Document and Entity Information
Document and Entity Information | 3 Months Ended |
Mar. 31, 2018shares | |
Document and Entity Information [Abstract] | |
Entity Registrant Name | FIRSTENERGY CORP |
Entity Central Index Key | 1,031,296 |
Document Type | 10-Q |
Document Period End Date | Mar. 31, 2018 |
Amendment Flag | false |
Document Fiscal Year Focus | 2,018 |
Document Fiscal Period Focus | Q1 |
Current Fiscal Year End Date | --12-31 |
Entity Filer Category | Large Accelerated Filer |
Entity Common Stock Shares Outstanding | 476,909,318 |
Consolidated Statements of Inco
Consolidated Statements of Income - USD ($) shares in Millions, $ in Millions | 3 Months Ended | ||
Mar. 31, 2018 | Mar. 31, 2017 | ||
REVENUES: | |||
Regulated Distribution | $ 2,576 | $ 2,500 | |
Regulated Transmission | 323 | 313 | |
Other | 77 | 42 | |
Total revenues | [1] | 2,976 | 2,855 |
OPERATING EXPENSES: | |||
Fuel | 187 | 204 | |
Purchased power | 825 | 791 | |
Other operating expenses | 962 | 657 | |
Provision for depreciation | 294 | 250 | |
Amortization (deferral) of regulatory assets, net | (148) | 83 | |
General taxes | 259 | 242 | |
Total operating expenses | 2,379 | 2,227 | |
OPERATING INCOME | 597 | 628 | |
OTHER INCOME (EXPENSE): | |||
Miscellaneous income | 67 | 14 | |
Interest expense | (250) | (245) | |
Capitalized financing costs | 15 | 12 | |
Total other expense | (168) | (219) | |
INCOME BEFORE INCOME TAXES | 429 | 409 | |
INCOME TAXES | 252 | 152 | |
INCOME FROM CONTINUING OPERATIONS | 177 | 257 | |
Discontinued operations (net of income tax benefits of $890 and $26) (Note 3) | 1,192 | (52) | |
NET INCOME | 1,369 | 205 | |
INCOME ALLOCATED TO PREFERRED STOCKHOLDERS (Note 4) | 156 | 0 | |
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS | $ 1,213 | $ 205 | |
EARNINGS PER SHARE OF COMMON STOCK (Note 4): | |||
Basic - Continuing Operations (in dollars per share) | $ 0.04 | $ 0.58 | |
Basic - Discontinued Operations (in dollars per share) | 2.51 | (0.12) | |
Basic - Net Income Attributable to Common Stockholders (in dollars per share) | 2.55 | 0.46 | |
Diluted - Continuing Operations (in dollars per share) | 0.04 | 0.58 | |
Diluted - Discontinued Operations (in dollars per share) | 2.50 | (0.12) | |
Diluted - Net Income Attributable to Common Stockholders (in dollars per share) | $ 2.54 | $ 0.46 | |
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING: | |||
Basic, in shares | 476 | 443 | |
Diluted, in shares | 478 | 444 | |
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK, in dollars per share | $ 0.72 | $ 0.72 | |
Excise taxes collected | $ 102 | $ 100 | |
[1] | Includes excise tax collections of $102 million and $100 million in the three months ended March 31, 2018 and 2017, respectively. |
Consolidated Statements of Inc3
Consolidated Statements of Income (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Income Statement [Abstract] | ||
Income tax expense (benefit) | $ (890) | $ (26) |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Statement of Comprehensive Income [Abstract] | ||
NET INCOME | $ 1,369 | $ 205 |
OTHER COMPREHENSIVE INCOME (LOSS): | ||
Pension and OPEB prior service costs | (18) | (18) |
Amortized losses on derivative hedges | 15 | 3 |
Change in unrealized gains on available-for-sale securities | (106) | 16 |
Other comprehensive income (loss) | (109) | 1 |
Income tax benefits on other comprehensive income (loss) | (53) | 0 |
Other comprehensive income (loss), net of tax | (56) | 1 |
COMPREHENSIVE INCOME | $ 1,313 | $ 206 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Mar. 31, 2018 | Dec. 31, 2017 |
CURRENT ASSETS: | ||
Cash and cash equivalents | $ 248 | $ 588 |
Restricted cash | 51 | 51 |
Receivables- | ||
Customers, net of allowance for uncollectible accounts of $50 in 2018 and $49 in 2017 | 1,279 | 1,282 |
Other, net of allowance for uncollectible accounts of $1 in 2018 and 2017 | 159 | 170 |
Materials and supplies, at average cost | 273 | 262 |
Prepaid taxes and other | 254 | 151 |
Current assets - discontinued operations | 2 | 606 |
Total current assets | 2,310 | 3,110 |
PROPERTY, PLANT AND EQUIPMENT: | ||
In service | 37,717 | 37,270 |
Less — Accumulated provision for depreciation | 10,267 | 10,098 |
Property, plant and equipment in service net of accumulated provision for depreciation | 27,450 | 27,172 |
Construction work in progress | 1,120 | 1,004 |
Total net property, plant and equipment | 28,570 | 28,176 |
PROPERTY, PLANT AND EQUIPMENT, NET - DISCONTINUED OPERATIONS | 353 | 1,057 |
INVESTMENTS: | ||
Nuclear plant decommissioning trusts | 800 | 822 |
Nuclear fuel disposal trust | 251 | 251 |
Other | 252 | 255 |
Investments - discontinued operations | 0 | 1,875 |
Total other property and investments | 1,303 | 3,203 |
DEFERRED CHARGES AND OTHER ASSETS: | ||
Goodwill | 5,618 | 5,618 |
Regulatory assets | 49 | 40 |
Other | 592 | 697 |
Deferred charges and other assets - discontinued operations | 0 | 356 |
Total deferred charges and other assets | 6,259 | 6,711 |
Total assets | 38,795 | 42,257 |
CURRENT LIABILITIES: | ||
Currently payable long-term debt | 1,157 | 558 |
Short-term borrowings | 1,200 | 300 |
Accounts payable | 1,005 | 827 |
Accrued taxes | 530 | 533 |
Accrued compensation and benefits | 254 | 257 |
Collateral | 37 | 39 |
Other | 882 | 626 |
Current liabilities - discontinued operations | 0 | 973 |
Total current liabilities | 5,065 | 4,113 |
Stockholders’ equity- | ||
Common stock, $0.10 par value, authorized 700,000,000 shares - 476,909,318 and 445,334,111 shares outstanding as of March 31, 2018 and December 31, 2017, respectively | 48 | 44 |
Mandatorily convertible preferred stock, $100 par value, authorized 5,000,000 shares - 1,616,000 shares issued and outstanding as of March 31, 2018 | 162 | 0 |
Other paid-in capital | 11,937 | 10,001 |
Accumulated other comprehensive income | 86 | 142 |
Accumulated deficit | (4,858) | (6,262) |
Total stockholders’ equity | 7,375 | 3,925 |
Long-term debt and other long-term obligations | 16,740 | 18,816 |
Total capitalization | 24,115 | 22,741 |
NONCURRENT LIABILITIES: | ||
Accumulated deferred income taxes | 2,505 | 3,171 |
Retirement benefits | 2,717 | 3,975 |
Regulatory liabilities | 2,632 | 2,720 |
Asset retirement obligations | 580 | 570 |
Adverse power contract liability | 124 | 130 |
Other | 1,057 | 1,438 |
Noncurrent liabilities - discontinued operations | 0 | 3,399 |
Total noncurrent liabilities | 9,615 | 15,403 |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 11) | ||
Total liabilities and capitalization | 38,795 | 42,257 |
Affiliated Companies | ||
Receivables- | ||
Customers, net of allowance for uncollectible accounts of $50 in 2018 and $49 in 2017 | $ 44 | $ 0 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions | Mar. 31, 2018 | Dec. 31, 2017 |
Stockholders’ equity- | ||
Common stock, par value (in dollars per share) | $ 0.1 | $ 0.1 |
Common stock, shares authorized | 700,000,000 | 700,000,000 |
Common stock, shares outstanding | 476,909,318 | 445,334,111 |
Customer | ||
Receivables- | ||
Allowance for uncollectible accounts | $ 50 | $ 49 |
Other | ||
Receivables- | ||
Allowance for uncollectible accounts | 1 | $ 1 |
Affiliated Companies | ||
Receivables- | ||
Allowance for uncollectible accounts | $ 624 | |
Series A Convertible Preferred Stock | ||
Stockholders’ equity- | ||
Par Value, in dollars per share | $ 100 | |
Preferred stock, shares authorized | 5,000,000 | |
Preferred stock shares issued | 1,616,000 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | ||
NET INCOME | $ 1,369 | $ 205 |
Adjustments to reconcile net income to net cash from operating activities- | ||
Gain on deconsolidation, net of tax (Note 3) | (1,239) | 0 |
Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs | 280 | 416 |
Deferred income taxes and investment tax credits, net | 278 | 114 |
Retirement benefits, net of payments | (46) | 10 |
Pension trust contributions | (1,250) | 0 |
Unrealized (gain) loss on derivative transactions | (10) | 47 |
Changes in current assets and liabilities- | ||
Receivables | 32 | 68 |
Materials and supplies | 36 | 11 |
Prepaid taxes and other | (144) | (111) |
Accounts payable | 96 | 45 |
Accrued taxes | (145) | (131) |
Accrued compensation and benefits | (108) | (137) |
Other current liabilities | (15) | 20 |
Collateral, net | (7) | 58 |
Other | (7) | 170 |
Net cash provided from (used for) operating activities | (880) | 785 |
New Financing- | ||
Long-term debt | 0 | 250 |
Short-term borrowings, net | 900 | 75 |
Preferred stock issuance | 1,616 | 0 |
Common stock issuance | 850 | 0 |
Redemptions and Repayments- | ||
Long-term debt | (1,476) | (211) |
Preferred stock dividend payments | (21) | 0 |
Common stock dividend payments | (171) | (159) |
Other | (19) | (13) |
Net cash provided from (used for) financing activities | 1,679 | (58) |
CASH FLOWS FROM INVESTING ACTIVITIES: | ||
Property additions | (583) | (588) |
Nuclear fuel | 0 | (132) |
Proceeds from asset sales | 20 | 0 |
Sales of investment securities held in trusts | 300 | 738 |
Purchases of investment securities held in trusts | (322) | (761) |
Notes receivable from affiliated companies | (500) | 0 |
Asset removal costs | (57) | (35) |
Other | (1) | (1) |
Net cash used for investing activites | (1,143) | (779) |
Net change in cash and cash equivalents and restricted cash | (344) | (52) |
Cash and cash equivalents and restricted cash at beginning of period | 643 | 260 |
Cash and cash equivalents and restricted cash at end of period | 299 | 208 |
SUPPLEMENTAL CASH FLOW INFORMATION: | ||
Non-cash transaction, beneficial conversion feature (Note 4) | 296 | 0 |
Non-cash transaction, deemed dividend preferred stock (Note 4) | $ (113) | $ 0 |
Organization and Basis of Prese
Organization and Basis of Presentation | 3 Months Ended |
Mar. 31, 2018 | |
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, AE Supply, MP, PE, WP, FET and its principal subsidiaries (ATSI, MAIT and TrAIL), and AESC. In addition, FE holds all of the outstanding equity of other direct subsidiaries including: FirstEnergy Properties, Inc., FEV, FELHC, Inc., GPU Nuclear, Inc., and Allegheny Ventures, Inc. 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 approximately 24,500 miles of lines and two regional transmission operation centers. Additionally, its regulated generation subsidiaries control 3,790 MWs of capacity. These interim financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and disclosures normally included in financial statements and notes prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. These interim financial statements should be read in conjunction with the financial statements and notes included in the Annual Report on Form 10-K for the year ended December 31, 2017 . 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 NRC, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU. The accompanying interim financial statements are unaudited, but reflect all adjustments, consisting of normal recurring adjustments, that, in the opinion of management, are necessary for a fair statement of the financial statements. 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. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see Note 8, "Variable Interest Entities"). 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, as discussed in "New Accounting Pronouncements" and Note 3, "Discontinued Operations." FES and FENOC Chapter 11 Filing On March 31, 2018, FES and FENOC 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 (which is referred to throughout as the FES Bankruptcy). As a result of the bankruptcy filings, FirstEnergy has concluded that it no longer has a controlling interest in FES or FENOC as the entities are subject to the control of the Bankruptcy Court and, accordingly, as of March 31, 2018, FES and FENOC were deconsolidated from FirstEnergy’s consolidated financial statements. FE will account for its investments in FES and FENOC with fair values of zero. FE concluded that in connection with the disposal, FES and FENOC became discontinued operations. In connection with the disposal, FE has recorded a gain on deconsolidation of approximately $1.2 billion for the three months ended March 31, 2018. See Note 3, "Discontinued Operations," for additional information. Capitalized Financing Costs For each of the three months ended March 31, 2018 and 2017 , capitalized financing costs on FirstEnergy's Consolidated Statements of Income include $11 million and $8 million , respectively, of allowance for equity funds used during construction and $4 million and $4 million , respectively, of capitalized interest. Restricted Cash Restricted cash primarily relates to the consolidated VIE's discussed in Note 8, "Variable Interest Entities." The cash collected from JCP&L, MP, PE and the Ohio Companies' customers is used to service debt of their respective funding companies. New Accounting Pronouncements Recently Adopted Pronouncements ASU 2014-09, "Revenue from Contracts with Customers" (Issued May 2014 and subsequently updated to address implementation questions): The new revenue recognition guidance establishes a new control-based revenue recognition model, changes the basis for deciding when revenue is recognized over time or at a point in time, provides new and more detailed guidance on specific topics and expands and improves disclosures about revenue. FirstEnergy evaluated its revenues and the new guidance had immaterial impacts to recognition practices upon adoption on January 1, 2018. As part of the adoption, FirstEnergy elected to apply the new guidance on a modified retrospective basis. FirstEnergy did not record a cumulative effect adjustment to retained earnings for initially applying the new guidance as no revenue recognition differences were identified in the timing or amount of revenue. In addition, upon adoption, certain immaterial financial statement presentation changes were implemented. See Note 2, " Revenue," for additional information on FirstEnergy revenues. ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities" (Issued January 2016 and subsequently updated in 2018): ASU 2016-01 primarily affects the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. FirstEnergy adopted this standard on January 1, 2018, and recognizes all gains and losses for equity securities in income with the exception of those that are accounted for under the equity method of accounting. The NDT equity portfolios of JCP&L, ME and PN will not be impacted as unrealized gains and losses will continue to be offset against regulatory assets or liabilities. As a result of adopting this standard, FirstEnergy recorded a cumulative effect adjustment to retained earnings of $115 million (pre-tax) on January 1, 2018, representing unrealized gains on equity securities with FES NDTs that were previously recorded to AOCI. Following deconsolidation of FES and FENOC, the adoption of this standard is not expected to have a material impact on FirstEnergy's financial statements as the majority of its equity securities are offset against a regulatory asset or liability. ASU 2016-18, " Restricted Cash" (Issued November 2016): ASU 2016-18 addresses the presentation of changes in restricted cash and restricted cash equivalents in the statement of cash flows. The guidance is required to be applied retrospectively. As a result of adopting this standard, FirstEnergy's statement of cash flows report changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents. Prior periods have been recasted to conform to the current year presentation. ASU 2017-01, "Business Combinations: Clarifying the Definition of a Business" (Issued January 2017) : ASU 2017-01 assists entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. FirstEnergy adopted ASU 2017-01 on January 1, 2018. The ASU will be applied prospectively to future transactions. ASU 2017-04, "Goodwill Impairment" (Issued January 2017): Simplifies the accounting for goodwill impairment by removing Step 2 of the current test, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two-step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. FirstEnergy has elected to early adopt ASU 2017-04 as of January 1, 2018, and will apply this standard on a prospective basis. ASU 2017-07, "Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost" (Issued March 2017) : ASU 2017-07 requires entities to retrospectively (1) disaggregate the current-service-cost component from the other components of net benefit cost (the “other components”) and present it with other current compensation costs for related employees in the income statement and (2) present the other components elsewhere in the income statement and outside of income from operations if such a subtotal is presented. In addition, only service costs are eligible for capitalization on a prospective basis. FirstEnergy adopted ASU 2017-07 on January 1, 2018. Because the non-service cost components of net benefit cost are no longer eligible for capitalization after December 31, 2017, FirstEnergy has recognized these components in income as a result of adopting this standard. FirstEnergy reclassified approximately $8 million of non-service costs from Other operating expense to Miscellaneous income for the three months ended March 31, 2017. ASU 2018-02, " Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income " (Issued February 2018): ASU 2018-02 allows entities to reclassify from AOCI to retained earnings stranded tax effects resulting from the Tax Act. FirstEnergy early adopted this standard during the first quarter of 2018 and has elected to present the change in the period of adoption. Upon adoption, FirstEnergy recorded a $22 million cumulative effect adjustment for stranded tax effects, such as pension and OPEB prior service costs and losses on derivative hedges, to retained earnings on January 1, 2018, of which $8 million was related to FES and FENOC. ASU 2018-05, " Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118 " (Issued March 2018): ASU 2018-05, effective 2018, expands income tax accounting and disclosure guidance to include SAB 118 issued by the SEC in December 2017. SAB 118 provides guidance on accounting for the income tax effects of the Tax Act and among other things allows for a measurement period not to exceed one year for companies to finalize the provisional amounts recorded as of December 31, 2017. See Note 7, "Income taxes," for additional information on FirstEnergy's accounting for the Tax Act. 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 or in the 2017 Annual Report on Form 10-K based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting. Below is an update to the discussion of pronouncements contained in the 2017 Annual Report on Form 10-K. ASU 2016-02, "Leases (Topic 842)" (Issued February 2016) and ASU 2018-01,"Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842" (Issued January 2018): ASU 2016-02 will require organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets. In addition, new qualitative and quantitative disclosures of the amounts, timing, and uncertainty of cash flows arising from leases will be required. The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. ASU 2018-01 (same effective date and transition requirements as ASU 2016-02) provides an optional transition practical expedient that, if elected, would not require an entity to reconsider its accounting for existing land easements that are not currently accounted for under the old leases standard. FirstEnergy does not plan to adopt these standards early. Lessors and lessees will be required to apply a modified retrospective transition approach, which requires adjusting the accounting for any leases existing at the beginning of the earliest comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date will not require any accounting adjustment. FirstEnergy expects an increase in assets and liabilities; however, it is currently assessing the impact on its Consolidated Financial Statements, including monitoring utility industry implementation guidance. FirstEnergy is in the process of developing a complete lease inventory, as well as identifying, assessing and documenting technical accounting issues, policy considerations and financial reporting implications. In addition, FirstEnergy is implementing a third-party software tool that will assist with the initial adoption and ongoing compliance. |
Revenue
Revenue | 3 Months Ended |
Mar. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Revenue | REVENUE FirstEnergy accounts for revenues from contracts with customers under ASC 606, Revenue from Contracts with Customers, which became effective January 1, 2018. As part of the adoption of ASC 606, FirstEnergy applied the new standard on a modified retrospective basis analyzing open contracts as of January 1, 2018. However, no cumulative effect adjustment to retained earnings was necessary as no revenue recognition differences were identified when comparing the revenue recognition criteria under ASC 606 to previous requirements. 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 new 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 new standard. As a result, tax collections and remittances within the scope of this election are excluded from recognition in the income statement and instead recorded through the balance sheet, consistent with FirstEnergy’s accounting process prior to the adoption of ASC 606. 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, with the exception of JCP&L transmission, 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. For a qualitative overview of FirstEnergy's performance obligations, see below. FirstEnergy’s revenues are primarily derived from electric service provided by its Utilities and transmission (ATSI, TrAIL and MAIT) subsidiaries. The following table represents a disaggregation of revenue from contracts with customers for the three months ended March 31, 2018, by type of service from each reportable segment: For the Three Months Ended March 31, 2018 Revenues by Type of Service Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments (1) Total (In millions) Distribution services (2) $ 1,281 $ — $ (12 ) $ 1,269 Retail generation 1,040 — (14 ) 1,026 Wholesale sales 123 — 120 243 Transmission (2) — 319 — 319 Other 35 — — 35 Total revenues from contracts with customers $ 2,479 $ 319 $ 94 $ 2,892 ARP 64 — — 64 Other non-customer revenue 33 4 (17 ) 20 Total revenues $ 2,576 $ 323 $ 77 $ 2,976 (1) Includes eliminations and reconciling adjustments of inter-segment revenues. (2) Includes $76 million in reductions to revenue related to amounts subject to refund resulting from the Tax Act ( $72 million at Regulated Distribution and $4 million at Regulated Transmission). Other non-customer revenue includes revenue from derivatives of $10 million for the three months ended March 31, 2018. Regulated Distribution The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies and also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. Each of the Utilities earn 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 13, "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. The following table represents a disaggregation of the Regulated Distribution segment revenue from contracts with distribution service and retail generation customers for the three months ended March 31, 2018, by class: For the Three Months Ended March 31, 2018 Revenues by Customer Class (In millions) Residential $ 1,463 Commercial 580 Industrial 254 Other 24 Total Revenues $ 2,321 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 from PJM to supply power to their customers. Generally, these power sales from generation and purchases to serve load are netted hourly and reported gross as either revenues or purchased power on the 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 BRA 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 reverses 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, revenue 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 currently has ARPs in Ohio, primarily under rider DMR, and in New Jersey. Regulated Transmission The Regulated Transmission segment provides transmission infrastructure owned and operated by ATSI, TrAIL, MAIT 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 at ATSI, TrAIL and MAIT, as well as stated transmission rates at certain of FirstEnergy’s utilities. As discussed in "Regulatory Matters - FERC Matters," below, MAIT filed a settlement with FERC on October 13, 2017, which settlement agreement is pending final order by FERC. Both the forward-looking formula and stated rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. Revenue requirements under stated rates are calculated annually by multiplying the highest one-hour peak load in each respective transmission zone by the approved, stated rate in that zone. Revenues and cash receipts for the stand-ready obligation of providing transmission service are recognized ratably over time. Effective January 1, 2018, JCP&L is subject to a FERC-approved settlement agreement that provides an annual revenue requirement of $155 million through December 31, 2019 which is recognized ratably as revenue over time. See Note 13 "Regulatory Matters - FERC Matters," for additional information. The following table represents a disaggregation of revenue from contracts with regulated transmission customers for the three months ended March 31, 2018, by transmission owner: For the Three Months Ended March 31, 2018 Revenues by Transmission Asset Owner (In millions) ATSI $ 159 TrAIL 62 MAIT 31 Other 71 Total Revenues $ 323 |
