EQUITY METHOD INVESTMENTS 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 reflected in "Investments". The percentage of FE's ownership share of the entity’s earnings is reported in the Consolidated Statements of Income and Comprehensive Income and reflected in “Miscellaneous Income, net”. Equity method investments are assessed for impairment annually or whenever events and changes in circumstances indicate that the carrying amount of the investment may not be recoverable. If the decline in value is considered to be other than temporary, the investment is written down to its estimated fair value, which establishes a new cost basis in the investment. Equity method investments included within "Investments" on the Consolidated Balance Sheets were $90 million and $88 million as of December 31, 2022 and 2021, respectively. Global Holdings - FEV currently 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 primarily focused on 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. For the years ended December 31, 2022, 2021 and 2020, pre-tax income related to FEV’s ownership in Global Holding was $168 million, $29 million and $2 million, respectively. FEV’s pre-tax equity earnings and investment in Global Holding are included in Corporate/Other for segment reporting. As of December 31, 2022 and 2021, the carrying value of the equity method investment was $57 million and $59 million, respectively. During 2022, FEV received cash dividends from Global Holding totaling $170 million, which were classified with “Cash from Operating Activities” on FirstEnergy’s Consolidated Statements of Cash Flow. 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, 2022 and 2021, the carrying value of the equity method investment was $18 million. FirstEnergy's pre-tax equity earnings in PATH-WV were immaterial for the years ended December 31, 2022, 2021 and 2020 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 10, “Capitalization,” for additional information on securitized bonds. Unconsolidated VIEs FirstEnergy is not the primary beneficiary of its equity method investments in Global Holding and PATH WV, as further discussed above, or its PPAs. 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 the Public Utility Regulatory Policies Act of 1978. 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. 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, 2022, 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, 2022: (In millions) Regulated Distribution Regulated Transmission Consolidated Goodwill $ 5,004 $ 614 $ 5,618 INVENTORY Materials and supplies inventory primarily includes emission allowances, 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. Emission allowances are accounted for at cost when purchased and charged to expense monthly based on each month’s emissions. NONCONTROLLING INTEREST FirstEnergy maintains a controlling financial interest in certain less than wholly owned subsidiaries. As a result, FirstEnergy presents the third-party investors’ ownership portion of FirstEnergy's net income, net assets and comprehensive income as noncontrolling interest. Noncontrolling interest is included as a component of equity on the Consolidated Balance Sheets. On November 6, 2021, FirstEnergy, along with FET, entered into the FET P&SA I, with Brookfield and the 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 would own 19.9% of the issued and outstanding membership interests of FET, for a purchase price of $2.375 billion. The transaction closed on May 31, 2022. The difference between the cash consideration received, net of transaction costs of approximately $37 million, and the carrying value of the noncontrolling interest of $451 million was recorded as an increase to OPIC. KATCo, which was a subsidiary of FET, became a wholly owned subsidiary of FE prior to the closing of the transaction and remains in the Regulated Transmission segment. 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, 2022 and 2021, were as follows: December 31, 2022 Property, Plant and Equipment In Service (1) Accum. Depr. Net Plant CWIP Total (In millions) Regulated Distribution $ 32,257 $ (9,636) $ 22,621 $ 828 $ 23,449 Regulated Transmission 14,468 (2,978) 11,490 818 12,308 Corporate/Other 1,125 (644) 481 47 528 Total $ 47,850 $ (13,258) $ 34,592 $ 1,693 $ 36,285 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 (1) Includes finance leases of $105 million and $143 million as of December 31, 2022 and 2021, respectively. Regulated Distribution has approximately $2.2 billion of total regulated generation property, plant and equipment as of December 31, 2022. 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 2022, 2021 and 2020. For the years ended December 31, 2022, 2021 and 2020, capitalized financing costs on FirstEnergy's Consolidated Statements of Income include $56 million, $48 million and $49 million, respectively, of allowance for equity funds used during construction and $28 million, $27 million and $28 million, respectively, of capitalized interest. 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. 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. 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 2022 and 2021: ARO Reconciliation (In millions) Balance, January 1, 2021 $ 159 Changes in timing and amount of estimated cash flows 8 Liabilities settled (1) Accretion 13 Balance, December 31, 2021 $ 179 Changes in timing and amount of estimated cash flows (2) Liabilities settled (6) Accretion 14 Balance, December 31, 2022 $ 185 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, 2022. 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. NEW ACCOUNTING PRONOUNCEMENTS Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB has not yet been adopted. Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable. FirstEnergy has assessed other FASB issuances of new standards not described below based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting. ASU 2022-03, " Fair Value Measurements of Equity Securities Subject to Contractual Sale Restrictions " (Issued in June 2022): ASU 2022-03 clarifies current guidance in Topic 820, Fair Value Measurement, when measuring the fair value of an equity security subject to contractual restrictions that prohibit the sale of an equity security, and introduces new disclosure requirements for those equity securities subject to contractual restrictions. For FirstEnergy, the guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2023, with early adoption permitted. |
REVENUE
REVENUE | 12 Months Ended |
Dec. 31, 2022 | |
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. 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. 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. 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 rate base and actual costs. Revenues and cash receipts for the stand-ready obligation of providing transmission service are recognized ratably over time. The following represents a disaggregation of revenue from contracts with customers for the years ended December 31, 2022, 2021 and 2020: For the Years Ended December 31, (In millions) 2022 2021 2020 Regulated Distribution Retail generation and distribution services (1) Residential $ 6,180 $ 5,713 $ 5,539 Commercial 2,499 2,284 2,140 Industrial 1,338 1,091 1,076 Other 85 75 81 Wholesale 494 362 251 Other revenue from contracts with customers 104 119 140 Total revenues from contracts with customers 10,700 9,644 9,227 ARP (2) — (27) 43 Other revenue unrelated to contracts with customers 101 94 93 Total Regulated Distribution $ 10,801 $ 9,711 $ 9,363 Regulated Transmission ATSI $ 912 $ 799 $ 804 TrAIL 270 233 247 MAIT 340 288 250 JCP&L 203 164 178 MP, PE and WP 138 124 134 Total revenues from contracts with customers 1,863 1,608 1,613 Other revenue unrelated to contracts with customers 5 10 17 Total Regulated Transmission $ 1,868 $ 1,618 $ 1,630 Corporate/Other and Reconciling Adjustments (3) Wholesale $ 27 $ 14 $ 9 Retail generation and distribution services (3) (186) (154) (148) Other revenue unrelated to contracts with customers (3) (51) (57) (64) Total Corporate/Other and Reconciling $ (210) $ (197) $ (203) FirstEnergy Total Revenues $ 12,459 $ 11,132 $ 10,790 (1) Includes approximately $58 million and $38 million as of December 31, 2022 and 2021, respectively, of customer refunds associated with the Ohio Stipulation that became effective in December 2021. See Note 12, “Regulatory Matters,” for further discussion. (2) Reflects amount the Ohio Companies refunded to customers that was previously collected under decoupling mechanisms, with interest. (3) Includes eliminations and reconciling adjustments of inter-segment revenues. Other revenue unrelated to contracts with customers includes revenue from late payment charges of $38 million, $36 million and $31 million, respectively, for the years ended December 31, 2022, 2021 and 2020. Other revenue unrelated to contracts with customers also includes revenue from derivatives of $15 million, $11 million and $14 million, respectively, for the years ended December 31, 2022, 2021 and 2020. RECEIVABLES Receivables from contracts 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, 2022 and 2021, with respect to any particular segment of FirstEnergy’s customers. Billed and unbilled customer receivables as of December 31, 2022 and 2021, are included below. As of December 31, Customer Receivables 2022 2021 (In millions) Billed (1) $ 674 $ 616 Unbilled 781 576 1,455 1,192 Less: Uncollectible Reserve 137 159 Total Customer Receivables $ 1,318 $ 1,033 (1) Includes approximately $290 million and $318 million as of December 31, 2022 and 2021, respectively, that are past due by greater than 30 days. 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. FirstEnergy reviews its allowance for uncollectible customer receivables utilizing a quantitative and qualitative assessment. 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. This analysis includes consideration of the outbreak of the pandemic and the impact on customer receivable balances outstanding and write-offs since the pandemic began and subsequent economic slowdown. FirstEnergy’s uncollectible risk on PJM receivables, resulting from transmission and wholesale sales, 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. During 2021, arrears levels continued to be elevated above 2019 pre-pandemic levels. Various regulatory actions impacted the growth and recovery of past due balances including extensions on moratoriums, significant restrictions regarding disconnections, and extended installment plans. FirstEnergy 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 continued to decrease in 2021, balances over 120 days past due continued 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 during 2021. During 2022, various regulatory actions including extensions on moratoriums, certain restrictions on disconnections and extended installment plan offerings continue to impact the level of past due balances in certain states. However, certain states have resumed normal collections activity and arrears levels have declined towards pre-pandemic levels. As a result, FirstEnergy recognized a $25 million decrease in its allowance for uncollectible customer receivables during the first quarter of 2022, of which $15 million was applied to existing deferred regulatory assets. As a result of certain customer installment or extended payment plans, inflationary pressures on customers and the economic slowdown, there were no material changes to the allowance for uncollectible customer receivables during the remainder of 2022. Additionally, as a result of the pandemic-related moratoriums and certain customer installment or extended payment plans offered, which caused the extension of when certain write offs would have otherwise occurred, the allowance for uncollectible accounts on receivables remains elevated above 2019 pre-pandemic levels. Activity in the allowance for uncollectible accounts on receivables for the years ended December 31, 2022, 2021 and 2020 are as follows: (In millions) 2022 2021 2020 (3) Customer Receivables Beginning of year balance $ 159 $ 164 $ 46 Charged to income (1) 59 54 174 Charged to other accounts (2) 62 42 46 Write-offs (143) (101) (102) End of year balance $ 137 $ 159 $ 164 Other Receivables Beginning of year balance $ 10 $ 26 $ 21 Charged to income 4 3 7 Charged to other accounts (2) 4 3 10 Write-offs (7) (22) (12) End of year balance $ 11 $ 10 $ 26 (1) Customer receivable amounts charged to income for the years ended December 31, 2022, 2021, and 2020 include approximately $11 million, $12 million, and $103 million respectively, deferred for future recovery. 2020 amounts charged to income includes $121 million of incremental expense due to pandemic conditions. (2) Represents recoveries and reinstatements of accounts previously written off for uncollectible accounts. |
EARNINGS PER SHARE OF COMMON ST
EARNINGS PER SHARE OF COMMON STOCK | 12 Months Ended |
Dec. 31, 2022 | |
Earnings Per Share [Abstract] | |
EARNINGS PER SHARE OF COMMON STOCK | EARNINGS PER SHARE OF COMMON STOCK EPS is calculated by dividing earnings attributable to FE by the weighted average number of common shares outstanding. Basic EPS 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. Diluted EPS reflects the dilutive effect of potential common shares from share-based awards. 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 following table reconciles basic and diluted EPS attributable to FE: For the Years Ended December 31, Reconciliation of Basic and Diluted EPS of Common Stock 2022 2021 2020 (In millions, except per share amounts) Earnings Attributable to FE - continuing operations $ 406 $ 1,239 $ 1,003 Earnings Attributable to FE - discontinued operations, net of tax — 44 76 Earnings Attributable to FE $ 406 $ 1,283 $ 1,079 Share Count information: Weighted average number of basic shares outstanding 571 545 542 Assumed exercise of dilutive share based awards 1 1 1 Weighted average number of diluted shares outstanding 572 546 543 EPS Attributable to FE: Income from continuing operations, basic $ 0.71 $ 2.27 $ 1.85 Discontinued operations, basic — 0.08 0.14 Basic EPS $ 0.71 $ 2.35 $ 1.99 Income from continuing operations, diluted $ 0.71 $ 2.27 $ 1.85 Discontinued operations, diluted — 0.08 0.14 Diluted EPS $ 0.71 $ 2.35 $ 1.99 For the years ended December 31, 2022, 2021 and 2020, there were no material amount of shares excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. |
ACCUMULATED OTHER COMPREHENSIVE
ACCUMULATED OTHER COMPREHENSIVE INCOME | 12 Months Ended |
Dec. 31, 2022 | |
Equity [Abstract] | |
ACCUMULATED OTHER COMPREHENSIVE INCOME | ACCUMULATED OTHER COMPREHENSIVE INCOME The changes in AOCI for the years ended December 31, 2022, 2021 and 2020, for FirstEnergy are shown in the following table: Gains & Losses on Cash Flow Hedges (1) Defined Benefit Pension & OPEB Plans (2)(3) Total (In millions) AOCI Balance, January 1, 2020 $ (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) Amounts reclassified from AOCI 9 (9) — Other comprehensive income (loss) 9 (9) — Income tax (benefits) on other comprehensive income (loss) 2 (3) (1) Other comprehensive income (loss), net of tax 7 (6) 1 AOCI Balance, December 31, 2022 $ — $ (14) $ (14) (1) Relates to previous cash flow hedges used to hedge fixed rate long-term debt securities prior to their issuance. Amounts reclassified from AOCI affects Interest expense line item in Consolidated Statements of Income. (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 5, "Pension and Other Post-Employment Benefits," for additional details. (3) Income tax (benefits) on other comprehensive income (loss) affects Income taxes line item in Consolidated Statements of Income. |
PENSION AND OTHER POST-EMPLOYME
PENSION AND OTHER POST-EMPLOYMENT BENEFITS | 12 Months Ended |
Dec. 31, 2022 | |
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 until 2025, which, based on various assumptions, including annual expected rate of return on assets of 8.0% in 2023, is expected to be approximately $250 million. 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. Actuarial Assumptions Pension OPEB 2022 2021 2020 (2) 2022 2021 2020 (2) Assumptions Related to Benefit Obligations: Discount rate 5.23 % 3.02 % 2.67 % 5.16 % 2.84 % 2.45 % Rate of compensation increase 4.30 % 4.10 % 4.10 % N/A N/A N/A Cash balance weighted average interest crediting rate 4.04 % 2.57 % 2.57 % N/A N/A N/A Assumptions Related to Benefit Costs: (1) Effective rate for interest on benefit obligations 2.44 % 1.94 % 2.89%/2.48% 2.18 % 1.66 % 2.71%/2.30% Effective rate for service costs 3.28 % 3.10 % 3.60%/3.24% 3.41 % 3.03 % 3.63%/3.29% Effective rate for interest on service costs 2.96 % 2.58 % 3.27%/2.90% 3.24 % 2.83 % 3.43%/3.06% 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 Assumed Health Care Cost Trend Rates: Health care cost trend rate assumed (pre/post-Medicare) N/A N/A N/A 6.00%- 5.50% 5.75%- 5.25% 6.00%- 5.50% Rate to which the cost trend rate is assumed to decline (ultimate trend rate) N/A N/A N/A 4.50 % 4.50 % 4.50 % Year that the rate reaches the ultimate trend rate N/A N/A N/A 2029 2028 2028 (1) Excludes impact of pension and OPEB mark-to-market adjustment. (2) As a result of the interim plan remeasurement during 2020 there were different rates in effect from January 1, 2020, through February 26, 2020 compared to February 27, 2020 through December 31, 2020. 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 2022, FirstEnergy’s qualified pension and OPEB plan assets experienced losses of $1,830 million or (19.1)%, compared to gains of $689 million, or 7.9% in 2021, and gains of $1,225 million, or 14.7% in 2020 and assumed a 7.50% rate of return on plan assets in 2022, 2021 and 2020, which generated $696 million, $688 million and $651 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, the historical performance of risk-based and fixed income securities and other factors. 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 2022, the Society of Actuaries elected not to release a new mortality improvement scale due to data available being severely impacted by COVID-19. It was determined that the Pri-2012 mortality table with projection scale MP-2021, actuarially adjusted to reflect increased mortality due to the ongoing impact of COVID-19 was most appropriate and such was utilized to determine the obligation as of December 31, 2022, for the FirstEnergy pension and OPEB plans. This adjustment acknowledges COVID-19 cannot be eradicated and assumes reductions in other causes will not offset future COVID-19 deaths enough to produce a normal level of improvements. 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 $23 million for the pension plans and was included in the 2022 pension and OPEB mark-to-market adjustment. Net Periodic Benefit Costs (Credits) - 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. Components of Net Periodic Benefit Costs (Credits) for the Years Ended December 31, Pension OPEB 2022 2021 2020 2022 2021 2020 (In millions) Service cost (1) $ 184 $ 195 $ 194 $ 3 $ 4 $ 4 Interest cost 273 226 287 11 11 15 Expected return on plan assets (657) (652) (618) (39) (36) (33) Amortization of prior service costs (credits) (2) 2 3 12 (11) (17) (46) One-time termination benefits (3) — — 8 — — — Pension & OPEB mark-to-market (98) (253) 463 26 (129) 14 Net periodic benefit costs (credits) $ (296) $ (481) $ 346 $ (10) $ (167) $ (46) (1) Includes amounts capitalized. (2) 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. (3) Costs represent additional benefits provided to FES and FENOC employees under the approved settlement agreement and are a component of discontinued operations. Approximately $15 million, $(31) million and $40 million of the annual pension and OPEB mark-to-market charges (credits) were allocated to the Regulated Transmission companies under forward-looking formula rates, and expected to be refunded or recovered through formula transmission rates, respectively. The 2022 pension and OPEB mark-to-market adjustment primarily reflects a 221 bps increase in the discount rate used to measure pension benefit obligations partially offset by lower than expected asset returns. Pension OPEB Obligations/Funded Status - Qualified and Non-Qualified Plans 2022 2021 2022 2021 (In millions) Change in benefit obligation: Benefit obligation as of January 1 $ 11,479 $ 11,935 $ 549 $ 676 Service cost 184 195 3 4 Interest cost 273 226 11 11 Plan participants’ contributions — — 3 4 Medicare retiree drug subsidy — — 1 1 Actuarial loss (gain) (2,515) (280) (83) (101) Benefits paid (593) (597) (45) (46) Benefit obligation as of December 31 $ 8,828 $ 11,479 $ 439 $ 549 Change in fair value of plan assets: Fair value of plan assets as of January 1 $ 9,020 $ 8,968 $ 548 $ 502 Actual return on plan assets (1,760) 625 (70) 64 Company contributions 26 24 24 24 Plan participants’ contributions — — 3 4 Benefits paid (593) (597) (45) (46) Fair value of plan assets as of December 31 $ 6,693 $ 9,020 $ 460 $ 548 Funded Status: Qualified plan $ (1,734) $ (1,974) $ — $ — Non-qualified plans (401) (485) — — Funded Status (Net liability as of December 31) $ (2,135) $ (2,459) $ 21 $ (1) Accumulated benefit obligation $ 8,500 $ 10,927 $ — $ — Amounts Recognized in AOCI: Prior service cost (credit) $ 6 $ 9 $ (10) $ (21) The following tables set forth pension financial assets that are accounted for at fair value by level within the fair value hierarchy. See Note 9, "Fair Value Measurements," for a description of each level of the fair value hierarchy. There were no significant transfers between levels during 2022 and 2021. December 31, 2022 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 714 $ — $ 714 11 % Public equity 1,871 216 — 2,087 33 % Fixed income — 942 — 942 15 % Derivatives (38) 2 — (36) (1) % Total (1) $ 1,833 $ 1,874 $ — $ 3,707 58 % Private - equity and debt funds (2) 1,061 17 % Insurance-linked securities (2) 159 3 % Hedge funds (2) 563 9 % Real estate funds (2) 853 13 % Total Investments $ 6,343 100 % (1) Excludes $350 million as of December 31, 2022, of receivables, payables, taxes, cash collateral for derivatives 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, 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 (3) 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. As of December 31, 2022, and 2021, the OPEB trust investments measured at fair value were as follows: December 31, 2022 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 87 $ — $ 87 19 % Public equity 217 — — 217 47 % Fixed income — 157 — 157 34 % Total (1) $ 217 $ 244 $ — $ 461 100 % (1) Excludes $(1) million as of December 31, 2022, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. 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 % FirstEnergy’s target asset allocations for its pension and OPEB trust portfolios for 2022 were as follows: Target Asset Allocations Pension OPEB Equities 36 % 50 % Fixed income 22.5 % 50 % Alternative investments 5 % — % Real estate 10 % — % Private - equity and debt funds 20 % — % Cash and derivatives 6.5 % — % 100 % 100 % 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. 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) 2023 $ 583 $ 44 $ (1) 2024 587 42 (1) 2025 597 40 (1) 2026 605 39 — 2027 612 37 — Years 2028-2031 3,120 167 (2) |
STOCK-BASED COMPENSATION PLANS
STOCK-BASED COMPENSATION PLANS | 12 Months Ended |
Dec. 31, 2022 | |
Share-Based Payment Arrangement [Abstract] | |
STOCK-BASED COMPENSATION PLANS | STOCK-BASED COMPENSATION PLANSFirstEnergy 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, 2022, approximately 11.9 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 less than a year 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, 2022, 2021 and 2020, were $8 million, $10 million and $20 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, 2022, 2021 and 2020, are included in the following tables: For the Years Ended December 31, Stock-based Compensation Plan 2022 2021 2020 (In millions) Restricted stock units $ 55 $ 40 $ 22 Restricted stock 3 2 1 401(k) savings plan 36 35 33 EDCP & DCPD 7 13 (5) Total $ 101 $ 90 $ 51 Stock-based compensation costs, net of amounts capitalized $ 54 $ 43 $ 25 Income tax benefits associated with stock-based compensation plan expense were $8 million, $5 million and $3 million for the years ended December 31, 2022, 2021 and 2020, respectively. Restricted Stock Units Two-thirds of each performance-based restricted stock unit 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 market 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. Beginning with awards granted in 2022, restricted stock units include a relative total shareholder return as a performance metric, utilizing the S&P 500 Utility Index as a comparator group. The estimated grant date fair value for these awards is also calculated using the Monte Carlo simulation method. In addition, outstanding awards are subject to an absolute total shareholder return, if FirstEnergy's is negative for the three 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, 2022, was $20 million. During 2022, approximately $9 million was paid in relation to the cash portion of restricted stock unit obligations that vested in 2022. The vesting period for the performance-based restricted stock unit awards granted in 2020, 2021 and 2022, 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, 2022, was as follows: Restricted Stock Unit Activity Shares (in millions) Weighted-Average Grant Date Fair Value (per share) Nonvested as of January 1, 2022 1.8 $ 41.89 Granted in 2022 1.0 41.19 Forfeited in 2022 (0.3) 39.58 Vested in 2022 (1) (0.6) 41.57 Nonvested as of December 31, 2022 1.9 $ 41.57 (1) Excludes dividend equivalents of approximately 80 thousand shares earned during vesting period. The weighted-average fair value per share of awards granted in 2022, 2021 and 2020 was $41.19, $35.50 and $44.42 per share, respectively. For the years ended December 31, 2022, 2021, and 2020, the fair value of restricted stock units vested was $26 million, $34 million, and $80 million, respectively. As of December 31, 2022, there was approximately $27 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 2022, was not material. 401(k) Savings Plan In 2022 and 2021, approximately 1 million shares of FE common stock, respectively, were issued and contributed to employee 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. Awards deferred into a retirement stock account will pay out in cash upon separation, including retirement, 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. The liability recognized for EDCP of approximately $193 million and $201 million as of December 31, 2022 and 2021, respectively, is included in “Retirement benefits,” on the Consolidated Balance Sheets. 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 $8 million and $9 million as of December 31, 2022 and 2021, respectively, is included in “Retirement benefits,” on the Consolidated Balance Sheets. |