Discontinued Operations
Discontinued Operations | 3 Months Ended |
Mar. 31, 2018 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Discontinued Operations | DISCONTINUED OPERATIONS As of March 31, 2018, FES, FENOC, BSPC and a portion of AE Supply, representing substantially all of FirstEnergy’s operations that previously comprised the CES reportable operating segment, are presented as discontinued operations in FirstEnergy’s consolidated financial statements resulting from actions taken as part of the strategic review of exiting commodity-exposed generation, as discussed below. Prior period results have been reclassified to conform with such presentation as discontinued operations. FES and FENOC Chapter 11 Filing As discussed in Note 1, "Organization and Basis of Presentation," on March 31, 2018, FES and FENOC announced the FES Bankruptcy. FirstEnergy concluded that it no longer has a controlling interest in FES or FENOC, as the entities are subject to the control of the Bankruptcy Court and, accordingly, as of March 31, 2018, FES and FENOC were deconsolidated from FirstEnergy's consolidated financial statements, and will account for its investments in FES and FENOC with fair values of zero . By eliminating a significant portion of its competitive generation fleet with the deconsolidation of FES and FENOC, FirstEnergy has concluded FES and FENOC 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. FES Borrowings from FE On March 9, 2018, FES borrowed $500 million from FE under the secured credit facility, dated as of December 6, 2016, among FES, as Borrower, FG and NG as guarantors, and FE, as lender, which fully utilized the committed line of credit available under the secured credit facility. Following deconsolidation of FES, FE fully reserved for the $500 million associated with the borrowings under the secured credit facility. On March 16, 2018, FES and FENOC withdrew from the unregulated companies' money pool, which included FE, FES and FENOC. As of the date of the withdrawal, FES and FENOC owed FE approximately $4 million in unsecured borrowings in the aggregate under the money pool. In addition, as of March 31, 2018, AE Supply had a $102 million outstanding unsecured promissory note owed from FES. Following deconsolidation of FES and FENOC, FE fully reserved the $4 million associated with the outstanding unsecured borrowings under the unregulated companies' money pool and the $102 million associated with the AE Supply unsecured promissory note. Services Agreement FirstEnergy will continue to provide shared services support to FES and FENOC under existing shared services agreements (Services Agreements) through at least December 31, 2018. Under the Services Agreements, costs are directly billed or assigned at no more than cost. The remaining 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 provided for in the Services Agreements. Transactions under the Services Agreements are generally settled within 30 days. At this time, FirstEnergy expects to provide shared services support to FES and FENOC under the Services Agreements through at least 2018. In addition, on March 16, 2018, FES, FENOC and FESC, entered into the FirstEnergy Solutions Money Pool Agreement in order for FESC to assist FES and FENOC with certain treasury support services under the shared service agreement. FESC is a party to the FirstEnergy Solutions Money Pool Agreement solely in the role as administrator of the money pool arrangement thereunder. Benefit Obligations FirstEnergy will retain certain obligations for FES and FENOC employees for services provided prior to emergence from bankruptcy. The retention of this obligation at March 31, 2018, resulted in a liability of $820 million (including EDCP, pension and OPEB) with a corresponding loss from discontinued operations. Net pension and OPEB costs earned by FES and FENOC employees during bankruptcy are expected to be billed under the Services Agreements, and will be reassessed as the bankruptcy proceedings progress. Guarantees provided by FE As discussed in Note 14, "Commitments, Guarantees and Contingencies," FE is the guarantor of the remaining payments due to CSX and BNSF in connection with the definitive settlement of a dispute regarding a transportation agreement. As of March 31, 2018, FE recorded an obligation for this guarantee in other current liabilities with a corresponding loss from discontinued operations. On April 6, 2018, FE paid the remaining $72 million owed under the settlement agreement as a result of the FES Bankruptcy. In addition, as of March 31, 2018, FE recorded a $58 million obligation for a sale-leaseback indemnity in other current liabilities with a corresponding loss from discontinued operations. Purchase Power FES at times provides power through affiliated company power sales to meet a portion of the Utilities' POLR and default service requirements and provide power to certain affiliates' facilities. As of March 31, 2018, the Utilities owed FES approximately $46 million related to these purchases. The terms and conditions of the agreements are generally consistent with industry practices and other third-party arrangements. For current and pre-disposal periods, the Utilities' expense associated with these transactions are recorded in continuing operations. Tax Allocation Agreement Until FES and FENOC emerge from bankruptcy, it is expected that FES and FENOC will remain parties to the intercompany income tax allocation agreement with FE and its other subsidiaries, which provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FE are generally reallocated to the subsidiaries of FirstEnergy that have taxable income. As of March 31, 2018, FE has a $94 million receivable from FES and FENOC, in the aggregate, related to the federal tax obligation. For U.S. federal income taxes, FES and FENOC will continue to be consolidated in FirstEnergy’s tax return and taxable income will be determined based on the tax basis of underlying individual net assets. Deferred taxes previously recorded on the inside basis differences may not represent the actual tax consequence for the outside basis difference, causing a recharacterization of an existing consolidated-return net operating loss as a future worthless stock deduction (currently estimated at approximately $628 million ). The estimated worthless stock deduction is contingent upon emergence and such amounts may be impacted by future events. AE Supply and BSPC Asset Sales FirstEnergy announced in January 2017 that AE Supply and AGC had entered into an asset purchase agreement with a subsidiary of LS Power, as amended and restated in August 2017, to sell four natural gas generating plants, AE Supply's interest in the Buchanan Generating facility and approximately 59% of AGC's interest in Bath County ( 1,615 MWs of combined capacity). On December 13, 2017, AE Supply completed the sale of the natural gas generating plants, with net proceeds, subject to post-closing adjustments, of approximately $388 million . On December 28, 2017, FERC issued an order authorizing the sale of BU Energy’s Buchanan interests, and on March 1, 2018, AE Supply completed the sale of the Buchanan Generating Facility with net proceeds of approximately $20 million . With the sale of the gas plants completed, upon the consummation of the sale of AGC's interest in the Bath County hydroelectric power station or the sale or deactivation of the Pleasants Power Station, AE Supply is obligated under the amended and restated purchase agreement and AE Supply's applicable debt agreements to satisfy and discharge approximately $305 million of currently outstanding senior notes, as well as its $142 million of pollution control notes and AGC's $100 million senior notes, which are expected to require the payment of "make-whole" premiums currently estimated to be approximately $90 million based on current interest rates. On December 12, 2017, FERC issued an order authorizing the partial transfer of the related hydroelectric license for Bath County under Part I of the FPA. On February 16, 2018, FERC issued an order authorizing the redemption of AE Supply’s shares in AGC upon consummation of the Bath County transaction. On March 30, 2018, the VSCC issued an order approving, among other items, the sale of AGC's interests in the Bath County hydroelectric power station. The sale of AGC's interests in Bath County is expected to generate net proceeds of approximately $355 million and is anticipated to close in the second quarter of 2018, subject to various customary and other closing conditions. There can be no assurance that all closing conditions will be satisfied or that the remaining transaction will be consummated. Assets classified as discontinued operations as of March 31, 2018, representing AGC's interest in Bath County hydroelectric power station, include property, plant and equipment (net of accumulated provision for depreciation) of $353 million and materials and supplies inventory of $2 million . Additionally, on March 9, 2018, BSPC and FG entered into an asset purchase agreement with Walleye Energy, LLC, for the sale of the Bay Shore Generating Facility, including the 136 MW Bay Shore Unit 1 and other retired coal-fired generating equipment owned by FG. The sale is subject to customary and other closing conditions, including regulatory approvals, various third-party consents and approval by the Bankruptcy Court in connection with the FES Bankruptcy. There can be no assurance that all regulatory approvals will be obtained and/or all closing conditions will be satisfied or that the transaction will be consummated. As a result of the asset purchase agreement, FirstEnergy recorded non-cash, pre-tax impairment charges of $14 million for the three month period ended March 31, 2018, and is included in Discontinued operations on the Consolidated Statements of Income. Individually, the AE Supply and BSPC asset sales did not qualify for reporting as discontinued operations. However, the asset sales were part of management’s strategic review to exit commodity-exposed generation and, when considered with FES and FENOC’s bankruptcy filings on March 31, 2018, represent a collective elimination of substantially all of FirstEnergy’s competitive generation fleet and meet the criteria for discontinued operations. Summarized Results of Discontinued Operations Summarized results of discontinued operations for the three months ended March 31, 2018 and 2017, were as follows: For the Three Months Ended March 31, (In millions) 2018 2017 Revenues $ 622 $ 689 Fuel (116 ) (164 ) Purchased power (53 ) (49 ) Other operating expenses (347 ) (492 ) Provision for depreciation (46 ) (25 ) General taxes (18 ) (29 ) Other Income (Expense) (60 ) (8 ) Loss from discontinued operations, before tax (18 ) (78 ) Income tax expense (benefit) 29 (26 ) Loss from discontinued operations, net of tax (47 ) (52 ) Gain on deconsolidation, net of tax 1,239 — Income (loss) from discontinued operations $ 1,192 $ (52 ) The gain on deconsolidation that was recognized in the three months ended March 31, 2018, consisted of the following: (In millions) Removal of investment in FES and FENOC $ 2,193 Assumption of benefit obligations retained at FE (including Pension, OPEB and EDCP) (820 ) Guarantees and credit support provided by FE (139 ) Reserve on receivables and allocated Pension/OPEB mark-to-market (914 ) Gain on deconsolidation of FES and FENOC, before tax 320 Income tax benefit including estimated worthless stock deduction 919 Gain on deconsolidation of FES and FENOC $ 1,239 The following table summarizes the major classes of assets and liabilities as discontinued operations as of March 31, 2018 and December 31, 2017: (In millions) March 31, 2018 December 31, 2017 Carrying amount of the major classes of assets included in discontinued operations: Cash $ — $ 1 Restricted cash — 3 Receivables — 202 Materials and supplies 2 201 Collateral — 130 Other current assets — 69 Total current assets 2 606 Property, plant and equipment 353 1,057 Investments — 1,875 Other non-current assets — 356 Total non-current assets 353 3,288 Total assets included in discontinued operations $ 355 $ 3,894 Carrying amount of the major classes of liabilities included in discontinued operations: Currently payable long-term debt $ — $ 524 Accounts payable — 200 Accrued taxes — 38 Accrued compensation and benefits — 79 Other current liabilities — 132 Total current liabilities — 973 Long-term debt and other long-term obligations — 2,299 Accumulated deferred income taxes (1) — (1,812 ) Asset retirement obligations — 1,945 Deferred gain on sale and leaseback transaction — 723 Other non-current liabilities — 244 Total noncurrent liabilities — 3,399 Total liabilities included in discontinued operations $ — $ 4,372 (1) Represents an increase in FirstEnergy's ADIT liability as an ADIT asset was removed upon deconsolidation of FES and FENOC. FirstEnergy's Consolidated Statement of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow statement category. The following table summarizes the major classes of cash flow items as discontinued operations for the three months ended March 31, 2018 and 2017: For the Three Months Ended March 31, (In millions) 2018 2017 CASH FLOWS FROM OPERATING ACTIVITIES: Income (loss) from discontinued operations $ 1,192 $ (52 ) Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs 47 79 Unrealized (gain) loss on derivative transactions (10 ) 47 CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (15 ) (90 ) Nuclear fuel — (132 ) Sales of investment securities held in trusts 109 231 Purchases of investment securities held in trusts (122 ) (245 ) |
Earnings Per Share Of Common St
Earnings Per Share Of Common Stock | 3 Months Ended |
Mar. 31, 2018 | |
Earnings Per Share [Abstract] | |
EARNINGS PER SHARE OF COMMON STOCK | EARNINGS PER SHARE OF COMMON STOCK The convertible Preferred Stock issued in January 2018 (see Note 11, "Capitalization") is considered participating securities since these shares participate in dividends on Common Stock on an "as-converted" basis. As a result, Earnings per share on Common Stock is computed using the two-class method required for participating securities. The two-class method uses an earnings allocation formula that treats participating securities as having rights to earnings that otherwise would have been available only to common stockholders. Under the two-class method, net income attributable to common stockholders is derived by subtracting the following from income from continuing operations: • preferred share dividends, • deemed dividends for the amortization of the beneficial conversion feature recognized at issuance of the Preferred Stock (if any), and • an allocation of undistributed earnings between the common shares and the participating securities (convertible Preferred Stock) based on their respective rights to receive dividends. Net losses are not allocated to the convertible Preferred Stock as they do not have a contractual obligation to share in the losses of FirstEnergy. FirstEnergy allocates undistributed earnings based upon income from continuing operations. The Preferred Stock includes an embedded conversion option at a price that is below the fair value of the Common Stock on the commitment date. This beneficial conversion feature, which was approximately $296 million , represents the difference between the fair value per share of the Common Stock and the conversion price, multiplied by the number of common shares issuable upon conversion. The beneficial conversion feature will be amortized as a deemed dividend over the period from the issue date to the first allowable conversion date (July 22, 2018) as a charge to OPIC, since FE is in an accumulated deficit position with no retained earnings to declare a dividend. As noted above, for EPS reporting purposes, this beneficial conversion feature will be reflected in net income attributable to common stockholders as a deemed dividend. The amount amortized in the first quarter of 2018 was approximately $113 million . Basic EPS available to common stockholders is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding during the period. Participating securities are excluded from basic weighted average ordinary shares outstanding. Diluted EPS available to common stockholders is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding, including all potentially dilutive common shares, if the effect of such common shares is dilutive. Diluted EPS reflects the dilutive effect of potential common shares from share-based awards and convertible preferred shares. The dilutive effect of outstanding share based awards is computed using the treasury stock method, which assumes any proceeds that could be obtained upon the exercise of the award would be used to purchase Common Stock at the average market price for the period. The dilutive effect of the convertible Preferred Stock is computed using the if-converted method, which assumes conversion of the convertible Preferred Stock at the beginning of the period, giving income recognition for the add-back of the preferred share dividends, amortization of beneficial conversion feature, and undistributed earnings allocated to preferred stockholders. The following table reconciles basic and diluted EPS of common stock: (In millions, except per share amounts) For the Three Months Ended March 31, Reconciliation of Basic and Diluted Earnings per Share of Common Stock 2018 2017 Earnings Per Share of Common Stock Income from continuing operations $ 177 $ 257 Less: Preferred dividends (43 ) — Less: Amortization of beneficial conversion feature (113 ) — Less: Undistributed earnings allocated to preferred stockholders (1) — — Income from continuing operations available to common stockholders 21 257 Discontinued operations, net of tax 1,192 (52 ) Less: Undistributed earnings allocated to preferred stockholders (1) — — Income (loss) from discontinued operations available to common stockholders 1,192 (52 ) Income available to common stockholders, basic and diluted $ 1,213 $ 205 Share Count information: Weighted average number of basic shares outstanding 476 443 Assumed exercise of dilutive stock options and awards 2 1 Assumed conversion of preferred stock — — Weighted average number of diluted shares outstanding 478 444 Income available to common stockholders, per common share: Income from continuing operations, basic $ 0.04 $ 0.58 Discontinued operations, basic 2.51 (0.12 ) Income available to common stockholders, basic $ 2.55 $ 0.46 Income from continuing operations, diluted $ 0.04 $ 0.58 Discontinued operations, diluted 2.50 (0.12 ) Income available to common stockholders, diluted $ 2.54 $ 0.46 (1) Undistributed earnings were not allocated to participating securities as income from continuing operations less dividends declared (common and preferred) and deemed dividends was a net loss. For the thre e months ended March 31 , 2018 and 2017, one million stock option and award shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive to basic EPS from continuing operations. Also, for the thre e months ended March 31 , 2018 , 59 million shares associated with the assumed conversion of Preferred Stock were excluded, as their inclusion would be antidilutive to basic EPS from continuing operations. |
Pension and Other Postemploymen
Pension and Other Postemployment Benefits | 3 Months Ended |
Mar. 31, 2018 | |
Retirement Benefits [Abstract] | |
PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS | PENSION AND OTHER POSTEMPLOYMENT BENEFITS The components of the consolidated net periodic costs (credits) for pension and OPEB (including amounts capitalized) were as follows: Components of Net Periodic Benefit Costs (Credits) Pension OPEB For the Three Months Ended March 31, 2018 2017 2018 2017 (In millions) Service costs $ 56 $ 52 $ 1 $ 1 Interest costs 93 97 6 7 Expected return on plan assets (144 ) (112 ) (8 ) (8 ) Amortization of prior service costs (credits) 2 2 (20 ) (20 ) Net periodic costs (credits) $ 7 $ 39 $ (21 ) $ (20 ) Pension and OPEB obligations are allocated to FE's subsidiaries employing the plan participants. The net periodic pension and OPEB costs (credits), net of amounts capitalized, recognized in earnings by FirstEnergy were as follows: Net Periodic Benefit Expense (Credit) Pension OPEB For the Three Months Ended March 31, 2018 2017 2018 2017 (In millions) FirstEnergy $ (14 ) $ 32 $ (21 ) $ (15 ) Amounts in the tables above include FES' and FENOC's share of the net periodic pension and OPEB costs (credits) of $13 million and $(10) million , respectively, for the three months ended March 31, 2018, and FES' and FENOC's share of the net periodic pension and OPEB costs (credits) of $16 million and $ (8) million , respectively, for the three months ended March 31, 2017. Such amounts are a component of Discontinued Operations in FirstEnergy's Consolidated Statements of Income. Following adoption of ASU 2017-07, " Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost " in 2018, service costs, net of capitalization, continue to be reported within Other operating expenses on the FirstEnergy Consolidated Statements of Income. Non-service costs are reported within Miscellaneous income within Other income (expense). Prior period amounts have been reclassified to conform with current year presentation. See Note 1, "Organization and Basis of Presentation," for additional information. In January 2018, FirstEnergy satisfied its minimum required funding obligations of $500 million and addressed funding obligations for future years to its qualified pension plan with additional contributions of $750 million . |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income | 3 Months Ended |
Mar. 31, 2018 | |
Equity [Abstract] | |
ACCUMULATED OTHER COMPREHENSIVE INCOME | ACCUMULATED OTHER COMPREHENSIVE INCOME The changes in AOCI, net of tax, in the thre e months ended March 31, 2018 and 2017 , for FirstEnergy are included in the following tables: Gains & Losses on Cash Flow Hedges Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total (In millions) AOCI balance as of January 1, 2 018 $ (22 ) $ 67 $ 97 $ 142 Other comprehensive income before reclassifications — (97 ) — (97 ) Amounts reclassified from AOCI 2 (1 ) (18 ) (17 ) Deconsolidation of FES and FENOC 13 (8 ) — 5 Other comprehensive income (loss) 15 (106 ) (18 ) (109 ) Income taxes (benefits) on other comprehensive income (loss) 8 (39 ) (22 ) (53 ) Other comprehensive income (loss), net of tax 7 (67 ) 4 (56 ) AOCI Balance as of March 31, 2018 $ (15 ) $ — $ 101 $ 86 AOCI balance as of January 1, 2 017 $ (28 ) $ 52 $ 150 $ 174 Other comprehensive income before reclassifications — 32 — 32 Amounts reclassified from AOCI 3 (16 ) (18 ) (31 ) Other comprehensive income (loss) 3 16 (18 ) 1 Income taxes (benefits) on other comprehensive income (loss) 1 5 (6 ) — Other comprehensive income (loss), net of tax 2 11 (12 ) 1 AOCI Balance as of March 31, 2017 $ (26 ) $ 63 $ 138 $ 175 The following amounts were reclassified from AOCI for FirstEnergy in the thre e months ended March 31, 2018 and 2017 : For the Three Months Ended March 31, Affected Line Item in the Consolidated Statements of Income Reclassifications from AOCI (2) 2018 2017 (In millions) Gains & losses on cash flow hedges Long-term debt $ 2 $ 3 Interest expense (1 ) (1 ) Income taxes $ 1 $ 2 Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (1 ) $ (10 ) Discontinued Operations Defined benefit pension and OPEB plans Prior-service costs $ (18 ) $ (18 ) (1) 5 6 Income taxes $ (13 ) $ (12 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 5, "Pension and Other Postemployment Benefits," for additional details. (2) Amounts in parenthesis represent credits to the Consolidated Statements of Income from AOCI. |
Income Taxes
Income Taxes | 3 Months Ended |
Mar. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES FirstEnergy’s interim effective tax rates reflect the estimated annual effective tax rates for 2018 and 2017 . These tax rates are affected by estimated annual 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. FirstEnergy’s effective tax rate for the three months ended March 31, 2018 and 2017 , was 58.7% and 37.2% , respectively. The increase in effective tax rate is primarily due to the legal and financial separation of FES and FENOC from FirstEnergy. This separation officially eroded the ties between FES, FENOC and other FirstEnergy subsidiaries doing business in West Virginia. As such, FES and FENOC were removed from the West Virginia unitary group when calculating West Virginia state income taxes, resulting in a $126 million charge to income tax expense in continuing operations associated with the re-measurement in state deferred taxes. This increase was partially offset by the decrease in the corporate federal income tax rate from 35% to 21%, which became effective January 1, 2018. At December 31, 2017, FirstEnergy recorded provisional income tax amounts in its accounting for certain effects of the provisions of the Tax Act as allowed under SEC Staff Accounting Bulletin 118 (SAB 118). In addition, SAB 118 allowed for a measurement period for companies to finalize the provisional amounts recorded as of December 31, 2017, not to exceed one year. As of March 31, 2018, FirstEnergy has not yet finalized its assessment of the provisional amounts and there were no significant adjustments recorded in the first quarter of 2018. FirstEnergy expects to complete its assessment and record any final adjustments to the provisional amounts by the fourth quarter of 2018, which could result in a material impact to FirstEnergy’s income tax provision or financial position. FirstEnergy's assessment of accounting for the Tax Act are based upon management's current understanding of the Tax Act. However, it is expected that further guidance will be issued during 2018, which may result in adjustments that could have a material impact to FirstEnergy's future results of operations, cash flows, or financial position. In March 2018, FirstEnergy recorded unrecognized tax benefits of $49 million which relates primarily to the tax benefit recognized for the investment in FES and FENOC. The tax impact is reflected in discontinued operations. On October 18, 2017, the Supreme Court of Pennsylvania affirmed the Commonwealth Court’s holding that the state’s net loss carryover provision violated the Pennsylvania Uniformity Clause and was unconstitutional. However, the court also opined that the portion of the net loss carryover provision that created the violation may be severed from the statute, enabling the statute to operate as the legislature intended, and on October 30, 2017, the Pennsylvania Governor signed House Bill 542 into law, which, among other things, amended Pennsylvania’s limitation on net loss deductions to remove the flat-dollar limitation. On January 4, 2018, the court declined to further hear any arguments related to the matter and, as a result, FirstEnergy withdrew its protective refund claims from the Commonwealth of Pennsylvania on January 30, 2018. Upon doing so, FirstEnergy reversed a previously recorded unrecognized tax benefit of approximately $45 million in the first quarter of 2018, none of which impacted FirstEnergy’s effective tax rate. As of March 31, 2018 , it was reasonably possible that approximately $2 million of unrecognized tax benefits may be resolved within the next twelve months as a result of the statute of limitations expiring, none of which would affect FirstEnergy's effective tax rate. In January 2018, the IRS completed its examination of FirstEnergy’s 2016 federal income tax return and issued a Full Acceptance Letter with no changes or adjustments to FirstEnergy’s taxable income. |
Variable Interest Entities
Variable Interest Entities | 3 Months Ended |
Mar. 31, 2018 | |
Variable Interest Entities [Abstract] | |
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 September 2012, the Ohio Companies created separate, wholly owned limited liability company SPEs which issued phase-in recovery bonds to securitize the recovery of certain all-electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds are payable only from, and secured by, phase-in recovery property owned by the SPEs. The bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and administers the phase-in recovery property including the billing, collection and remittance of usage-based charges payable by retail electric customers. In the aggregate, the Ohio Companies are entitled to annual servicing fees of $445 thousand that are recoverable through the usage-based charges. The SPEs are considered VIEs and each one is consolidated into its applicable utility. As of March 31, 2018 and December 31, 2017 , $304 million and $315 million of the phase-in recovery bonds were outstanding, respectively. • JCP&L Securitization - In August 2006, JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy’s and JCP&L’s Consolidated Balance Sheets. The transition bonds are the sole obligations of JCP&L Transition Funding II and are collateralized by its equity and assets, which consist primarily of bondable transition property. As of March 31, 2018 and December 31, 2017 , $52 million and $56 million of the transition bonds were outstanding, respectively. • MP and PE Environmental Funding Companies - The entities issued bonds, the proceeds of which were used to construct environmental control facilities. The limited liability company SPEs own the irrevocable right to collect non-bypassable environmental control charges from all customers who receive electric delivery service in MP's and PE's West Virginia service territories. 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 March 31, 2018 and December 31, 2017 , $371 million and $383 million of the environmental control bonds were outstanding, respectively. Unconsolidated VIEs FirstEnergy is not the primary beneficiary of the following VIEs: • Global Holding - FEV holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales in U.S. and international markets. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint venture's economic performance. FEV's ownership interest is subject to the equity method of accounting. In 2015, FirstEnergy fully impaired the value of its investment in Global Holding. As discussed in Note 14, "Commitments, Guarantees and Contingencies," FE is the guarantor under Global Holding's term loan facility, which has an outstanding principal balance of $255 million . Failure by Global Holding to meet the terms and conditions under its term loan facility could require FE to be obligated under the provisions of its guarantee, resulting in consolidation of Global Holding by FE. • 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 March 31, 2018 , the carrying value of the equity method investment was $17 million . • Purchase Power Agreements - FirstEnergy evaluated its PPAs and determined that certain NUG entities at its Regulated Distribution segment may be VIEs to the extent that they own a plant that sells substantially all of its output to the applicable utilities and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy maintains 12 long-term PPAs with NUG entities that were entered into pursuant to PURPA. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, any of these entities. FirstEnergy has determined that for all but one of these NUG entities, it does not have a variable interest or the entities do not meet the criteria to be considered a VIE. FirstEnergy may hold a variable interest in the remaining one entity; however, it applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities. Because FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred at its Regulated Distribution segment to be recovered from customers. Purchased power costs related to the contract that may contain a variable interest during the three months ended March 31, 2018 and 2017 , were $32 million and $28 million , respectively. • FES and FENOC - As a result of the Chapter 11 bankruptcy filing discussed in Note 3, "Discontinued Operations," FE evaluated its investments in FES and FENOC and determined they are VIEs. FE is not the primary beneficiary because it lacks a controlling interest in FES and FENOC, which are subject to the control of the Bankruptcy Court as of March 31, 2018. The carrying values of the equity investments in FES and FENOC were zero at March 31, 2018 . |
Fair Value Measurements
Fair Value Measurements | 3 Months Ended |
Mar. 31, 2018 | |
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, which has been reviewed and approved by FirstEnergy's Risk Policy Committee, 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. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. See Note 10, "Derivative Instruments," for additional information regarding FirstEnergy's FTRs. NUG contracts represent PPAs with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. NUG contract carrying values are recorded at fair value and adjusted periodically using a mark-to-model methodology, which approximates market. The primary unobservable inputs into the model are regional power prices and generation MWH. Pricing for the NUG contracts is a combination of market prices for the current year and next two years based on observable data and internal models using historical trends and market data for the remaining years under contract. The internal models use forecasted energy purchase prices as an input when prices are not defined by the contract. Forecasted market prices are based on ICE quotes and management assumptions. Generation MWH reflects data provided by contractual arrangements and historical trends. The model calculates the fair value by multiplying the prices by the generation MWH. Generally, significant increases or decreases in inputs in isolation could result 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 March 31, 2018 , from those used as of December 31, 2017 . 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. Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the thre e months ended March 31, 2018 . The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy: FirstEnergy Recurring Fair Value Measurements March 31, 2018 December 31, 2017 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 468 $ — $ 468 $ — $ 476 $ — $ 476 Derivative assets - FTRs — — 1 1 — — 3 3 Equity securities (2) 288 — — 288 297 — — 297 Foreign government debt securities — 24 — 24 — 23 — 23 U.S. government debt securities — 28 — 28 — 21 — 21 U.S. state debt securities — 245 — 245 — 247 — 247 Other (3) 248 30 — 278 588 38 — 626 Total assets $ 536 $ 795 $ 1 $ 1,332 $ 885 $ 805 $ 3 $ 1,693 Liabilities Derivative liabilities - commodity contracts $ — $ — $ — $ — $ — $ (4 ) $ — $ (4 ) Derivative liabilities - NUG contracts (1) — — (74 ) (74 ) — — (79 ) (79 ) Total liabilities $ — $ — $ (74 ) $ (74 ) $ — $ (4 ) $ (79 ) $ (83 ) Net assets (liabilities) (4) $ 536 $ 795 $ (73 ) $ 1,258 $ 885 $ 801 $ (76 ) $ 1,610 (1) NUG contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. (2) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. (3) Primarily consists of short-term cash investments. (4) Excludes $(15) million and $(11) million as of March 31, 2018 and December 31, 2017 , respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. Rollforward of Level 3 Measurements The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended March 31, 2018 and December 31, 2017 : NUG Contracts (1) FTRs Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net (In millions) January 1, 2017 Balance $ 1 $ (108 ) $ (107 ) $ 3 $ (1 ) $ 2 Unrealized gain (loss) — (10 ) (10 ) 1 (1 ) — Purchases — — — 3 — 3 Settlements (1 ) 39 38 (4 ) 2 (2 ) December 31, 2017 Balance $ — $ (79 ) $ (79 ) $ 3 $ — $ 3 Unrealized gain (loss) — (2 ) (2 ) 1 — 1 Settlements — 7 7 (3 ) — (3 ) March 31, 2018 Balance $ — $ (74 ) $ (74 ) $ 1 $ — $ 1 (1) NUG contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. Level 3 Quantitative Information The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2018 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ 1 Model RTO auction clearing prices $0.50 to $5.10 $1.20 Dollars/MWH NUG Contracts $ (74 ) Model Generation 400 to 1,881,000 382,000 MWH Regional electricity prices $29.10 to $30.90 $30.00 Dollars/MWH INVESTMENTS All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include equity securities, 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 NDTs of JCP&L, ME and PN are subject to regulatory accounting with all gains and losses on equity and AFS debt securities offset against regulatory assets. The investment policy for the NDT funds restricts or limits the trusts' ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, securities convertible into common stock and securities of the trust funds' custodian or managers and their parents or subsidiaries. Nuclear Decommissioning and Nuclear Fuel Disposal Trusts JCP&L, ME and PN hold debt and equity securities within their NDT and nuclear fuel disposal trusts. The debt securities are classified as AFS securities, recognized at fair market value. The following table summarizes the amortized cost basis, unrealized gains, unrealized losses and fair values of investments held in NDT and nuclear fuel disposal trusts as of March 31, 2018 and December 31, 2017 : March 31, 2018 December 31, 2017 (1) Cost Basis Unrealized Gains Unrealized Losses Fair Value Cost Basis Unrealized Gains Unrealized Losses Fair Value (In millions) Debt securities $ 783 $ 5 $ (22 ) $ 766 $ 774 $ 11 $ (17 ) $ 768 Equity securities $ 263 $ 24 $ (2 ) $ 285 $ 254 $ 40 $ — $ 294 (1) Excludes short-term cash investments of $11 million . Proceeds from the sale of investments in equity and AFS debt securities, realized gains and losses on those sales and interest and dividend income for the thre e months ended March 31, 2018 and 2017 were as follows: For the Three Months Ended March 31, 2018 2017 (In millions) Sale Proceeds $ 191 $ 507 Realized Gains 19 21 Realized Losses (16 ) (15 ) Interest and Dividend Income 10 9 Other Investments Other investments include employee benefit trusts, which are primarily invested in corporate-owned life insurance policies, and equity method investments. Other investments were $252 million and $255 million as of March 31, 2018 and December 31, 2017 , respectively, and are excluded from the amounts reported above. LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported as Short-term borrowings on the Consolidated Balance Sheets at cost. Since these borrowings are short-term in nature, FirstEnergy believes that their costs approximate their fair market value. The following table provides the approximate fair value and related carrying amounts of FirstEnergy's long-term debt, which excludes capital lease obligations and net unamortized debt issuance costs, premiums and discounts as of March 31, 2018 and December 31, 2017: March 31, 2018 December 31, 2017 (In millions) Carrying Value $ 17,949 $ 19,425 Fair Value $ 19,487 $ 21,551 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 March 31, 2018 and December 31, 2017 . |
Derivative Instruments
Derivative Instruments | 3 Months Ended |
Mar. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVE INSTRUMENTS | DERIVATIVE INSTRUMENTS FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, coal and energy transmission. To manage the volatility related to these exposures, FirstEnergy’s Risk Policy Committee, comprised of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Risk Policy Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. FirstEnergy also uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value (unless they meet the normal purchases and normal sales criteria) as follows: • Changes in the fair value of derivative instruments that are designated and qualify as cash flow hedges are recorded to AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings. • Changes in the fair value of derivative instruments that are designated and qualify as fair value hedges are recorded as an adjustment to the item being hedged. When fair value hedges are discontinued, the adjustment recorded to the item being hedged is amortized into earnings. • Changes in the fair value of derivative instruments that are not designated in a hedging relationship are recorded in earnings on a mark-to-market basis, unless otherwise noted. Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of accounting with their effects included in earnings at the time of contract performance. FirstEnergy has contractual derivative agreements through 2020 . Cash Flow Hedges FirstEnergy has used forward starting interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were designated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. Total pre-tax unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $20 million and $22 million as of March 31, 2018 and December 31, 2017 , respectively. Based on current estimates, approximately $6 million of these unamortized losses are expected to be amortized to interest expense during the next twelve months. Refer to Note 6, "Accumulated Other Comprehensive Income," for reclassifications from AOCI during the three months ended March 31, 2018 and 2017 . As of March 31, 2018 and December 31, 2017 , no commodity or interest rate derivatives were designated as cash flow hedges. Fair Value Hedges FirstEnergy has used fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. As of March 31, 2018 and December 31, 2017 , no fixed-for-floating interest rate swap agreements were outstanding. Unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $3 million as of March 31, 2018 and December 31, 2017 . NUGs As of March 31, 2018 and December 31, 2017 , FirstEnergy's net liability position under NUG contracts was $74 million and $79 million , respectively, representing contracts held at JCP&L and PN. NUG contracts are classified as an Adverse power contract liability on the Consolidated Balance Sheets. During the first quarter of 2018, there were settlements of $7 million and unrealized losses of $2 million . Changes in the fair value of NUG contracts are subject to regulatory accounting treatment and do not impact earnings. FTRs As of March 31, 2018 , and December 31, 2017 , FirstEnergy's net asset position associated with FTRs was not material. FirstEnergy holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with FirstEnergy’s load obligations. FirstEnergy acquires the majority of its FTRs in an annual auction through a self-scheduling process involving the use of ARRs allocated to members of PJM that have load serving obligations. |
Capitalization
Capitalization | 3 Months Ended |
Mar. 31, 2018 | |
Regulated Operations [Abstract] | |
CAPITALIZATION | CAPITALIZATION Stock Issuance On January 22, 2018, FirstEnergy entered into agreements for the private placement of its equity securities representing an approximately $2.5 billion investment in the Company. The Company entered into a Preferred Stock Purchase Agreement (the Preferred SPA) for the private placement of 1,616,000 shares of mandatorily convertible preferred stock, designated as the Series A Convertible Preferred Stock, par value $100 per share, representing an investment of nearly $1.62 billion ( $162 million of mandatorily convertible preferred stock and $1.46 billion of OPIC). The Company also entered into a Common Stock Purchase Agreement for the private placement of 30,120,482 shares of the Company’s common stock, par value $0.10 per share, representing an investment of $850 million ( $3 million of Common Stock and $847 million of OPIC). The Preferred Stock participates in dividends on the Common Stock on an as-converted basis based on the number of shares of Common Stock a holder of Preferred Stock would receive if its shares of Preferred Stock were converted on the dividend record date at the conversion price in effect at that time. Such dividends are paid at the same time that the dividends on Common Stock are paid. Each share of Preferred Stock will be convertible into a number of shares of Common Stock equal to the $1,000 liquidation preference, divided by the Conversion Price then in effect. As of January 22, 2018, the Conversion Price in effect was $27.42 per share. The Conversion Price is subject to anti-dilution adjustments and adjustments for subdivisions and combinations of the Common Stock, as well as dividends on the Common Stock paid in Common Stock and for certain equity issuances below the Conversion Price then in effect. The Preferred Stock will generally be convertible at the option of holders beginning on July 22, 2018. The holders of Preferred Stock may also elect to convert their shares if the Company undergoes a fundamental change. Furthermore, the Preferred Stock will automatically convert to Common Stock upon certain events of bankruptcy or liquidation of the Company. The Company may elect to convert the Preferred Stock if, at any time, fewer than 323,200 shares of Preferred Stock are outstanding. In general, any shares of Preferred Stock outstanding on July 22, 2019, will be automatically converted. However, no shares of Preferred Stock will be converted prior to January 22, 2020, if such conversion will cause a converting holder to be deemed to beneficially own, together with its affiliates whose holdings would be aggregated with such holder for purposes of Section 13(d) under the Exchange Act, more than 4.9% of the then-outstanding Common Stock. Furthermore, in no event shall the Company issue more than 58,964,222 shares of Common Stock (the Share Cap) in the aggregate upon conversion of the convertible Preferred Stock. From and after the time at which the aggregate number of shares of Common Stock issued upon conversion of the Preferred Stock equals the Share Cap, each holder electing to convert convertible Preferred Stock will be entitled to receive a cash payment equal to the market value of the Common Stock such holder does not receive upon conversion. The holders of Preferred Stock have limited class voting rights related to the creation of additional securities that are senior or equal with the Preferred Stock, as well as certain reclassifications and amendments that would affect the rights of the holders of Preferred Stock. The holders of Preferred Stock also have the right to approve issuances of securities convertible or exchangeable for Common Stock, subject to certain exceptions for compensation arrangements and bona fide dividend reinvestment or share purchase plans. Pursuant to the Preferred SPA, FirstEnergy formed a RWG composed of three employees of FirstEnergy and two outside members identified in the Preferred SPA to advise FirstEnergy management regarding FES' restructuring. The outside RWG members are industry professionals C. John Wilder, Executive Chairman of Bluescape Energy Partners, LLC, and Anthony (Tony) Horton, Chief Financial Officer and Executive Vice President of Energy Future Holdings Corp. |
Asset Retirement Obligations
Asset Retirement Obligations | 3 Months Ended |
Mar. 31, 2018 | |
Asset Retirement Obligation [Abstract] | |