TAXES
TAXES | 12 Months Ended |
Dec. 31, 2022 | |
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. Prior to 2022, net tax benefits attributable to FE, excluding any tax benefits derived from certain interest expense, were generally reallocated to the subsidiaries of FE that have taxable income. Effective January 1, 2022, the intercompany income tax allocation agreement was amended and revised whereas FE no longer reallocates such tax benefits to the FE subsidiaries. On August 16, 2022, President Biden signed into law the IRA of 2022, which, among other things, imposes a new 15% corporate AMT based on AFSI applicable to corporations with a three-year average AFSI over $1 billion. The AMT is effective for the 2023 tax year and, if applicable, corporations must pay the greater of the regular corporate income tax or the AMT. Although NOL carryforwards created through the regular corporate income tax system cannot be used to reduce the AMT, financial statement net operating losses can be used to reduce AFSI and the amount of AMT owed. The IRA of 2022 as enacted requires the U.S. Treasury to provide regulations and other guidance necessary to administer the AMT, including further defining allowable adjustments to determine AFSI, which directly impacts the amount of AMT to be paid. Based on interim guidance issued by the U.S. Treasury in late December 2022, FirstEnergy continues to believe that it is more likely than not it will be subject to the AMT beginning 2023. Until final U.S. Treasury guidance is issued, the amount of AMT FirstEnergy would pay could be significantly different than current estimates or it may not be a payer at all. The regulatory treatment of the impacts of this legislation will also be subject to the discretion of the FERC and state public utility commissions. Any adverse development in this legislation, including guidance from the U.S. Treasury and/ or the IRS or unfavorable regulatory treatment, could reduce future cash flows and impact financial condition. As discussed above, FirstEnergy expects to close on the sale of an additional 30% interest in FET in 2024, at which time FirstEnergy expects to realize an approximate $7.1 billion tax gain from the combined sale of 49.9% of the membership interests of FET, approximately $3.5 billion of which is attributable to the sale of 30% and the remainder being gain deferred from the sale of 19.9% in 2022, including consideration received and recapture of negative tax basis in FET. Upon closing in 2024, FET will be deconsolidated from FirstEnergy’s consolidated federal income tax group, however, FET will continue to be consolidated in FirstEnergy’s GAAP financial statements. As of December 31, 2022, FirstEnergy had approximately $7.1 billion of federal NOL carryforwards, all of which it expects to utilize by the end of 2024 to mostly offset taxable income and the tax gains associated with the combined 49.9% sales in FET. As a result of the expected additional sale in FET, FirstEnergy recognized a charge to income tax expense in the fourth quarter of 2022 of approximately $752 million, representing the deferred tax liability associated with the deferred tax gain on the 19.9% sale closed in May 2022. Additionally, FirstEnergy recognized a $54 million benefit to income tax expense in the fourth quarter of 2022 associated with reversal of certain valuation allowances on state income tax NOL carryforwards that are now expected to be utilized as a result of the tax gain associated with the transaction. See Note 1, "Organization, Basis of Presentation and Significant Accounting Policies", for further discussion of the additional minority interest sale in FET. On July 8, 2022, Pennsylvania’s Governor signed into law Pennsylvania House Bill 1342, which reduces Pennsylvania’s corporate net income tax rate from 9.99% to 8.99% beginning January 1, 2023, and an additional 0.5% annually through 2031, when it reaches 4.99%. As of December 31, 2022, FirstEnergy recorded a $230 million net decrease to FirstEnergy’s ADIT liabilities, with a corresponding increase in regulatory liabilities of $236 million, which are expected to be settled through future customer rates, and a $6 million increase in income tax expense. The decrease in the Pennsylvania income tax rate is not expected to have a material impact to FirstEnergy’s future financial statements. During 2022, FirstEnergy recognized an income statement benefit of approximately $38 million from remeasurement of a valuation allowance previously recorded on business interest expense carryforwards from the 2018 and 2019 tax years. The business interest expense could not be deducted previously due to certain limitations imposed on interest expense from non-utility operations under section 163(j) of the Tax Act. As provided by the Tax Act, the nondeductible interest expense can be carried forward, indefinitely, and deducted against income from non-utility operations. Due primarily to the realized and expected future earnings from FEV’s equity ownership in Global Holding, FirstEnergy expects to utilize a portion of the interest expense carryforward on its consolidated federal income tax return. For the Years Ended December 31, INCOME TAXES (1) 2022 2021 2020 (In millions) Currently payable (receivable)- Federal (2) $ — $ 2 $ (14) State 11 21 21 11 23 7 Deferred, net- Federal (3) 946 174 171 State (4) 47 127 (38) 993 301 133 Investment tax credit amortization (4) (4) (14) Total income taxes $ 1,000 $ 320 $ 126 (1) Income Taxes on Income from Continuing Operations. (2) Excludes $2 million of federal tax benefit associated with discontinued operations for the years ended December 31, 2021. (3) Excludes $46 million and $66 million of federal tax benefits associated with discontinued operations for the years ended December 31, 2021 and 2020, respectively. (4) Excludes $1 million of state tax expense associated with discontinued operations for the year ended December 31, 2020. 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, 2022, 2021 and 2020: For the Years Ended December 31, 2022 2021 2020 (In millions) Income from Continuing Operations, before income taxes $ 1,439 $ 1,559 $ 1,129 Federal income tax expense at statutory rate (21%) $ 302 $ 327 $ 237 Increases (reductions) in taxes resulting from- State and municipal income taxes, net of federal tax benefit 56 122 75 AFUDC equity and other flow-through (26) (29) (38) Amortization of investment tax credits (4) (4) (14) Deferred gain on 19.9% FET minority interest sale 752 — — Federal tax credits claimed (3) (34) — Nondeductible DPA monetary penalty — 52 — Excess deferred tax amortization due to the Tax Act (51) (54) (56) TMI-2 reversal of tax regulatory liabilities — — (40) Uncertain tax positions 2 (82) (1) Valuation allowances (47) 17 (49) Other, net 19 5 12 Total income taxes $ 1,000 $ 320 $ 126 Effective income tax rate 69.5 % 20.5 % 11.2 % Accumulated deferred income taxes as of December 31, 2022 and 2021, are as follows: As of December 31, 2022 2021 (In millions) Property basis differences $ 5,528 $ 5,670 Pension and OPEB (496) (570) AROs (22) (21) Regulatory asset/liability 432 322 Deferred compensation (149) (155) Deferred gain on 19.9% FET minority interest sale 752 — Loss carryforwards and tax credits (2,073) (2,040) Valuation reserve 440 484 All other (210) (253) Net deferred income tax liability $ 4,202 $ 3,437 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, 2022, FirstEnergy's loss carryforwards primarily consisted of $7.1 billion ($1.5 billion, net of tax) of federal NOL carryforwards, $5 billion ($1 billion, net of tax) which have no expiration and the remainder that will begin to expire in 2031, and federal general business tax credits of $51 million that begin to expire in 2030. As discussed above, FirstEnergy expects to utilize all the federal NOL carryforwards by the end of 2024 to mostly offset taxable income and the tax gain recognized from the combined sale of the 49.9% equity interest in FET. The table below summarizes pre-tax NOL carryforwards and their respective anticipated expirations for state and local income tax purposes of approximately $12.6 billion ($568 million, net of tax) for FirstEnergy, of which approximately $3.9 billion ($199 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) 2023-2027 $ 2,479 $ 4,317 2028-2032 1,603 — 2033-2037 876 — 2038-2042 935 — Indefinite 2,351 — $ 8,244 $ 4,317 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, 2022, 2021 and 2020: (In millions) 2022 2021 2020 Beginning of year balance $ 484 $ 496 $ 441 Charged to income (44) (12) 55 Charged to other accounts — — — Write-offs — — — End of year balance $ 440 $ 484 $ 496 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. If ultimately recognized in future years, approximately $41 million of unrecognized income tax benefits would impact the effective tax rate. As of December 31, 2022, it is reasonably possible that approximately $25 million of unrecognized tax benefits may be resolved during 2023 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, 2022, 2021 and 2020: (In millions) Balance, January 1, 2020 $ 164 Current year increases 7 Prior year decreases (28) Effectively settled with taxing authorities (2) Decrease for lapse in statute (2) Balance, December 31, 2020 $ 139 Current year increases 15 Prior year decreases (8) Effectively settled with taxing authorities (97) Decrease for lapse in statute (2) Balance, December 31, 2021 $ 47 Prior years increases 2 Decrease for lapse in statute (7) Balance, December 31, 2022 $ 42 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 2022, 2021 and 2020, was not material. For the years ended December 31, 2022 and 2021, 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, 2022, 2021 and 2020, recognized in continuing operations is summarized as follows: For the Years Ended December 31, 2022 2021 2020 (In millions) kWh excise $ 191 $ 189 $ 183 State gross receipts 219 190 182 Real and personal property 596 571 541 Social security and unemployment 105 103 112 Other 18 20 28 Total general taxes $ 1,129 $ 1,073 $ 1,046 |
LEASES
LEASES | 12 Months Ended |
Dec. 31, 2022 | |
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, 2022 (In millions) Vehicles Buildings Other Total Operating lease costs (1) $ 50 $ 8 $ 15 $ 73 Finance lease costs: Amortization of right-of-use assets 10 1 2 13 Interest on lease liabilities — 3 — 3 Total finance lease cost 10 4 2 16 Total lease cost $ 60 $ 12 $ 17 $ 89 (1) Includes $19 million of short-term lease costs. 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. Supplemental cash flow information related to leases was as follows: For the Years Ended December 31, (In millions) 2022 2021 2020 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 56 $ 64 $ 44 Operating cash flows from finance leases 3 4 4 Finance cash flows from finance leases 12 13 15 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 26 $ 60 $ 67 Finance leases — 5 — Lease terms and discount rates were as follows: As of December 31, 2022 2021 2020 Weighted-average remaining lease terms (years) Operating leases 7.30 7.97 8.55 Finance leases 11.33 8.12 7.74 Weighted-average discount rate (1) Operating leases 4.22 % 4.16 % 4.21 % Finance leases 14.77 % 12.22 % 11.58 % (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 2022 2021 Assets Operating lease (1) Deferred charges and other assets $ 262 $ 279 Finance lease (2) Property, plant and equipment 45 48 Total leased assets $ 307 $ 327 Liabilities Current: Operating Other current liabilities $ 48 $ 39 Finance Currently payable long-term debt 6 13 Noncurrent: Operating Other noncurrent liabilities 247 271 Finance Long-term debt and other long-term obligations 17 23 Total leased liabilities $ 318 $ 346 (1) Operating lease assets are recorded net of accumulated amortization of $114 million and $79 million as of December 31, 2022 and 2021, respectively. (2) Finance lease assets are recorded net of accumulated amortization of $60 million and $95 million as of December 31, 2022 and 2021, respectively. Maturities of lease liabilities as of December 31, 2022, were as follows: (In millions) Operating Leases Finance Leases Total 2023 $ 56 $ 9 $ 65 2024 52 5 57 2025 49 5 54 2026 45 5 50 2027 39 4 43 Thereafter 105 5 110 Total lease payments (1) 346 33 379 Less imputed interest 51 10 61 Total net present value $ 295 $ 23 $ 318 (1) Operating lease payments for certain leases are offset by sublease receipts of $9 million over 10 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, 2022 (In millions) Vehicles Buildings Other Total Operating lease costs (1) $ 50 $ 8 $ 15 $ 73 Finance lease costs: Amortization of right-of-use assets 10 1 2 13 Interest on lease liabilities — 3 — 3 Total finance lease cost 10 4 2 16 Total lease cost $ 60 $ 12 $ 17 $ 89 (1) Includes $19 million of short-term lease costs. 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. Supplemental cash flow information related to leases was as follows: For the Years Ended December 31, (In millions) 2022 2021 2020 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 56 $ 64 $ 44 Operating cash flows from finance leases 3 4 4 Finance cash flows from finance leases 12 13 15 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 26 $ 60 $ 67 Finance leases — 5 — Lease terms and discount rates were as follows: As of December 31, 2022 2021 2020 Weighted-average remaining lease terms (years) Operating leases 7.30 7.97 8.55 Finance leases 11.33 8.12 7.74 Weighted-average discount rate (1) Operating leases 4.22 % 4.16 % 4.21 % Finance leases 14.77 % 12.22 % 11.58 % (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 2022 2021 Assets Operating lease (1) Deferred charges and other assets $ 262 $ 279 Finance lease (2) Property, plant and equipment 45 48 Total leased assets $ 307 $ 327 Liabilities Current: Operating Other current liabilities $ 48 $ 39 Finance Currently payable long-term debt 6 13 Noncurrent: Operating Other noncurrent liabilities 247 271 Finance Long-term debt and other long-term obligations 17 23 Total leased liabilities $ 318 $ 346 (1) Operating lease assets are recorded net of accumulated amortization of $114 million and $79 million as of December 31, 2022 and 2021, respectively. (2) Finance lease assets are recorded net of accumulated amortization of $60 million and $95 million as of December 31, 2022 and 2021, respectively. Maturities of lease liabilities as of December 31, 2022, were as follows: (In millions) Operating Leases Finance Leases Total 2023 $ 56 $ 9 $ 65 2024 52 5 57 2025 49 5 54 2026 45 5 50 2027 39 4 43 Thereafter 105 5 110 Total lease payments (1) 346 33 379 Less imputed interest 51 10 61 Total net present value $ 295 $ 23 $ 318 (1) Operating lease payments for certain leases are offset by sublease receipts of $9 million over 10 years. |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 12 Months Ended |
Dec. 31, 2022 | |
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. 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, 2022, from those used as of December 31, 2021. 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, 2022 December 31, 2021 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Derivative assets FTRs (1) $ — $ — $ 11 $ 11 $ — $ — $ 9 $ 9 Equity securities 2 — — 2 2 — — 2 U.S. state debt securities — 266 — 266 — 273 — 273 Cash, cash equivalents and restricted cash (2) 206 — — 206 1,511 — — 1,511 Other (3) — 40 — 40 — 42 — 42 Total assets $ 208 $ 306 $ 11 $ 525 $ 1,513 $ 315 $ 9 $ 1,837 Liabilities Derivative liabilities FTRs (1) $ — $ — $ (2) $ (2) $ — $ — $ (1) $ (1) Total liabilities $ — $ — $ (2) $ (2) $ — $ — $ (1) $ (1) Net assets (liabilities) $ 208 $ 306 $ 9 $ 523 $ 1,513 $ 315 $ 8 $ 1,836 (1) Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. (2) Restricted cash of $46 million and $49 million as of December 31, 2022 and 2021 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. See Note 10, Capitalization for additional information. (3) Primarily consists of short-term investments. 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. 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 United States Department of Energy 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, 2022 and 2021: December 31, 2022 (1) December 31, 2021 (2) Cost Basis Unrealized Gains Unrealized Losses Fair Value Cost Basis Unrealized Gains Unrealized Losses Fair Value (In millions) Debt securities $ 294 $ — $ (28) $ 266 $ 280 $ 2 $ (9) $ 273 (1) Excludes short-term cash investments of $5 million. (2) Excludes short-term cash investments of $11 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, 2022, 2021 and 2020, were as follows: For the Years Ended December 31, 2022 2021 2020 (1) (In millions) Sale Proceeds $ 48 $ 48 $ 186 Realized Gains 8 — 12 Realized Losses (13) (3) (8) Interest and Dividend Income 11 11 22 (1) Includes amounts associated with Nuclear Decommissioning Trusts 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. Earnings and losses associated with corporate-owned life insurance policies and equity method investments are reflected in the “Miscellaneous Income, net” line of FirstEnergy’s Consolidated Statements of Income. Other investments were $351 million and $371 million as of December 31, 2022 and 2021, respectively, and are excluded from the amounts reported above. See Note 1, "Organization and Basis of Presentation," for additional information on FirstEnergy's equity method investments. For the years ended December 31, 2022, 2021 and 2020, pre-tax income (expense) related to corporate-owned life insurance policies were $(20) million, $13 million and $20 million, respectively. Corporate-owned life insurance policies are valued using the cash surrender value and any changes in value during the period are recognized as income or expense. 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, 2022 and 2021: As of December 31, 2022 2021 (In millions) Carrying Value $ 21,641 $ 23,946 Fair Value 19,784 27,043 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, 2022 and 2021. See Note 10, "Capitalization," for further information on long-term debt issued and redeemed during the twelve months ended December 31, 2022. |
CAPITALIZATION
CAPITALIZATION | 12 Months Ended |
Dec. 31, 2022 | |
Capitalization, Long-Term Debt and Equity [Abstract] | |
CAPITALIZATION | CAPITALIZATION COMMON STOCK Retained Earnings and Dividends As of December 31, 2022, FirstEnergy had an accumulated deficit of $1 billion. Dividends declared in 2022 and 2021 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 2022 and 2021, respectively. On December 13, 2022, the FE Board declared a quarterly dividend of $0.39 per share to be paid from OPIC in the first quarter of 2023. 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 I and FET P&SA II, 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, 2022. Common Stock Issuance FE issued approximately 2 million shares of common stock in 2022, 1 million shares of common stock in 2021 and 2 million shares of common stock in 2020 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, 2022, 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, 2022 and 2021, there were no preferred stock or preference stock outstanding. 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, 2022 and 2021: As of December 31, 2022 As of December 31, (Dollar amounts in millions) Maturity Date Interest Rate 2022 2021 FMBs and secured notes - fixed rate 2023-2059 2.650% - 8.250% $ 5,153 $ 5,021 Unsecured notes - fixed rate 2023-2050 1.600% - 7.375% 16,488 18,925 Finance lease obligations 23 36 Unamortized debt discounts (5) (8) Unamortized debt issuance costs (110) (126) Unamortized fair value adjustments 5 6 Currently payable long-term debt (351) (1,606) Total long-term debt and other long-term obligations $ 21,203 $ 22,248 See Note 8, "Leases," for additional information related to finance leases. FirstEnergy had the following redemptions and issuances during the twelve months ended December 31, 2022: Company Type Redemption/Issuance Date Interest Rate Maturity Amount Description Redemptions FE Unsecured Notes January, 2022 4.25% 2023 $850 In December 2021, FE provided notice of redemption with a make-whole premium of approximately $38 million ($30 million after-tax). TE Senior Secured Notes February, 2022 2.65% 2028 $25 On January 27, 2022, TE instructed its indenture trustee to provide notice of partial redemption. CEI Senior Notes, Series A March, 2022 2.77% 2034 $150 On February 11, 2022, CEI instructed its indenture trustee to provide notice of full redemption. WP FMBs April, 2022 3.34% 2022 $100 WP redeemed FMBs that became due. FE Unsecured Notes June, 2022 2.85% 2022 $500 On May 23, 2022 FE provided notice of redemption. FE Unsecured Notes June, 2022 7.375% 2031 $715 On May 25, 2022, FE commenced an offer to purchase for cash a portion of its 2031 Notes and 2047 Notes, which had $1.5 billion and $1 billion principal amounts outstanding, respectively. A portion of these notes were redeemed for approximately $1.1 billion, including a tender premium of approximately $101 million ($80 million after-tax). In addition, FE recognized approximately $7 million ($5 million after-tax) of deferred cash flow hedge losses and $10 million ($8 million after-tax) in other unamortized debt costs and fees associated with the FE debt redemptions. FE Unsecured Notes June, 2022 4.85% 2047 $284 Penn FMBs June, 2022 6.09% 2022 $100 Penn redeemed FMBs that became due. FE Unsecured Notes August-November 2022 7.375% 2031 $128 Beginning in the third quarter of 2022, FE repurchased a portion of the principal amount of its 2031 Notes and 2047 Notes through the open market for approximately $249 million including a premium of approximately $11 million ($9 million after tax). In addition, FE recognized approximately $3 million ($2 million after-tax) in other unamortized debt costs related to the FE open market repurchases. FE Unsecured Notes August-September 2022 4.85% 2047 $110 Issuances OE Senior Unsecured Notes September, 2022 5.50% 2033 $300 Proceeds were used to repay borrowings outstanding under the regulated money pool, to finance capital expenditures, to fund working capital needs and for other general corporate purposes. Penn FMBs November, 2022 3.79% 2032 $150 Proceeds were used to repay short-term borrowings. WP FMBs November, 2022 5.29% 2033 $250 Proceeds were used to repay short-term borrowings. On November 29, 2022, WP issued $300 million of 5.29% FMBs due 2033. $250 million was funded on December 13, 2022, and the remaining $50 million was funded on January 10, 2023. Proceeds of the issuance of the FMBs were used to repay short term borrowings. 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, 2022. (In millions) 2023 2024 2025 2026 2027 Scheduled debt repayments $344 $1,246 $2,023 $1,076 $2,003 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, 2022 and 2021, $247 million and $274 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. The SPEs are considered VIEs and each one is consolidated into its applicable utility. As of December 31, 2022 and 2021, $206 million and $222 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, 2022, 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, 2022 | |
Debt Disclosure [Abstract] | |
SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT | SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT FirstEnergy had $100 million of short-term borrowings as of December 31, 2022. As of December 31, 2021, FirstEnergy had no outstanding short-term borrowings. 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, 2022, 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, certain amounts 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, 2022, 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, 2022, the borrowers were in compliance with the applicable interest coverage and debt-to-total-capitalization ratio covenants in each case as defined under the 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. During 2022, interest rates have increased significantly, which has caused the rate and interest on borrowings and lending under the money pools to be significantly higher. The average interest rate for borrowings in 2022 was 2.27% per annum for the regulated companies’ money pool, as compared to 1.01% in 2021, and 2.14% per annum for the unregulated companies’ money pool, as compared to 0.60% in 2021. Weighted Average Interest Rates |