Asset Retirement Obligations | ASSET RETIREMENT OBLIGATIONS FirstEnergy has recognized applicable legal obligations for AROs and their associated cost, primarily for the decommissioning of the TMI-2 nuclear generating facility and environmental remediation, 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. FirstEnergy uses an expected cash flow approach to measure the fair value of the nuclear decommissioning and environmental remediation AROs, considering the expected timing of settlement of the ARO based on the expected economic useful life of the plants. 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. The aggregate ARO liabilities for FirstEnergy are approximately $580 million and $570 million as of March 31, 2018 and December 31, 2017, respectively. 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. Based on an assessment of the finalized regulations, the future cost of compliance and expected timing had no significant impact on FirstEnergy's existing AROs associated with CCRs. Although not currently expected, changes in timing and closure plan requirements in the future could materially and adversely impact FirstEnergy's AROs . |
Regulatory Matters
Regulatory Matters | 3 Months Ended |
Mar. 31, 2018 | |
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 Ohio by the PUCO, in New Jersey by the NJBPU, 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 are subject to certain regulations of the VSCC. 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. In addition, 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. Following the adoption of the Tax Act, various state regulatory proceedings have been initiated to investigate the impact of the Tax Act on the Utilities’ rates and charges. State proceedings that have arisen are discussed below. The Utilities continue to monitor and investigate the impact of state regulatory proceedings resulting from the Tax Act. MARYLAND PE 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 Maryland legislature adopted a statute in 2008 codifying the EmPOWER Maryland goals to reduce electric consumption and demand and requiring each electric utility to file a plan every three years. On July 16, 2015, the MDPSC issued an order setting new incremental energy savings goals for 2017 and beyond, beginning with the goal of 0.97% savings achieved under PE's plan for 2016, and increasing 0.2% per year thereafter to reach 2%. The Maryland legislature in April 2017 adopted a statute requiring the same 0.2% per year increase, up to the ultimate goal of 2% annual savings, for the duration of the 2018-2020 and 2021-2023 EmPOWER Maryland program cycles, to the extent the MDPSC determines that cost-effective programs and services are available. The costs of PE's 2015-2017 plan approved by the MDPSC in December 2014 were approximately $60 million. PE's approved 2018-2020 EmPOWER Maryland plan continues and expands upon prior years' programs, and adds new programs, for a projected total cost of $116 million over the three-year period. On December 22, 2017, the MDPSC issued an order approving the 2018-2020 plan with various modifications. PE recovers program costs subject to a five-year amortization. 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. On February 27, 2013, the MDPSC issued an order requiring the Maryland electric utilities to submit analyses relating to the costs and benefits of making further system and staffing enhancements in order to attempt to reduce storm outage durations. PE's responsive filings discussed the steps needed to harden the utility's system in order to attempt to achieve various levels of storm response speed described in the February 2013 Order, and projected that it would require approximately $2.7 billion in infrastructure investments over 15 years to attempt to achieve the quickest level of response for the largest storm projected in the February 2013 Order. On July 1, 2014, the Staff of the MDPSC issued a set of reports that recommended the imposition of extensive additional requirements in the areas of storm response, feeder performance, estimates of restoration times, and regulatory reporting, as well as the imposition of penalties, including customer rebates, for a utility's failure or inability to comply with the escalating standards of storm restoration speed proposed by the Staff of the MDPSC. In addition, the Staff of the MDPSC proposed that the Maryland utilities be required to develop and implement system hardening plans, up to a rate impact cap on cost. The MDPSC conducted a hearing September 15-18, 2014, to consider certain of these matters, and has not issued a ruling on any of those matters. On September 26, 2016, the MDPSC initiated a new proceeding to consider an array of issues relating to electric distribution system design, including matters relating to electric vehicles, distributed energy resources, advanced metering infrastructure, energy storage, system planning, rate design, and impacts on low-income customers. Comments were filed and a hearing was held in late 2016. On January 31, 2017, the MDPSC issued a notice establishing five working groups to address these issues over the following eighteen months, and also directed the retention of an outside consultant to prepare a report on costs and benefits of distributed solar generation in Maryland. On January 19, 2018, PE filed a joint petition, along with other utility companies, work group stakeholders, and the MDPSC electric vehicle work group leader, to implement a statewide electric vehicle portfolio. If approved, PE will launch an electric vehicle charging infrastructure program on January 1, 2019, offering up to 2,000 rebates for electric vehicle charging equipment to residential customers, and deploying up to 259 chargers at non-residential customer service locations at a projected total cost of $12 million. PE is proposing to recover program costs subject to a five-year amortization. On February 6, 2018, the MDPSC opened a new proceeding to consider the petition and numerous parties filed comments on the petition on March 27, 2018. On January 12, 2018, the MDPSC instituted a proceeding to examine the impacts of the Tax Act on the rates and charges of Maryland utilities. PE was required to track and apply regulatory accounting treatment for the impacts beginning January 1, 2018, and submitted a report to the MDPSC on February 15, 2018, estimating that the Tax Act impacts would be approximately $7 million to $8 million annually for PE’s customers. PE proposed to file a base rate case in the third quarter of 2018 where the benefits from the effects of the Tax Act will be realized by customers through a lower rate increase than would otherwise be necessary . NEW JERSEY JCP&L currently 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. The supply for BGS is comprised of two components, procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU. One BGS component reflects hourly real time energy prices and is available for larger commercial and industrial customers. The second BGS component provides a fixed price service and is intended for smaller commercial and residential customers. 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 currently operates under rates that were approved by the NJBPU on December 12, 2016, effective as of January 1, 2017. These rates provide an annual increase in operating revenues of approximately $80 million from those previously in place and are intended to improve service and benefit customers by supporting equipment maintenance, tree trimming, and inspections of lines, poles and substations, while also compensating for other business and operating expenses. In addition, on January 25, 2017, the NJBPU approved the acceleration of the amortization of JCP&L’s 2012 major storm expenses that are recovered through the SRC in order for JCP&L to achieve full recovery by December 31, 2019. Pursuant to the NJBPU's March 26, 2015 final order in JCP&L's 2012 rate case proceeding directing that certain studies be completed, on July 22, 2015, the NJBPU approved the NJBPU staff's recommendation to implement such studies, which included operational and financial components. The independent consultant conducting the review issued a final report on July 27, 2016, recognizing that JCP&L is meeting the NJBPU requirements and making various operational and financial recommendations. The NJBPU issued an Order on August 24, 2016, that accepted the independent consultant’s final report and directed JCP&L, the Division of Rate Counsel and other interested parties to address the recommendations. In an Order issued October 22, 2014, in a generic proceeding to review its policies with respect to the use of a CTA in base rate cases, the NJBPU stated that it would continue to apply its current CTA policy in base rate cases, subject to incorporating the following modifications: (i) calculating savings using a five-year look back from the beginning of the test year; (ii) allocating savings with 75% retained by the company and 25% allocated to rate payers; and (iii) excluding transmission assets of electric distribution companies in the savings calculation. On November 5, 2014, the Division of Rate Counsel appealed the NJBPU Order regarding the generic CTA proceeding to the Superior Court of New Jersey Appellate Division and JCP&L filed to participate as a respondent in that proceeding supporting the order. On September 18, 2017, the Superior Court of New Jersey Appellate Division reversed the NJBPU's Order on the basis that the NJBPU's modification of its CTA methodology did not comply with the procedures of the NJAPA. JCP&L's existing rates are not expected to be impacted by this order. On December 19, 2017, the NJBPU approved the issuance of proposed rules to modify the CTA methodology consistent with its October 22, 2014 Generic Order, which were published in the NJ Register on January 16, 2018, and republished on February 6, 2018, to correct an error. JCP&L filed comments supporting the proposed rulemaking on April 6, 2018. At the December 19, 2017 NJBPU public meeting, the NJBPU approved its IIP rulemaking. The IIP creates a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing components that enhance reliability, resiliency, and/or safety. JCP&L expects to make a filing in 2018. On January 31, 2018, the NJBPU instituted a proceeding to examine the impacts of the Tax Act on the rates and charges of New Jersey utilities. The NJBPU ordered New Jersey utilities to: (1) defer on their books the impacts of the Tax Act effective January 1, 2018; (2) to file tariffs effective April 1, 2018, reflecting the rate impacts of changes in current taxes; and (3) to file tariffs effective July 1, 2018, reflecting the rate impacts of changes in deferred taxes. On March 2, 2018, JCP&L filed a petition with the NJBPU, which included proposed tariffs for a base rate reduction of $28.6 million effective April 1, 2018, and a rider to reflect $1.3 million in rate impacts of changes in deferred taxes. On March 26, 2018, the NJBPU approved JCP&L’s rate reduction effective April 1, 2018, on an interim basis subject to refund, pending the outcome of this proceeding. The NJBPU, however, did not address refunds and other proposed rider tariffs at such time, but may be addressed at a later date. OHIO The Ohio Companies currently operate under ESP IV which commenced June 1, 2016 and expires May 31, 2024. The material terms of ESP IV, as approved in the PUCO’s Opinion and Order issued on March 31, 2016 and Fifth Entry on Rehearing on October 12, 2016, include Rider DMR, which provides for the Ohio Companies to collect $132.5 million annually for three years, with the possibility of a two-year extension. Rider DMR will be grossed up for federal income taxes, resulting in an approved amount of approximately $168 million annually in 2018 and 2019. Revenues from Rider DMR will be excluded from the significantly excessive earnings test for the initial three-year term but the exclusion will be reconsidered upon application for a potential two-year extension. The PUCO set three conditions for continued recovery under Rider DMR: (1) retention of the corporate headquarters and nexus of operations in Akron, Ohio; (2) no change in control of the Ohio Companies; and (3) a demonstration of sufficient progress in the implementation of grid modernization programs approved by the PUCO. ESP IV also continues a base distribution rate freeze through May 31, 2024. In addition, ESP IV continues the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continues Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $30 million per year from June 1, 2016 through May 31, 2019; $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. Other material terms of ESP IV include: (1) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (2) an agreement to file a Grid Modernization Business Plan for PUCO consideration and approval (which filing was made on February 29, 2016 and remains pending); (3) a goal across FirstEnergy to reduce CO 2 emissions by 90% below 2005 levels by 2045; (4) 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 Agency to ensure preservation and growth of the competitive market in Ohio; and (5) an agreement to file an application to transition to a straight fixed variable cost recovery mechanism for residential customers' base distribution rates, which filing was made on April 3, 2017 and remains pending. Several parties, including the Ohio Companies, filed applications for rehearing regarding the Ohio Companies’ ESP IV with the PUCO. The Ohio Companies’ application for rehearing challenged, among other things, the PUCO’s failure to adopt the Ohio Companies’ suggested modifications to Rider DMR. The Ohio Companies had previously suggested that a properly designed Rider DMR would be valued at $558 million annually for eight years, and include an additional amount that recognizes the value of the economic impact of FirstEnergy maintaining its headquarters in Ohio. Other parties’ applications for rehearing argued, among other things, that the PUCO’s adoption of Rider DMR is not supported by law or sufficient evidence. On August 16, 2017, the PUCO denied all remaining intervenor applications for rehearing, denied the Ohio Companies’ challenges to the modifications to Rider DMR and added a third-party monitor to ensure that Rider DMR funds are spent appropriately. On September 15, 2017, the Ohio Companies filed an application for rehearing of the PUCO’s August 16, 2017 ruling on the issues of the third-party monitor and the ROE calculation for advanced metering infrastructure. On October 11, 2017, the PUCO denied the Ohio Companies' application for rehearing on both issues. On October 16, 2017, the Sierra Club and the Ohio Manufacturer's Association Energy Group filed notices of appeal with the Supreme Court of Ohio appealing various PUCO entries on their applications for rehearing. On November 16, 2017, the Ohio Companies intervened in the appeal. Additional parties subsequently filed notices of appeal with the Supreme Court of Ohio challenging various PUCO entries on their applications for rehearing. On February 26, 2018, appellants filed their briefs. Briefs of the PUCO and the Ohio Companies are due May 7, 2018. Under ORC 4928.66, the Ohio Companies are required to implement energy efficiency programs that achieve certain annual energy savings and total peak demand reductions. Starting in 2017, ORC 4928.66 requires the energy savings benchmark to increase by 1% and the peak demand reduction benchmark to increase by 0.75% annually thereafter through 2020 and the energy savings benchmark to increase by 2% annually from 2021 through 2027, with a cumulative benchmark of 22.2% by 2027. On April 15, 2016, the Ohio Companies filed an application for approval of their three-year energy efficiency portfolio plans for the period from January 1, 2017 through December 31, 2019. The plans as proposed comply with benchmarks contemplated by ORC 4928.66 and provisions of the ESP IV, and include a portfolio of energy efficiency programs targeted to a variety of customer segments, including residential customers, low income customers, small commercial customers, large commercial and industrial customers and governmental entities. On December 9, 2016, the Ohio Companies filed a Stipulation and Recommendation with several parties that contained changes to the plan and a decrease in the plan costs. The Ohio Companies anticipate the cost of the plans will be approximately $268 million over the life of the portfolio plans and such costs are expected to be recovered through the Ohio Companies’ existing rate mechanisms. On November 21, 2017, the PUCO issued an order that approved the filed Stipulation and Recommendation with several modifications, including a cap on the Ohio Companies’ collection of program costs and shared savings set at 4% of the Ohio Companies’ total sales to customers as reported on 2015 FERC Form 1. On December 21, 2017, the Ohio Companies filed an application for rehearing challenging the PUCO’s modification of the Stipulation and Recommendation to include the 4% cost cap, which was denied by the PUCO on January 10, 2018. On March 12, 2018, the Ohio Companies filed a Notice of Appeal with the Supreme Court of Ohio challenging the PUCO’s imposition of a 4% cost cap. Various other parties also filed Notices of Appeal challenging various PUCO entries on their applications for rehearing. The Ohio Companies' brief is due on May 21, 2018. Ohio law requires electric utilities and electric service companies in Ohio to serve part of their load from renewable energy resources measured by an annually increasing percentage amount through 2026, except that in 2014 SB310 froze 2015 and 2016 requirements at the 2014 level (2.5%), pushing back scheduled increases, which resumed in 2017 (3.5%), and increases 1% each year through 2026 (to 12.5%) and shall remain at 12.5% in 2027 and each year thereafter. The Ohio Companies conducted RFPs in 2009, 2010 and 2011 to secure RECs to help meet these renewable energy requirements. In September 2011, the PUCO opened a docket to review the Ohio Companies' alternative energy recovery rider through which the Ohio Companies recover the costs of acquiring these RECs. The PUCO issued an Opinion and Order on August 7, 2013, approving the Ohio Companies' acquisition process and their purchases of RECs to meet statutory mandates in all instances except for certain purchases arising from one auction and directed the Ohio Companies to credit non-shopping customers in the amount of $43.4 million, plus interest, on the basis that the Ohio Companies did not prove such purchases were prudent. On December 24, 2013, following the denial of their application for rehearing, the Ohio Companies filed a notice of appeal and a motion for stay of the PUCO's order with the Supreme Court of Ohio, which was granted. The OCC and the ELPC also filed appeals of the PUCO's order. On January 24, 2018, the Supreme Court of Ohio reversed the PUCO order finding that the order violated the rule against prohibiting retroactive ratemaking. On February 5, 2018, the OCC and ELPC filed a motion for reconsideration, to which the Ohio Companies responded in opposition on February 15, 2018. On December 1, 2017, the Ohio Companies filed an application with the PUCO for approval of a DPM Plan. The DPM Plan is a portfolio of approximately $450 million in distribution platform investment projects, which are designed to modernize the Ohio Companies’ distribution grid, prepare it for further grid modernization projects, and provide customers with immediate reliability benefits. The Ohio Companies have requested that the PUCO issue an order approving the DPM Plan and associated cost recovery no later than May 2, 2018, so that the Ohio Companies can expeditiously commence the DPM Plan and customers can begin to realize the associated benefits. On January 10, 2018, the PUCO opened a case to consider the impacts of the Tax Act and determine the appropriate course of action to pass benefits on to customers. The Ohio Companies, effective January 1, 2018, were required to establish a regulatory liability for the estimated reduction in federal income tax resulting from the Tax Act, and filed comments on February 15, 2018, explaining that customers will save nearly $40 million annually as a result of updating tariff riders for the tax rate changes and that the Ohio Companies’ base distribution rates are not impacted by the Tax Act changes because they are frozen through May 2024. The Ohio Companies filed reply comments on March 7, 2018. PENNSYLVANIA The Pennsylvania Companies operate under DSPs for the June 1, 2017 through May 31, 2019 delivery period, which provide for the competitive procurement of generation supply for customers who do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. Under the DSPs, the supply will be provided by wholesale suppliers through a mix of 12 and 24-month energy contracts, as well as one RFP for 2-year SREC contracts for ME, PN and Penn. The DSPs include modifications to the Pennsylvania Companies’ POR programs in order to reduce the level of uncollectible expense the Pennsylvania Companies experience associated with alternative EGS charges. On December 11, 2017, the Pennsylvania Companies filed DSPs for the June 1, 2019 through May 31, 2023 delivery period. Under the 2019-2023 DSPs, the supply is proposed to 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. The 2019-2023 DSPs as proposed also include modifications to the Pennsylvania Companies’ POR programs in order to continue their clawback pilot program as a long-term, permanent program. The 2019-2023 DSPs also introduce a retail market enhancement rate mechanism designed to stimulate residential customer shopping, and modifications to the Pennsylvania Companies’ customer class definitions to allow for the introduction of hourly priced default service to customers at or above 100kW. A hearing was held on April 10, 2018, and the PPUC is expected to issue a final order on these DSPs by mid-September 2018. The Pennsylvania Companies operate under rates that were approved by the PPUC on January 19, 2017, effective as of January 27, 2017. These rates provide annual increases in operating revenues of approximately $96 million at ME, $100 million at PN, $29 million at Penn, and $66 million at WP, and are intended to benefit customers by modernizing the grid with smart technologies, increasing vegetation management activities, and continuing other customer service enhancements. Pursuant to Pennsylvania's EE&C legislation in Act 129 of 2008 and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs. On June 19, 2015, the PPUC issued a Phase III Final Implementation Order setting: demand reduction targets, relative to each Pennsylvania Companies' 2007-2008 peak demand (in MW), at 1.8% for ME, 1.7% for Penn, 1.8% for WP, and 0% for PN; and energy consumption reduction targets, as a percentage of each Pennsylvania Companies’ historic 2010 forecasts (in MWH), at 4.0% for ME, 3.9% for PN, 3.3% for Penn, and 2.6% for WP. The Pennsylvania Companies' Phase III EE&C plans for the June 2016 through May 2021 period, which were approved in March 2016, with expected costs up to $390 million, are designed to achieve the targets established in the PPUC's Phase III Final Implementation Order with full recovery through the reconcilable EE&C riders. Pursuant to Act 11 of 2012, Pennsylvania EDCs may establish a DSIC to recover costs of infrastructure improvements and costs related to highway relocation projects with PPUC approval. Pennsylvania EDCs must file LTIIPs outlining infrastructure improvement plans for PPUC review and approval prior to approval of a DSIC. On February 11, 2016, the PPUC approved LTIIPs for each of the Pennsylvania Companies. On June 14, 2017, the PPUC approved modified LTIIPs for ME, PN and Penn for the remaining years of 2017 through 2020 to provide additional support for reliability and infrastructure investments. The LTIIPs estimated costs for the remaining period of 2018 to 2020, as modified, are: WP $50.1 million; PN $44.8 million; Penn $33.2 million; and ME $51.3 million. On April 10, 2018, the PPUC notified each of the Pennsylvania Companies that the PPUC was initiating a review of the LTIIPs as required by regulation once every five years. Comments from interested parties concerning the LTIIPs are due to the PPUC by May 10, 2018, and reply comments by May 30, 2018. On February 16, 2016, the Pennsylvania Companies filed DSIC riders for PPUC approval for quarterly cost recovery, which were approved by the PPUC on June 9, 2016, and went into effect July 1, 2016, subject to hearings and refund or reallocation among customer classes. On January 19, 2017, in the PPUC’s order approving the Pennsylvania Companies’ general rate cases, the PPUC added an additional issue to the DSIC proceeding to include whether ADIT should be included in DSIC calculations. On February 2, 2017, the parties to the DSIC proceeding submitted a Joint Settlement to the ALJ that resolved the issues that were pending from the order issued on June 9, 2016. On August 31, 2017, the ALJ issued a decision recommending that the complaint of the Pennsylvania OCA be granted by the PPUC such that the Pennsylvania Companies reflect all federal and state income tax deductions related to DSIC-eligible property in the currently effective DSIC rates. On April 19, 2018, the PPUC approved the Joint Settlement without modification and reversed the ALJ's decision that would have required the Pennsylvania Companies to reflect all federal and state income tax deductions related to DSIC-eligible property in currently effective DSIC rates. On February 12, 2018, the PPUC initiated a proceeding to determine the effects of the Tax Act on the tax liability of utilities and the feasibility of reflecting such impacts in rates charged to customers. On March 9, 2018, the Pennsylvania Companies submitted their calculation of the net annual effect of the Tax Act on income tax expense and rate base to be $37 million for ME, $40 million for PN, $9 million for Penn, and $30 million for WP. The Pennsylvania Companies also filed comments proposing that rates be adjusted to reflect the tax rate changes prospectively from the date of a final PPUC order via a reconcilable rider, with the amount that would otherwise accrue between January 1, 2018 and the date of a final order being used to invest in the Pennsylvania Companies’ infrastructure. On March 15, 2018, the PPUC issued a Temporary Rates Order making the Pennsylvania Companies’ rates temporary and subject to refund for six months, with a possible six-month extension, during which time the PPUC will direct any negative surcharge, refund or other rate adjustment that it deems to be necessary, just and reasonable. WEST VIRGINIA MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking. 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 September 23, 2016, the WVPSC approved the Phase II energy efficiency program for MP and PE as reflected in a unanimous settlement, which includes three energy efficiency programs to meet the Phase II requirement of energy efficiency reductions of 0.5% of 2013 distribution sales for the January 1, 2017 through May 31, 2018 period, which was approved by the WVPSC in the 2012 proceeding approving the transfer of ownership of Harrison Power Station to MP. The costs for the Phase II program are expected to be $10.4 million and are eligible for recovery through the existing energy efficiency rider which is reviewed in the fuel (ENEC) case each year. On December 15, 2017, the WVPSC approved MP's and PE's proposed annual decrease in their EE&C rates, effective January 1, 2018, which decrease is not material to FirstEnergy. On December 9, 2016, the WVPSC approved the annual ENEC case for MP and PE as reflected in a unanimous settlement, resulting in an increase in the ENEC rate of $25 million annually beginning January 1, 2017. In addition, ENEC rates will be maintained at the same level for a two year period. AE Supply was the winning bidder of a December 2016 RFP to address MP’s generation shortfall and on March 6, 2017, MP and AE Supply signed an asset purchase agreement for MP to acquire AE Supply’s Pleasants Power Station (1,300 MWs) for approximately $195 million, subject to customary and other closing conditions, including regulatory approvals . On January 12, 2018, FERC issued an order denying authorization for the transaction, holding that MP and AE Supply did not demonstrate that the sale was consistent with the public interest and the transaction did not fall within the safe harbors for meeting FERC’s affiliate cross-subsidization analysis. The WVPSC issued its order on January 26, 2018, approving the transfer of Pleasants Power Station under certain conditions, which included MP assuming significant commodity risk. Based on the FERC ruling and the conditions included in the WVPSC order, MP and AE Supply terminated the asset purchase agreement and on February 16, 2018, AE Supply announced its intent to exit operations of the Pleasants Power Station by January 1, 2019, through either sale or deactivation. On September 1, 2017, MP and PE filed with the WVPSC for a reconciliation of their VMS to confirm that rate recovery matches VMP costs and for a regular review of that program. MP and PE proposed a $15 million annual decrease in VMS rates effective January 1, 2018, and an additional $15 million decrease in rates for 2019. This is an overall decrease in total revenue and average rates of 1%. On December 15, 2017, the WVPSC issued an order adopting a unanimous settlement without modification. On January 3, 2018, the WVPSC initiated a proceeding to investigate the effects of the Tax Act on the revenue requirements of utilities. MP and PE must track the tax savings resulting from the Tax Act on a monthly basis, effective January 1, 2018, and file written testimony explaining the impact of the Tax Act on federal income tax and revenue requirements by May 30, 2018. On January 26, 2018, the WVPSC issued an order clarifying that regulatory accounting should be implemented as of January 1, 2018, including the recording of any regulatory liabilities resulting from the Tax Act. FERC MATTERS Reliability Matters Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, AE Supply, ATSI, MAIT and TrAIL. NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of FirstEnergy's facilities are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC. FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstE |
Commitments, Guarantees and Con
Commitments, Guarantees and Contingencies | 3 Months Ended |
Mar. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS, GUARANTEES AND CONTINGENCIES | COMMITMENTS, GUARANTEES AND CONTINGENCIES GUARANTEES AND OTHER ASSURANCES FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. As of March 31, 2018 , FirstEnergy's outstanding guarantees and other assurances aggregated approximately $1.9 billion , consisting of guarantees and assurances on behalf of FES and FENOC ( $484 million ), parental guarantees on behalf of its consolidated subsidiaries ( $1,007 million ), other guarantees ( $255 million ) and other assurances ( $178 million ). COLLATERAL AND CONTINGENT-RELATED FEATURES In the normal course of business, FE and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel, and emission allowances. Certain bilateral agreements and derivative instruments 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 ratings from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. Bilateral agreements and derivative instruments entered into by FE and its subsidiaries have margining provisions that require posting of collateral. Based on AE Supply's power portfolio exposure as of March 31, 2018 , AE Supply had no posted collateral . The Utilities and FET had posted collateral of $6 million . These credit-risk-related contingent features, or the margining provisions within bilateral agreements, 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. Depending on the volume of forward contracts and future price movements, higher amounts for margining, which is the ability to secure additional collateral when needed, could be required. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of March 31, 2018. Potential Collateral Obligations AE Supply Utilities and FET FE Corp Total (In millions) Contractual Obligations for Additional Collateral At Current Credit Rating $ 1 $ — $ — $ 1 Upon Further Downgrade — 46 — 46 Surety Bonds (Collateralized Amount) 1 109 236 346 Total Exposure from Contractual Obligations $ 2 $ 155 $ 236 $ 393 Surety Bonds are not tied to a credit rating. Surety Bonds' impact assumes maximum contractual obligations (typical obligations require 30 days to cure). FE provides credit support for FG surety bonds of $169 million and $31 million for the benefit of the PA DEP with respect to LBR and the Hatfield's Ferry disposal site, respectively . OTHER COMMITMENTS AND CONTINGENCIES FE is a guarantor under a syndicated senior secured term loan facility due March 3, 2020, under which Global Holding's outstanding balance is $255 million . In addition to FE, Signal Peak, Global Rail, Global Mining Group, LLC and Global Coal Sales Group, LLC, each being a direct or indirect subsidiary of Global Holding, continue to provide their joint and several guarantees of the obligations of Global Holding under the facility. In connection with the facility, 69.99% of Global Holding's direct and indirect membership interests in Signal Peak, Global Rail and their affiliates along with FEV's and WMB Marketing Ventures, LLC's respective 33-1/3% membership interests in Global Holding, are pledged to the lenders under the current facility as collateral. ENVIRONMENTAL MATTERS Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Pursuant to a March 28, 2017 executive order, the EPA and other federal agencies are to review existing regulations that potentially burden the development or use of domestically produced energy resources and appropriately suspend, revise or rescind those that unduly burden the development of domestic energy resources beyond the degree necessary to protect the public interest or otherwise comply with the law. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof, in particular with respect to existing environmental regulations, may impact its business, results of operations, cash flows and financial condition. Compliance with environmental regulations could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that FirstEnergy competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Clean Air Act FirstEnergy complies with SO 2 and NOx emission reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls and/or using emission allowances. CSAPR requires reductions of NOx and SO 2 emissions in two phases (2015 and 2017), ultimately capping SO 2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO 2 emission allowances between power plants located in the same state and interstate trading of NOx and SO 2 emission allowances with some restrictions. The D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO 2 emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia. This follows 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 rule on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR update rule to the D.C. Circuit in November and December 2016. On September 6, 2017, the D.C. Circuit rejected the industry's bid for a lengthy pause in the litigation and set a briefing schedule. Depending on the outcome of the appeals, the EPA’s reconsideration of the CSAPR update rule and how the EPA and the states ultimately implement CSAPR, the future cost of compliance may be material and changes to FirstEnergy's operations may result. The EPA tightened the primary and secondary NAAQS for ozone from the 2008 standard levels of 75 PPB to 70 PPB on October 1, 2015. The EPA stated the vast majority of U.S. counties will meet the new 70 PPB standard by 2025 due to other federal and state rules and programs but the EPA will designate those counties that fail to attain the new 2015 ozone NAAQS by October 1, 2017. The EPA missed the October 1, 2017, deadline and has not yet promulgated the attainment designations. States will then have roughly three years to develop implementation plans to attain the new 2015 ozone NAAQS. On December 5, 2017, fourteen states and the District of Columbia filed complaints in the U.S. District Court of Northern California seeking an order that the EPA promulgate the attainment designations for the new 2015 ozone NAAQS. Depending on how the EPA and the states implement the new 2015 ozone NAAQS, the future cost of compliance may be material and changes to FirstEnergy’s operations may result. In August 2016, the State of Delaware filed a CAA Section 126 petition with the EPA alleging that the Harrison generating facility's NOx emissions significantly contribute to Delaware's inability to attain the ozone NAAQS. The petition seeks a short-term NOx emission rate limit of 0.125 lb/mmBTU over an averaging period of no more than 24 hours. On September 27, 2016, the EPA extended the time frame for acting on the State of Delaware's CAA Section 126 petition by six months to April 7, 2017 , but has not taken any further action. On January 2, 2018, the State of Delaware provided the EPA a notice required at least 60 days prior to filing a suit seeking to compel the EPA to either approve or deny the August 2016 CAA Section 126 petition . In November 2016, the State of Maryland filed a CAA Section 126 petition with the EPA alleging that NOx emissions from 36 EGUs, including Harrison Units 1, 2 and 3 and Pleasants Units 1 and 2, significantly contribute to Maryland's inability to attain the ozone NAAQS. The petition seeks NOx emission rate limits for the 36 EGUs by May 1, 2017. On January 3, 2017, the EPA extended the time frame for acting on the CAA Section 126 petition by six months to July 15, 2017 , but has not taken any further action. On September 27, 2017 , and October 4, 2017, the State of Maryland and various environmental organizations filed complaints in the U.S. District Court for the District of Maryland seeking an order that the EPA either approve or deny the CAA Section 126 petition of November 16, 2016. 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 Ohio, Pennsylvania and West Virginia) significantly contribute to New York’s inability to attain the ozone NAAQS. The petition seeks suitable emission rate limits for large stationary sources that are affecting New York’s air quality within the three years allowed by CAA Section 126. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss. MATS imposed emission limits for mercury, PM, and HCl for all existing and new fossil fuel fired EGUs effective in April 2015 with averaging of emissions from multiple units located at a single plant. The majority of FirstEnergy's MATS compliance program and related costs have been completed. On May 1, 2017, FE and FG and CSX and BNSF entered into a definitive settlement agreement, which resolved all claims related to a coal transportation contract dispute as a result of MATS on the terms and conditions set forth below. Pursuant to the settlement agreement, FG agreed to pay CSX and BNSF an aggregate amount equal to $109 million, payable in three annual installments, the first of which was made on May 1, 2017. FE agreed to unconditionally and continually guarantee the settlement payments due by FG pursuant to the terms of the settlement agreement. The settlement agreement further provided that in the event of the initiation of bankruptcy proceedings or failure to make timely settlement payments, the unpaid settlement amount will immediately accelerate and become due and payable in full. On April 6, 2018, FE paid the remaining $72 million under the settlement agreement as a result of the FES Bankruptcy. As to a specific coal supply agreement, AE Supply, the party thereto, asserted termination rights effective in 2015 as a result of MATS. In response to notification of the termination, on January 15, 2015, Tunnel Ridge, LLC, the coal supplier, commenced litigation in the Court of Common Pleas of Allegheny County, Pennsylvania , alleging AE Supply did not have sufficient justification to terminate the agreement and seeking damages for the difference between the market and contract price of the coal, or lost profits plus incidental damages. On February 18, 2018, the parties reached an agreement in principle settling all claims in dispute. The agreement in principle includes, among other matters, a $93 million payment by AE Supply, as well as certain coal supply commitments for Pleasants Power Station during its remaining operation by AE Supply. Certain aspects of the final settlement agreement are guaranteed by FE, including the $93 million payment. The parties executed the final settlement agreement on March 9, 2018 and the plaintiff dismissed the matter with prejudice on March 15, 2018. Climate Change FirstEnergy has established a goal to reduce CO 2 emissions by 90% below 2005 levels by 2045. There are a number of 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. The EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act,” in December 2009, concluding that concentrations of several key GHGs constitutes 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. On June 23, 2014, the U.S. Supreme Court decided that CO 2 or other GHG emissions alone cannot trigger permitting requirements under the CAA, but that air emission sources that need PSD permits due to other regulated air pollutants can be required by the EPA to install GHG control technologies. The EPA released its final CPP regulations in August 2015 (which have been stayed by the U.S. Supreme Court), to reduce CO 2 emissions from existing fossil fuel-fired EGUs. The EPA also 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 January 21, 2016, a panel of the D.C. Circuit denied the motions for stay and set an expedited schedule for briefing and argument. 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 October 16, 2017, the EPA issued a proposed rule to repeal the CPP. Depending on the outcomes of the review pursuant to the executive order, of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material. At the international level, the United Nations Framework Convention on Climate Change resulted in the Kyoto Protocol requiring participating countries, which does not include the U.S., to reduce GHGs commencing in 2008 and has been extended through 2020. The Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide GHG emissions by 26 to 28 percent below 2005 levels by 2025, and in September 2016, joined in adopting the agreement reached on December 12, 2015, at the United Nations Framework Convention on Climate Change meetings in Paris. The Paris Agreement was ratified by the requisite number of countries (i.e., at least 55 countries representing at least 55% of global GHG emissions) in October 2016 and its non-binding obligations to limit global warming to well 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. 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. 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 plants. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations. The EPA finalized CWA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts of a cooling water intake system to a 12% annual average and requiring cooling water intake structures exceeding 125 million gallons per day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. Depending on any final action taken by the states with respect to impingement and entrainment, the future capital costs of compliance with these standards may be material. 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 phase-in as permits are renewed on a five-year cycle from 2018 to 2023. The final rule also allows plants to commit to more stringent effluent limits for wet scrubber systems based on evaporative technology and in return have until the end of 2023 to meet the more stringent limits. On April 13, 2017, the EPA granted a Petition for Reconsideration and administratively stayed (effective upon publication in the Federal Register) all deadlines in the effluent limits rule pending a new rulemaking. Also, on September 18, 2017, the EPA postponed certain compliance deadlines for two years. Depending on the outcome of appeals and how any final rules are ultimately implemented, the future costs of compliance with these standards may be substantial and changes to FirstEnergy's operations may result. In October 2009, the WVDEP issued an NPDES water discharge permit for the Fort Martin plant, which imposes TDS, sulfate concentrations and other effluent limitations for heavy metals, as well as temperature limitations. Concurrent with the issuance of the Fort Martin NPDES permit, WVDEP also issued an administrative order setting deadlines for MP to meet certain of the effluent limits that were effective immediately under the terms of the NPDES permit. MP appealed, and a stay of certain conditions of the NPDES permit and order have been granted pending a final decision on the appeal and subject to WVDEP moving to dissolve the stay. The Fort Martin NPDES permit could require an initial capital investment ranging from $150 million to $300 million in order to install technology to meet the TDS and sulfate limits, which technology may also meet certain of the other effluent limits. Additional technology may be needed to meet certain other limits in the Fort Martin NPDES permit. MP intends to vigorously pursue these issues but cannot predict the outcome of the appeal or estimate the possible loss or range of loss. FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the loss or range of loss. Regulation of Waste Disposal Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act. Certain CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. Based on an assessment of the finalized regulations, the future cost of compliance and expected timing had no significant impact on FirstEnergy's existing AROs associated with CCRs. Although not currently expected, changes in timing and closure plan requirements in the future could materially and adversely impact FirstEnergy's AROs . Pursuant to a 2013 consent decree, PA DEP issued a 2014 permit for the Little Blue Run CCR impoundment requiring the Bruce Mansfield plant to cease disposal of CCRs by December 31, 2016, and FG to provide bonding for 45 years of closure and post-closure activities and to complete closure within a 12-year period, but authorizing FG to seek a permit modification based on "unexpected site conditions that have or will slow closure progress." The permit does not require active dewatering of the CCRs, but does require a groundwater assessment for arsenic and abatement if certain conditions in the permit are met. The CCRs from the Bruce Mansfield plant are being beneficially reused with the majority used for reclamation of a site owned by the Marshall County Coal Company in Moundsville, W. Va., and the remainder recycled into drywall by National Gypsum. These beneficial reuse options are expected to be sufficient for ongoing plant operations, however, the Bruce Mansfield plant is pursuing other options. On May 22, 2015 and September 21, 2015, the PA DEP reissued a permit for the Hatfield's Ferry CCR disposal facility and then modified that permit to allow disposal of Bruce Mansfield plant CCR. The Sierra Club's Notices of Appeal before the Pennsylvania Environmental Hearing Board challenging the renewal, reissuance and modification of the permit for the Hatfield’s Ferry CCR disposal facility were resolved through a Consent Adjudication between FG, PA DEP and the Sierra Club requiring operational changes that became effective November 3, 2017. As noted above, FE provides credit support for FG surety bonds of $169 million and $31 million for the benefit of the PA DEP with respect to LBR and the Hatfield's Ferry disposal site, respectively. FirstEnergy 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 March 31, 2018, 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 $125 million have been accrued through March 31, 2018. Included in the total are accrued liabilities of approximately $85 million for environmental remediation of former manufactured gas plants 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 Nuclear Plant Matters Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its retired nuclear facility, TMI-2. As of March 31, 2018 , FirstEnergy had approximately $0.8 billion invested in external trusts to be used for the decommissioning and environmental remediation of its retired TMI-2 nuclear generating facility. The values of FirstEnergy's NDTs also fluctuate based on market conditions. If the values of the trusts decline by a material amount, FirstEnergy's obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDTs. FES Bankruptcy On March 31, 2018, FES, including its consolidated subsidiaries, FG, NG, FE Aircraft Leasing Corp., Norton Energy Storage L.L.C. and FirstEnergy Generation Mansfield Unit 1 Corp, and FENOC filed voluntary petitions for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court. See Note 3, "Discontinued Operations," for additional information. Other Legal Matters There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to FE or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 13, "Regulatory Matters." FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that FE or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on FE's or its subsidiaries' financial condition, results of operations and cash flows. |