REGULATORY MATTERS
REGULATORY MATTERS | 12 Months Ended |
Dec. 31, 2022 | |
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, 2022: 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) Rates were 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. On August 16, 2022, the MDPSC ordered each utility to file, by October 28, 2022, a set of plans for paying down all amortization balances by the scheduled expiration of the EmPOWER program on December 31, 2029. PE submitted its required plan on October 28, 2022, and, at the direction of the MDPSC, filed a revised plan on January 11, 2023. 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. NEW JERSEY JCP&L operates under NJBPU approved rates that took effect as of January 1, 2021, and 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. JCP&L has instituted energy efficiency and peak demand reduction programs in accordance with the New Jersey Clean Energy Act as approved by the NJBPU in April 2021. The NJBPU approved plans include 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. 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 September 19, 2022, the NJBPU issued a notice to re-adopt its rules of practice, including proposed changes to the rules regarding CTA policy in base rate cases consistent with the Superior Court’s June 7, 2021 order. Once the proposed rules of practice 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 October 28, 2020, the NJBPU approved a stipulated settlement between JCP&L and various parties, resolving JCP&L’s request for distribution base rate increase. The settlement provided for 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. The settlement additionally provided that JCP&L would be subject to a management audit, which began in May 2021 and is currently ongoing. JCP&L is currently waiting for issuance of the final report. On September 14, 2021, JCP&L submitted a supplemental filing with the NJBPU to revise a previously filed AMI Program, which proposed the deployment of approximately 1.2 million advanced meters. 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 investments 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. The Stipulation, which was approved by NJBPU order on February 23, 2022, also provides 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 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. No moratorium on residential disconnections remains in effect for investor-owned electric utilities such as JCP&L, but investor-owned electric public utilities are required to offer qualifying residential customers deferred payment arrangements meeting certain minimum criteria prior to disconnecting service. Additionally, new legislation was enacted on March 25, 2022, prohibiting utilities from disconnecting electric service to customers that have applied for utility bill assistance before June 15, 2022 until such time as the state agency administering the assistance program makes a decision on the application and further requiring that all utilities offer a deferred payment arrangement meeting certain minimum criteria after the state agency’s decision on the application has been made. 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. On May 2, 2022, JCP&L filed with the NJBPU a stipulation entered into with the NJBPU staff, NJ Rate Counsel and others that provided a total budget of approximately $40 million for JCP&L’s electric vehicle program, including investments of approximately $29 million and operations and maintenance expenses of approximately $11 million. Electric vehicle related capital and operations and maintenance costs shall be deferred and placed in separate regulatory assets for recovery in JCP&L’s next base rate case. The stipulation was approved without modification by the NJBPU on June 8, 2022. On September 17, 2022, in connection with Mid-Atlantic Offshore Development, LLC, a transmission company jointly owned by Shell New Energies US and EDF Renewables North America, JCP&L submitted a proposal to the NJBPU and PJM to build transmission infrastructure connecting offshore wind-generated electricity to the New Jersey power grid. On October 26, 2022, the JCP&L proposal was accepted in an order issued by NJBPU. The proposal included approximately $723 million in investments to both build new and upgrade existing transmission infrastructure. JCP&L’s proposal projects an investment ROE of 10.2% and includes the option for JCP&L to acquire up to a 20% equity stake in Mid-Atlantic Offshore Development, LLC. The resulting rates associated with the project are expected to be shared among the ratepayers of all New Jersey electric utilities. Construction is expected to begin in 2025. 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. On May 16, 2022, the Ohio Companies filed their application for determination of the existence of SEET under ESP IV for calendar year 2021, which demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings. On July 15, 2022, the Ohio Companies filed an application with the PUCO for approval of phase two of their distribution grid modernization plan that would, among other things, provide for the installation of an additional 700,000 smart meters, distribution automation equipment on approximately 240 distribution circuits, voltage regulating equipment on approximately 220 distribution circuits, and other investments and pilot programs in related technologies designed to provide enhanced customer benefits. The Ohio Companies propose that phase two will be implemented over a four-year budget period with estimated capital investments of approximately $626 million and operations and maintenance expenses of approximately $144 million over the deployment period. Under the proposal, costs of phase two of the grid modernization plan would be recovered through the Ohio Companies’ AMI rider, pursuant to the terms and conditions approved in ESP IV. On December 27, 2022, the Ohio Companies filed a motion with the PUCO requesting a procedural schedule that would facilitate the issuance of an order by year-end 2023. 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 on December 1, 2021, and refunds began in December 2021. Current and future rate reductions are 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. 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 and the auditor filed the final audit report on January 14, 2022, which made certain 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 identity. 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. Final comments and responses were filed by parties during the second quarter of 2022. 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. On May 4, 2022, the PUCO selected a third-party auditor to determine whether the show cause demonstration submitted by the Ohio Companies is sufficient to ensure that the cost of any political or charitable spending in support of HB 6 or the subsequent referendum effort was not included, directly or indirectly, in any rates or charges paid by ratepayers. 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. 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. On August 16, 2022, the U.S. Attorney for the Southern District of Ohio requested that the PUCO stay the above pending HB 6- related matters for a period of six months, which request was granted by the PUCO on August 24, 2022. Unless otherwise ordered by the PUCO, the four cases are stayed in their entirety, including discovery and motions, and all related procedural schedules are vacated. 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 to provide for refunds in the event such provisions of HB 6 are repealed. Neither the Ohio Companies nor FE benefit from the OVEC-related charges the Ohio Companies collect. Instead, the Ohio Companies are further required by HB 6 to remit all the OVEC-related charges they collect to non-FE Ohio electric distribution utilities. The Ohio Companies contested the motions, which are pending before 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. An evidentiary hearing was held on April 13, 2022, and on April 20, 2022, the parties filed a partial settlement with the PPUC resolving certain of the issues in the proceeding and setting aside the remainder of the issues to be resolved through briefing. PPUC approved the partial settlement, without modification, on August 4, 2022. 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-tax charge of $61 million in the fourth quarter of 2021, associated with the additional refund and based on the November 2021 PPUC order and methodology. The Pennsylvania Companies filed petitions to propose the timing and methodology of the refund of these amounts on February 17, 2022. The Pennsylvania Companies’ petitions and the proposed refunds addressed within were approved by the PPUC on June 16, 2022, without modification, effective July 1, 2022, and which refunds were fully completed by December 31, 2022. Pursuant to Pennsylvania Act 129 of 2008 and PPUC orders, the Pennsylvania Companies implemented energy efficiency and peak demand reduction programs with demand reduction targets, relative to 2007 to 2008 peak demands, at 2.9% MW for ME, 3.3% MW for PN, 2.0% MW for Penn, and 2.5% MW for WP; and energy consumption reduction targets, as a percentage of the Pennsylvania Companies’ historic 2009 to 2010 reference load at 3.1% MWH for ME, 3.0% MWH for PN, 2.7% MWH for Penn, and 2.4% MWH for WP. Pennsylvania EDCs are permitted to seek PPUC approval of an LTIIP for infrastructure improvements and costs related to highway relocation projects, after which a DSIC may be approved to recover LTIIP costs. On January 16, 2020, the PPUC approved the Pennsylvania Companies’ LTIIPs for the five-year period beginning January 1, 2020 and ending December 31, 2024 for a total capital investment of approximately $572 million for certain infrastructure improvement initiatives. On June 25, 2021, the Pennsylvania Office of Consumer Advocate filed a complaint against Penn’s quarterly DSIC rate, disputing the recoverability of the Companies’ automated distribution management system investment under the DSIC mechanism. On January 26, 2022, the parties filed a joint petition for settlement that resolves all issues in this matter, which was approved by the PPUC without modification on April 14, 2022. Following the Pennsylvania Companies’ 2016 base rate proceedings, the PPUC ruled in a separate proceeding related to the DSIC mechanisms that the Pennsylvania Companies were not required to reflect federal and state income tax deductions related to DSIC-eligible property in DSIC rates. The decision was appealed to the Pennsylvania Supreme Court and in July 2021 the court upheld the Pennsylvania Commonwealth Court’s reversal of the PPUC’s decision and remanded the matter back to the PPUC for determination as to how DSIC calculations shall account for ADIT and state taxes. The PPUC issued the order as directed, which was challenged by an intervening party. All parties have briefed the issue and await a ruling from the PPUC. Neither the PPUC’s determination or the underlying order are expected to result in a material impact to FirstEnergy. WEST VIRGINIA MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operate under WVPSC-approved rates that became effective in February 2015. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP’s and PE’s ENEC rate is updated annually. On December 29, 2021, the WVPSC issued an order granting MP and PE’s requested $19.6 million increase in ENEC rates, requiring, among other things, that MP and PE refund to its large industrial customers their respective portion of the $7.7 million rate reduction discussed above and also requires MP and PE to negotiate a PPA for its capacity shortfall and a reasonable reserve margin if certain conditions are met. By order dated March 2, 2022, the WVPSC reopened the case to determine whether rates should be increased to recover growing ENEC under-recoveries. On May 17, 2022, the WVPSC issued an order approving an interim rate increase of $94 million, effective for customer rates on May 18, 2022, subject to a prudence review during MP and PE’s 2022 ENEC case. On August 25, 2022, MP and PE filed with the WVPSC their annual ENEC case requesting an increase in ENEC rates of $183.8 million beginning January 1, 2023, which represents a 12.2% increase to the rates then in effect. The increase was driven by an underrecovery during the review period (July 1, 2021 to June 30, 2022) of $144.9 million due to higher coal, reagent, and allowance expenses. This filing additionally addresses, among other things, the WVPSC’s May 2022 request for a prudence review of current rates. At a hearing on December 8, 2022, the parties in the case presented a unanimous settlement to increase rates by approximately $92 million, effective January 1, 2023, and carry over to MP and PE’s 2023 ENEC case, approximately $92 million at a carrying charge of 4%. In an order dated December 30, 2022, the WVPSC approved the settlement with respect to the proposed rate increase, but MP and PE rates remain subject to a prudence review in their 2023 ENEC case. The order also instructs MP to evaluate the feasibility of purchasing the Pleasants Power Station and file a summary of the evaluation by March 31, 2023. On December 27, 2021, the WVPSC approved a settlement granting MP and PE a $16 million increase in rates effective January 1, 2022, and permitting the continuation of the vegetation management program and surcharge for another two years. WVPSC additionally ordered MP and PE to perform equipment inspections within a reasonable time after vegetation management occurs on a circuit. On November 22, 2021, MP and PE filed with the WVPSC their plan to construct 50 MWs of solar generation at five sites in West Virginia. The plan includes a tariff to offer solar power to West Virginia customers and cost recovery for MP and PE from other customers through a surcharge for any solar investment not fully subscribed by their customers. A hearing was held in mid-March 2022 and on April 21, 2022, the WVPSC issued an order approving, effective May 1, 2022, the requested tariff and requiring MP and PE to subscribe at least 85% of the planned 50 MWs before seeking final tariff approval. MP and PE must seek separate approval from the WVPSC to recover any solar generation costs in excess of the approved tariff. The first solar generation site is expected to be in-service by the end of 2023 and all construction completed at the other sites no later than the end of 2025 at a total investment cost of approximately $110 million. On December 17, 2021, MP and PE filed with the WVPSC for approval of environmental compliance projects at the Ft. Martin and Harrison Power Stations to comply with the EPA’s ELG and operate these plants beyond 2028. The request includes a surcharge to recover the expected $142 million capital investment and $3 million in annual operation and maintenance expense. MP and PE reached a settlement agreement with WVPSC staff and all intervenors, recommending: (i) approval of the ELG compliance plan submitted by MP and PE and (ii) recovery of costs through a surcharge. A ruling approving the settlement without modification was issued by the WVPSC on September 12, 2022, and construction is expected to be completed by the end of 2025. See Note 13, “Commitments, Guarantees and Contingencies - Environmental Matters - Clean Water Act" below, for additional details on the EPA's ELG. On Janua |
COMMITMENTS, GUARANTEES AND CON
COMMITMENTS, GUARANTEES AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2022 | |
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 LOCs, 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, 2022, outstanding guarantees and other assurances aggregated approximately $1.0 billion, consisting of parental guarantees on behalf of its consolidated subsidiaries ($528 million) and other assurances ($449 million). 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, 2022, $50 million of net cash 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. FE or its subsidiaries are holding $206 million of net cash collateral as of December 31, 2022, from certain generation suppliers, primarily due to the rise in power prices, and such amount is included in "Other current liabilities" 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, 2022: Potential Collateral Obligations Utilities and Transmission Companies FE Total (In millions) Contractual Obligations for Additional Collateral Upon Further Downgrade $ 70 $ — $ 70 Surety Bonds (collateralized amount) (1) 61 249 310 Total Exposure from Contractual Obligations $ 131 $ 249 $ 380 (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. 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 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 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 National Ambient Air Quality Standards. 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 prior CSAPR Update and the New York Section 126 petition. In December 2021, MP purchased NOx emissions allowances to comply with 2021 ozone season requirements. On April 6, 2022, the EPA published proposed rules seeking to impose further significant reductions in EGU NO x emissions in 25 states, including West Virginia. The EPA held a virtual public hearing regarding the proposed rules on April 21, 2022, and MP submitted written comments on June 21, 2022. 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. 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. Vacating the ACE Rule had the unintended effect of reinstating the CPP because the repeal of the CPP was a provision within the ACE Rule. The D.C. Circuit decision was appealed by several states and interested parties, including West Virginia, arguing that the EPA did not have the authorization under Section 111(d) of the Clean Air Act to require “generation shifting” as a way to limit GHGs. On June 30, 2022, the U.S. Supreme Court held that the EPA’s regulation of GHGs under Section 111(d) of the Clean Air Act was not authorized by Congress and remanded the Rule to the EPA for further reconsideration. 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 Spring of 2023 and a final rule later in 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 operation at the Ft. Martin and Harrison power stations from what was approved by the WVPSC in September 2022 to comply with the ELG rule. Regulation of Waste Disposal Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act, 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 cease accepting waste date for the 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, 2022, 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 $97 million have been accrued through December 31, 2022, of which, approximately $62 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 Southern District 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, and July 11, 2022, the SEC issued additional subpoenas to FE, with which FE has complied. 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 (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. The class certification hearing is scheduled to take place on March 17, 2023. 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. and Brighthouse Funds II – MFS Value Portfolio, et al. v. FirstEnergy Corp., et al. (S.D. Ohio) on December 17, 2021 and February 21, 2022, purported stockholders of FE filed complaints against FE, certain current and former officers, and certain current and former officers of EH. The complaints allege 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 seek the same relief as the In re FirstEnergy Corp. Securities Litigation described above. FE believes that it is probable that it will incur losses in connection with the resolution of these lawsuits. 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 (Conservation Support Rider) 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. (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. FE agreed to a class settlement to resolve these claims on April 11, 2022. In the fourth quarter of 2021, FirstEnergy recognized a pre-tax reserve of $37.5 million in the aggregate with respect to these lawsuits and the Emmons lawsuit below. On June 22, 2022, the court preliminarily approved the class settlement and the final fairness hearing was held on November 9, 2022. On December 5, 2022, the court issued an order memorializing its final approval of the class settlement. The settlement amount was satisfied on December 7, 2022. • 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. FE agreed to a class settlement to resolve these claims on April 11, 2022. In the fourth quarter of 2021, FirstEnergy recognized 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 June 22, 2022, the court preliminarily approved the class settlement and the final fairness hearing was held on November 9, 2022. The S.D. Ohio issued a final written order approving the settlement on December 5, 2022. The settlement amount was satisfied on December 7, 2022. 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. (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. (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. On March 11, 2022, the parties executed a stipulation and agreement of settlement, and filed a motion the same day requesting preliminary settlement approval in the S.D. Ohio, which the S.D Ohio granted on May 9, 2022. Subsequently, following a hearing on August 4, 2022, the S.D. Ohio granted final approval of the settlement on August 24, 2022. The settlement agreement is expected to resolve fully these shareholder derivative lawsuits and includes a series of corporate governance enhancements, that have resulted in the following: • Six then-members of the FE Board did 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 was formed to initiate a review process of the then current senior executive team. The review of the senior executive team by the special FE Board committee and the FE Board was completed in September 2022; • The FE Board will oversee FE’s lobbying and political activities, including periodically reviewing and approving political and lobbying action plans prepared by management; • An FE Board committee of recently appointed independent directors will 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 FE of $180 million, to be paid by insurance after the judgment has become final, less $36 million in court-ordered attorney’s fees awarded to plaintiffs. On September 20, 2022, a purported FE stockholder filed a motion for reconsideration of the S.D. Ohio’s final settlement approval. The parties filed oppositions to that motion on October 11, 2022 and the motion is under consideration by the S.D. Ohio. The N.D. Ohio matter remains pending. On June 2, 2022, the N.D. Ohio entered an order to show cause why the court should not appoint new plaintiffs’ counsel, and thereafter, on June 10, 2022, the parties filed a joint motion to dismiss the matter without prejudice, which the N.D. Ohio denied on July 5, 2022. On August 15, 2022, the N.D. Ohio issued an order stating its intention to appoint one group of applicants as new plaintiffs’ counsel, and on August 22, 2022, the N.D. Ohio ordered that any objections to the appointment be submitted by August 26, 2022. The parties filed their objections by that deadline, and on September 2, 2022, the applicants responded to those objections. In the meantime, on August 25, 2022, a purported FE stockholder represented by the applicants filed a motion to intervene, attaching a proposed complaint-in-intervention purporting to assert claims that the FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act as well as a claim against a third party for professional negligence and malpractice. The parties filed oppositions to that motion to intervene on September 8, 2022, and the proposed intervenor's reply in support of his motion to intervene was filed on September 22, 2022. On August 24, 2022, the parties filed a joint motion to dismiss the action pending in the N.D. Ohio based upon and in light of the approval of the settlement by the S.D. Ohio. On August 30, 2022, the parties filed a joint motion to dismiss the state court action, which the court granted on September 2, 2022. 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. On December 30, 2022, FERC approved a Stipulation and Consent Agreement that resolves the investigation. The agreement includes a FirstEnergy admission of violating FERC’s “duty of candor” rule and related laws, and obligates FirstEnergy to pay a civil penalty of $3.86 million, and to submit two annual compliance monitoring reports to FERC’s Office of Enforcement regarding improvements to FirstEnergy’s compliance programs. FE terminated Charles E. Jones as its chief executive officer effective October 29, 2020. As a result of Mr. Jones’ termination, and due to the determination of a committee of independent members of the FE Board that Mr. Jones violated certain FirstEnergy policies and its code of conduct, all grants, awards and compensation under FirstEnergy’s short-term incentive compensation program and long-term |