Segment Information
Segment Information | 3 Months Ended |
Mar. 31, 2018 | |
Segment Reporting [Abstract] | |
SEGMENT INFORMATION | SEGMENT INFORMATION FirstEnergy's reportable segments are as follows: Regulated Distribution and Regulated Transmission. On March 31, 2018, as discussed in Note 3 , “Discontinued Operations , ” FirstEnergy deconsolidated FES and FENOC and presented FES, FENOC, BSPC and a portion of AE Supply, representing substantially all of FirstEnergy’s operations that previously comprised the CES reportable operating segment, as discontinued operations in FirstEnergy’s consolidated financial statements resulting from actions taken as part of the strategic review of exiting commodity-exposed generation. The financial information for all periods has been revised to present the discontinued operations within Reconciling Adjustments. The remaining business activities that previously comprised the CES reportable operating segment were not material and, as such, have been combined into Corporate/Other for reporting purposes. 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 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. The segment's results reflect the commodity costs of securing electric generation and the deferral and amortization of certain fuel costs. The Regulated Transmission segment provides transmission infrastructure owned and operated by ATSI, TrAIL, MAIT 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 at ATSI, TrAIL, and MAIT as well as stated transmission rates at certain of FirstEnergy’s utilities. As discussed in Note 13, "Regulatory Matters - FERC Matters" above, MAIT filed a settlement with FERC on October 13, 2017, which settlement agreement is pending final order by FERC. Both the forward-looking formula and stated rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. The segment's results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy's transmission facilities. Corporate support not charged to FE's subsidiaries, interest expense on stand-alone holding company debt, corporate income taxes and other businesses that do not constitute an operating segment are categorized as Corporate/Other for reportable business segment purposes. Additionally, reconciling adjustments for the elimination of inter-segment transactions are included in Corporate/Other. As of March 31, 2018, 2,123 MWs of electric generating capacity was included in Corporate/Other, including, as discussed in Note 3, "Discontinued Operations," AGC's interests in Bath County (713 MWs), the sale of which is expected to close in the second quarter of 2018. As of March 31, 2018, Corporate/Other had $5.35 billion of stand-alone holding company long-term debt and $1.2 billion was borrowed by FE under its revolving credit facility. Financial information for each of FirstEnergy's reportable segments is presented in the tables below. Segment Financial Information For the Three Months Ended Regulated Distribution Regulated Transmission Corporate/ Other Reconciling Adjustments Consolidated (In millions) March 31, 2018 Revenues $ 2,576 $ 323 $ 125 $ (48 ) $ 2,976 Depreciation 196 61 19 18 294 Amortization (deferral) of regulatory assets, net (152 ) 4 — — (148 ) Miscellaneous income 56 4 16 (9 ) 67 Interest expense 128 39 92 (9 ) 250 Income taxes 93 32 127 — 252 Income (loss) from continuing operations 322 99 (244 ) — 177 Total assets 27,504 9,681 1,255 355 38,795 Total goodwill 5,004 614 — — 5,618 Property additions 264 292 12 15 583 March 31, 2017 Revenues $ 2,500 $ 313 $ 92 $ (50 ) $ 2,855 Depreciation 178 51 4 17 250 Amortization of regulatory assets, net 81 2 — — 83 Miscellaneous income 15 — 6 (7 ) 14 Interest expense 138 39 75 (7 ) 245 Income taxes (benefits) 138 52 (38 ) — 152 Income (loss) from continuing operations 237 88 (68 ) — 257 Total assets 27,826 8,938 1,160 5,288 43,212 Total goodwill 5,004 614 — — 5,618 Property additions 264 224 10 90 588 |
Subsequent Events (Notes)
Subsequent Events (Notes) | 3 Months Ended |
Mar. 31, 2018 | |
Subsequent Events [Abstract] | |
Subsequent Events | SUBSEQUENT EVENTS On April 20, 2018, FirstEnergy reached an agreement in principle with two groups of key FES creditors in the FES Bankruptcy. The first is an ad hoc group, which includes a majority of the pollution control revenue bonds supported by notes issued by FG and NG and the holders of senior notes issued by FES, while the second group includes the majority of Bruce Mansfield unit 1 sale and leaseback transaction certificate holders. The agreement confirms FE will pay certain pre-petition FES and FENOC employee-related obligations, which include unfunded pension obligations and other employee benefits, and provides for the waiver of certain related party claims held by FE, among them the full borrowings by FES under the $500 million secured credit facility, the $200 million credit agreement being used to support surety bonds and the BNSF/CSX rail settlement guarantee. Additionally, the agreement provides for, among other things, (1) the full release of all claims against FirstEnergy by FES, FENOC and their creditors; (2) a $225 million cash payment from FirstEnergy which includes a reversal of the $88 million NOL purchase prior to the FES Bankruptcy; (3) up to a $628 million note from FirstEnergy, which is intended to represent the estimated value of a worthless stock deduction associated with the FES Bankruptcy and is designed to trade at par value of such note when issued; (4) the transfer of the Pleasants Power Station to FES for the benefit of FES’ creditors; and (5) a right of FirstEnergy to share in recoveries after an agreed-upon threshold is met. FE will also provide FES certain assistance in areas of operations, regulatory and governmental affairs. The agreement will be subject to approval by the FE, FES, FENOC and AE Supply Boards of Directors, the execution of definitive agreements and the approval of the Bankruptcy Court. Additionally, the Bruce Mansfield certificate holders’ support for the agreement is subject to and conditioned upon the ultimate implementation of the agreed upon treatment of certain claims of the Bruce Mansfield certificate holders. The ad hoc group and Bruce Mansfield certificate holders will use their best efforts to have the Official Committee of the Unsecured Creditors, appointed in the FES Bankruptcy, as well as any remaining key creditors join the settlement by June 15, 2018. There can be no assurance that a definitive agreement will be finalized and approved and, even if approved, whether the conditions to the settlement will be satisfied, and the actual outcome of this matter may differ materially from the terms of the agreement in principle described herein. |
Organization and Basis of Pre24
Organization and Basis of Presentation (Policies) | 3 Months Ended |
Mar. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Accounting | These interim financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and disclosures normally included in financial statements and notes prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. These interim financial statements should be read in conjunction with the financial statements and notes included in the Annual Report on Form 10-K for the year ended December 31, 2017 . 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 NRC, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU. The accompanying interim financial statements are unaudited, but reflect all adjustments, consisting of normal recurring adjustments, that, in the opinion of management, are necessary for a fair statement of the financial statements. 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 Policy | 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. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see Note 8, "Variable Interest Entities"). 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. |
New Accounting Pronouncements | New Accounting Pronouncements Recently Adopted Pronouncements ASU 2014-09, "Revenue from Contracts with Customers" (Issued May 2014 and subsequently updated to address implementation questions): The new revenue recognition guidance establishes a new control-based revenue recognition model, changes the basis for deciding when revenue is recognized over time or at a point in time, provides new and more detailed guidance on specific topics and expands and improves disclosures about revenue. FirstEnergy evaluated its revenues and the new guidance had immaterial impacts to recognition practices upon adoption on January 1, 2018. As part of the adoption, FirstEnergy elected to apply the new guidance on a modified retrospective basis. FirstEnergy did not record a cumulative effect adjustment to retained earnings for initially applying the new guidance as no revenue recognition differences were identified in the timing or amount of revenue. In addition, upon adoption, certain immaterial financial statement presentation changes were implemented. See Note 2, " Revenue," for additional information on FirstEnergy revenues. ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities" (Issued January 2016 and subsequently updated in 2018): ASU 2016-01 primarily affects the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. FirstEnergy adopted this standard on January 1, 2018, and recognizes all gains and losses for equity securities in income with the exception of those that are accounted for under the equity method of accounting. The NDT equity portfolios of JCP&L, ME and PN will not be impacted as unrealized gains and losses will continue to be offset against regulatory assets or liabilities. As a result of adopting this standard, FirstEnergy recorded a cumulative effect adjustment to retained earnings of $115 million (pre-tax) on January 1, 2018, representing unrealized gains on equity securities with FES NDTs that were previously recorded to AOCI. Following deconsolidation of FES and FENOC, the adoption of this standard is not expected to have a material impact on FirstEnergy's financial statements as the majority of its equity securities are offset against a regulatory asset or liability. ASU 2016-18, " Restricted Cash" (Issued November 2016): ASU 2016-18 addresses the presentation of changes in restricted cash and restricted cash equivalents in the statement of cash flows. The guidance is required to be applied retrospectively. As a result of adopting this standard, FirstEnergy's statement of cash flows report changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents. Prior periods have been recasted to conform to the current year presentation. ASU 2017-01, "Business Combinations: Clarifying the Definition of a Business" (Issued January 2017) : ASU 2017-01 assists entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. FirstEnergy adopted ASU 2017-01 on January 1, 2018. The ASU will be applied prospectively to future transactions. ASU 2017-04, "Goodwill Impairment" (Issued January 2017): Simplifies the accounting for goodwill impairment by removing Step 2 of the current test, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two-step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. FirstEnergy has elected to early adopt ASU 2017-04 as of January 1, 2018, and will apply this standard on a prospective basis. ASU 2017-07, "Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost" (Issued March 2017) : ASU 2017-07 requires entities to retrospectively (1) disaggregate the current-service-cost component from the other components of net benefit cost (the “other components”) and present it with other current compensation costs for related employees in the income statement and (2) present the other components elsewhere in the income statement and outside of income from operations if such a subtotal is presented. In addition, only service costs are eligible for capitalization on a prospective basis. FirstEnergy adopted ASU 2017-07 on January 1, 2018. Because the non-service cost components of net benefit cost are no longer eligible for capitalization after December 31, 2017, FirstEnergy has recognized these components in income as a result of adopting this standard. FirstEnergy reclassified approximately $8 million of non-service costs from Other operating expense to Miscellaneous income for the three months ended March 31, 2017. ASU 2018-02, " Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income " (Issued February 2018): ASU 2018-02 allows entities to reclassify from AOCI to retained earnings stranded tax effects resulting from the Tax Act. FirstEnergy early adopted this standard during the first quarter of 2018 and has elected to present the change in the period of adoption. Upon adoption, FirstEnergy recorded a $22 million cumulative effect adjustment for stranded tax effects, such as pension and OPEB prior service costs and losses on derivative hedges, to retained earnings on January 1, 2018, of which $8 million was related to FES and FENOC. ASU 2018-05, " Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118 " (Issued March 2018): ASU 2018-05, effective 2018, expands income tax accounting and disclosure guidance to include SAB 118 issued by the SEC in December 2017. SAB 118 provides guidance on accounting for the income tax effects of the Tax Act and among other things allows for a measurement period not to exceed one year for companies to finalize the provisional amounts recorded as of December 31, 2017. See Note 7, "Income taxes," for additional information on FirstEnergy's accounting for the Tax Act. 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 or in the 2017 Annual Report on Form 10-K based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting. Below is an update to the discussion of pronouncements contained in the 2017 Annual Report on Form 10-K. ASU 2016-02, "Leases (Topic 842)" (Issued February 2016) and ASU 2018-01,"Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842" (Issued January 2018): ASU 2016-02 will require organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets. In addition, new qualitative and quantitative disclosures of the amounts, timing, and uncertainty of cash flows arising from leases will be required. The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. ASU 2018-01 (same effective date and transition requirements as ASU 2016-02) provides an optional transition practical expedient that, if elected, would not require an entity to reconsider its accounting for existing land easements that are not currently accounted for under the old leases standard. FirstEnergy does not plan to adopt these standards early. Lessors and lessees will be required to apply a modified retrospective transition approach, which requires adjusting the accounting for any leases existing at the beginning of the earliest comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date will not require any accounting adjustment. FirstEnergy expects an increase in assets and liabilities; however, it is currently assessing the impact on its Consolidated Financial Statements, including monitoring utility industry implementation guidance. FirstEnergy is in the process of developing a complete lease inventory, as well as identifying, assessing and documenting technical accounting issues, policy considerations and financial reporting implications. In addition, FirstEnergy is implementing a third-party software tool that will assist with the initial adoption and ongoing compliance. |
Earnings Per Share | The convertible Preferred Stock issued in January 2018 (see Note 11, "Capitalization") is considered participating securities since these shares participate in dividends on Common Stock on an "as-converted" basis. As a result, Earnings per share on Common Stock is computed using the two-class method required for participating securities. The two-class method uses an earnings allocation formula that treats participating securities as having rights to earnings that otherwise would have been available only to common stockholders. Under the two-class method, net income attributable to common stockholders is derived by subtracting the following from income from continuing operations: • preferred share dividends, • deemed dividends for the amortization of the beneficial conversion feature recognized at issuance of the Preferred Stock (if any), and • an allocation of undistributed earnings between the common shares and the participating securities (convertible Preferred Stock) based on their respective rights to receive dividends. Net losses are not allocated to the convertible Preferred Stock as they do not have a contractual obligation to share in the losses of FirstEnergy. FirstEnergy allocates undistributed earnings based upon income from continuing operations. The Preferred Stock includes an embedded conversion option at a price that is below the fair value of the Common Stock on the commitment date. This beneficial conversion feature, which was approximately $296 million , represents the difference between the fair value per share of the Common Stock and the conversion price, multiplied by the number of common shares issuable upon conversion. The beneficial conversion feature will be amortized as a deemed dividend over the period from the issue date to the first allowable conversion date (July 22, 2018) as a charge to OPIC, since FE is in an accumulated deficit position with no retained earnings to declare a dividend. As noted above, for EPS reporting purposes, this beneficial conversion feature will be reflected in net income attributable to common stockholders as a deemed dividend. The amount amortized in the first quarter of 2018 was approximately $113 million . Basic EPS available to common stockholders is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding during the period. Participating securities are excluded from basic weighted average ordinary shares outstanding. Diluted EPS available to common stockholders is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding, including all potentially dilutive common shares, if the effect of such common shares is dilutive. Diluted EPS reflects the dilutive effect of potential common shares from share-based awards and convertible preferred shares. The dilutive effect of outstanding share based awards is computed using the treasury stock method, which assumes any proceeds that could be obtained upon the exercise of the award would be used to purchase Common Stock at the average market price for the period. The dilutive effect of the convertible Preferred Stock is computed using the if-converted method, which assumes conversion of the convertible Preferred Stock at the beginning of the period, giving income recognition for the add-back of the preferred share dividends, amortization of beneficial conversion feature, and undistributed earnings allocated to preferred stockholders. |
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. |
Investment Policy | 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 equity securities, 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 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. |
Derivatives Instruments Policy | FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value (unless they meet the normal purchases and normal sales criteria) as follows: • Changes in the fair value of derivative instruments that are designated and qualify as cash flow hedges are recorded to AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings. • Changes in the fair value of derivative instruments that are designated and qualify as fair value hedges are recorded as an adjustment to the item being hedged. When fair value hedges are discontinued, the adjustment recorded to the item being hedged is amortized into earnings. • Changes in the fair value of derivative instruments that are not designated in a hedging relationship are recorded in earnings on a mark-to-market basis, unless otherwise noted. Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of accounting with their effects included in earnings at the time of contract performance. |
Revenue (Tables)
Revenue (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The following table represents a disaggregation of revenue from contracts with customers for the three months ended March 31, 2018, by type of service from each reportable segment: For the Three Months Ended March 31, 2018 Revenues by Type of Service Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments (1) Total (In millions) Distribution services (2) $ 1,281 $ — $ (12 ) $ 1,269 Retail generation 1,040 — (14 ) 1,026 Wholesale sales 123 — 120 243 Transmission (2) — 319 — 319 Other 35 — — 35 Total revenues from contracts with customers $ 2,479 $ 319 $ 94 $ 2,892 ARP 64 — — 64 Other non-customer revenue 33 4 (17 ) 20 Total revenues $ 2,576 $ 323 $ 77 $ 2,976 (1) Includes eliminations and reconciling adjustments of inter-segment revenues. (2) Includes $76 million in reductions to revenue related to amounts subject to refund resulting from the Tax Act ( $72 million at Regulated Distribution and $4 million at Regulated Transmission). The following table represents a disaggregation of the Regulated Distribution segment revenue from contracts with distribution service and retail generation customers for the three months ended March 31, 2018, by class: For the Three Months Ended March 31, 2018 Revenues by Customer Class (In millions) Residential $ 1,463 Commercial 580 Industrial 254 Other 24 Total Revenues $ 2,321 The following table represents a disaggregation of revenue from contracts with regulated transmission customers for the three months ended March 31, 2018, by transmission owner: For the Three Months Ended March 31, 2018 Revenues by Transmission Asset Owner (In millions) ATSI $ 159 TrAIL 62 MAIT 31 Other 71 Total Revenues $ 323 |
Discontinued Operations (Tables
Discontinued Operations (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Disposal Groups, Including Discontinued Operations | Summarized results of discontinued operations for the three months ended March 31, 2018 and 2017, were as follows: For the Three Months Ended March 31, (In millions) 2018 2017 Revenues $ 622 $ 689 Fuel (116 ) (164 ) Purchased power (53 ) (49 ) Other operating expenses (347 ) (492 ) Provision for depreciation (46 ) (25 ) General taxes (18 ) (29 ) Other Income (Expense) (60 ) (8 ) Loss from discontinued operations, before tax (18 ) (78 ) Income tax expense (benefit) 29 (26 ) Loss from discontinued operations, net of tax (47 ) (52 ) Gain on deconsolidation, net of tax 1,239 — Income (loss) from discontinued operations $ 1,192 $ (52 ) The gain on deconsolidation that was recognized in the three months ended March 31, 2018, consisted of the following: (In millions) Removal of investment in FES and FENOC $ 2,193 Assumption of benefit obligations retained at FE (including Pension, OPEB and EDCP) (820 ) Guarantees and credit support provided by FE (139 ) Reserve on receivables and allocated Pension/OPEB mark-to-market (914 ) Gain on deconsolidation of FES and FENOC, before tax 320 Income tax benefit including estimated worthless stock deduction 919 Gain on deconsolidation of FES and FENOC $ 1,239 The following table summarizes the major classes of assets and liabilities as discontinued operations as of March 31, 2018 and December 31, 2017: (In millions) March 31, 2018 December 31, 2017 Carrying amount of the major classes of assets included in discontinued operations: Cash $ — $ 1 Restricted cash — 3 Receivables — 202 Materials and supplies 2 201 Collateral — 130 Other current assets — 69 Total current assets 2 606 Property, plant and equipment 353 1,057 Investments — 1,875 Other non-current assets — 356 Total non-current assets 353 3,288 Total assets included in discontinued operations $ 355 $ 3,894 Carrying amount of the major classes of liabilities included in discontinued operations: Currently payable long-term debt $ — $ 524 Accounts payable — 200 Accrued taxes — 38 Accrued compensation and benefits — 79 Other current liabilities — 132 Total current liabilities — 973 Long-term debt and other long-term obligations — 2,299 Accumulated deferred income taxes (1) — (1,812 ) Asset retirement obligations — 1,945 Deferred gain on sale and leaseback transaction — 723 Other non-current liabilities — 244 Total noncurrent liabilities — 3,399 Total liabilities included in discontinued operations $ — $ 4,372 (1) Represents an increase in FirstEnergy's ADIT liability as an ADIT asset was removed upon deconsolidation of FES and FENOC. FirstEnergy's Consolidated Statement of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow statement category. The following table summarizes the major classes of cash flow items as discontinued operations for the three months ended March 31, 2018 and 2017: For the Three Months Ended March 31, (In millions) 2018 2017 CASH FLOWS FROM OPERATING ACTIVITIES: Income (loss) from discontinued operations $ 1,192 $ (52 ) Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs 47 79 Unrealized (gain) loss on derivative transactions (10 ) 47 CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (15 ) (90 ) Nuclear fuel — (132 ) Sales of investment securities held in trusts 109 231 Purchases of investment securities held in trusts (122 ) (245 ) |
Earnings Per Share Of Common 27
Earnings Per Share Of Common Stock (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Earnings Per Share [Abstract] | |
Reconciliation of basic and diluted earnings per share | The following table reconciles basic and diluted EPS of common stock: (In millions, except per share amounts) For the Three Months Ended March 31, Reconciliation of Basic and Diluted Earnings per Share of Common Stock 2018 2017 Earnings Per Share of Common Stock Income from continuing operations $ 177 $ 257 Less: Preferred dividends (43 ) — Less: Amortization of beneficial conversion feature (113 ) — Less: Undistributed earnings allocated to preferred stockholders (1) — — Income from continuing operations available to common stockholders 21 257 Discontinued operations, net of tax 1,192 (52 ) Less: Undistributed earnings allocated to preferred stockholders (1) — — Income (loss) from discontinued operations available to common stockholders 1,192 (52 ) Income available to common stockholders, basic and diluted $ 1,213 $ 205 Share Count information: Weighted average number of basic shares outstanding 476 443 Assumed exercise of dilutive stock options and awards 2 1 Assumed conversion of preferred stock — — Weighted average number of diluted shares outstanding 478 444 Income available to common stockholders, per common share: Income from continuing operations, basic $ 0.04 $ 0.58 Discontinued operations, basic 2.51 (0.12 ) Income available to common stockholders, basic $ 2.55 $ 0.46 Income from continuing operations, diluted $ 0.04 $ 0.58 Discontinued operations, diluted 2.50 (0.12 ) Income available to common stockholders, diluted $ 2.54 $ 0.46 (1) Undistributed earnings were not allocated to participating securities as income from continuing operations less dividends declared (common and preferred) and deemed dividends was a net loss. |
Pension and Other Postemploym28
Pension and Other Postemployment Benefits (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Retirement Benefits [Abstract] | |
Components of Net Periodic Benefit Costs | The components of the consolidated net periodic costs (credits) for pension and OPEB (including amounts capitalized) were as follows: Components of Net Periodic Benefit Costs (Credits) Pension OPEB For the Three Months Ended March 31, 2018 2017 2018 2017 (In millions) Service costs $ 56 $ 52 $ 1 $ 1 Interest costs 93 97 6 7 Expected return on plan assets (144 ) (112 ) (8 ) (8 ) Amortization of prior service costs (credits) 2 2 (20 ) (20 ) Net periodic costs (credits) $ 7 $ 39 $ (21 ) $ (20 ) |
Net Periodic Pension and OPEB Costs | Pension and OPEB obligations are allocated to FE's subsidiaries employing the plan participants. The net periodic pension and OPEB costs (credits), net of amounts capitalized, recognized in earnings by FirstEnergy were as follows: Net Periodic Benefit Expense (Credit) Pension OPEB For the Three Months Ended March 31, 2018 2017 2018 2017 (In millions) FirstEnergy $ (14 ) $ 32 $ (21 ) $ (15 ) |
Accumulated Other Comprehensi29
Accumulated Other Comprehensive Income (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Equity [Abstract] | |
Schedule of Accumulated Other Comprehensive Income | The changes in AOCI, net of tax, in the thre e months ended March 31, 2018 and 2017 , for FirstEnergy are included in the following tables: Gains & Losses on Cash Flow Hedges Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total (In millions) AOCI balance as of January 1, 2 018 $ (22 ) $ 67 $ 97 $ 142 Other comprehensive income before reclassifications — (97 ) — (97 ) Amounts reclassified from AOCI 2 (1 ) (18 ) (17 ) Deconsolidation of FES and FENOC 13 (8 ) — 5 Other comprehensive income (loss) 15 (106 ) (18 ) (109 ) Income taxes (benefits) on other comprehensive income (loss) 8 (39 ) (22 ) (53 ) Other comprehensive income (loss), net of tax 7 (67 ) 4 (56 ) AOCI Balance as of March 31, 2018 $ (15 ) $ — $ 101 $ 86 AOCI balance as of January 1, 2 017 $ (28 ) $ 52 $ 150 $ 174 Other comprehensive income before reclassifications — 32 — 32 Amounts reclassified from AOCI 3 (16 ) (18 ) (31 ) Other comprehensive income (loss) 3 16 (18 ) 1 Income taxes (benefits) on other comprehensive income (loss) 1 5 (6 ) — Other comprehensive income (loss), net of tax 2 11 (12 ) 1 AOCI Balance as of March 31, 2017 $ (26 ) $ 63 $ 138 $ 175 |
Reclassification out of Accumulated Other Comprehensive Income | The following amounts were reclassified from AOCI for FirstEnergy in the thre e months ended March 31, 2018 and 2017 : For the Three Months Ended March 31, Affected Line Item in the Consolidated Statements of Income Reclassifications from AOCI (2) 2018 2017 (In millions) Gains & losses on cash flow hedges Long-term debt $ 2 $ 3 Interest expense (1 ) (1 ) Income taxes $ 1 $ 2 Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (1 ) $ (10 ) Discontinued Operations Defined benefit pension and OPEB plans Prior-service costs $ (18 ) $ (18 ) (1) 5 6 Income taxes $ (13 ) $ (12 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 5, "Pension and Other Postemployment Benefits," for additional details. (2) Amounts in parenthesis represent credits to the Consolidated Statements of Income from AOCI. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Assets and liabilities measured on recurring basis | The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy: FirstEnergy Recurring Fair Value Measurements March 31, 2018 December 31, 2017 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 468 $ — $ 468 $ — $ 476 $ — $ 476 Derivative assets - FTRs — — 1 1 — — 3 3 Equity securities (2) 288 — — 288 297 — — 297 Foreign government debt securities — 24 — 24 — 23 — 23 U.S. government debt securities — 28 — 28 — 21 — 21 U.S. state debt securities — 245 — 245 — 247 — 247 Other (3) 248 30 — 278 588 38 — 626 Total assets $ 536 $ 795 $ 1 $ 1,332 $ 885 $ 805 $ 3 $ 1,693 Liabilities Derivative liabilities - commodity contracts $ — $ — $ — $ — $ — $ (4 ) $ — $ (4 ) Derivative liabilities - NUG contracts (1) — — (74 ) (74 ) — — (79 ) (79 ) Total liabilities $ — $ — $ (74 ) $ (74 ) $ — $ (4 ) $ (79 ) $ (83 ) Net assets (liabilities) (4) $ 536 $ 795 $ (73 ) $ 1,258 $ 885 $ 801 $ (76 ) $ 1,610 (1) NUG contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. (2) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. (3) Primarily consists of short-term cash investments. (4) Excludes $(15) million and $(11) million as of March 31, 2018 and December 31, 2017 , respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. |
Reconciliation of changes in the fair value roll forward of level 3 measurements of NUG contracts | The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended March 31, 2018 and December 31, 2017 : NUG Contracts (1) FTRs Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net (In millions) January 1, 2017 Balance $ 1 $ (108 ) $ (107 ) $ 3 $ (1 ) $ 2 Unrealized gain (loss) — (10 ) (10 ) 1 (1 ) — Purchases — — — 3 — 3 Settlements (1 ) 39 38 (4 ) 2 (2 ) December 31, 2017 Balance $ — $ (79 ) $ (79 ) $ 3 $ — $ 3 Unrealized gain (loss) — (2 ) (2 ) 1 — 1 Settlements — 7 7 (3 ) — (3 ) March 31, 2018 Balance $ — $ (74 ) $ (74 ) $ 1 $ — $ 1 (1) NUG contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. |
Quantitative information for level 3 valuation | The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2018 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ 1 Model RTO auction clearing prices $0.50 to $5.10 $1.20 Dollars/MWH NUG Contracts $ (74 ) Model Generation 400 to 1,881,000 382,000 MWH Regional electricity prices $29.10 to $30.90 $30.00 Dollars/MWH |
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities | The following table summarizes the amortized cost basis, unrealized gains, unrealized losses and fair values of investments held in NDT and nuclear fuel disposal trusts as of March 31, 2018 and December 31, 2017 : March 31, 2018 December 31, 2017 (1) Cost Basis Unrealized Gains Unrealized Losses Fair Value Cost Basis Unrealized Gains Unrealized Losses Fair Value (In millions) Debt securities $ 783 $ 5 $ (22 ) $ 766 $ 774 $ 11 $ (17 ) $ 768 Equity securities $ 263 $ 24 $ (2 ) $ 285 $ 254 $ 40 $ — $ 294 (1) Excludes short-term cash investments of $11 million . |
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income | Proceeds from the sale of investments in equity and AFS debt securities, realized gains and losses on those sales and interest and dividend income for the thre e months ended March 31, 2018 and 2017 were as follows: For the Three Months Ended March 31, 2018 2017 (In millions) Sale Proceeds $ 191 $ 507 Realized Gains 19 21 Realized Losses (16 ) (15 ) Interest and Dividend Income 10 9 |
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 FirstEnergy's long-term debt, which excludes capital lease obligations and net unamortized debt issuance costs, premiums and discounts as of March 31, 2018 and December 31, 2017: March 31, 2018 December 31, 2017 (In millions) Carrying Value $ 17,949 $ 19,425 Fair Value $ 19,487 $ 21,551 |
Commitments, Guarantees and C31
Commitments, Guarantees and Contingencies (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Guarantor Obligations | Potential Collateral Obligations AE Supply Utilities and FET FE Corp Total (In millions) Contractual Obligations for Additional Collateral At Current Credit Rating $ 1 $ — $ — $ 1 Upon Further Downgrade — 46 — 46 Surety Bonds (Collateralized Amount) 1 109 236 346 Total Exposure from Contractual Obligations $ 2 $ 155 $ 236 $ 393 |
Segment Information (Tables)
Segment Information (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Segment Reporting [Abstract] | |
Segment Financial Information | Segment Financial Information For the Three Months Ended Regulated Distribution Regulated Transmission Corporate/ Other Reconciling Adjustments Consolidated (In millions) March 31, 2018 Revenues $ 2,576 $ 323 $ 125 $ (48 ) $ 2,976 Depreciation 196 61 19 18 294 Amortization (deferral) of regulatory assets, net (152 ) 4 — — (148 ) Miscellaneous income 56 4 16 (9 ) 67 Interest expense 128 39 92 (9 ) 250 Income taxes 93 32 127 — 252 Income (loss) from continuing operations 322 99 (244 ) — 177 Total assets 27,504 9,681 1,255 355 38,795 Total goodwill 5,004 614 — — 5,618 Property additions 264 292 12 15 583 March 31, 2017 Revenues $ 2,500 $ 313 $ 92 $ (50 ) $ 2,855 Depreciation 178 51 4 17 250 Amortization of regulatory assets, net 81 2 — — 83 Miscellaneous income 15 — 6 (7 ) 14 Interest expense 138 39 75 (7 ) 245 Income taxes (benefits) 138 52 (38 ) — 152 Income (loss) from continuing operations 237 88 (68 ) — 257 Total assets 27,826 8,938 1,160 5,288 43,212 Total goodwill 5,004 614 — — 5,618 Property additions 264 224 10 90 588 |
Organization and Basis of Pre33
Organization and Basis of Presentation (Details Textuals) customer in Millions, $ in Millions | 3 Months Ended | |||
Mar. 31, 2018USD ($)customertransmission_centercompanymiMW | Mar. 31, 2017USD ($) | Jan. 01, 2018USD ($) | Dec. 31, 2017USD ($) | |
Property, Plant and Equipment [Line Items] | ||||
Length of transmission lines | mi | 24,500 | |||
Number of regional transmission centers | transmission_center | 2 | |||
Capitalized cost of equity | $ 11 | $ 8 | ||
Capitalized interest | $ 4 | 4 | ||
Accounting Standards Update 2018-02 | Retained Earnings | ||||
Property, Plant and Equipment [Line Items] | ||||
Cumulative effect of new accounting principle | $ 22 | |||
Regulated Distribution | ||||
Property, Plant and Equipment [Line Items] | ||||
Number of existing utility operating companies | company | 10 | |||
Number of customers served by utility operating companies | customer | 6 | |||
Plant capacity (in MW's) | MW | 3,790 | |||
FES | Accounting Standards Update 2016-01 | Retained Earnings | ||||
Property, Plant and Equipment [Line Items] | ||||
Cumulative effect of new accounting principle | $ 115 | |||
FES and FENOC | Accounting Standards Update 2018-02 | Retained Earnings | ||||
Property, Plant and Equipment [Line Items] | ||||
Cumulative effect of new accounting principle | $ 8 | |||
Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC | ||||
Property, Plant and Equipment [Line Items] | ||||
Gain on deconsolidation, net of tax | $ 1,239 | $ 0 | ||
Other Operating Expense | Accounting Standards Update 2017-07 | ||||
Property, Plant and Equipment [Line Items] | ||||
Effect of change on net income | (8) | |||
Miscellaneous Income | Accounting Standards Update 2017-07 | ||||
Property, Plant and Equipment [Line Items] | ||||
Effect of change on net income | $ 8 |
Revenue (Details)
Revenue (Details) $ in Millions | 3 Months Ended | ||
Mar. 31, 2018USD ($)companyMW | Mar. 31, 2017USD ($) | ||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | $ 2,892 | ||
ARP | 64 | ||
Other non-customer revenue | 20 | ||
Total revenues | [1] | 2,976 | $ 2,855 |
Regulated Transmission | 323 | 313 | |
Distribution services | Customer | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | 1,269 | ||
Retail generation | Customer | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | 1,026 | ||
Wholesale sales | Customer | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | 243 | ||
Transmission | Customer | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | 319 | ||
Other | Customer | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | 35 | ||
Derivative Revenue | Other Non-Customer Revenue | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues | 10 | ||
Regulated Distribution | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues | 2,321 | ||
Reduction in revenue | $ 72 | ||
Number of existing utility operating companies | company | 10 | ||
Megawatts of net demonstrated capacity of competitive segment | MW | 3,790 | ||
Utility customer payment period | 30 days | ||
Regulated Distribution | Residential | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues | $ 1,463 | ||
Regulated Distribution | Commercial | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues | 580 | ||
Regulated Distribution | Industrial | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues | 254 | ||
Regulated Distribution | Other | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues | 24 | ||
Regulated Transmission | |||
Disaggregation of Revenue [Line Items] | |||
Reduction in revenue | 4 | ||
Regulated Transmission | 323 | ||
Regulated Transmission | JCP&L | FERC | |||
Disaggregation of Revenue [Line Items] | |||
Annual revenue requirement | 155 | ||
Regulated Transmission | Other | |||
Disaggregation of Revenue [Line Items] | |||
Regulated Transmission | 71 | ||
Regulated Transmission | ATSI | |||
Disaggregation of Revenue [Line Items] | |||
Regulated Transmission | 159 | ||
Regulated Transmission | TrAIL | |||
Disaggregation of Revenue [Line Items] | |||
Regulated Transmission | 62 | ||
Regulated Transmission | MAIT | |||
Disaggregation of Revenue [Line Items] | |||
Regulated Transmission | 31 | ||
Operating Segments | Customer | |||
Disaggregation of Revenue [Line Items] | |||
Reduction in revenue | 76 | ||
Operating Segments | Regulated Distribution | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | 2,479 | ||
ARP | 64 | ||
Other non-customer revenue | 33 | ||
Total revenues | 2,576 | 2,500 | |
Operating Segments | Regulated Distribution | Distribution services | Customer | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | 1,281 | ||
Operating Segments | Regulated Distribution | Retail generation | Customer | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | 1,040 | ||
Operating Segments | Regulated Distribution | Wholesale sales | Customer | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | 123 | ||
Operating Segments | Regulated Distribution | Transmission | Customer | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | 0 | ||
Operating Segments | Regulated Distribution | Other | Customer | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | 35 | ||
Operating Segments | Regulated Transmission | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | 319 | ||
ARP | 0 | ||
Other non-customer revenue | 4 | ||
Total revenues | 323 | $ 313 | |
Operating Segments | Regulated Transmission | Distribution services | Customer | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | 0 | ||
Operating Segments | Regulated Transmission | Retail generation | Customer | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | 0 | ||
Operating Segments | Regulated Transmission | Wholesale sales | Customer | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | 0 | ||
Operating Segments | Regulated Transmission | Transmission | Customer | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | 319 | ||
Operating Segments | Regulated Transmission | Other | Customer | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | 0 | ||
Corporate/Other and Reconciling Adjustments | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | 94 | ||
ARP | 0 | ||
Other non-customer revenue | (17) | ||
Total revenues | 77 | ||
Corporate/Other and Reconciling Adjustments | Distribution services | Customer | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | (12) | ||
Corporate/Other and Reconciling Adjustments | Retail generation | Customer | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | (14) | ||
Corporate/Other and Reconciling Adjustments | Wholesale sales | Customer | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | 120 | ||
Corporate/Other and Reconciling Adjustments | Transmission | Customer | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | 0 | ||
Corporate/Other and Reconciling Adjustments | Other | Customer | |||
Disaggregation of Revenue [Line Items] | |||
Total revenues from contracts with customers | $ 0 | ||
[1] | Includes excise tax collections of $102 million and $100 million in the three months ended March 31, 2018 and 2017, respectively. |
Discontinued Operations - Narra
Discontinued Operations - Narrative (Details) $ in Millions | Apr. 06, 2018USD ($) | Mar. 09, 2018USD ($)MW | Dec. 13, 2017USD ($) | Aug. 31, 2017Natural_gas_plantMW | Mar. 31, 2018USD ($) | Jun. 30, 2018USD ($) | Dec. 31, 2017USD ($) | Aug. 30, 2017USD ($) |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||
Short-term borrowings | $ 1,200 | $ 300 | ||||||
Purchase Agreement with Subsidiary of LS Power | ||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||
Plant capacity (in MW's) | MW | 1,615 | |||||||
AE Supply | Purchase Agreement with Subsidiary of LS Power | ||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||
Number of gas generating plants | Natural_gas_plant | 4 | |||||||
Long-term debt and other long-term obligations | $ 305 | |||||||
Make-whole premiums | 90 | |||||||
AGC | Purchase Agreement with Subsidiary of LS Power | ||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||
Ownership percentage | 59.00% | |||||||
Natural Gas Generating Plants | Purchase Agreement with Subsidiary of LS Power | ||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||
Cash purchase price | $ 388 | |||||||
Bath County Hydro | Purchase Agreement with Subsidiary of LS Power | ||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||
Property, plant and equipment | 353 | |||||||
Materials and supplies inventory | 2 | |||||||
Bay Shore Unit 1 | Asset Purchase Agreement with Walleye Energy, LLC | ||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||
Plant capacity (in MW's) | MW | 136 | |||||||
Pre-tax impairment charges | $ 14 | |||||||
Scenario, Forecast | Bath County Hydroelectric Power Station and Buchanan Generating Facility | Purchase Agreement with Subsidiary of LS Power | ||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||
Cash purchase price | $ 20 | |||||||
Scenario, Forecast | Bath County Hydro | Purchase Agreement with Subsidiary of LS Power | ||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||
Cash purchase price | $ 355 | |||||||
Promissory Notes | FES and FENOC | ||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||
Outstanding borrowings | 102 | |||||||
Loan reserves | 102 | |||||||
PCRB | AE Supply | Purchase Agreement with Subsidiary of LS Power | ||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||
Long-term debt and other long-term obligations | 142 | |||||||
Senior Notes | AGC | Purchase Agreement with Subsidiary of LS Power | ||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||
Long-term debt and other long-term obligations | $ 100 | |||||||
Revolving Credit Facility | Line of Credit | FES | ||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||
Line of credit outstanding | $ 500 | 500 | ||||||
Loan reserves | 500 | |||||||
Money Pool | FES and FENOC | ||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||
Short-term borrowings | 4 | |||||||
Loan reserves | 4 | |||||||
Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC | ||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||
Investments in subsidiaries | 0 | |||||||
Assumption of benefit obligations retained at FE (including Pension, OPEB and EDCP) | 820 | |||||||
Tax consequence of outside basis difference | 628 | |||||||
Discontinued Operations, Disposed of by Means Other than Sale | Subsequent Event | FES and FENOC | ||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||
Settlement payments | $ 72 | |||||||
Other Current Liabilities | Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC | ||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||
Indemnification obligation | 58 | |||||||
Power Purchase Agreements | Affiliated Companies | Discontinued Operations, Disposed of by Means Other than Sale | FES | FES and FENOC | ||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||
Due from related parties | 46 | |||||||
Tax Allocation Agreement | Affiliated Companies | Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC | ||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||
Due to related parties | $ 94 |
Discontinued Operations - Summa
Discontinued Operations - Summarized Results of Discontinued Operations (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Income tax expense (benefit) | $ (890) | $ (26) |
Loss from discontinued operations, net of tax | 1,239 | 0 |
Income (loss) from discontinued operations | 1,192 | (52) |
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 | 622 | 689 |
Fuel | (116) | (164) |
Purchased power | (53) | (49) |
Other operating expenses | (347) | (492) |
Provision for depreciation | (46) | (25) |
General taxes | (18) | (29) |
Other Income (Expense) | (60) | (8) |
Loss from discontinued operations, before tax | (18) | (78) |
Income tax expense (benefit) | 29 | (26) |
Loss from discontinued operations, net of tax | (47) | (52) |
Gain on deconsolidation, net of tax | 1,239 | 0 |
Income (loss) from discontinued operations | $ 1,192 | $ (52) |
Discontinued Operations - Gain