SEGMENT INFORMATION
SEGMENT INFORMATION | 12 Months Ended |
Dec. 31, 2022 | |
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. FirstEnergy evaluates segment performance based on Earnings attributable to FE. 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. 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. 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 in the first quarter of 2021. 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 (deferral) of regulatory assets, net”, line on the Consolidated Statements of Income, resulting in no earnings impact to FirstEnergy or JCP&L. 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 I, with Brookfield and the 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 would own 19.9% of the issued and outstanding membership interests of FET, for a purchase price of $2.375 billion. The transaction closed on May 31, 2022. On February 2, 2023, FE, along with FET, entered into the FET P&SA II with Brookfield and the Brookfield Guarantors, pursuant to which FE agreed to sell to Brookfield at the closing, and Brookfield agreed to purchase from FE, an incremental 30% equity interest in FET for a purchase price of $3.5 billion. The purchase price will be payable in part by the issuance of a promissory note expected to be in the principal amount of $1.75 billion. The remaining $1.75 billion of the purchase price will be payable in cash at the closing. As a result of the consummation of the transaction, Brookfield’s interest in FET will increase from 19.9% to 49.9%, while FE will retain the remaining 50.1% ownership interests of FET. The transaction is subject to customary closing conditions, including approval from the FERC and certain state utility commissions, and completion of review by the CFIUS. In addition, pursuant to the FET P&SA II, FirstEnergy has agreed to make the necessary filings with the applicable regulatory authorities for the PA Consolidation. The FET Minority Equity Interest Sale is expected to close by early 2024. Upon closing, FET will continue to be consolidated in FirstEnergy’s GAAP financial statements. KATCo, which was a subsidiary of FET, became a wholly owned subsidiary of FE prior to the closing of the FET P&SA I and remains 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 investments or businesses that do not constitute an operating segment. Reconciling adjustments for the elimination of inter-segment transactions are shown separately in the following table of Segment Financial Information. As of December 31, 2022, 67 MWs of electric generating capacity, representing AE Supply's OVEC capacity entitlement, was also included in Corporate/Other for segment reporting. As of December 31, 2022, Corporate/Other had approximately $5.4 billion of FE holding company debt. Financial information for FirstEnergy’s business segments and reconciliations to consolidated amounts is presented below: For the Years Ended December 31, (In millions) 2022 2021 2020 External revenues Regulated Distribution $ 10,569 $ 9,510 $ 9,168 Regulated Transmission 1,863 1,608 1,613 Corporate/Other 27 14 9 Reconciling Adjustments — — — Total external revenues $ 12,459 $ 11,132 $ 10,790 Internal revenues Regulated Distribution $ 232 $ 201 $ 195 Regulated Transmission 5 10 17 Corporate/Other — — — Reconciling Adjustments (237) (211) (212) Total internal revenues $ — $ — $ — Total revenues $ 12,459 $ 11,132 $ 10,790 Depreciation Regulated Distribution $ 967 $ 911 $ 896 Regulated Transmission 335 325 313 Corporate/Other 7 3 4 Reconciling Adjustments 66 63 61 Total depreciation $ 1,375 $ 1,302 $ 1,274 Amortization (deferral) of regulatory assets, net Regulated Distribution $ (362) $ 260 $ (64) Regulated Transmission (3) 9 11 Corporate/Other — — — Reconciling Adjustments — — — Total amortization (deferral) of regulatory assets, net $ (365) $ 269 $ (53) DPA penalty Corporate/Other $ — $ 230 $ — Total DPA penalty $ — $ 230 $ — Miscellaneous income (expense), net Regulated Distribution $ 361 $ 399 $ 332 Regulated Transmission 36 41 30 Corporate/Other 85 58 81 Reconciling Adjustments (67) (12) (13) Total miscellaneous income (expense), net $ 415 $ 486 $ 430 Interest expense Regulated Distribution $ 526 $ 522 $ 501 Regulated Transmission 230 247 219 Corporate/Other 350 382 358 Reconciling Adjustments (67) (12) (13) Total interest expense $ 1,039 $ 1,139 $ 1,065 Income taxes (benefits) Regulated Distribution $ 251 $ 364 $ 113 Regulated Transmission 110 127 138 Corporate/Other 639 (171) (125) Reconciling Adjustments — — — Total income taxes (benefits) $ 1,000 $ 320 $ 126 For the Years Ended December 31, (In millions) 2022 2021 2020 Net income (loss) Regulated Distribution $ 957 $ 1,288 $ 959 Regulated Transmission 394 408 464 Corporate/Other (912) (413) (344) Reconciling Adjustments — — — Total net income (loss) $ 439 $ 1,283 $ 1,079 Income attributable to noncontrolling interest Regulated Transmission $ 33 $ — $ — Total income attributable to noncontrolling interest $ 33 $ — $ — Earnings attributable to FE Regulated Distribution $ 957 $ 1,288 $ 959 Regulated Transmission 361 408 464 Corporate/Other (912) (413) (344) Reconciling Adjustments — — — Total earnings attributable to FE $ 406 $ 1,283 $ 1,079 Property additions Regulated Distribution $ 1,513 $ 1,395 $ 1,514 Regulated Transmission 1,192 958 1,067 Corporate/Other 51 92 76 Reconciling Adjustments — — — Total property additions $ 2,756 $ 2,445 $ 2,657 As of December 31, (In millions) 2022 2021 Assets Regulated Distribution $ 31,749 $ 30,812 Regulated Transmission 13,835 13,237 Corporate/Other 524 1,383 Reconciling Adjustments — — Total assets $ 46,108 $ 45,432 Goodwill Regulated Distribution $ 5,004 $ 5,004 Regulated Transmission 614 614 Corporate/Other — — Reconciling Adjustments — — Total goodwill $ 5,618 $ 5,618 |
DISCONTINUED OPERATIONS
DISCONTINUED OPERATIONS | 12 Months Ended |
Dec. 31, 2022 | |
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, 2022, 2021, and 2020 were as follows: For the Years Ended December 31, (In millions) 2022 2021 2020 Revenues $ — $ — $ 7 Fuel — — (6) Other operating expenses — — (6) Pleasants economic interest (1) — — 5 Other expense, net — (4) — Loss from discontinued operations, before tax — (4) — Income tax expense (benefit) — (1) — Loss from discontinued operations, net of tax — (3) — Settlement consideration and services credit — — (1) Accelerated net pension and OPEB prior service credits — — 18 Gain on disposal of FES and FENOC, before tax — — 17 Income tax benefits, including worthless stock deduction — (47) (59) Gain on disposal of FES and FENOC, net of tax — 47 76 Income from discontinued operations (2) $ — $ 44 $ 76 (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. (2) Income from discontinued operations are included in Corporate/Other for segment reporting. 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, 2022, 2021 and 2020: For the Years Ended December 31, (In millions) 2022 2021 2020 CASH FLOWS FROM OPERATING ACTIVITIES: Income from discontinued operations $ — $ 44 $ 76 Gain on disposal, net of tax — (47) (76) |
ORGANIZATION AND BASIS OF PRE_2
ORGANIZATION AND BASIS OF PRESENTATION (Policies) | 12 Months Ended |
Dec. 31, 2022 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Accounting | The accompanying consolidated financial statements have been prepared in accordance with GAAP and the rules and regulations of the SEC. 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. |
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 limited 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. |
Equity Method Investments | EQUITY METHOD INVESTMENTS 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 reflected in "Investments". The percentage of FE's ownership share of the entity’s earnings is reported in the Consolidated Statements of Income and Comprehensive Income and reflected in “Miscellaneous Income, net”. Equity method investments are assessed for impairment annually or whenever events and changes |
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 10, “Capitalization,” for additional information on securitized bonds. Unconsolidated VIEs FirstEnergy is not the primary beneficiary of its equity method investments in Global Holding and PATH WV, as further discussed above, or its PPAs. 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 the Public Utility Regulatory Policies Act of 1978. 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. |
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 | INVENTORYMaterials and supplies inventory primarily includes emission allowances, 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. Emission allowances are accounted for at cost when purchased and charged to expense monthly based on each month’s emissions. |
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 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. |
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 |
New Accounting Pronouncements | NEW ACCOUNTING PRONOUNCEMENTS Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB has not yet been adopted. Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable. FirstEnergy has assessed other FASB issuances of new standards not described below based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting. ASU 2022-03, " Fair Value Measurements of Equity Securities Subject to Contractual Sale Restrictions " (Issued in June 2022): ASU 2022-03 clarifies current guidance in Topic 820, Fair Value Measurement, when measuring the fair value of an equity security subject to contractual restrictions that prohibit the sale of an equity security, and introduces new disclosure requirements for those equity securities subject to contractual restrictions. For FirstEnergy, the guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2023, with early adoption permitted. |
Receivable | RECEIVABLESReceivables from contracts from customers include retail electric sales and distribution deliveries to residential, commercial and industrial customers of the Utilities. 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. FirstEnergy reviews its allowance for uncollectible customer receivables utilizing a quantitative and qualitative assessment. 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. This analysis includes consideration of the outbreak of the pandemic and the impact on customer receivable balances outstanding and write-offs since the pandemic began and subsequent economic slowdown. FirstEnergy’s uncollectible risk on PJM receivables, resulting from transmission and wholesale sales, 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. During 2021, arrears levels continued to be elevated above 2019 pre-pandemic levels. Various regulatory actions impacted the growth and recovery of past due balances including extensions on moratoriums, significant restrictions regarding disconnections, and extended installment plans. FirstEnergy 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 continued to decrease in 2021, balances over 120 days past due continued 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 during 2021. During 2022, various regulatory actions including extensions on moratoriums, certain restrictions on disconnections and extended installment plan offerings continue to impact the level of past due balances in certain states. However, certain states have resumed normal collections activity and arrears levels have declined towards pre-pandemic levels. As a result, FirstEnergy recognized a $25 million decrease in its allowance for uncollectible customer receivables during the first quarter of 2022, of which $15 million was applied to existing deferred regulatory assets. As a result of certain customer installment or extended payment plans, inflationary pressures on customers and the economic slowdown, there were no material changes to the allowance for uncollectible customer receivables during the remainder of 2022. Additionally, as a result of the pandemic-related moratoriums and certain customer installment or extended payment plans offered, which caused the extension of when certain write offs would have otherwise occurred, the allowance for uncollectible accounts on receivables remains elevated above 2019 pre-pandemic levels. |
Earnings Per Share of Common Stock | Basic EPS 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. Diluted EPS reflects the dilutive effect of potential common shares from share-based awards. 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. |
Pension and Other Postretirement Plans | 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 until 2025, which, based on various assumptions, including annual expected rate of return on assets of 8.0% in 2023, is expected to be approximately $250 million. 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. |
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 less than a year 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. |
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. |
Investments | 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. |
Long-Term Debt and Other Long-Term Obligations | LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONSAll 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. |
ORGANIZATION AND BASIS OF PRE_3
ORGANIZATION AND BASIS OF PRESENTATION (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Regulatory assets on the Balance Sheets | The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2022 and 2021, and the changes during the year ended December 31, 2022: As of December 31, Net Regulatory Assets (Liabilities) by Source 2022 2021 Change (In millions) Customer payables for future income taxes $ (2,463) $ (2,345) $ (118) Spent nuclear fuel disposal costs (83) (101) 18 Asset removal costs (675) (646) (29) Deferred transmission costs 50 (3) 53 Deferred generation costs 235 118 117 Deferred distribution costs 164 49 115 Storm-related costs 683 660 23 Uncollectible and pandemic-related costs 63 56 7 Energy efficiency program costs 94 47 47 New Jersey societal benefit costs 94 109 (15) Vegetation management 63 33 30 Other (39) (30) (9) Net Regulatory Liabilities included on the Consolidated Balance Sheets $ (1,814) $ (2,053) $ 239 The following table provides information about the composition of net regulatory assets that do not earn a current return as of December 31, 2022 and 2021, of which approximately $511 million and $228 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 2022 2021 Change (In millions) Deferred transmission costs $ 8 $ 13 $ (5) Deferred generation costs 262 63 199 Deferred distribution costs 27 2 25 Storm-related costs 568 549 19 Pandemic-related costs 70 65 5 Vegetation management 52 31 21 Other 10 9 1 Regulatory Assets Not Earning a Current Return $ 997 $ 732 $ 265 |
Schedule of Goodwill | The following table presents goodwill by reporting unit as of December 31, 2022: (In millions) Regulated Distribution Regulated Transmission Consolidated Goodwill $ 5,004 $ 614 $ 5,618 |
Schedule of Property, plant and equipment balances | Property, plant and equipment balances by segment as of December 31, 2022 and 2021, were as follows: December 31, 2022 Property, Plant and Equipment In Service (1) Accum. Depr. Net Plant CWIP Total (In millions) Regulated Distribution $ 32,257 $ (9,636) $ 22,621 $ 828 $ 23,449 Regulated Transmission 14,468 (2,978) 11,490 818 12,308 Corporate/Other 1,125 (644) 481 47 528 Total $ 47,850 $ (13,258) $ 34,592 $ 1,693 $ 36,285 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 (1) Includes finance leases of $105 million and $143 million as of December 31, 2022 and 2021, respectively. |
Schedule of Changes to the asset retirement obligations | The following table summarizes the changes to the ARO balances during 2022 and 2021: ARO Reconciliation (In millions) Balance, January 1, 2021 $ 159 Changes in timing and amount of estimated cash flows 8 Liabilities settled (1) Accretion 13 Balance, December 31, 2021 $ 179 Changes in timing and amount of estimated cash flows (2) Liabilities settled (6) Accretion 14 Balance, December 31, 2022 $ 185 |
REVENUE (Tables)
REVENUE (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Revenue from Contract with Customer [Abstract] | |
Schedule of Disaggregation of Revenue | The following represents a disaggregation of revenue from contracts with customers for the years ended December 31, 2022, 2021 and 2020: For the Years Ended December 31, (In millions) 2022 2021 2020 Regulated Distribution Retail generation and distribution services (1) Residential $ 6,180 $ 5,713 $ 5,539 Commercial 2,499 2,284 2,140 Industrial 1,338 1,091 1,076 Other 85 75 81 Wholesale 494 362 251 Other revenue from contracts with customers 104 119 140 Total revenues from contracts with customers 10,700 9,644 9,227 ARP (2) — (27) 43 Other revenue unrelated to contracts with customers 101 94 93 Total Regulated Distribution $ 10,801 $ 9,711 $ 9,363 Regulated Transmission ATSI $ 912 $ 799 $ 804 TrAIL 270 233 247 MAIT 340 288 250 JCP&L 203 164 178 MP, PE and WP 138 124 134 Total revenues from contracts with customers 1,863 1,608 1,613 Other revenue unrelated to contracts with customers 5 10 17 Total Regulated Transmission $ 1,868 $ 1,618 $ 1,630 Corporate/Other and Reconciling Adjustments (3) Wholesale $ 27 $ 14 $ 9 Retail generation and distribution services (3) (186) (154) (148) Other revenue unrelated to contracts with customers (3) (51) (57) (64) Total Corporate/Other and Reconciling $ (210) $ (197) $ (203) FirstEnergy Total Revenues $ 12,459 $ 11,132 $ 10,790 (1) Includes approximately $58 million and $38 million as of December 31, 2022 and 2021, respectively, of customer refunds associated with the Ohio Stipulation that became effective in December 2021. See Note 12, “Regulatory Matters,” for further discussion. (2) Reflects amount the Ohio Companies refunded to customers that was previously collected under decoupling mechanisms, with interest. |
Schedule of Receivables from customers | Billed and unbilled customer receivables as of December 31, 2022 and 2021, are included below. As of December 31, Customer Receivables 2022 2021 (In millions) Billed (1) $ 674 $ 616 Unbilled 781 576 1,455 1,192 Less: Uncollectible Reserve 137 159 Total Customer Receivables $ 1,318 $ 1,033 (1) Includes approximately $290 million and $318 million as of December 31, 2022 and 2021, respectively, that are past due by greater than 30 days. |
Schedule of Activity in the allowance for uncollectible accounts on customer receivables | Activity in the allowance for uncollectible accounts on receivables for the years ended December 31, 2022, 2021 and 2020 are as follows: (In millions) 2022 2021 2020 (3) Customer Receivables Beginning of year balance $ 159 $ 164 $ 46 Charged to income (1) 59 54 174 Charged to other accounts (2) 62 42 46 Write-offs (143) (101) (102) End of year balance $ 137 $ 159 $ 164 Other Receivables Beginning of year balance $ 10 $ 26 $ 21 Charged to income 4 3 7 Charged to other accounts (2) 4 3 10 Write-offs (7) (22) (12) End of year balance $ 11 $ 10 $ 26 (1) Customer receivable amounts charged to income for the years ended December 31, 2022, 2021, and 2020 include approximately $11 million, $12 million, and $103 million respectively, deferred for future recovery. 2020 amounts charged to income includes $121 million of incremental expense due to pandemic conditions. (2) Represents recoveries and reinstatements of accounts previously written off for uncollectible accounts. |
EARNINGS PER SHARE OF COMMON _2
EARNINGS PER SHARE OF COMMON STOCK (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Earnings Per Share [Abstract] | |
Schedule of Reconciliation of Basic and Diluted Earnings Per Share | The following table reconciles basic and diluted EPS attributable to FE: For the Years Ended December 31, Reconciliation of Basic and Diluted EPS of Common Stock 2022 2021 2020 (In millions, except per share amounts) Earnings Attributable to FE - continuing operations $ 406 $ 1,239 $ 1,003 Earnings Attributable to FE - discontinued operations, net of tax — 44 76 Earnings Attributable to FE $ 406 $ 1,283 $ 1,079 Share Count information: Weighted average number of basic shares outstanding 571 545 542 Assumed exercise of dilutive share based awards 1 1 1 Weighted average number of diluted shares outstanding 572 546 543 EPS Attributable to FE: Income from continuing operations, basic $ 0.71 $ 2.27 $ 1.85 Discontinued operations, basic — 0.08 0.14 Basic EPS $ 0.71 $ 2.35 $ 1.99 Income from continuing operations, diluted $ 0.71 $ 2.27 $ 1.85 Discontinued operations, diluted — 0.08 0.14 Diluted EPS $ 0.71 $ 2.35 $ 1.99 |
ACCUMULATED OTHER COMPREHENSI_2
ACCUMULATED OTHER COMPREHENSIVE INCOME (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Equity [Abstract] | |
Schedule of Accumulated Other Comprehensive Income | The changes in AOCI for the years ended December 31, 2022, 2021 and 2020, for FirstEnergy are shown in the following table: Gains & Losses on Cash Flow Hedges (1) Defined Benefit Pension & OPEB Plans (2)(3) Total (In millions) AOCI Balance, January 1, 2020 $ (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) Amounts reclassified from AOCI 9 (9) — Other comprehensive income (loss) 9 (9) — Income tax (benefits) on other comprehensive income (loss) 2 (3) (1) Other comprehensive income (loss), net of tax 7 (6) 1 AOCI Balance, December 31, 2022 $ — $ (14) $ (14) (1) Relates to previous cash flow hedges used to hedge fixed rate long-term debt securities prior to their issuance. Amounts reclassified from AOCI affects Interest expense line item in Consolidated Statements of Income. (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 5, "Pension and Other Post-Employment Benefits," for additional details. (3) Income tax (benefits) on other comprehensive income (loss) affects Income taxes line item in Consolidated Statements of Income. |
PENSION AND OTHER POST-EMPLOY_2
PENSION AND OTHER POST-EMPLOYMENT BENEFITS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Schedule of Assumptions Used to Determine Net Periodic Benefit Cost | Actuarial Assumptions Pension OPEB 2022 2021 2020 (2) 2022 2021 2020 (2) Assumptions Related to Benefit Obligations: Discount rate 5.23 % 3.02 % 2.67 % 5.16 % 2.84 % 2.45 % Rate of compensation increase 4.30 % 4.10 % 4.10 % N/A N/A N/A Cash balance weighted average interest crediting rate 4.04 % 2.57 % 2.57 % N/A N/A N/A Assumptions Related to Benefit Costs: (1) Effective rate for interest on benefit obligations 2.44 % 1.94 % 2.89%/2.48% 2.18 % 1.66 % 2.71%/2.30% Effective rate for service costs 3.28 % 3.10 % 3.60%/3.24% 3.41 % 3.03 % 3.63%/3.29% Effective rate for interest on service costs 2.96 % 2.58 % 3.27%/2.90% 3.24 % 2.83 % 3.43%/3.06% 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 Assumed Health Care Cost Trend Rates: Health care cost trend rate assumed (pre/post-Medicare) N/A N/A N/A 6.00%- 5.50% 5.75%- 5.25% 6.00%- 5.50% Rate to which the cost trend rate is assumed to decline (ultimate trend rate) N/A N/A N/A 4.50 % 4.50 % 4.50 % Year that the rate reaches the ultimate trend rate N/A N/A N/A 2029 2028 2028 (1) Excludes impact of pension and OPEB mark-to-market adjustment. |
Schedule of Components of Net Periodic Benefit Costs | Components of Net Periodic Benefit Costs (Credits) for the Years Ended December 31, Pension OPEB 2022 2021 2020 2022 2021 2020 (In millions) Service cost (1) $ 184 $ 195 $ 194 $ 3 $ 4 $ 4 Interest cost 273 226 287 11 11 15 Expected return on plan assets (657) (652) (618) (39) (36) (33) Amortization of prior service costs (credits) (2) 2 3 12 (11) (17) (46) One-time termination benefits (3) — — 8 — — — Pension & OPEB mark-to-market (98) (253) 463 26 (129) 14 Net periodic benefit costs (credits) $ (296) $ (481) $ 346 $ (10) $ (167) $ (46) (1) Includes amounts capitalized. (2) 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. (3) Costs represent additional benefits provided to FES and FENOC employees under the approved settlement agreement and are a component of discontinued operations. |
Schedule of Obligations and Funded Status | Pension OPEB Obligations/Funded Status - Qualified and Non-Qualified Plans 2022 2021 2022 2021 (In millions) Change in benefit obligation: Benefit obligation as of January 1 $ 11,479 $ 11,935 $ 549 $ 676 Service cost 184 195 3 4 Interest cost 273 226 11 11 Plan participants’ contributions — — 3 4 Medicare retiree drug subsidy — — 1 1 Actuarial loss (gain) (2,515) (280) (83) (101) Benefits paid (593) (597) (45) (46) Benefit obligation as of December 31 $ 8,828 $ 11,479 $ 439 $ 549 Change in fair value of plan assets: Fair value of plan assets as of January 1 $ 9,020 $ 8,968 $ 548 $ 502 Actual return on plan assets (1,760) 625 (70) 64 Company contributions 26 24 24 24 Plan participants’ contributions — — 3 4 Benefits paid (593) (597) (45) (46) Fair value of plan assets as of December 31 $ 6,693 $ 9,020 $ 460 $ 548 Funded Status: Qualified plan $ (1,734) $ (1,974) $ — $ — Non-qualified plans (401) (485) — — Funded Status (Net liability as of December 31) $ (2,135) $ (2,459) $ 21 $ (1) Accumulated benefit obligation $ 8,500 $ 10,927 $ — $ — Amounts Recognized in AOCI: Prior service cost (credit) $ 6 $ 9 $ (10) $ (21) |
Schedule of Target asset allocations for pension and OPEB portfolio | FirstEnergy’s target asset allocations for its pension and OPEB trust portfolios for 2022 were as follows: Target Asset Allocations Pension OPEB Equities 36 % 50 % Fixed income 22.5 % 50 % Alternative investments 5 % — % Real estate 10 % — % Private - equity and debt funds 20 % — % Cash and derivatives 6.5 % — % 100 % 100 % |
Schedule of 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) 2023 $ 583 $ 44 $ (1) 2024 587 42 (1) 2025 597 40 (1) 2026 605 39 — 2027 612 37 — Years 2028-2031 3,120 167 (2) |
Pension | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Schedule of 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 9, "Fair Value Measurements," for a description of each level of the fair value hierarchy. There were no significant transfers between levels during 2022 and 2021. December 31, 2022 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 714 $ — $ 714 11 % Public equity 1,871 216 — 2,087 33 % Fixed income — 942 — 942 15 % Derivatives (38) 2 — (36) (1) % Total (1) $ 1,833 $ 1,874 $ — $ 3,707 58 % Private - equity and debt funds (2) 1,061 17 % Insurance-linked securities (2) 159 3 % Hedge funds (2) 563 9 % Real estate funds (2) 853 13 % Total Investments $ 6,343 100 % (1) Excludes $350 million as of December 31, 2022, of receivables, payables, taxes, cash collateral for derivatives 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, 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 (3) 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. |
OPEB | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Schedule of Pension investments measured at fair value | As of December 31, 2022, and 2021, the OPEB trust investments measured at fair value were as follows: December 31, 2022 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 87 $ — $ 87 19 % Public equity 217 — — 217 47 % Fixed income — 157 — 157 34 % Total (1) $ 217 $ 244 $ — $ 461 100 % (1) Excludes $(1) million as of December 31, 2022, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. 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 % |
STOCK-BASED COMPENSATION PLANS
STOCK-BASED COMPENSATION PLANS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
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, 2022, 2021 and 2020, are included in the following tables: For the Years Ended December 31, Stock-based Compensation Plan 2022 2021 2020 (In millions) Restricted stock units $ 55 $ 40 $ 22 Restricted stock 3 2 1 401(k) savings plan 36 35 33 EDCP & DCPD 7 13 (5) Total $ 101 $ 90 $ 51 Stock-based compensation costs, net of amounts capitalized $ 54 $ 43 $ 25 |
Schedule of Nonvested Restricted Stock Units Activity | Restricted stock unit activity for the year ended December 31, 2022, was as follows: Restricted Stock Unit Activity Shares (in millions) Weighted-Average Grant Date Fair Value (per share) Nonvested as of January 1, 2022 1.8 $ 41.89 Granted in 2022 1.0 41.19 Forfeited in 2022 (0.3) 39.58 Vested in 2022 (1) (0.6) 41.57 Nonvested as of December 31, 2022 1.9 $ 41.57 |
TAXES (Tables)
TAXES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Income Tax Disclosure [Abstract] | |
Schedule of Provision for income taxes (benefits) | For the Years Ended December 31, INCOME TAXES (1) 2022 2021 2020 (In millions) Currently payable (receivable)- Federal (2) $ — $ 2 $ (14) State 11 21 21 11 23 7 Deferred, net- Federal (3) 946 174 171 State (4) 47 127 (38) 993 301 133 Investment tax credit amortization (4) (4) (14) Total income taxes $ 1,000 $ 320 $ 126 (1) Income Taxes on Income from Continuing Operations. (2) Excludes $2 million of federal tax benefit associated with discontinued operations for the years ended December 31, 2021. (3) Excludes $46 million and $66 million of federal tax benefits associated with discontinued operations for the years ended December 31, 2021 and 2020, respectively. (4) Excludes $1 million of state tax expense associated with discontinued operations for the year ended December 31, 2020. |
Schedule of 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, 2022, 2021 and 2020: For the Years Ended December 31, 2022 2021 2020 (In millions) Income from Continuing Operations, before income taxes $ 1,439 $ 1,559 $ 1,129 Federal income tax expense at statutory rate (21%) $ 302 $ 327 $ 237 Increases (reductions) in taxes resulting from- State and municipal income taxes, net of federal tax benefit 56 122 75 AFUDC equity and other flow-through (26) (29) (38) Amortization of investment tax credits (4) (4) (14) Deferred gain on 19.9% FET minority interest sale 752 — — Federal tax credits claimed (3) (34) — Nondeductible DPA monetary penalty — 52 — Excess deferred tax amortization due to the Tax Act (51) (54) (56) TMI-2 reversal of tax regulatory liabilities — — (40) Uncertain tax positions 2 (82) (1) Valuation allowances (47) 17 (49) Other, net 19 5 12 Total income taxes $ 1,000 $ 320 $ 126 Effective income tax rate 69.5 % 20.5 % 11.2 % |
Schedule of Accumulated deferred income taxes | ccumulated deferred income taxes as of December 31, 2022 and 2021, are as follows: As of December 31, 2022 2021 (In millions) Property basis differences $ 5,528 $ 5,670 Pension and OPEB (496) (570) AROs (22) (21) Regulatory asset/liability 432 322 Deferred compensation (149) (155) Deferred gain on 19.9% FET minority interest sale 752 — Loss carryforwards and tax credits (2,073) (2,040) Valuation reserve 440 484 All other (210) (253) Net deferred income tax liability $ 4,202 $ 3,437 |
Schedule of Pre-tax net operating loss expiration period | Expiration Period State Local (In millions) 2023-2027 $ 2,479 $ 4,317 2028-2032 1,603 — 2033-2037 876 — 2038-2042 935 — Indefinite 2,351 — $ 8,244 $ 4,317 |
Schedule of 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, 2022, 2021 and 2020: (In millions) 2022 2021 2020 Beginning of year balance $ 484 $ 496 $ 441 Charged to income (44) (12) 55 Charged to other accounts — — — Write-offs — — — End of year balance $ 440 $ 484 $ 496 |
Schedule of Changes in unrecognized tax benefits | The following table summarizes the changes in unrecognized tax positions for the years ended December 31, 2022, 2021 and 2020: (In millions) Balance, January 1, 2020 $ 164 Current year increases 7 Prior year decreases (28) Effectively settled with taxing authorities (2) Decrease for lapse in statute (2) Balance, December 31, 2020 $ 139 Current year increases 15 Prior year decreases (8) Effectively settled with taxing authorities (97) Decrease for lapse in statute (2) Balance, December 31, 2021 $ 47 Prior years increases 2 Decrease for lapse in statute (7) Balance, December 31, 2022 $ 42 |
Schedule of Details of general taxes | General tax expense for the years ended December 31, 2022, 2021 and 2020, recognized in continuing operations is summarized as follows: For the Years Ended December 31, 2022 2021 2020 (In millions) kWh excise $ 191 $ 189 $ 183 State gross receipts 219 190 182 Real and personal property 596 571 541 Social security and unemployment 105 103 112 Other 18 20 28 Total general taxes $ 1,129 $ 1,073 $ 1,046 |
LEASES (Tables)
LEASES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Leases [Abstract] | |
Schedule of Components of Lease Expense | The components of lease expense were as follows: For the Year Ended December 31, 2022 (In millions) Vehicles Buildings Other Total Operating lease costs (1) $ 50 $ 8 $ 15 $ 73 Finance lease costs: Amortization of right-of-use assets 10 1 2 13 Interest on lease liabilities — 3 — 3 Total finance lease cost 10 4 2 16 Total lease cost $ 60 $ 12 $ 17 $ 89 (1) Includes $19 million of short-term lease costs. 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. Supplemental cash flow information related to leases was as follows: For the Years Ended December 31, (In millions) 2022 2021 2020 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 56 $ 64 $ 44 Operating cash flows from finance leases 3 4 4 Finance cash flows from finance leases 12 13 15 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 26 $ 60 $ 67 Finance leases — 5 — Maturities of lease liabilities as of December 31, 2022, were as follows: (In millions) Operating Leases Finance Leases Total 2023 $ 56 $ 9 $ 65 2024 52 5 57 2025 49 5 54 2026 45 5 50 2027 39 4 43 Thereafter 105 5 110 Total lease payments (1) 346 33 379 Less imputed interest 51 10 61 Total net present value $ 295 $ 23 $ 318 (1) Operating lease payments for certain leases are offset by sublease receipts of $9 million over 10 years. |
Schedule of Assets and Liabilities, Lessee | Lease terms and discount rates were as follows: As of December 31, 2022 2021 2020 Weighted-average remaining lease terms (years) Operating leases 7.30 7.97 8.55 Finance leases 11.33 8.12 7.74 Weighted-average discount rate (1) Operating leases 4.22 % 4.16 % 4.21 % Finance leases 14.77 % 12.22 % 11.58 % (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 2022 2021 Assets Operating lease (1) Deferred charges and other assets $ 262 $ 279 Finance lease (2) Property, plant and equipment 45 48 Total leased assets $ 307 $ 327 Liabilities Current: Operating Other current liabilities $ 48 $ 39 Finance Currently payable long-term debt 6 13 Noncurrent: Operating Other noncurrent liabilities 247 271 Finance Long-term debt and other long-term obligations 17 23 Total leased liabilities $ 318 $ 346 (1) Operating lease assets are recorded net of accumulated amortization of $114 million and $79 million as of December 31, 2022 and 2021, respectively. |
Schedule of Maturity of Operating Lease Liabilities | Maturities of lease liabilities as of December 31, 2022, were as follows: (In millions) Operating Leases Finance Leases Total 2023 $ 56 $ 9 $ 65 2024 52 5 57 2025 49 5 54 2026 45 5 50 2027 39 4 43 Thereafter 105 5 110 Total lease payments (1) 346 33 379 Less imputed interest 51 10 61 Total net present value $ 295 $ 23 $ 318 (1) Operating lease payments for certain leases are offset by sublease receipts of $9 million over 10 years. |
Schedule of Maturity of Finance Lease Liabilities | Maturities of lease liabilities as of December 31, 2022, were as follows: (In millions) Operating Leases Finance Leases Total 2023 $ 56 $ 9 $ 65 2024 52 5 57 2025 49 5 54 2026 45 5 50 2027 39 4 43 Thereafter 105 5 110 Total lease payments (1) 346 33 379 Less imputed interest 51 10 61 Total net present value $ 295 $ 23 $ 318 (1) Operating lease payments for certain leases are offset by sublease receipts of $9 million over 10 years. |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Fair Value Disclosures [Abstract] | |
Schedule of 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, 2022 December 31, 2021 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Derivative assets FTRs (1) $ — $ — $ 11 $ 11 $ — $ — $ 9 $ 9 Equity securities 2 — — 2 2 — — 2 U.S. state debt securities — 266 — 266 — 273 — 273 Cash, cash equivalents and restricted cash (2) 206 — — 206 1,511 — — 1,511 Other (3) — 40 — 40 — 42 — 42 Total assets $ 208 $ 306 $ 11 $ 525 $ 1,513 $ 315 $ 9 $ 1,837 Liabilities Derivative liabilities FTRs (1) $ — $ — $ (2) $ (2) $ — $ — $ (1) $ (1) Total liabilities $ — $ — $ (2) $ (2) $ — $ — $ (1) $ (1) Net assets (liabilities) $ 208 $ 306 $ 9 $ 523 $ 1,513 $ 315 $ 8 $ 1,836 (1) Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. (2) Restricted cash of $46 million and $49 million as of December 31, 2022 and 2021 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. See Note 10, Capitalization for additional information. (3) Primarily consists of short-term investments. |
Schedule of 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, 2022 and 2021: December 31, 2022 (1) December 31, 2021 (2) Cost Basis Unrealized Gains Unrealized Losses Fair Value Cost Basis Unrealized Gains Unrealized Losses Fair Value (In millions) Debt securities $ 294 $ — $ (28) $ 266 $ 280 $ 2 $ (9) $ 273 (1) Excludes short-term cash investments of $5 million. (2) Excludes short-term cash investments of $11 million. |
Schedule of 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, 2022, 2021 and 2020, were as follows: For the Years Ended December 31, 2022 2021 2020 (1) (In millions) Sale Proceeds $ 48 $ 48 $ 186 Realized Gains 8 — 12 Realized Losses (13) (3) (8) Interest and Dividend Income 11 11 22 (1) Includes amounts associated with Nuclear Decommissioning Trusts that were previously held by JCP&L, ME, and PN. See above for additional information. |
Schedule of 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, 2022 and 2021: As of December 31, 2022 2021 (In millions) Carrying Value $ 21,641 $ 23,946 Fair Value 19,784 27,043 |
CAPITALIZATION (Tables)
CAPITALIZATION (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Capitalization, Long-Term Debt and Equity [Abstract] | |
Schedule of Preferred stock and preference stock authorizations | FirstEnergy and the Utilities were authorized to issue preferred stock and preference stock as of December 31, 2022, 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 |
Schedule of 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, 2022 and 2021: As of December 31, 2022 As of December 31, (Dollar amounts in millions) Maturity Date Interest Rate 2022 2021 FMBs and secured notes - fixed rate 2023-2059 2.650% - 8.250% $ 5,153 $ 5,021 Unsecured notes - fixed rate 2023-2050 1.600% - 7.375% 16,488 18,925 Finance lease obligations 23 36 Unamortized debt discounts (5) (8) Unamortized debt issuance costs (110) (126) Unamortized fair value adjustments 5 6 Currently payable long-term debt (351) (1,606) Total long-term debt and other long-term obligations $ 21,203 $ 22,248 FirstEnergy had the following redemptions and issuances during the twelve months ended December 31, 2022: Company Type Redemption/Issuance Date Interest Rate Maturity Amount Description Redemptions FE Unsecured Notes January, 2022 4.25% 2023 $850 In December 2021, FE provided notice of redemption with a make-whole premium of approximately $38 million ($30 million after-tax). TE Senior Secured Notes February, 2022 2.65% 2028 $25 On January 27, 2022, TE instructed its indenture trustee to provide notice of partial redemption. CEI Senior Notes, Series A March, 2022 2.77% 2034 $150 On February 11, 2022, CEI instructed its indenture trustee to provide notice of full redemption. WP FMBs April, 2022 3.34% 2022 $100 WP redeemed FMBs that became due. FE Unsecured Notes June, 2022 2.85% 2022 $500 On May 23, 2022 FE provided notice of redemption. FE Unsecured Notes June, 2022 7.375% 2031 $715 On May 25, 2022, FE commenced an offer to purchase for cash a portion of its 2031 Notes and 2047 Notes, which had $1.5 billion and $1 billion principal amounts outstanding, respectively. A portion of these notes were redeemed for approximately $1.1 billion, including a tender premium of approximately $101 million ($80 million after-tax). In addition, FE recognized approximately $7 million ($5 million after-tax) of deferred cash flow hedge losses and $10 million ($8 million after-tax) in other unamortized debt costs and fees associated with the FE debt redemptions. FE Unsecured Notes June, 2022 4.85% 2047 $284 Penn FMBs June, 2022 6.09% 2022 $100 Penn redeemed FMBs that became due. FE Unsecured Notes August-November 2022 7.375% 2031 $128 Beginning in the third quarter of 2022, FE repurchased a portion of the principal amount of its 2031 Notes and 2047 Notes through the open market for approximately $249 million including a premium of approximately $11 million ($9 million after tax). In addition, FE recognized approximately $3 million ($2 million after-tax) in other unamortized debt costs related to the FE open market repurchases. FE Unsecured Notes August-September 2022 4.85% 2047 $110 Issuances OE Senior Unsecured Notes September, 2022 5.50% 2033 $300 Proceeds were used to repay borrowings outstanding under the regulated money pool, to finance capital expenditures, to fund working capital needs and for other general corporate purposes. Penn FMBs November, 2022 3.79% 2032 $150 Proceeds were used to repay short-term borrowings. WP FMBs November, 2022 5.29% 2033 $250 Proceeds were used to repay short-term borrowings. |
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, 2022. (In millions) 2023 2024 2025 2026 2027 Scheduled debt repayments $344 $1,246 $2,023 $1,076 $2,003 |
REGULATORY MATTERS (Tables)
REGULATORY MATTERS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Regulated Operations [Abstract] | |
Schedule of Distribution Rate Orders | The following table summarizes the key terms of base distribution rate orders in effect for the Utilities as of December 31, 2022: 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) Rates were 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, 2022: 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) Actual (13-month average) (1) 11.35% (1) PE January 1, 2021 (1) Actual (13-month average) (1) 11.35% (1) WP January 1, 2021 (1) 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. On January 18, 2023, MP, PE, and WP submitted an uncontested settlement to FERC, which is subject to FERC approval, which includes an allowed ROE of 10.45% and a capital structure of the lower of actual (13-month average) or 56%. |
COMMITMENTS, GUARANTEES AND C_2
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
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, 2022: Potential Collateral Obligations Utilities and Transmission Companies FE Total (In millions) Contractual Obligations for Additional Collateral Upon Further Downgrade $ 70 $ — $ 70 Surety Bonds (collateralized amount) (1) 61 249 310 Total Exposure from Contractual Obligations $ 131 $ 249 $ 380 (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. |
SEGMENT INFORMATION (Tables)
SEGMENT INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Segment Reporting [Abstract] | |
Schedule of Segment Financial Information | For the Years Ended December 31, (In millions) 2022 2021 2020 External revenues Regulated Distribution $ 10,569 $ 9,510 $ 9,168 Regulated Transmission 1,863 1,608 1,613 Corporate/Other 27 14 9 Reconciling Adjustments — — — Total external revenues $ 12,459 $ 11,132 $ 10,790 Internal revenues Regulated Distribution $ 232 $ 201 $ 195 Regulated Transmission 5 10 17 Corporate/Other — — — Reconciling Adjustments (237) (211) (212) Total internal revenues $ — $ — $ — Total revenues $ 12,459 $ 11,132 $ 10,790 Depreciation Regulated Distribution $ 967 $ 911 $ 896 Regulated Transmission 335 325 313 Corporate/Other 7 3 4 Reconciling Adjustments 66 63 61 Total depreciation $ 1,375 $ 1,302 $ 1,274 Amortization (deferral) of regulatory assets, net Regulated Distribution $ (362) $ 260 $ (64) Regulated Transmission (3) 9 11 Corporate/Other — — — Reconciling Adjustments — — — Total amortization (deferral) of regulatory assets, net $ (365) $ 269 $ (53) DPA penalty Corporate/Other $ — $ 230 $ — Total DPA penalty $ — $ 230 $ — Miscellaneous income (expense), net Regulated Distribution $ 361 $ 399 $ 332 Regulated Transmission 36 41 30 Corporate/Other 85 58 81 Reconciling Adjustments (67) (12) (13) Total miscellaneous income (expense), net $ 415 $ 486 $ 430 Interest expense Regulated Distribution $ 526 $ 522 $ 501 Regulated Transmission 230 247 219 Corporate/Other 350 382 358 Reconciling Adjustments (67) (12) (13) Total interest expense $ 1,039 $ 1,139 $ 1,065 Income taxes (benefits) Regulated Distribution $ 251 $ 364 $ 113 Regulated Transmission 110 127 138 Corporate/Other 639 (171) (125) Reconciling Adjustments — — — Total income taxes (benefits) $ 1,000 $ 320 $ 126 For the Years Ended December 31, (In millions) 2022 2021 2020 Net income (loss) Regulated Distribution $ 957 $ 1,288 $ 959 Regulated Transmission 394 408 464 Corporate/Other (912) (413) (344) Reconciling Adjustments — — — Total net income (loss) $ 439 $ 1,283 $ 1,079 Income attributable to noncontrolling interest Regulated Transmission $ 33 $ — $ — Total income attributable to noncontrolling interest $ 33 $ — $ — Earnings attributable to FE Regulated Distribution $ 957 $ 1,288 $ 959 Regulated Transmission 361 408 464 Corporate/Other (912) (413) (344) Reconciling Adjustments — — — Total earnings attributable to FE $ 406 $ 1,283 $ 1,079 Property additions Regulated Distribution $ 1,513 $ 1,395 $ 1,514 Regulated Transmission 1,192 958 1,067 Corporate/Other 51 92 76 Reconciling Adjustments — — — Total property additions $ 2,756 $ 2,445 $ 2,657 As of December 31, (In millions) 2022 2021 Assets Regulated Distribution $ 31,749 $ 30,812 Regulated Transmission 13,835 13,237 Corporate/Other 524 1,383 Reconciling Adjustments — — Total assets $ 46,108 $ 45,432 Goodwill Regulated Distribution $ 5,004 $ 5,004 Regulated Transmission 614 614 Corporate/Other — — Reconciling Adjustments — — Total goodwill $ 5,618 $ 5,618 |
DISCONTINUED OPERATIONS (Tables
DISCONTINUED OPERATIONS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Schedule of Disposal Groups, Including Discontinued Operations | Summarized results of discontinued operations for the years ended December 31, 2022, 2021, and 2020 were as follows: For the Years Ended December 31, (In millions) 2022 2021 2020 Revenues $ — $ — $ 7 Fuel — — (6) Other operating expenses — — (6) Pleasants economic interest (1) — — 5 Other expense, net — (4) — Loss from discontinued operations, before tax — (4) — Income tax expense (benefit) — (1) — Loss from discontinued operations, net of tax — (3) — Settlement consideration and services credit — — (1) Accelerated net pension and OPEB prior service credits — — 18 Gain on disposal of FES and FENOC, before tax — — 17 Income tax benefits, including worthless stock deduction — (47) (59) Gain on disposal of FES and FENOC, net of tax — 47 76 Income from discontinued operations (2) $ — $ 44 $ 76 (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. (2) Income from discontinued operations are included in Corporate/Other for segment reporting. 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, 2022, 2021 and 2020: For the Years Ended December 31, (In millions) 2022 2021 2020 CASH FLOWS FROM OPERATING ACTIVITIES: Income from discontinued operations $ — $ 44 $ 76 Gain on disposal, net of tax — (47) (76) |
ORGANIZATION AND BASIS OF PRE_4
ORGANIZATION AND BASIS OF PRESENTATION - Narrative (Details) $ in Millions | 12 Months Ended | |||||
Feb. 02, 2023 USD ($) director | May 31, 2022 USD ($) director | Dec. 31, 2022 USD ($) mi² entity company customer agreement transmissionCenter MW | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | Jun. 30, 2013 USD ($) | |
Regulatory Assets [Line Items] | ||||||
Number of regional transmission centers | transmissionCenter | 2 | |||||
Regulatory assets currently being recovered through deferred returns | $ 464 | $ 228 | ||||
Investments (Note 9) | 622 | 655 | ||||
Equity method investment earnings (Note 1) | $ 168 | $ 31 | $ 2 | |||
Number of contracts that may contain variable interest | entity | 1 | |||||
Public utilities, property, plant and equipment, disclosure of composite depreciation rate for plants in service | 2.70% | 2.70% | 2.70% | |||
Capitalized financing costs | $ 56 | $ 48 | $ 49 | |||
Interest costs capitalized | 28 | 27 | 28 | |||
Property, plant and equipment | $ 36,285 | 34,744 | ||||
Brookfield II | FET | Subsequent Event | ||||||
Regulatory Assets [Line Items] | ||||||
Sale of ownership interest by parent | 30% | |||||
Noncontrolling interest ownership percentage | 49.90% | |||||
Power Purchase Agreements | ||||||
Regulatory Assets [Line Items] | ||||||
Number of long term power purchase agreements maintained by parent company with Non utility generation entities | agreement | 6 | |||||
Utilities and Transmission Companies | ||||||
Regulatory Assets [Line Items] | ||||||
Number of existing utility operating companies | company | 10 | |||||
Number of customers served by utility operating companies | customer | 6,000,000 | |||||
Number of square miles in service area | mi² | 65,000 | |||||
Plant generation capacity (in MW's) | MW | 3,580 | |||||
Property, plant and equipment, net | $ 2,200 | |||||
Regulated Transmission | ||||||
Regulatory Assets [Line Items] | ||||||
Number of square miles in service area | mi² | 24,000 | |||||
Global Holding | ||||||
Regulatory Assets [Line Items] | ||||||
Equity method investments | $ 57 | 59 | ||||
Path-WV | Variable Interest Entity, Not Primary Beneficiary | ||||||
Regulatory Assets [Line Items] | ||||||
Equity method investments | $ 18 | 18 | ||||
Percentage of high-voltage transmission line project owned by subsidiary of FE on the Allegheny Series | 100% | |||||
Variable Interest Entities Percentage Of high voltage transmission line project owned By variable interest entity one in joint venture party two | 50% | |||||
Global Holding And PATH WV | Power Purchase Agreements | ||||||
Regulatory Assets [Line Items] | ||||||
Ownership interest | 0% | |||||
FET | FE | Subsequent Event | ||||||
Regulatory Assets [Line Items] | ||||||
Ownership interest | 50.10% | |||||
Other Sundry Investments | ||||||
Regulatory Assets [Line Items] | ||||||
Equity method investments | $ 90 | 88 | ||||
FEV | Global Holding | ||||||
Regulatory Assets [Line Items] | ||||||
Proceeds from dividends received | $ 170 | |||||
FEV | Global Holding | Signal Peak | ||||||
Regulatory Assets [Line Items] | ||||||
Ownership interest | 33.33% | |||||
FEV | Global Holding | Other Nonoperating Income (Expense) | Corporate/Other | ||||||
Regulatory Assets [Line Items] | ||||||
Equity method investment earnings (Note 1) | $ 168 | 29 | 2 | |||
Ohio Funding Companies | Phase In Recovery Bonds | ||||||
Regulatory Assets [Line Items] | ||||||
Face amount of loan | $ 445 | |||||
Other FE subsidiaries | Power Purchase Agreements | ||||||
Regulatory Assets [Line Items] | ||||||
Purchased power | $ 119 | $ 111 | $ 113 | |||
FET | ||||||
Regulatory Assets [Line Items] | ||||||
Debt covenants minimum ownership interest percentage | 9.90% | |||||
Consolidation, less than wholly owned subsidiary, parent ownership interest, changes, transaction costs | $ 37 | |||||
Consolidation, less than wholly owned subsidiary, parent ownership interest, changes, carrying value of noncontrolling interest | $ 451 | |||||
Number of directors | director | 5 | |||||
Debt-to-Capital terms included in sale for the first 5 years | 65% | |||||
Debt-to-Capital terms included in sale for thereafter | 70% | |||||
FET | Subsequent Event | ||||||
Regulatory Assets [Line Items] | ||||||
Number of directors | director | 5 | |||||
FET | Brookfield II | ||||||
Regulatory Assets [Line Items] | ||||||
Sale of ownership interest by parent | 19.90% | |||||
Sale of ownership interest by parent | $ 2,375 | |||||
Number of directors | director | 1 | |||||
FET | Brookfield II | Subsequent Event | ||||||
Regulatory Assets [Line Items] | ||||||
Consideration | $ 3,500 | |||||
Debt covenants minimum ownership interest percentage | 30% | |||||
Number of directors | director | 2 | |||||
Liabilities incurred | $ 1,750 | |||||
FET | FE | ||||||
Regulatory Assets [Line Items] | ||||||
Number of directors | director | 4 | |||||
FET | FE | Subsequent Event | ||||||
Regulatory Assets [Line Items] | ||||||
Number of directors | director | 3 | |||||
Waverly, New York | PN | ||||||
Regulatory Assets [Line Items] | ||||||
Number of customers served by utility operating companies | customer | 4,000 | |||||
VIRGINIA | ||||||
Regulatory Assets [Line Items] | ||||||
Plant generation capacity (in MW's) | MW | 3,003 | |||||
VIRGINIA | AGC | ||||||
Regulatory Assets [Line Items] | ||||||
Plant generation capacity (in MW's) | MW | 487 | |||||
Proportionate ownership share | 16.25% | |||||
Property, plant and equipment | $ 153 | |||||
VIRGINIA | Virginia Electric and Power Company | ||||||
Regulatory Assets [Line Items] | ||||||
Proportionate ownership share | 60% |
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, 2022 | Dec. 31, 2021 | |
Regulatory assets on the Balance Sheets | ||
Regulatory liability | $ (1,847) | $ (2,124) |
Regulatory assets | 33 | 71 |
Net Regulatory Liabilities included on the Consolidated Balance Sheets | (1,814) | (2,053) |
Change | 239 | |
Current Return | 997 | 732 |
Change | 265 | |
Customer payables for future income taxes | ||
Regulatory assets on the Balance Sheets | ||
Regulatory liability | (2,463) | (2,345) |
Change | (118) | |
Spent nuclear fuel disposal costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory liability | (83) | (101) |
Change | 18 | |
Asset removal costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory liability | (675) | (646) |
Change | (29) | |
Deferred transmission costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory assets | 50 | (3) |
Change | 53 | |
Current Return | 8 | 13 |
Change | (5) | |
Deferred generation costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory assets | 235 | 118 |
Change | 117 | |
Current Return | 262 | 63 |
Change | 199 | |
Deferred distribution costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory assets | 164 | 49 |
Change | 115 | |
Current Return | 27 | 2 |
Change | 25 | |
Storm-related costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory assets | 683 | 660 |
Change | 23 | |
Current Return | 568 | 549 |
Change | 19 | |
Uncollectible and pandemic-related costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory assets | 63 | 56 |
Change | 7 | |
Current Return | 70 | 65 |
Change | 5 | |
Energy efficiency program costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory assets | 94 | 47 |
Change | 47 | |
New Jersey societal benefit costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory assets | 94 | 109 |
Change | (15) | |
Vegetation management | ||
Regulatory assets on the Balance Sheets | ||
Regulatory assets | 63 | 33 |
Change | 30 | |
Current Return | 52 | 31 |
Change | 21 | |
Other | ||
Regulatory assets on the Balance Sheets | ||
Regulatory liability | (39) | (30) |
Change | (9) | |
Current Return | 10 | $ 9 |
Change | $ 1 |
ORGANIZATION AND BASIS OF PRE_6
ORGANIZATION AND BASIS OF PRESENTATION - Summary of Changes in Goodwill (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
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_7
ORGANIZATION AND BASIS OF PRESENTATION - Property, Plant and Equipment Balances (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Property, Plant and Equipment | ||
In Service | $ 47,850 | $ 46,002 |
Accum. Depr. | (13,258) | (12,672) |
Net Plant | 34,592 | 33,330 |
CWIP | 1,693 | 1,414 |
Total | 36,285 | 34,744 |
Finance leases | 105 | 143 |
Regulated Distribution | ||
Property, Plant and Equipment | ||
In Service | 32,257 | 31,154 |
Accum. Depr. | (9,636) | (9,284) |
Net Plant | 22,621 | 21,870 |
CWIP | 828 | 774 |
Total | 23,449 | 22,644 |
Regulated Transmission | ||
Property, Plant and Equipment | ||
In Service | 14,468 | 13,744 |
Accum. Depr. | (2,978) | (2,789) |
Net Plant | 11,490 | 10,955 |
CWIP | 818 | 580 |
Total | 12,308 | 11,535 |
Corporate/Other | ||
Property, Plant and Equipment | ||
In Service | 1,125 | 1,104 |
Accum. Depr. | (644) | (599) |
Net Plant | 481 | 505 |
CWIP | 47 | 60 |
Total | $ 528 | $ 565 |
ORGANIZATION AND BASIS OF PRE_8
ORGANIZATION AND BASIS OF PRESENTATION - Asset Retirement Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Asset Retirement Obligation Period Increase Decrease Abstract [Roll Forward] | ||
Beginning Balance | $ 179 | $ 159 |
Changes in timing and amount of estimated cash flows | (2) | 8 |
Liabilities settled | (6) | (1) |
Accretion | 14 | 13 |
Ending Balance | $ 185 | $ 179 |
REVENUE - Narrative (Details)
REVENUE - Narrative (Details) | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2022 USD ($) | Dec. 31, 2022 USD ($) company MW | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | ||
Disaggregation of Revenue [Line Items] | |||||
Utility customer payment period | 30 days | ||||
Total revenues | [1] | $ 12,459,000,000 | $ 11,132,000,000 | $ 10,790,000,000 | |
Concentration of risk of accounts receivable | $ 0 | $ 0 | |||
Accounts receivable, allowance for credit loss, period increase (Decrease) | $ 25,000,000 | $ (121,000,000) | |||
LateFeeIncomeServicingFinancialAssetStatementOfIncomeOrComprehensiveIncomeExtensibleEnumerationNotDisclosedFlag | late payment charges | late payment charges | late payment charges | ||
Deferred Regulatory Assets | |||||
Disaggregation of Revenue [Line Items] | |||||
Accounts receivable, allowance for credit loss, period increase (Decrease) | $ 15,000,000 | ||||
Other Non-Customer Revenue | Derivative Revenue | |||||
Disaggregation of Revenue [Line Items] | |||||
Total revenues | $ 15,000,000 | $ 11,000,000 | $ 14,000,000 | ||
Other Non-Customer Revenue | Other revenue unrelated to contracts with customers | |||||
Disaggregation of Revenue [Line Items] | |||||
Late payment charges | $ 38,000,000 | $ 36,000,000 | $ 31,000,000 | ||
Utilities and Transmission Companies | |||||
Disaggregation of Revenue [Line Items] | |||||
Number of existing utility operating companies | company | 10 | ||||
Plant generation capacity (in MW's) | MW | 3,580 | ||||
[1]Includes excise and gross receipts tax collections of $406 million, $374 million and $362 million in 2022, 2021 and 2020, respectively. |
REVENUE - Schedule of Disaggreg
REVENUE - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | ||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | [1] | $ 12,459 | $ 11,132 | $ 10,790 |
Operating Segments | Utilities and Transmission Companies | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 10,700 | 9,644 | 9,227 | |
Total revenues | 10,801 | 9,711 | 9,363 | |
Operating Segments | Utilities and Transmission Companies | Wholesale | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 494 | 362 | 251 | |
Operating Segments | Utilities and Transmission Companies | Other revenue from contracts with customers | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 104 | 119 | 140 | |
Operating Segments | Utilities and Transmission Companies | ARP | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 0 | (27) | 43 | |
Operating Segments | Utilities and Transmission Companies | Other revenue unrelated to contracts with customers | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 101 | 94 | 93 | |
Operating Segments | Utilities and Transmission Companies | Distribution services and retail generation | Ohio Stipulation | ||||
Disaggregation of Revenue [Line Items] | ||||
Rate refunds | 58 | 38 | ||
Operating Segments | Regulated Transmission | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 1,863 | 1,608 | 1,613 | |
Total revenues | 1,868 | 1,618 | 1,630 | |
Operating Segments | Regulated Transmission | Other revenue unrelated to contracts with customers | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 5 | 10 | 17 | |
Operating Segments | Residential | Utilities and Transmission Companies | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 6,180 | 5,713 | 5,539 | |
Operating Segments | Commercial | Utilities and Transmission Companies | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 2,499 | 2,284 | 2,140 | |
Operating Segments | Industrial | Utilities and Transmission Companies | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 1,338 | 1,091 | 1,076 | |
Operating Segments | Other | Utilities and Transmission Companies | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 85 | 75 | 81 | |
Operating Segments | ATSI | Regulated Transmission | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 912 | 799 | 804 | |
Operating Segments | TrAIL | Regulated Transmission | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 270 | 233 | 247 | |
Operating Segments | MAIT | Regulated Transmission | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 340 | 288 | 250 | |
Operating Segments | JCP&L | Regulated Transmission | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 203 | 164 | 178 | |
Operating Segments | MP, PE and WP | Regulated Transmission | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 138 | 124 | 134 | |
Corporate/Other and Reconciling Adjustments | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | (210) | (197) | (203) | |
Corporate/Other and Reconciling Adjustments | Wholesale | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 27 | 14 | 9 | |
Corporate/Other and Reconciling Adjustments | Other revenue unrelated to contracts with customers | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | (51) | (57) | (64) | |
Corporate/Other and Reconciling Adjustments | Retail generation and distribution services | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | $ (186) | $ (154) | $ (148) | |
[1]Includes excise and gross receipts tax collections of $406 million, $374 million and $362 million in 2022, 2021 and 2020, respectively. |
REVENUE - Receivables from Cust
REVENUE - Receivables from Customers (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Customers | $ 1,455 | $ 1,192 |
Less — Allowance for uncollectible customer receivables | 137 | 159 |
Customers | 1,318 | 1,033 |
Billed | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Customers | 674 | 616 |
Billed | Financial Asset, Greater than 30 Days Past Due | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Customers | 290 | 318 |
Unbilled | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Customers | $ 781 | $ 576 |
REVENUE - Activity in Uncollect
REVENUE - Activity in Uncollectable Accounts (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2022 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||||
Deferred for recovery | $ 11 | $ 12 | $ 103 | |
Increase (decrease) in allowance for credit loss, | $ (25) | 121 | ||
Customer Receivables | ||||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||||
Beginning balance | 159 | 159 | 164 | 46 |
Charged to income | 59 | 54 | 174 | |
Charged to other accounts | 62 | 42 | 46 | |
Write-offs | (143) | (101) | (102) | |
Ending balance | 137 | 159 | 164 | |
Other Receivables | ||||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||||
Beginning balance | 10 | 10 | 26 | 21 |
Charged to income | 4 | 3 | 7 | |
Charged to other accounts | 4 | 3 | 10 | |
Write-offs | (7) | (22) | (12) | |
Ending balance | 11 | 10 | 26 | |
Affiliated Companies Receivables | FES | ||||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||||
Beginning balance | $ 0 | 0 | 0 | |
Write-offs | (1,100) | |||
Ending balance | $ 0 | $ 0 | $ 0 |
EARNINGS PER SHARE OF COMMON _3
EARNINGS PER SHARE OF COMMON STOCK (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | ||
Earnings Per Share [Abstract] | ||||
Earnings Attributable to FE - continuing operations | $ 406 | $ 1,239 | $ 1,003 | |
Earnings Attributable to FE - discontinued operations, net of tax | [1] | 0 | 44 | 76 |
EARNINGS ATTRIBUTABLE TO FIRSTENERGY CORP. | $ 406 | $ 1,283 | $ 1,079 | |
Share Count information: | ||||
Weighted average number of basic shares outstanding (in shares) | 571 | 545 | 542 | |
Assumed exercise of dilutive stock options and awards (in shares) | 1 | 1 | 1 | |
Weighted average number of diluted shares outstanding (in shares) | 572 | 546 | 543 | |
EPS Attributable to FE: | ||||
Basic - Income from continuing operations, basic (in dollars per share) | $ 0.71 | $ 2.27 | $ 1.85 | |
Basic - Discontinued operations, basic (in dollars per share) | 0 | 0.08 | 0.14 | |
Basic - EPS (in dollars per share) | 0.71 | 2.35 | 1.99 | |
Diluted - Income from continuing operations, diluted (in dollars per share) | 0.71 | 2.27 | 1.85 | |
Diluted - Discontinued operations, diluted (in dollars per share) | 0 | 0.08 | 0.14 | |
Diluted - EPS (in dollars per share) | $ 0.71 | $ 2.35 | $ 1.99 | |
[1]Net of income tax benefit of $48 million and $59 million in 2021 and 2020, respectively. |
EARNINGS PER SHARE OF COMMON _4
EARNINGS PER SHARE OF COMMON STOCK - Narrative (Details) - shares shares in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Stock Options | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive securities excluded from computation of EPS (in shares) | 0 | 0 | 0 |
ACCUMULATED OTHER COMPREHENSI_3
ACCUMULATED OTHER COMPREHENSIVE INCOME - Components of AOCI (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
Beginning Balance | $ 8,675 | ||
Amounts reclassified from AOCI | 0 | $ (13) | $ (33) |
Other comprehensive loss | 0 | (13) | (33) |
Income tax (benefits) on other comprehensive income (loss) | (1) | (3) | (8) |
Other comprehensive income (loss), net of tax | 1 | (10) | (25) |
Ending Balance | 10,166 | 8,675 | |
Accumulated Other Comprehensive Income | |||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
Beginning Balance | (15) | (5) | 20 |
Other comprehensive income (loss), net of tax | 1 | (10) | (25) |
Ending Balance | (14) | (15) | (5) |
Gains & Losses on Cash Flow Hedges | |||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
Beginning Balance | (7) | (8) | (9) |
Amounts reclassified from AOCI | 9 | 1 | 1 |
Other comprehensive loss | 9 | 1 | 1 |
Income tax (benefits) on other comprehensive income (loss) | 2 | 0 | 0 |
Other comprehensive income (loss), net of tax | 7 | 1 | 1 |
Ending Balance | 0 | (7) | (8) |
Defined Benefit Pension & OPEB Plans | |||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
Beginning Balance | (8) | 3 | 29 |
Amounts reclassified from AOCI | (9) | (14) | (34) |
Other comprehensive loss | (9) | (14) | (34) |
Income tax (benefits) on other comprehensive income (loss) | (3) | (3) | (8) |
Other comprehensive income (loss), net of tax | (6) | (11) | (26) |
Ending Balance | $ (14) | $ (8) | $ 3 |
PENSION AND OTHER POST-EMPLOY_3
PENSION AND OTHER POST-EMPLOYMENT BENEFITS - Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Defined Benefit Plan Disclosure [Line Items] | ||||
Increase in discount rate | 2.21% | |||
Pension | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Expected return on plan assets | 7.50% | 7.50% | 7.50% | |
Expected future contributions in 2025 | $ 250 | |||
Expected return on plan assets | 657 | $ 652 | $ 618 | |
Actual return on plan assets | (1,760) | 625 | ||
Increase in benefit obligation due to RP2014 mortality table | 23 | |||
Pension | Forecast | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Expected return on plan assets | 8% | |||
Pensions and OPEB | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Expected return on plan assets | 696 | 688 | 651 | |
Actual return on plan assets | $ (1,830) | $ 689 | $ 1,225 | |
Actual return on plan assets (percent) | (19.10%) | 7.90% | 14.70% | |
OPEB | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Expected return on plan assets | 7.50% | 7.50% | 7.50% | |
Expected return on plan assets | $ 39 | $ 36 | $ 33 | |
Actual return on plan assets | (70) | 64 | ||
OPEB | Regulated Transmission | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Mark-to-market adjustment, net of capitalized amounts | $ 15 | $ (31) | $ 40 |
PENSION AND OTHER POST-EMPLOY_4
PENSION AND OTHER POST-EMPLOYMENT BENEFITS - Assumptions Used to Determine Net Periodic Benefit Cost (Details) | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Pension | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Discount rate | 5.23% | 3.02% | 2.67% |
Rate of compensation increase | 4.30% | 4.10% | 4.10% |
Cash balance weighted average interest crediting rate | 4.04% | 2.57% | 2.57% |
Expected return on plan assets | 7.50% | 7.50% | 7.50% |
Rate of compensation increase | 4.10% | 4.10% | 4.10% |
Pension | Interest on Benefit Obligations | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted-average discount rate | 2.44% | 1.94% | |
Pension | Interest on Benefit Obligations | Minimum | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted-average discount rate | 2.89% | ||
Pension | Interest on Benefit Obligations | Maximum | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted-average discount rate | 2.48% | ||
Pension | Service Cost | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted-average discount rate | 3.28% | 3.10% | |
Pension | Service Cost | Minimum | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted-average discount rate | 360% | ||
Pension | Service Cost | Maximum | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted-average discount rate | 3.24% | ||
Pension | Interest Cost | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted-average discount rate | 2.96% | 2.58% | |
Pension | Interest Cost | Minimum | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted-average discount rate | 327% | ||
Pension | Interest Cost | Maximum | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted-average discount rate | 2.90% | ||
OPEB | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Discount rate | 5.16% | 2.84% | 2.45% |
Expected return on plan assets | 7.50% | 7.50% | 7.50% |
Rate to which the cost trend rate is assumed to decline (ultimate trend rate) | 4.50% | 4.50% | 4.50% |
OPEB | Pre Medicare | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Health care cost trend rate assumed (pre/post-Medicare) | 6% | 5.75% | 6% |
OPEB | Post Medicare | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Health care cost trend rate assumed (pre/post-Medicare) | 5.50% | 5.25% | 5.50% |
OPEB | Interest on Benefit Obligations | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted-average discount rate | 2.18% | 1.66% | |
OPEB | Interest on Benefit Obligations | Minimum | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted-average discount rate | 271% | ||
OPEB | Interest on Benefit Obligations | Maximum | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted-average discount rate | 2.30% | ||
OPEB | Service Cost | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted-average discount rate | 3.41% | 3.03% | |
OPEB | Service Cost | Minimum | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted-average discount rate | 363% | ||
OPEB | Service Cost | Maximum | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted-average discount rate | 3.29% | ||
OPEB | Interest Cost | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted-average discount rate | 3.24% | 2.83% | |
OPEB | Interest Cost | Minimum | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted-average discount rate | 343% | ||
OPEB | Interest Cost | Maximum | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted-average discount rate | 3.06% |
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 | ||
Mar. 31, 2020 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Pension | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Service cost | $ 184 | $ 195 | $ 194 | |
Interest cost | 273 | 226 | 287 | |
Expected return on plan assets | (657) | (652) | (618) | |
Amortization of prior service costs (credits) | 2 | 3 | 12 | |
One-time termination benefits | 0 | 0 | 8 | |
Pension & OPEB mark-to-market | (98) | (253) | 463 | |
Net periodic benefit costs (credits) | (296) | (481) | 346 | |
Net accelerated credits | $ 18 | |||
OPEB | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Service cost | 3 | 4 | 4 | |
Interest cost | 11 | 11 | 15 | |
Expected return on plan assets | (39) | (36) | (33) | |
Amortization of prior service costs (credits) | (11) | (17) | (46) | |
One-time termination benefits | 0 | 0 | 0 | |
Pension & OPEB mark-to-market | 26 | (129) | 14 | |
Net periodic benefit costs (credits) | $ (10) | $ (167) | $ (46) |
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, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Pension | |||
Change in benefit obligation: | |||
Benefit obligation as of January 1 | $ 11,479 | $ 11,935 | |
Service cost | 184 | 195 | $ 194 |
Interest cost | 273 | 226 | 287 |
Plan participants’ contributions | 0 | 0 | |
Medicare retiree drug subsidy | 0 | 0 | |
Actuarial loss (gain) | (2,515) | (280) | |
Benefits paid | (593) | (597) | |
Benefit obligation as of December 31 | 8,828 | 11,479 | 11,935 |
Change in fair value of plan assets: | |||
Fair value of plan assets as of January 1 | 9,020 | 8,968 | |
Actual return on plan assets | (1,760) | 625 | |
Company contributions | 26 | 24 | |
Plan participants’ contributions | 0 | 0 | |
Benefits paid | (593) | (597) | |
Fair value of plan assets as of December 31 | 6,693 | 9,020 | 8,968 |
Funded Status: | |||
Funded Status (Net liability as of December 31) | (2,135) | (2,459) | |
Accumulated benefit obligation | 8,500 | 10,927 | |
Amounts Recognized in AOCI: | |||
Prior service cost (credit) | 6 | 9 | |
Pension | Qualified plan | |||
Funded Status: | |||
Funded Status (Net liability as of December 31) | (1,734) | (1,974) | |
Pension | Non-qualified plans | |||
Funded Status: | |||
Funded Status (Net liability as of December 31) | (401) | (485) | |
OPEB | |||
Change in benefit obligation: | |||
Benefit obligation as of January 1 | 549 | 676 | |
Service cost | 3 | 4 | 4 |
Interest cost | 11 | 11 | 15 |
Plan participants’ contributions | 3 | 4 | |
Medicare retiree drug subsidy | 1 | 1 | |
Actuarial loss (gain) | (83) | (101) | |
Benefits paid | (45) | (46) | |
Benefit obligation as of December 31 | 439 | 549 | 676 |
Change in fair value of plan assets: | |||
Fair value of plan assets as of January 1 | 548 | 502 | |
Actual return on plan assets | (70) | 64 | |
Company contributions | 24 | 24 | |
Plan participants’ contributions | 3 | 4 | |
Benefits paid | (45) | (46) | |
Fair value of plan assets as of December 31 | 460 | 548 | $ 502 |
Funded Status: | |||
Funded Status (Net liability as of December 31) | 21 | (1) | |
Accumulated benefit obligation | 0 | 0 | |
Amounts Recognized in AOCI: | |||
Prior service cost (credit) | (10) | (21) | |
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, 2022 | Dec. 31, 2021 |
Pension | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 6,343 | $ 9,067 |
Asset Allocation | 100% | 100% |
Excluded from total investments | $ 350 | $ (47) |
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 | $ 3,707 | $ 6,372 |
Asset Allocation | 58% | 70% |
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 | $ 714 | $ 746 |
Asset Allocation | 11% | 8% |
Pension | Public equity | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 2,087 | $ 3,153 |
Asset Allocation | 33% | 35% |
Pension | Fixed income | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 942 | $ 2,453 |
Asset Allocation | 15% | 27% |
Pension | Derivatives | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ (36) | $ 20 |
Asset Allocation | (1.00%) | 0% |
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 | $ 1,061 | $ 811 |
Asset Allocation | 17% | 9% |
Pension | Insurance-linked securities | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 159 | $ 320 |
Asset Allocation | 3% | 4% |
Pension | Hedge funds | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 563 | $ 678 |
Asset Allocation | 9% | 7% |
Pension | Real estate funds | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 853 | $ 886 |
Asset Allocation | 13% | 10% |
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 | $ 1,833 | $ 2,887 |
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 | 1,871 | 2,867 |
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 | (38) | 20 |
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 | 1,874 | 3,485 |
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 | 714 | 746 |
Pension | Level 2 | Public equity | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 216 | 286 |
Pension | Level 2 | Fixed income | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 942 | 2,453 |
Pension | Level 2 | Derivatives | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 2 | 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 | $ 461 | $ 548 |
Asset Allocation | 100% | 100% |
Excluded from total investments | $ (1) | |
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 | $ 87 | $ 95 |
Asset Allocation | 19% | 17% |
OPEB | Public equity | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 217 | $ 278 |
Asset Allocation | 47% | 51% |
OPEB | Fixed income | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 157 | $ 175 |
Asset Allocation | 34% | 32% |
OPEB | Level 1 | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 217 | $ 278 |
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 | 217 | 278 |
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 | 244 | 270 |
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 | 87 | 95 |
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 | 157 | 175 |
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 |
PENSION AND OTHER POST-EMPLOY_8
PENSION AND OTHER POST-EMPLOYMENT BENEFITS - Target Asset Allocations for Pension and OPEB Portfolio (Details) | Dec. 31, 2022 |
OPEB | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Asset Allocations | 100% |
Pension | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Asset Allocations | 100% |
Equities | OPEB | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Asset Allocations | 50% |
Equities | Pension | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Asset Allocations | 36% |
Fixed Income | OPEB | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Asset Allocations | 50% |
Fixed Income | Pension | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Asset Allocations | 22.50% |
Alternative investments | OPEB | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Asset Allocations | 0% |
Alternative investments | Pension | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Asset Allocations | 5% |
Real estate | OPEB | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Asset Allocations | 0% |
Real estate | Pension | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Asset Allocations | 10% |
Private - equity and debt funds | OPEB | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Asset Allocations | 0% |
Private - equity and debt funds | Pension | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Asset Allocations | 20% |
Cash and derivatives | OPEB | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Asset Allocations | 0% |
Cash and derivatives | Pension | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Asset Allocations | 6.50% |
PENSION AND OTHER POST-EMPLOY_9
PENSION AND OTHER POST-EMPLOYMENT BENEFITS - Estimated Future Benefit Payments (Details) $ in Millions | Dec. 31, 2022 USD ($) |
Pension | |
Estimated Future Benefit Payments | |
2023 | $ 583 |
2024 | 587 |
2025 | 597 |
2026 | 605 |
2027 | 612 |
Years 2028-2031 | 3,120 |
OPEB | |
Estimated Future Benefit Payments | |
2023 | 44 |
2024 | 42 |
2025 | 40 |
2026 | 39 |
2027 | 37 |
Years 2028-2031 | 167 |
Defined Benefit Plan, Expected Future Prescription Drug Subsidy Receipt [Abstract] | |
2023 | (1) |
2024 | (1) |
2025 | (1) |
2026 | 0 |
2027 | 0 |
Years 2028-2031 | $ (2) |
STOCK-BASED COMPENSATION PLAN_2
STOCK-BASED COMPENSATION PLANS - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Realized tax benefits | $ 8 | $ 10 | $ 20 |
Tax benefit associated with stock-based compensation expense | 8 | 5 | 3 |
Cash portion of RSU paid | 9 | ||
Fair value of restricted stock units vested | 26 | 34 | $ 80 |
EDCP | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Net liability recognized | 193 | 201 | |
DCPD | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Net liability recognized | $ 8 | $ 9 | |
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) | $ 41.19 | $ 35.50 | $ 44,420,000 |
Unrecognized cost | $ 27 | ||
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% | ||
Award performance period | 3 years | ||
Maximum payout of awards during negative performance period | 100% | ||
Liability recognized | $ 20 | ||
Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation award vesting period | 1 year | ||
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 (in shares) | 11,900,000 | ||
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 (in shares) | 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, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | $ 101 | $ 90 | $ 51 |
Stock-based compensation costs, net of amounts capitalized | 54 | 43 | 25 |
Incentive Plans | Restricted stock units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | 55 | 40 | 22 |
Incentive Plans | Restricted stock | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | 3 | 2 | 1 |
401(k) savings plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | 36 | 35 | 33 |
EDCP & DCPD | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | $ 7 | $ 13 | $ (5) |
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, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Weighted-Average Grant Date Fair Value (per share) | |||
Dividend shares earned during period, number of shares | 80 | ||
Restricted stock units | |||
Shares (in millions) | |||
Nonvested, beginning balance (shares) | 1,800 | ||
Granted (shares) | 1,000 | ||
Forfeited (shares) | (300) | ||
Vested (shares) | (600) | ||
Nonvested, ending balance (shares) | 1,900 | 1,800 | |
Weighted-Average Grant Date Fair Value (per share) | |||
Beginning balance (in dollars per share) | $ 41.89 | ||
Granted (in dollars per share) | 41.19 | $ 35.50 | $ 44,420,000 |
Forfeited (in dollars per share) | 39.58 | ||
Vested (in dollars per share) | 41.57 | ||
Ending balance (in dollars per share) | $ 41.57 | $ 41.89 |
TAXES - Narrative (Details)
TAXES - Narrative (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||
Jul. 08, 2022 | Dec. 31, 2022 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2024 | May 31, 2022 | |
Provision for Income Tax [Line Items] | |||||||
Operating loss carryforwards, subject to expiration | $ 7,100 | $ 7,100 | |||||
Nondeductible DPA monetary penalty | 752 | ||||||
Valuation allowances | (47) | $ 17 | $ (49) | ||||
Excess deferred tax amortization due to the Tax Act | (51) | (54) | (56) | ||||
Income taxes (benefits) | 1,000 | $ 320 | $ 126 | ||||
Operating loss carryforwards, subject to expiration, net of tax | 1,500 | 1,500 | |||||
Operating loss carryforwards, not subject to expiration | 5,000 | 5,000 | |||||
Operating loss carryforwards, not subject to expiration, net of tax | 1,000 | 1,000 | |||||
General business tax credits | 51 | 51 | |||||
Unrecognized tax benefits that would impact future tax rates | 41 | 41 | |||||
Unrecognized tax benefits, portion expected to be resolved in the next fiscal year | 25 | 25 | |||||
Unrecognized tax benefits that would impact effective tax rate | 24 | 24 | |||||
State and Local | |||||||
Provision for Income Tax [Line Items] | |||||||
Valuation allowances | 54 | ||||||
Operating loss carryforwards, not subject to expiration | 12,600 | 12,600 | |||||
Operating loss carryforwards, not subject to expiration, net of tax | 568 | 568 | |||||
Pre-tax net operating loss carryforwards expected to utilized | 3,900 | 3,900 | |||||
Operating loss carryforwards expected to utilized, net of tax | $ 199 | 199 | |||||
Tax Years 2018 and 2019 | |||||||
Provision for Income Tax [Line Items] | |||||||
Valuation allowances | $ 38 | ||||||
Brookfield II | FET | |||||||
Provision for Income Tax [Line Items] | |||||||
Sale of ownership interest by parent | 19.90% | ||||||
Brookfield II | FET | Forecast | |||||||
Provision for Income Tax [Line Items] | |||||||
Sale of ownership interest by parent | 30% | ||||||
Operating loss carryforwards, subject to expiration | $ 7,100 | ||||||
Equity interest rate of combined sale | 49.90% | ||||||
Consideration | $ 3,500 | ||||||
Pennsylvania | |||||||
Provision for Income Tax [Line Items] | |||||||
Excess deferred tax amortization due to the Tax Act | $ 230 | ||||||
Increase (decrease) in regulatory liabilities | 236 | ||||||
Income taxes (benefits) | $ 6 |
TAXES - Provision for Income Ta
TAXES - Provision for Income Taxes (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Currently payable (receivable)- | |||
Federal | $ 0 | $ 2 | $ (14) |
State | 11 | 21 | 21 |
Currently payable (receivable) Total | 11 | 23 | 7 |
Deferred, net- | |||
Federal | 946 | 174 | 171 |
State | 47 | 127 | (38) |
Deferred Tax Total | 993 | 301 | 133 |
Investment tax credit amortization | (4) | (4) | (14) |
Total income taxes | $ 1,000 | 320 | 126 |
Federal | |||
Deferred, net- | |||
Income tax expense (benefit), continuing operations, discontinued operations | 2 | ||
Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC | Federal | |||
Deferred, net- | |||
Federal | $ 46 | 66 | |
Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC | State and Local | |||
Deferred, net- | |||
Federal | $ 1 |
TAXES - Reconciliation of Feder
TAXES - Reconciliation of Federal Income Tax Expense (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | May 31, 2022 | |
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 | $ 1,439 | $ 1,559 | $ 1,129 | |
Federal income tax expense at statutory rate (21%) | 302 | 327 | 237 | |
Increases (reductions) in taxes resulting from- | ||||
State and municipal income taxes, net of federal tax benefit | 56 | 122 | 75 | |
AFUDC equity and other flow-through | (26) | (29) | (38) | |
Amortization of investment tax credits | (4) | (4) | (14) | |
Deferred gain on 19.9% FET minority interest sale | 752 | 0 | 0 | |
Federal tax credits claimed | (3) | (34) | 0 | |
Nondeductible DPA monetary penalty | 0 | 52 | 0 | |
Excess deferred tax amortization due to the Tax Act | (51) | (54) | (56) | |
TMI-2 reversal of tax regulatory liabilities | 0 | 0 | (40) | |
Uncertain tax positions | 2 | (82) | (1) | |
Valuation allowances | (47) | 17 | (49) | |
Other, net | 19 | 5 | 12 | |
Total income taxes | $ 1,000 | $ 320 | $ 126 | |
Effective income tax rate (percent) | 69.50% | 20.50% | 11.20% | |
Brookfield II | FET | ||||
Provision for Income Tax [Line Items] | ||||
Sale of ownership interest by parent | 19.90% |
TAXES - Accumulated Deferred In
TAXES - Accumulated Deferred Income Taxes (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Income Tax Disclosure [Abstract] | ||||
Property basis differences | $ 5,528 | $ 5,670 | ||
Pension and OPEB | (496) | (570) | ||
AROs | (22) | (21) | ||
Regulatory asset/liability | 432 | 322 | ||
Deferred compensation | (149) | (155) | ||
Deferred gain on 19.9% FET minority interest sale | 752 | 0 | ||
Loss carryforwards and tax credits | (2,073) | (2,040) | ||
Valuation reserve | 440 | 484 | $ 496 | $ 441 |
All other | (210) | (253) | ||
Net deferred income tax liability | $ 4,202 | $ 3,437 |
TAXES - Pre-tax Net Operating L
TAXES - Pre-tax Net Operating Loss Expiration Period (Details) $ in Millions | Dec. 31, 2022 USD ($) |
State | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | $ 8,244 |
State | 2023-2027 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 2,479 |
State | 2028-2032 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 1,603 |
State | 2033-2037 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 876 |
State | 2038-2042 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 935 |
State | Indefinite | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 2,351 |
Local | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 4,317 |
Local | 2023-2027 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 4,317 |
Local | 2028-2032 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 0 |
Local | 2033-2037 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 0 |
Local | 2038-2042 | |
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, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Loss Carry Forward Valuation Reserve | |||
Beginning of year balance | $ 484 | $ 496 | $ 441 |
Charged to income | (44) | (12) | 55 |
Charged to other accounts | 0 | 0 | 0 |
Write-offs | 0 | 0 | 0 |
End of year balance | $ 440 | $ 484 | $ 496 |
TAXES - Changes in Unrecognized
TAXES - Changes in Unrecognized Tax Benefits (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Changes in unrecognized tax benefits | |||
Beginning balance | $ 47 | $ 139 | $ 164 |
Current year increases | 15 | 7 | |
Increase resulting related to federal positions | 2 | ||
Prior year decreases | (8) | (28) | |
Effectively settled with taxing authorities | (97) | (2) | |
Decrease for lapse in statute | (7) | (2) | (2) |
Ending balance | $ 42 | $ 47 | $ 139 |
TAXES - Details of General Taxe
TAXES - Details of General Taxes (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
General Taxes | |||
kWh excise | $ 191 | $ 189 | $ 183 |
State gross receipts | 219 | 190 | 182 |
Real and personal property | 596 | 571 | 541 |
Social security and unemployment | 105 | 103 | 112 |
Other | 18 | 20 | 28 |
Total general taxes | $ 1,129 | $ 1,073 | $ 1,046 |
LEASES - Narrative (Details)
LEASES - Narrative (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2022 USD ($) | |
Lessor, Lease, Description [Line Items] | |
Amount of leases not yet commenced | $ 1 |
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, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Lessee, Lease, Description [Line Items] | |||
Operating lease costs | $ 73 | $ 71 | $ 60 |
Amortization of right-of-use assets | 13 | 14 | 15 |
Interest on lease liabilities | 3 | 4 | 5 |
Total finance lease cost | 16 | 18 | 20 |
Total lease cost | 89 | 89 | 80 |
Short-term lease costs | 19 | 21 | 17 |
Cash paid for amounts included in the measurement of lease liabilities: | |||
Operating cash flows from operating leases | 56 | 64 | 44 |
Operating cash flows from finance leases | 3 | 4 | 4 |
Finance cash flows from finance leases | 12 | 13 | 15 |
Right-of-use assets obtained in exchange for lease obligations: | |||
Operating leases | 26 | 60 | 67 |
Finance leases | 0 | 5 | 0 |
Vehicles | |||
Lessee, Lease, Description [Line Items] | |||
Operating lease costs | 50 | 44 | 35 |
Amortization of right-of-use assets | 10 | 12 | 14 |
Interest on lease liabilities | 0 | 1 | 2 |
Total finance lease cost | 10 | 13 | 16 |
Total lease cost | 60 | 57 | 51 |
Buildings | |||
Lessee, Lease, Description [Line Items] | |||
Operating lease costs | 8 | 9 | 8 |
Amortization of right-of-use assets | 1 | 1 | 0 |
Interest on lease liabilities | 3 | 3 | 3 |
Total finance lease cost | 4 | 4 | 3 |
Total lease cost | 12 | 13 | 11 |
Other | |||
Lessee, Lease, Description [Line Items] | |||
Operating lease costs | 15 | 18 | 17 |
Amortization of right-of-use assets | 2 | 1 | 1 |
Interest on lease liabilities | 0 | 0 | 0 |
Total finance lease cost | 2 | 1 | 1 |
Total lease cost | $ 17 | $ 19 | $ 18 |
LEASES - Assets and Liabilities
LEASES - Assets and Liabilities, Lessee (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Weighted-average remaining lease terms (years) | |||
Operating leases | 7 years 3 months 18 days | 7 years 11 months 19 days | 8 years 6 months 18 days |
Finance leases | 11 years 3 months 29 days | 8 years 1 month 13 days | 7 years 8 months 26 days |
Weighted-average discount rate | |||
Operating leases | 4.22% | 4.16% | 4.21% |
Finance leases | 14.77% | 12.22% | 11.58% |
Assets | |||
Operating lease | $ 262 | $ 279 | |
Finance lease | 45 | 48 | |
Total leased assets | 307 | 327 | |
Current: | |||
Operating | 48 | 39 | |
Finance | 6 | 13 | |
Noncurrent: | |||
Operating | 247 | 271 | |
Finance lease obligations | 17 | 23 | |
Total leased liabilities | 318 | 346 | |
Operating lease assets, accumulated amortization | 114 | 79 | |
Financing lease, accumulated amortization | $ 60 | $ 95 | |
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 |
LEASES - Maturity of Operating
LEASES - Maturity of Operating and Finance Lease Liabilities (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Operating Leases | ||
2023 | $ 56 | |
2024 | 52 | |
2025 | 49 | |
2026 | 45 | |
2027 | 39 | |
Thereafter | 105 | |
Total lease payments | 346 | |
Less imputed interest | 51 | |
Total net present value | 295 | |
Finance Leases | ||
2023 | 9 | |
2024 | 5 | |
2025 | 5 | |
2026 | 5 | |
2027 | 4 | |
Thereafter | 5 | |
Total lease payments | 33 | |
Less imputed interest | 10 | |
Finance lease obligations | 23 | $ 36 |
Total | ||
2023 | 65 | |
2024 | 57 | |
2025 | 54 | |
2026 | 50 | |
2027 | 43 | |
Thereafter | 110 | |
Total lease payments | 379 | |
Less imputed interest | 61 | |
Total net present value | 318 | |
Sublease income | $ 9 | |
Sublease income term | 10 years |
FAIR VALUE MEASUREMENTS - Narra
FAIR VALUE MEASUREMENTS - Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | 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 | $ 351 | $ 371 | |
Corporate-Owned Life Insurance | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Gain (Loss) on investments | $ (20) | $ 13 | $ 20 |
FAIR VALUE MEASUREMENTS - Recur
FAIR VALUE MEASUREMENTS - Recurring Assets and Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Liabilities | ||
Restricted cash | $ 46 | $ 49 |
Recurring | ||
Assets | ||
Fair value, assets | 525 | 1,837 |
Liabilities | ||
Fair value, liabilities | (2) | (1) |
Net assets (liabilities) | 523 | 1,836 |
Recurring | FTRs | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | (2) | (1) |
Recurring | FTRs | Derivative Assets | ||
Assets | ||
Fair value, assets | 11 | 9 |
Recurring | Equity securities | ||
Assets | ||
Fair value, assets | 2 | 2 |
Recurring | U.S. state debt securities | ||
Assets | ||
Fair value, assets | 266 | 273 |
Recurring | Cash, cash equivalents and restricted cash | ||
Assets | ||
Fair value, assets | 206 | 1,511 |
Recurring | Other | ||
Assets | ||
Fair value, assets | 40 | 42 |
Recurring | Level 1 | ||
Assets | ||
Fair value, assets | 208 | 1,513 |
Liabilities | ||
Fair value, liabilities | 0 | 0 |
Net assets (liabilities) | 208 | 1,513 |
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 | U.S. state debt securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Recurring | Level 1 | Cash, cash equivalents and restricted cash | ||
Assets | ||
Fair value, assets | 206 | 1,511 |
Recurring | Level 1 | Other | ||
Assets | ||
Fair value, assets | 0 | 0 |
Recurring | Level 2 | ||
Assets | ||
Fair value, assets | 306 | 315 |
Liabilities | ||
Fair value, liabilities | 0 | 0 |
Net assets (liabilities) | 306 | 315 |
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 | U.S. state debt securities | ||
Assets | ||
Fair value, assets | 266 | 273 |
Recurring | Level 2 | Cash, cash equivalents and restricted cash | ||
Assets | ||
Fair value, assets | 0 | 0 |
Recurring | Level 2 | Other | ||
Assets | ||
Fair value, assets | 40 | 42 |
Recurring | Level 3 | ||
Assets | ||
Fair value, assets | 11 | 9 |
Liabilities | ||
Fair value, liabilities | (2) | (1) |
Net assets (liabilities) | 9 | 8 |
Recurring | Level 3 | FTRs | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | (2) | (1) |
Recurring | Level 3 | FTRs | Derivative Assets | ||
Assets | ||
Fair value, assets | 11 | 9 |
Recurring | Level 3 | Equity securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Recurring | Level 3 | U.S. state debt 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 | Other | ||
Assets | ||
Fair value, assets | $ 0 | $ 0 |
FAIR VALUE MEASUREMENTS - Inves
FAIR VALUE MEASUREMENTS - Investments Held in Trusts (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Debt Securities, Available-for-sale [Abstract] | ||
Short-term cash investments | $ 5 | $ 11 |
Debt Securities | ||
Debt Securities, Available-for-sale [Abstract] | ||
Cost Basis | 294 | 280 |
Unrealized Gains | 0 | 2 |
Unrealized Losses | (28) | (9) |
Fair Value | $ 266 | $ 273 |
FAIR VALUE MEASUREMENTS - Proce
FAIR VALUE MEASUREMENTS - Proceeds from the Sale of Investments (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Fair Value Disclosures [Abstract] | |||
Sale Proceeds | $ 48 | $ 48 | $ 186 |
Realized Gains | 8 | 0 | 12 |
Realized Losses | (13) | (3) | (8) |
Interest and Dividend Income | $ 11 | $ 11 | $ 22 |
FAIR VALUE MEASUREMENTS - Carry
FAIR VALUE MEASUREMENTS - Carrying Amounts of Long-term Debt (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
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 | $ 21,641 | $ 23,946 |
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 | $ 19,784 | $ 27,043 |
CAPITALIZATION - Narrative (Det
CAPITALIZATION - Narrative (Details) | 2 Months Ended | 3 Months Ended | 12 Months Ended | ||||||||||||||
Jan. 10, 2023 USD ($) | Dec. 13, 2022 USD ($) $ / shares | Nov. 06, 2021 USD ($) $ / shares shares | Dec. 31, 2021 USD ($) $ / shares shares | Dec. 31, 2022 USD ($) $ / shares shares | Sep. 30, 2022 $ / shares | Jun. 30, 2022 $ / shares | Mar. 31, 2022 $ / shares | Dec. 31, 2021 USD ($) $ / shares shares | Sep. 30, 2021 $ / shares | Jun. 30, 2021 $ / shares | Mar. 31, 2021 $ / shares | Dec. 31, 2022 USD ($) subsidiary $ / shares shares | Dec. 31, 2021 USD ($) $ / shares shares | Dec. 31, 2020 $ / shares shares | Nov. 29, 2022 USD ($) | Jun. 30, 2013 USD ($) | |
Debt Instrument [Line Items] | |||||||||||||||||
Retained earnings (accumulated deficit) | $ (1,605,000,000) | $ (1,199,000,000) | $ (1,605,000,000) | $ (1,199,000,000) | $ (1,605,000,000) | ||||||||||||
Dividends declared (in dollars per share) | $ / shares | $ 0.39 | $ 1.56 | $ 1.56 | $ 1.56 | |||||||||||||
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% | ||||||||||||||||
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 | ||||||||||||
Number of subsidiaries that issued environmental control bonds | subsidiary | 2 | ||||||||||||||||
Environmental control bonds outstanding | $ 274,000,000 | $ 247,000,000 | $ 274,000,000 | $ 247,000,000 | $ 274,000,000 | ||||||||||||
Principal default amount specified in debt covenants | 100,000,000 | ||||||||||||||||
Phase In Recovery Bonds | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Long-term debt and other long-term obligations | 222,000,000 | $ 206,000,000 | $ 222,000,000 | $ 206,000,000 | $ 222,000,000 | ||||||||||||
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 | 2,000,000 | 1,000,000 | 2,000,000 | ||||||||||||||
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% | ||||||||||||||||
WP | 5.29% First Mortgage Bond Due 2033 | First Mortgage Bond | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Face amount of loan | $ 300,000,000 | ||||||||||||||||
Proceeds from issuance of FMB's | $ 250,000,000 | ||||||||||||||||
Interest Rate | 5.29% | ||||||||||||||||
WP | 5.29% First Mortgage Bond Due 2033 | First Mortgage Bond | Subsequent Event | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Proceeds from issuance of FMB's | $ 50,000,000 |
CAPITALIZATION - Preferred and
CAPITALIZATION - Preferred and Preference Stock (Details) | Dec. 31, 2022 $ / shares shares |
Preferred stock and preference stock authorizations | |
Shares Authorized (in shares) | 5,000,000 |
Par Value (in dollars per share) | $ / shares | $ 100 |
Penn | |
Preferred stock and preference stock authorizations | |
Shares Authorized (in shares) | 1,200,000 |
Par Value (in dollars per share) | $ / shares | $ 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) | $ / shares | $ 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) | $ / shares | $ 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) | $ / shares | $ 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) | $ / shares | $ 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) | $ / shares | $ 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) | $ / shares | $ 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) | $ / shares | $ 25 |
CAPITALIZATION - Long-term Debt
CAPITALIZATION - Long-term Debt and Other Long-term Obligations (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Schedule of Capitalization [Line Items] | ||
Finance lease obligations | $ 23 | $ 36 |
Unamortized debt discounts | (5) | (8) |
Unamortized debt issuance costs | (110) | (126) |
Unamortized fair value adjustments | 5 | 6 |
Currently payable long-term debt | (351) | (1,606) |
Total long-term debt and other long-term obligations | 21,203 | 22,248 |
FMBs and secured notes - fixed rate | ||
Schedule of Capitalization [Line Items] | ||
FMBs and secured notes - fixed rate | $ 5,153 | 5,021 |
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 | $ 16,488 | $ 18,925 |
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) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
May 25, 2022 | Sep. 30, 2022 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Nov. 30, 2022 | Jun. 30, 2022 | Apr. 30, 2022 | Mar. 31, 2022 | Feb. 28, 2022 | Jan. 31, 2022 | |
Debt Instrument [Line Items] | |||||||||||
Losses on deferred cash flows | $ 7 | ||||||||||
Losses on deferred cash flows, net | 5 | ||||||||||
Debt issuance costs | 10 | $ 3 | |||||||||
Debt issuance costs, after tax | 8 | 2 | |||||||||
Repayments of debt | 3,005 | $ 532 | $ 1,114 | ||||||||
Senior Notes | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Prepayments of debt | 1,100 | ||||||||||
Debt premium | 101 | 38 | |||||||||
Make-whole premium, net | 80 | $ 30 | |||||||||
Open market discount | 11 | ||||||||||
Open market discount, net | $ 9 | ||||||||||
4.25% Notes Due 2023 | Promissory Notes | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Interest Rate | 4.25% | ||||||||||
Face amount of loan | $ 850 | ||||||||||
2.65%, Senior Secured Notes Maturing 2028 | Promissory Notes | TE | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Interest Rate | 2.65% | ||||||||||
Face amount of loan | $ 25 | ||||||||||
2.77% Series A Senior Notes Due 2034 | Promissory Notes | CEI | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Interest Rate | 2.77% | ||||||||||
Face amount of loan | $ 150 | ||||||||||
3.34% First Mortgage Bond Due April 2022 | Promissory Notes | WP | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Interest Rate | 3.34% | ||||||||||
Face amount of loan | $ 100 | ||||||||||
2.85%, 500 Million Notes | Promissory Notes | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Interest Rate | 2.85% | ||||||||||
Face amount of loan | $ 500 | ||||||||||
7.375% Notes Due 2031 | Promissory Notes | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Interest Rate | 7.375% | 7.375% | |||||||||
Face amount of loan | $ 128 | $ 715 | |||||||||
7.375% Notes Due 2031 | Senior Notes | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Long-term debt and other long-term obligations | 1,500 | ||||||||||
4.85% Notes Due 2047 | Promissory Notes | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Interest Rate | 4.85% | 4.85% | |||||||||
Face amount of loan | $ 110 | $ 284 | |||||||||
6.09% First Mortgage Bond Due June 2022 | Promissory Notes | Penn | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Interest Rate | 6.09% | ||||||||||
Face amount of loan | $ 100 | ||||||||||
3.79%, 150 Million Notes Maturing 2032 | First Mortgage Bond | Penn | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Interest Rate | 3.79% | ||||||||||
Face amount of loan | $ 150 | ||||||||||
5.50%, 300 Million Notes Maturing 2033 | Senior Notes | OE | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Interest Rate | 5.50% | ||||||||||
Face amount of loan | $ 300 | ||||||||||
Series C 4.85% Senior Notes Due 2047 | Senior Notes | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Long-term debt and other long-term obligations | $ 1,000 | ||||||||||
7.375% Notes Due 2031 and 5.35% Notes Due 2047 | Senior Notes | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Repayments of debt | $ 249 | ||||||||||
5.29% First Mortgage Bond Due 2033 | First Mortgage Bond | WP | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Interest Rate | 5.29% | ||||||||||
Face amount of loan | $ 250 |
CAPITALIZATION - Sinking Fund R
CAPITALIZATION - Sinking Fund Requirements (Details) $ in Millions | Dec. 31, 2022 USD ($) |
Capitalization, Long-Term Debt and Equity [Abstract] | |
2023 | $ 344 |
2024 | 1,246 |
2025 | 2,023 |
2026 | 1,076 |
2027 | $ 2,003 |
SHORT-TERM BORROWINGS AND BAN_2
SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT - Narrative (Details) | 12 Months Ended | ||
Oct. 18, 2021 USD ($) agreement | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | |||
Short-term borrowings | $ 100,000,000 | $ 0 | |
Average interest rate for borrowings | 3.93% | 2.42% | |
Revolving Credit Facility | Line of Credit | |||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | |||
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% | ||
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% | ||
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% | ||
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 | 2.27% | 1.01% | |
Money Pool | Unregulated Companies | |||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | |||
Average interest rate for borrowings | 2.14% | 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 | Line of Credit | Letter of Credit | |||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | |||
Outstanding borrowings | $ 4,000,000 |
REGULATORY MATTERS - Distributi
REGULATORY MATTERS - Distribution Rate Orders (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Jan. 01, 2021 | |
CEI | ||
Public Utilities, General Disclosures [Line Items] | ||
Allowed debt | 51% | |
Allowed Equity | 49% | |
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% | |
Allowed Equity | 46% | |
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% | |
Allowed Equity | 49% | |
Approved ROE | 10.50% | |
Penn | West Virginia | ||
Public Utilities, General Disclosures [Line Items] | ||
Allowed debt | 54% | |
Allowed Equity | 46% | |
Penn | Maryland | ||
Public Utilities, General Disclosures [Line Items] | ||
Allowed debt | 47% | |
Allowed Equity | 53% | |
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% | |
Allowed Equity | 49% | |
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 | 1 Months Ended | 12 Months Ended | 36 Months Ended | ||||||
Sep. 17, 2022 USD ($) | May 02, 2022 USD ($) | Sep. 14, 2021 USD ($) meter | Mar. 01, 2021 program | Oct. 28, 2020 USD ($) | Jul. 16, 2015 | Apr. 30, 2021 USD ($) | Dec. 31, 2022 | Dec. 31, 2020 USD ($) | |
PE | Maryland | |||||||||
Regulatory Matters [Line Items] | |||||||||
Incremental energy savings goal per year (percent) | 0.20% | ||||||||
Incremental energy savings goal thereafter (percent) | 2% | ||||||||
PE | Maryland | 2021-2023 EmPOWER Program Cycle | |||||||||
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 | ||||||||
JCP&L | New Jersey | |||||||||
Regulatory Matters [Line Items] | |||||||||
Requested ROE | 10.20% | ||||||||
Transmission infrastructure cost | $ 723 | ||||||||
Public utility, offshore development, percent | 20% | ||||||||
JCP&L | New Jersey | Regulated Distribution | Advanced Metering Infrastructure Supplemental Filing | |||||||||
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 | ||||||||
JCP&L | New Jersey | NJBPU | |||||||||
Regulatory Matters [Line Items] | |||||||||
Settled amount of increase in revenue | $ 94 | ||||||||
Requested ROE | 9.60% | ||||||||
JCP&L | New Jersey | NJBPU | Regulated Distribution | Energy Efficiency and Peak Demand Reduction Stipulation Settlement | |||||||||
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 | ||||||||
JCP&L | New Jersey | NJBPU | Regulated Distribution | Energy Efficiency and Peak Demand Reduction | |||||||||
Regulatory Matters [Line Items] | |||||||||
Amortization period for expenditures for cost recovery program | 10 years | ||||||||
JCP&L | New Jersey | NJBPU | Regulated Distribution | Electrical Vehicle Program | |||||||||
Regulatory Matters [Line Items] | |||||||||
Electric vehicle program period | 4 years | ||||||||
Number of programs | program | 6 | ||||||||
Public Utilities, Approved Budget, Amount | $ 40 | ||||||||
Public Utilities, Approved Return on Equity, Amount | 29 | ||||||||
Public Utilities, Approved Rate Increase (Decrease), Apportioned for Operations and Maintenance Expense, Amount | $ 11 | ||||||||
JCP&L | New Jersey | NJBPU | Regulated Distribution | Advanced metering infrastructure | |||||||||
Regulatory Matters [Line Items] | |||||||||
Number of meters to be deployed | meter | 1.2 | ||||||||
Deployment period | 3 years |
REGULATORY MATTERS - Ohio (Deta
REGULATORY MATTERS - Ohio (Details) - Ohio - PUCO meter in Thousands, $ in Thousands | 3 Months Ended | |||||
Jul. 15, 2022 USD ($) meter circuit | Nov. 01, 2021 USD ($) | Jun. 01, 2016 USD ($) | Dec. 31, 2021 USD ($) | Sep. 13, 2021 requirement | Aug. 06, 2021 USD ($) | |
Regulatory Matters [Line Items] | ||||||
Proposed reduction in power plants carbon pollution (percent) | 90% | |||||
DCR Rider | ||||||
Regulatory Matters [Line Items] | ||||||
Revenue cap for Rider for years 3-6 | $ 20,000 | |||||
Revenue cap for Rider for years 6-8 | 15,000 | |||||
Ohio Stipulation | ||||||
Regulatory Matters [Line Items] | ||||||
Rate refunds | $ 210,000 | |||||
Rate refund in 2022 | 80,000 | |||||
Rate refund in 2023 | 60,000 | |||||
Rate refund in 2024 | 45,000 | |||||
Rate refund in 2025 | 25,000 | |||||
Ohio Stipulation | Regulated Distribution | ||||||
Regulatory Matters [Line Items] | ||||||
Pre-tax charges | $ 96,000 | |||||
Energy Conservation, Economic Development and Job Retention | ||||||
Regulatory Matters [Line Items] | ||||||
Contribution amount | $ 51,000 | |||||
Ohio Companies | Rider Delivery Capital Recovery Audit Report | ||||||
Regulatory Matters [Line Items] | ||||||
Refund to customer of pole attachment rates | $ 15 | |||||
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 | $ 96,000 | |||||
Ohio Companies | Phase Two of Grid Modernization Plan | ||||||
Regulatory Matters [Line Items] | ||||||
Numbers of additional meters to be installed | meter | 700 | |||||
Number of circuits additional automation equipment to be installed on | circuit | 240 | |||||
Number of circuits additional voltage regulating equipment to be installed on | circuit | 220 | |||||
Period of grid modernization plan | 4 years | |||||
Requested amount of capital investments | $ 626,000 | |||||
Requested amount of operations and maintenance expenses | $ 144,000 |
REGULATORY MATTERS - Pennsylvan
REGULATORY MATTERS - Pennsylvania and West Virginia (Details) $ in Millions | 3 Months Ended | ||||||||||||
Jan. 13, 2023 USD ($) | Aug. 25, 2022 USD ($) | May 17, 2022 USD ($) | Dec. 29, 2021 USD ($) | Dec. 27, 2021 USD ($) | Dec. 17, 2021 USD ($) | Nov. 22, 2021 USD ($) plant MW | Nov. 18, 2021 USD ($) | Aug. 27, 2021 USD ($) | Aug. 30, 2019 USD ($) | Jun. 01, 2019 proposal | Dec. 31, 2021 USD ($) | Jun. 18, 2020 | |
Pennsylvania | PPUC | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Revised requested rate increase | $ 61 | ||||||||||||
Pennsylvania | PPUC | Utilities and Transmission Companies | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Pre-tax charges | $ 61 | ||||||||||||
Pennsylvania | PPUC | Penn | ENEC Phase IV | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Approved demand reduction targets | 2% | ||||||||||||
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 | ||||||||||||
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 | 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% | ||||||||||||
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 | ||||||||||||
Public utilities, interim rate increase (decrease), amount | $ 94 | ||||||||||||
West Virginia | WVPSC | MP and PE | Subsequent Event | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Requested amount of annual depreciation expense | $ 75.5 | ||||||||||||
West Virginia | WVPSC | MP and PE | Ft. Martin and Harrison Power Stations | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Requested annual rate increase | $ 3 | ||||||||||||
Requested rate increase (decrease) | $ 142 | ||||||||||||
West Virginia | WVPSC | MP and PE | Solar Generation Project | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Solar generation plant capacity (in MW's) | MW | 50,000,000 | ||||||||||||
Expected cost of the program | $ 110 | ||||||||||||
Percent of subscriptions required prior to commencement | 85% | ||||||||||||
West Virginia | WVPSC | MP and PE | ENEC | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Approved amount of rate increase (decrease) | $ 92 | ||||||||||||
Approved ROE | 4% | ||||||||||||
Public utilities, supplemental approved annual rate increase (decrease), amount | $ (7.7) | ||||||||||||
Requested rate increase (decrease) | $ 183.8 | ||||||||||||
Under recovered amount, percent | 12.20% | ||||||||||||
Supplemental requested decrease | $ 144.9 | ||||||||||||
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 | ||||||||||||
Surcharge period | 2 years |
REGULATORY MATTERS - Reliabilit
REGULATORY MATTERS - Reliability and FERC Matters (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Sep. 30, 2022 | Dec. 31, 2022 | Sep. 30, 2021 | |
FERC | FE | Transmission Related Vegetation Management Programs | |||
Regulatory Matters [Line Items] | |||
Refund payments | $ 45 | ||
Refund payments, net | 34 | ||
Capital assets reclassified into earnings | 195 | ||
Utilities operating expense | 90 | ||
Utilities operating expense, net | 67 | ||
Utilities reduction in operating expense | $ 160 | ||
FERC | FE | Other Nonoperating Income (Expense) | Transmission Related Vegetation Management Programs | |||
Regulatory Matters [Line Items] | |||
Pre-tax impairment of regulatory asset | $ 21 | ||
Regulated Transmission | |||
Regulatory Matters [Line Items] | |||
Approved ROE | 10.45% | ||
Approved capital structure | 56% | ||
Regulated Transmission | FERC | |||
Regulatory Matters [Line Items] | |||
Pre-tax impairment of regulatory asset | $ 25 | ||
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% | ||
Approved capital structure | 51.40% | ||
JCP&L | Regulated Transmission | |||
Regulatory Matters [Line Items] | |||
Approved ROE | 10.20% | ||
MAIT | Regulated Transmission | |||
Regulatory Matters [Line Items] | |||
Allowed debt | 60% | ||
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% | ||
Approved capital structure | 46% | ||
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% | ||
Approved capital structure | 50.30% | ||
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, 2022 USD ($) | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | $ 380 |
Percent of face amount of debt | 100% |
Curing period | 30 days |
Utilities and Transmission Companies | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | $ 131 |
FE | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 249 |
Upon Further Downgrade | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 70 |
Upon Further Downgrade | Utilities and Transmission Companies | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 70 |
Upon Further Downgrade | FE | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 0 |
Surety Bond | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | $ 310 |
Percent of face amount of debt | 60% |
Capped portion of surety bond obligations | $ 39 |
Surety Bond | Utilities and Transmission Companies | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 61 |
Surety Bond | FE | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | $ 249 |
COMMITMENTS, GUARANTEES AND C_4
COMMITMENTS, GUARANTEES AND CONTINGENCIES - Narrative (Details) $ in Thousands | 12 Months Ended | |||||
Feb. 09, 2022 USD ($) | Jul. 21, 2021 USD ($) | Oct. 29, 2020 USD ($) review | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Nov. 30, 2021 USD ($) | |
Loss Contingencies [Line Items] | ||||||
Outstanding guarantees and other assurances aggregated | $ 1,000,000 | |||||
Company posted collateral related to net liability positions | 50,000 | |||||
Collateral received | $ 206,000 | |||||
Civil penalty | $ 3,860 | |||||
Number of compliance reviews | review | 2 | |||||
EnvironmentalLossContingencyStatementOfFinancialPositionExtensibleEnumerationNotDisclosedFlag | The settlement also includes a payment to FE | |||||
Other Assurances | ||||||
Loss Contingencies [Line Items] | ||||||
Outstanding guarantees and other assurances aggregated | $ 449,000 | |||||
FE | ||||||
Loss Contingencies [Line Items] | ||||||
Outstanding guarantees and other assurances aggregated | $ 528,000 | |||||
Climate change | ||||||
Loss Contingencies [Line Items] | ||||||
Proposed reduction in power plants carbon pollution (percent) | 30% | |||||
Code of Conduct Violation, Recoupment Amount | Chief Executive Officer | ||||||
Loss Contingencies [Line Items] | ||||||
Proposed penalty | $ 56,000 | |||||
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 | ||||||
Loss Contingencies [Line Items] | ||||||
Proposed penalty | $ 36,000 | |||||
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 | |||||
Regulation of Waste Disposal | ||||||
Loss Contingencies [Line Items] | ||||||
Accrual for environmental loss contingencies | $ 97,000 | |||||
Environmental liabilities former gas facilities | $ 62,000 |
SEGMENT INFORMATION - Narrative
SEGMENT INFORMATION - Narrative (Details) mi² in Thousands, $ in Millions | 3 Months Ended | 12 Months Ended | ||||||
Feb. 02, 2023 USD ($) | May 31, 2022 USD ($) | Mar. 05, 2021 USD ($) | Apr. 06, 2020 | Dec. 31, 2020 USD ($) | Dec. 31, 2022 USD ($) mi² company customer MW | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | |
Segment Reporting Information [Line Items] | ||||||||
Gain on sale of property | $ 0 | $ 109 | $ 0 | |||||
DiscontinuedOperationGainLossOnDisposalStatementOfIncomeOrComprehensiveIncomeExtensibleEnumerationNotDisclosedFlag | TMI-2 to TMI-2 Solutions | |||||||
Brookfield II | FET | Subsequent Event | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Sale of ownership interest by parent | 30% | |||||||
Noncontrolling interest ownership percentage | 49.90% | |||||||
FET | Brookfield II | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Sale of ownership interest by parent | 19.90% | |||||||
Sale of ownership interest by parent | $ 2,375 | |||||||
FET | Brookfield II | Subsequent Event | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Consideration | $ 3,500 | |||||||
Liabilities incurred | $ 1,750 | |||||||
JCP&L | New Jersey | Yard's Creek Energy, LLC Hydro Generation Facility | NJBPU | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Disposal group, including discontinued operation, ownership interest sold | 50% | |||||||
Regulated Distribution | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Number of existing utility operating companies | company | 10 | |||||||
Number of customers served by utility operating companies | customer | 6,000,000 | |||||||
Number of square miles in service area | mi² | 65 | |||||||
Megawatts of net demonstrated capacity of competitive segment (in MW's) | MW | 3,580 | |||||||
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 | |||||||
Regulated Distribution | JCP&L | New Jersey | Yard's Creek Energy, LLC Hydro Generation Facility | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Gain on sale of property | $ 109 | |||||||
Other/Corporate | OVEC | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Megawatts of net demonstrated capacity of competitive segment (in MW's) | MW | 67 | |||||||
FE | Subsequent Event | FET | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Ownership interest | 50.10% | |||||||
FE | Other/Corporate | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Long-term debt and other long-term obligations | $ 5,400 |
SEGMENT INFORMATION (Details)
SEGMENT INFORMATION (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | ||
Segment Reporting Information [Line Items] | ||||
Total revenues | [1] | $ 12,459 | $ 11,132 | $ 10,790 |
Total depreciation | 1,375 | 1,302 | 1,274 | |
Total amortization (deferral) of regulatory assets, net | (365) | 269 | (53) | |
Total DPA penalty | 0 | 230 | 0 | |
Total miscellaneous income (expense), net | 415 | 486 | 430 | |
Total interest expense | 1,039 | 1,139 | 1,065 | |
Income taxes (benefits) | 1,000 | 320 | 126 | |
Total net income (loss) | 439 | 1,283 | 1,079 | |
Total income attributable to noncontrolling interest | 33 | 0 | 0 | |
Total earnings attributable to FE | 406 | 1,283 | 1,079 | |
Total property additions | 2,756 | 2,445 | 2,657 | |
Assets | 46,108 | 45,432 | ||
Goodwill | 5,618 | 5,618 | ||
Corporate, Non-Segment | ||||
Segment Reporting Information [Line Items] | ||||
Total revenues | (210) | (197) | (203) | |
Total amortization (deferral) of regulatory assets, net | 0 | 0 | 0 | |
Total DPA penalty | 0 | 230 | 0 | |
Total miscellaneous income (expense), net | 85 | 58 | 81 | |
Total net income (loss) | (912) | (413) | (344) | |
Total earnings attributable to FE | (912) | (413) | (344) | |
Segment Reconciling Items | ||||
Segment Reporting Information [Line Items] | ||||
Total amortization (deferral) of regulatory assets, net | 0 | 0 | 0 | |
Total miscellaneous income (expense), net | (67) | (12) | (13) | |
Total net income (loss) | 0 | 0 | 0 | |
Total earnings attributable to FE | 0 | 0 | 0 | |
Utilities and Transmission Companies | ||||
Segment Reporting Information [Line Items] | ||||
Goodwill | 5,004 | |||
Utilities and Transmission Companies | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total revenues | 10,801 | 9,711 | 9,363 | |
Total depreciation | 967 | 911 | 896 | |
Total amortization (deferral) of regulatory assets, net | (362) | 260 | (64) | |
Total miscellaneous income (expense), net | 361 | 399 | 332 | |
Income taxes (benefits) | 251 | 364 | 113 | |
Total net income (loss) | 957 | 1,288 | 959 | |
Total earnings attributable to FE | 957 | 1,288 | 959 | |
Regulated Transmission | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total revenues | 1,868 | 1,618 | 1,630 | |
Total depreciation | 335 | 325 | 313 | |
Total amortization (deferral) of regulatory assets, net | (3) | 9 | 11 | |
Total miscellaneous income (expense), net | 36 | 41 | 30 | |
Income taxes (benefits) | 110 | 127 | 138 | |
Total net income (loss) | 394 | 408 | 464 | |
Total income attributable to noncontrolling interest | 33 | 0 | 0 | |
Total earnings attributable to FE | 361 | 408 | 464 | |
Miscellaneous income (expense), net | ||||
Segment Reporting Information [Line Items] | ||||
Total revenues | 12,459 | 11,132 | 10,790 | |
Regulated Distribution | ||||
Segment Reporting Information [Line Items] | ||||
Total revenues | 0 | 0 | 0 | |
Regulated Distribution | Utilities and Transmission Companies | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total revenues | 232 | 201 | 195 | |
Regulated Distribution | Regulated Transmission | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total revenues | 5 | 10 | 17 | |
Operating Segments | Utilities and Transmission Companies | ||||
Segment Reporting Information [Line Items] | ||||
Total interest expense | 526 | 522 | 501 | |
Total property additions | 1,513 | 1,395 | 1,514 | |
Assets | 31,749 | 30,812 | ||
Goodwill | 5,004 | 5,004 | ||
Operating Segments | Regulated Transmission | ||||
Segment Reporting Information [Line Items] | ||||
Total interest expense | 230 | 247 | 219 | |
Total property additions | 1,192 | 958 | 1,067 | |
Assets | 13,835 | 13,237 | ||
Goodwill | 614 | 614 | ||
Operating Segments | Miscellaneous income (expense), net | Utilities and Transmission Companies | ||||
Segment Reporting Information [Line Items] | ||||
Total revenues | 10,569 | 9,510 | 9,168 | |
Operating Segments | Miscellaneous income (expense), net | Regulated Transmission | ||||
Segment Reporting Information [Line Items] | ||||
Total revenues | 1,863 | 1,608 | 1,613 | |
Corporate, Non-Segment | ||||
Segment Reporting Information [Line Items] | ||||
Total depreciation | 7 | 3 | 4 | |
Total interest expense | 350 | 382 | 358 | |
Income taxes (benefits) | 639 | (171) | (125) | |
Total property additions | 51 | 92 | 76 | |
Assets | 524 | 1,383 | ||
Goodwill | 0 | 0 | ||
Corporate, Non-Segment | Miscellaneous income (expense), net | ||||
Segment Reporting Information [Line Items] | ||||
Total revenues | 27 | 14 | 9 | |
Corporate, Non-Segment | Regulated Distribution | ||||
Segment Reporting Information [Line Items] | ||||
Total revenues | 0 | 0 | 0 | |
Segment Reconciling Items | ||||
Segment Reporting Information [Line Items] | ||||
Total depreciation | 66 | 63 | 61 | |
Total interest expense | (67) | (12) | (13) | |
Total property additions | 0 | 0 | 0 | |
Assets | 0 | 0 | ||
Goodwill | 0 | 0 | ||
Segment Reconciling Items | Miscellaneous income (expense), net | ||||
Segment Reporting Information [Line Items] | ||||
Total revenues | 0 | 0 | 0 | |
Segment Reconciling Items | Regulated Distribution | ||||
Segment Reporting Information [Line Items] | ||||
Total revenues | (237) | (211) | (212) | |
Intersegment Eliminations | ||||
Segment Reporting Information [Line Items] | ||||
Income taxes (benefits) | $ 0 | $ 0 | $ 0 | |
[1]Includes excise and gross receipts tax collections of $406 million, $374 million and $362 million in 2022, 2021 and 2020, respectively. |
DISCONTINUED OPERATIONS - Narra
DISCONTINUED OPERATIONS - Narrative (Details) $ in Millions | 1 Months Ended | 3 Months Ended | |||||
Feb. 27, 2020 USD ($) | Sep. 30, 2018 USD ($) | Dec. 31, 2022 USD ($) | Sep. 30, 2022 USD ($) | Dec. 31, 2021 USD ($) | Mar. 31, 2020 USD ($) | Dec. 31, 2018 MW | |
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 | ||||||
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, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Income tax expense (benefit) | $ (48) | $ (59) | ||
Income from discontinued operations | [1] | $ 0 | 44 | 76 |
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 | 0 | 7 | |
Fuel | 0 | 0 | (6) | |
Other operating expenses | 0 | 0 | (6) | |
Pleasants economic interest | 0 | 0 | 5 | |
Other expense, net | 0 | (4) | 0 | |
Loss from discontinued operations, before tax | 0 | (4) | 0 | |
Income tax expense (benefit) | 0 | (1) | 0 | |
Loss from discontinued operations, net of tax | 0 | (3) | 0 | |
Settlement consideration and services credit | 0 | 0 | (1) | |
Accelerated net pension and OPEB prior service credits | 0 | 0 | 18 | |
Gain on disposal of FES and FENOC, before tax | 0 | 0 | 17 | |
Income tax benefits, including worthless stock deduction | 0 | (47) | (59) | |
Gain on disposal of FES and FENOC, net of tax | 0 | 47 | 76 | |
Income from discontinued operations | $ 0 | $ 44 | $ 76 | |
[1]Net of income tax benefit of $48 million and $59 million in 2021 and 2020, respectively. |
DISCONTINUED OPERATIONS - Major
DISCONTINUED OPERATIONS - Major Classes of Cash Flow Items from Discontinued Operations (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | ||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||
Income from discontinued operations | [1] | $ 0 | $ 44 | $ 76 |
Gain on disposal, net of tax | $ 0 | $ (47) | $ (76) | |
DisposalGroupNotDiscontinuedOperationGainLossOnDisposalStatementOfIncomeExtensibleListNotDisclosedFlag | Gain on disposal, net of tax | Gain on disposal, net of tax | Gain on disposal, net of tax | |
FES and FENOC | Discontinued Operations, Disposed of by Means Other than Sale | ||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||
Income from discontinued operations | $ 0 | $ 44 | $ 76 | |
Gain on disposal, net of tax | $ 0 | $ (47) | $ (76) | |
[1]Net of income tax benefit of $48 million and $59 million in 2021 and 2020, respectively. |