Discontinued Operations - Gain on Deconsolidation (Details) - FES and FENOC - Discontinued Operations, Disposed of by Means Other than Sale - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Removal of investment in FES and FENOC | $ 2,193 | |
Assumption of benefit obligations retained at FE (including Pension, OPEB and EDCP) | (820) | |
Guarantees and credit support provided by FE | (139) | |
Reserve on receivables and allocated Pension/OPEB mark-to-market | (914) | |
Gain on deconsolidation of FES and FENOC, before tax | 320 | |
Income tax benefit including estimated worthless stock deduction | 919 | |
Gain on deconsolidation of FES and FENOC | $ 1,239 | $ 0 |
Discontinued Operations - Major
Discontinued Operations - Major Classes of Assets and Liabilities as Discontinued Operations (Details) - USD ($) $ in Millions | Mar. 31, 2018 | Dec. 31, 2017 |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Total current assets | $ 2 | $ 606 |
Property, plant and equipment | 353 | 1,057 |
Total current liabilities | 0 | 973 |
Total noncurrent liabilities | 0 | 3,399 |
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] | ||
Cash | 0 | 1 |
Restricted cash | 0 | 3 |
Receivables | 0 | 202 |
Materials and supplies | 2 | 201 |
Collateral | 0 | 130 |
Other current assets | 0 | 69 |
Total current assets | 2 | 606 |
Property, plant and equipment | 353 | 1,057 |
Investments | 0 | 1,875 |
Other non-current assets | 0 | 356 |
Total non-current assets | 353 | 3,288 |
Total assets included in discontinued operations | 355 | 3,894 |
Currently payable long-term debt | 0 | 524 |
Accounts payable | 0 | 200 |
Accrued taxes | 0 | 38 |
Accrued compensation and benefits | 0 | 79 |
Other current liabilities | 0 | 132 |
Total current liabilities | 0 | 973 |
Long-term debt and other long-term obligations | 0 | 2,299 |
Accumulated deferred income taxes | 0 | (1,812) |
Asset retirement obligations | 0 | 1,945 |
Deferred gain on sale and leaseback transaction | 0 | 723 |
Other non-current liabilities | 0 | 244 |
Total noncurrent liabilities | 0 | 3,399 |
Total liabilities included in discontinued operations | $ 0 | $ 4,372 |
Discontinued Operations - Maj39
Discontinued Operations - Major Classes of Cash Flow Items from Discontinued Operations (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | ||
Income (loss) from discontinued operations | $ 1,192 | $ (52) |
Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs | 280 | 416 |
Unrealized (gain) loss on derivative transactions | (10) | 47 |
CASH FLOWS FROM INVESTING ACTIVITIES: | ||
Property additions | (583) | (588) |
Nuclear fuel | 0 | (132) |
Sales of investment securities held in trusts | 300 | 738 |
Purchases of investment securities held in trusts | (322) | (761) |
FES and FENOC | Discontinued Operations, Disposed of by Means Other than Sale | ||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||
Income (loss) from discontinued operations | 1,192 | (52) |
Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs | 47 | 79 |
Unrealized (gain) loss on derivative transactions | (10) | 47 |
CASH FLOWS FROM INVESTING ACTIVITIES: | ||
Property additions | (15) | (90) |
Nuclear fuel | 0 | (132) |
Sales of investment securities held in trusts | 109 | 231 |
Purchases of investment securities held in trusts | $ (122) | $ (245) |
Earnings Per Share Of Common 40
Earnings Per Share Of Common Stock (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | Jan. 31, 2018 | Mar. 31, 2018 | Mar. 31, 2017 |
Earnings Per Share [Abstract] | |||
Amount of beneficial conversion | $ 296 | $ 296 | $ 0 |
Earnings Per Share of Common Stock | |||
Income from continuing operations | 177 | 257 | |
Less: Preferred dividends | (43) | 0 | |
Less: Amortization of beneficial conversion feature | (113) | 0 | |
Less: Undistributed earnings allocated to preferred shareholders | 0 | 0 | |
Income from continuing operations available to common stockholders | 21 | 257 | |
Discontinued operations, net of tax | 1,192 | (52) | |
Less: Undistributed earnings allocated to preferred shareholders | 0 | 0 | |
Income (loss) from discontinued operations available to common stockholders | 1,192 | (52) | |
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS | $ 1,213 | $ 205 | |
Share Count information: | |||
Weighted average number of basic shares outstanding (in shares) | 476 | 443 | |
Assumed exercise of dilutive stock options and awards (in shares) | 2 | 1 | |
Assumed conversion of preferred stock (in shares) | 0 | 0 | |
Weighted average number of diluted shares outstanding | 478 | 444 | |
Income available to common stockholders, per common share: | |||
Income from continuing operations, basic (in dollars per share) | $ 0.04 | $ 0.58 | |
Discontinued operations, basic (in dollars per share) | 2.51 | (0.12) | |
Basic - Net Income Attributable to Common Stockholders (in dollars per share) | 2.55 | 0.46 | |
Income from continuing operations, diluted (in dollars per share) | 0.04 | 0.58 | |
Discontinued operations, diluted (in dollars per share) | 2.50 | (0.12) | |
Diluted - Net Income Attributable to Common Stockholders (in dollars per share) | $ 2.54 | $ 0.46 | |
Stock Options | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Shares excluded from the calculation of diluted shares outstanding, in shares | 1 | 1 | |
Preferred Stock | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Shares excluded from the calculation of diluted shares outstanding, in shares | 59 |
Pension and Other Postemploym41
Pension and Other Postemployment Benefits (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | |
Jan. 31, 2018 | Mar. 31, 2018 | Mar. 31, 2017 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Additional funding contributions | $ 750 | ||
Pension | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Service costs | $ 56 | $ 52 | |
Interest costs | 93 | 97 | |
Expected return on plan assets | (144) | (112) | |
Amortization of prior service costs (credits) | 2 | 2 | |
Net periodic costs (credits) | 7 | 39 | |
Pension | FES and FENOC | Discontinued Operations, Disposed of by Means Other than Sale | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Net periodic costs (credits) | 13 | 16 | |
OPEB | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Service costs | 1 | 1 | |
Interest costs | 6 | 7 | |
Expected return on plan assets | (8) | (8) | |
Amortization of prior service costs (credits) | (20) | (20) | |
Net periodic costs (credits) | (21) | (20) | |
OPEB | FES and FENOC | Discontinued Operations, Disposed of by Means Other than Sale | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Net periodic costs (credits) | (10) | (8) | |
FirstEnergy | Pension | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Net periodic benefit expense (credit) | (14) | 32 | |
FirstEnergy | OPEB | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Net periodic benefit expense (credit) | $ (21) | $ (15) | |
Minimum | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Contributions by employer | $ 500 |
Accumulated Other Comprehensi42
Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ||
AOCI Beginning Balance | $ 142 | $ 174 |
Other comprehensive income before reclassifications | (97) | 32 |
Amounts reclassified from AOCI | (17) | (31) |
Deconsolidation of FES and FENOC | 5 | |
Other comprehensive income (loss) | (109) | 1 |
Income taxes (benefits) on other comprehensive income (loss) | (53) | 0 |
Other comprehensive income (loss), net of tax | (56) | 1 |
AOCI Ending Balance | 86 | 175 |
Gains & Losses on Cash Flow Hedges | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ||
AOCI Beginning Balance | (22) | (28) |
Other comprehensive income before reclassifications | 0 | 0 |
Amounts reclassified from AOCI | 2 | 3 |
Deconsolidation of FES and FENOC | 13 | |
Other comprehensive income (loss) | 15 | 3 |
Income taxes (benefits) on other comprehensive income (loss) | 8 | 1 |
Other comprehensive income (loss), net of tax | 7 | 2 |
AOCI Ending Balance | (15) | (26) |
Unrealized Gains on AFS Securities | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ||
AOCI Beginning Balance | 67 | 52 |
Other comprehensive income before reclassifications | (97) | 32 |
Amounts reclassified from AOCI | (1) | (16) |
Deconsolidation of FES and FENOC | (8) | |
Other comprehensive income (loss) | (106) | 16 |
Income taxes (benefits) on other comprehensive income (loss) | (39) | 5 |
Other comprehensive income (loss), net of tax | (67) | 11 |
AOCI Ending Balance | 0 | 63 |
Defined Benefit Pension & OPEB Plans | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ||
AOCI Beginning Balance | 97 | 150 |
Other comprehensive income before reclassifications | 0 | 0 |
Amounts reclassified from AOCI | (18) | (18) |
Deconsolidation of FES and FENOC | 0 | |
Other comprehensive income (loss) | (18) | (18) |
Income taxes (benefits) on other comprehensive income (loss) | (22) | (6) |
Other comprehensive income (loss), net of tax | 4 | (12) |
AOCI Ending Balance | $ 101 | $ 138 |
Accumulated Other Comprehensi43
Accumulated Other Comprehensive Income (Details 1) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | ||
Interest expense | $ 250 | $ 245 |
Income taxes | (252) | (152) |
Prior-service costs | (962) | (657) |
NET INCOME | 1,369 | 205 |
Reclassifications from AOCI | Gains & losses on cash flow hedges | ||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | ||
Income taxes | (1) | (1) |
Net of tax | 1 | 2 |
Reclassifications from AOCI | Gains & losses on cash flow hedges | Long-term debt | ||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | ||
Interest expense | (2) | (3) |
Reclassifications from AOCI | Unrealized gains on AFS securities | ||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | ||
Net of tax | (1) | (10) |
Reclassifications from AOCI | Net prior service costs | ||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | ||
Income taxes | 5 | 6 |
Prior-service costs | (18) | (18) |
NET INCOME | $ (13) | $ (12) |
Income Taxes (Details)
Income Taxes (Details) - USD ($) | 1 Months Ended | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2018 | Mar. 31, 2017 | |
Income Taxes (Textuals) [Abstract] | |||
Effective tax rate (percent) | 58.70% | 37.20% | |
Unrecognized tax benefits from lapse of statute of limitations | $ 2,000,000 | ||
Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC | |||
Income Taxes (Textuals) [Abstract] | |||
Increase in unrecognized tax benefits | $ 49,000,000 | ||
State and Local Jurisdiction | West Virginia | |||
Income Taxes (Textuals) [Abstract] | |||
Re-measurement in state deferred taxes | 126,000,000 | ||
State and Local Jurisdiction | Pennsylvania | |||
Income Taxes (Textuals) [Abstract] | |||
Decrease resulting from settlements with taxing authorities | 45,000,000 | ||
Unrecognized tax benefits that would impact effective tax rate | $ 0 | $ 0 |
Variable Interest Entities (Det
Variable Interest Entities (Details Textuals) | 3 Months Ended | ||
Mar. 31, 2018USD ($)agreemententity | Mar. 31, 2017USD ($) | Dec. 31, 2017USD ($) | |
Variable Interest Entities (Textuals) [Abstract] | |||
Long-term transition bond | $ 52,000,000 | $ 56,000,000 | |
Long-term pollution control bond | 371,000,000 | 383,000,000 | |
Guarantor obligations | $ 393,000,000 | ||
Number of contracts that may contain variable interest | entity | 1 | ||
Purchased power | $ 825,000,000 | $ 791,000,000 | |
Power Purchase Agreements | |||
Variable Interest Entities (Textuals) [Abstract] | |||
Ownership interest | 0.00% | ||
Number of long-term power purchase agreements maintained by FirstEnergy with NUG entities | agreement | 12 | ||
Phase In Recovery Bonds | |||
Variable Interest Entities (Textuals) [Abstract] | |||
Long-term debt and other long-term obligations | $ 304,000,000 | $ 315,000,000 | |
Ohio Funding Companies | |||
Variable Interest Entities (Textuals) [Abstract] | |||
Annual servicing fees | 445,000 | ||
Other FE subsidiaries | Power Purchase Agreements | |||
Variable Interest Entities (Textuals) [Abstract] | |||
Purchased power | $ 32,000,000 | $ 28,000,000 | |
Path-WV | |||
Variable Interest Entities (Textuals) [Abstract] | |||
Percentage of high-voltage transmission line project owned by subsidiary of FE on the Allegheny Series | 100.00% | ||
Percentage of high-voltage transmission line project owned by subsidiary of FE on the West Virginia Series | 50.00% | ||
Equity method investments | $ 17,000,000 | ||
Global Holding | Guarantee of senior secured loan facility | |||
Variable Interest Entities (Textuals) [Abstract] | |||
Guarantor obligations | $ 255,000,000 | ||
Signal Peak | Global Holding | FEV | |||
Variable Interest Entities (Textuals) [Abstract] | |||
Ownership interest | 33.33% |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - Recurring - USD ($) $ in Millions | Mar. 31, 2018 | Dec. 31, 2017 |
Assets | ||
Fair value, assets | $ 1,332 | $ 1,693 |
Liabilities | ||
Fair value, liabilities | (74) | (83) |
Net assets (liabilities) | 1,258 | 1,610 |
Commodity contracts | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | 0 | (4) |
NUG contracts | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | (74) | (79) |
Corporate debt securities | ||
Assets | ||
Fair value, assets | 468 | 476 |
FTRs | Derivative Assets | ||
Assets | ||
Fair value, assets | 1 | 3 |
Equity securities | ||
Assets | ||
Fair value, assets | 288 | 297 |
Foreign government debt securities | ||
Assets | ||
Fair value, assets | 24 | 23 |
U.S. government debt securities | ||
Assets | ||
Fair value, assets | 28 | 21 |
U.S. state debt securities | ||
Assets | ||
Fair value, assets | 245 | 247 |
Other | ||
Assets | ||
Fair value, assets | 278 | 626 |
Level 1 | ||
Assets | ||
Fair value, assets | 536 | 885 |
Liabilities | ||
Fair value, liabilities | 0 | 0 |
Net assets (liabilities) | 536 | 885 |
Level 1 | Commodity contracts | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | 0 | 0 |
Level 1 | NUG contracts | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | 0 | 0 |
Level 1 | Corporate debt securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 1 | FTRs | Derivative Assets | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 1 | Equity securities | ||
Assets | ||
Fair value, assets | 288 | 297 |
Level 1 | Foreign government debt securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 1 | U.S. government debt securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 1 | U.S. state debt securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 1 | Other | ||
Assets | ||
Fair value, assets | 248 | 588 |
Level 2 | ||
Assets | ||
Fair value, assets | 795 | 805 |
Liabilities | ||
Fair value, liabilities | 0 | (4) |
Net assets (liabilities) | 795 | 801 |
Level 2 | Commodity contracts | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | 0 | (4) |
Level 2 | NUG contracts | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | 0 | 0 |
Level 2 | Corporate debt securities | ||
Assets | ||
Fair value, assets | 468 | 476 |
Level 2 | FTRs | Derivative Assets | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 2 | Equity securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 2 | Foreign government debt securities | ||
Assets | ||
Fair value, assets | 24 | 23 |
Level 2 | U.S. government debt securities | ||
Assets | ||
Fair value, assets | 28 | 21 |
Level 2 | U.S. state debt securities | ||
Assets | ||
Fair value, assets | 245 | 247 |
Level 2 | Other | ||
Assets | ||
Fair value, assets | 30 | 38 |
Level 3 | ||
Assets | ||
Fair value, assets | 1 | 3 |
Liabilities | ||
Fair value, liabilities | (74) | (79) |
Net assets (liabilities) | (73) | (76) |
Level 3 | Commodity contracts | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | 0 | 0 |
Level 3 | NUG contracts | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | (74) | (79) |
Level 3 | Corporate debt securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 3 | FTRs | Derivative Assets | ||
Assets | ||
Fair value, assets | 1 | 3 |
Level 3 | Equity securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 3 | Foreign government debt securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 3 | U.S. government debt securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 3 | U.S. state debt securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 3 | Other | ||
Assets | ||
Fair value, assets | $ 0 | $ 0 |
Fair Value Measurements (Deta47
Fair Value Measurements (Details 1) - Level 3 - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended |
Mar. 31, 2018 | Dec. 31, 2017 | |
NUG contracts | ||
Reconciliation of changes in the fair value of FTRs contracts | ||
Beginning Balance, Derivative Assets | $ 0 | $ 1 |
Beginning Balance, Derivative Liabilities | (79) | (108) |
Beginning Balance, Net | (79) | (107) |
Unrealized gain (loss), Derivative Assets | 0 | 0 |
Unrealized loss, Derivative Liabilities | (2) | (10) |
Unrealized loss, Net | (2) | (10) |
Purchases, Derivative Assets | 0 | |
Purchases, Derivative Liabilities | 0 | |
Purchases, Net | 0 | |
Settlements, Derivative Assets | 0 | (1) |
Settlements, Derivative Liabilities | 7 | 39 |
Settlements, Net | 7 | 38 |
Ending Balance, Derivative Assets | 0 | 0 |
Ending Balance, Derivative Liabilities | (74) | (79) |
Ending Balance, Net | (74) | (79) |
FTRs | ||
Reconciliation of changes in the fair value of FTRs contracts | ||
Beginning Balance, Derivative Assets | 3 | 3 |
Beginning Balance, Derivative Liabilities | 0 | (1) |
Beginning Balance, Net | 3 | 2 |
Unrealized gain (loss), Derivative Assets | 1 | 1 |
Unrealized loss, Derivative Liabilities | 0 | (1) |
Unrealized loss, Net | 1 | 0 |
Purchases, Derivative Assets | 3 | |
Purchases, Derivative Liabilities | 0 | |
Purchases, Net | 3 | |
Settlements, Derivative Assets | (3) | (4) |
Settlements, Derivative Liabilities | 0 | 2 |
Settlements, Net | (3) | (2) |
Ending Balance, Derivative Assets | 1 | 3 |
Ending Balance, Derivative Liabilities | 0 | 0 |
Ending Balance, Net | $ 1 | $ 3 |
Fair Value Measurements (Deta48
Fair Value Measurements (Details 2) - Level 3 $ in Millions | 3 Months Ended | ||
Mar. 31, 2018USD ($)MWh$ / MWh | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
FTRs | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value | $ | $ 1 | $ 3 | $ 2 |
NUG contracts | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value | $ | (74) | $ (79) | $ (107) |
Model | FTRs | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value | $ | 1 | ||
Model | NUG contracts | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value | $ | $ (74) | ||
Model | Minimum | FTRs | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH) | 0.50 | ||
Model | Minimum | NUG contracts | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value Inputs, Power (in MWH) | MWh | 400 | ||
Fair Value Inputs, Power, Regional Prices (in $/MWH) | 29.10 | ||
Model | Maximum | FTRs | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH) | 5.10 | ||
Model | Maximum | NUG contracts | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value Inputs, Power (in MWH) | MWh | 1,881,000 | ||
Fair Value Inputs, Power, Regional Prices (in $/MWH) | 30.90 | ||
Model | Weighted Average | FTRs | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH) | 1.20 | ||
Model | Weighted Average | NUG contracts | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value Inputs, Power (in MWH) | MWh | 382,000 | ||
Fair Value Inputs, Power, Regional Prices (in $/MWH) | 30 |
Fair Value Measurements (Deta49
Fair Value Measurements (Details 3) - USD ($) $ in Millions | Mar. 31, 2018 | Dec. 31, 2017 |
Debt securities | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Cost Basis | $ 783 | $ 774 |
Unrealized Gain | 5 | 11 |
Unrealized Losses | (22) | (17) |
Fair Value | 766 | 768 |
Equity securities | ||
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities | ||
Cost Basis | 263 | 254 |
Unrealized Gains | 24 | 40 |
Unrealized Losses | (2) | 0 |
Fair Value | $ 285 | $ 294 |
Fair Value Measurements (Deta50
Fair Value Measurements (Details 4) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income | ||
Sales Proceeds | $ 191 | $ 507 |
Realized Gains | 19 | 21 |
Realized Losses | (16) | (15) |
Interest and Dividend Income | $ 10 | $ 9 |
Fair Value Measurements (Deta51
Fair Value Measurements (Details 5) - USD ($) $ in Millions | Mar. 31, 2018 | Dec. 31, 2017 |
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 | $ 17,949 | $ 19,425 |
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 | $ 19,487 | $ 21,551 |
Fair Value Measurements (Deta52
Fair Value Measurements (Details Textuals) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2018 | Dec. 31, 2017 | |
Fair Value of Financial Instruments [Line Items] | ||
Investment excludes receivables, payables and accrued income | $ (15) | $ (11) |
Cash balance excluded from available for sale securities | 11 | |
Investments not required to be disclosed | $ 252 | $ 255 |
NUG contracts | ||
Fair Value of Financial Instruments [Line Items] | ||
Period of future observable data to determine contract price | 2 years |
Derivative Instruments (Details
Derivative Instruments (Details Textuals) $ in Millions | 3 Months Ended | |
Mar. 31, 2018USD ($)agreement | Dec. 31, 2017USD ($)agreement | |
Cash Flow Hedges | ||
Derivative [Line Items] | ||
Unamortized losses associated with prior interest rate hedges | $ 20 | $ 22 |
Gains (losses) to be amortized to interest expenses during next twelve months | $ (6) | |
Number of outstanding commodity or interest rate derivatives | agreement | 0 | 0 |
Fair Value Hedging | ||
Derivative [Line Items] | ||
Number of fixed-for-floating interest rate swap agreements outstanding | agreement | 0 | |
Gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements | $ 3 | $ 3 |
NUGs | ||
Derivative [Line Items] | ||
Liability position | 74 | $ 79 |
Settlements | 7 | |
Unrealized gain (loss) | $ (2) |
Capitalization (Details)
Capitalization (Details) | Jan. 22, 2018USD ($)employee$ / sharesshares | Mar. 31, 2018$ / sharesshares | Dec. 31, 2017$ / shares |
Class of Stock [Line Items] | |||
Proceeds from issuance of equity | $ 2,500,000,000 | ||
Par Value, in dollars per share | $ / shares | $ 100 | ||
Amount of private placement shares | shares | 30,120,482 | ||
Common stock, par value (in dollars per share) | $ / shares | $ 0.10 | $ 0.1 | $ 0.1 |
Amount of private placement | $ 850,000,000 | ||
Liquidation preference value | $ 1,000 | ||
Conversion price (in dollars per share) | $ / shares | $ 27.42 | ||
Conversion threshold of Preferred Stock (in shares) | shares | 323,200 | ||
Common stock share cap (in shares) | shares | 58,964,222 | ||
RWG number of board members | employee | 2 | ||
Other Paid-in Capital | |||
Class of Stock [Line Items] | |||
Amount of private placement | $ 847,000,000 | ||
Common Stock | |||
Class of Stock [Line Items] | |||
Amount of private placement | $ 3,000,000 | ||
Series A Convertible Preferred Stock | |||
Class of Stock [Line Items] | |||
Preferred stock shares issued | shares | 1,616,000 | 1,616,000 | |
Par Value, in dollars per share | $ / shares | $ 100 | ||
Amount of preferred stock investment | $ 1,620,000,000 | ||
Series A Convertible Preferred Stock | Preferred Stock | |||
Class of Stock [Line Items] | |||
Amount of preferred stock investment | 162,000,000 | ||
Series A Convertible Preferred Stock | Other Paid-in Capital | |||
Class of Stock [Line Items] | |||
Amount of preferred stock investment | $ 1,460,000,000 | ||
FE | |||
Class of Stock [Line Items] | |||
RWG number of board members | employee | 3 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Millions | Mar. 31, 2018 | Dec. 31, 2017 |
Asset Retirement Obligation [Abstract] | ||
Asset retirement obligation | $ 580 | $ 570 |
Regulatory Matters - Maryland a
Regulatory Matters - Maryland and New Jersey (Details) $ in Millions | Mar. 26, 2018USD ($) | Jan. 19, 2018USD ($)rebate | Dec. 12, 2016USD ($) | Jul. 16, 2015 | Feb. 27, 2013USD ($) | Mar. 31, 2018component | Dec. 31, 2020USD ($) | Dec. 31, 2017USD ($) | Feb. 15, 2018USD ($) |
Maryland | |||||||||
Regulatory Matters [Line Items] | |||||||||
Expected infrastructure investments | $ 2,700 | ||||||||
Period of expected infrastructure investments | 15 years | ||||||||
New Jersey | |||||||||
Regulatory Matters [Line Items] | |||||||||
Number of supply components | component | 2,000,000 | ||||||||
PE | Maryland | |||||||||
Regulatory Matters [Line Items] | |||||||||
Recovery period for expenditures for cost recovery program | 3 years | ||||||||
Incremental energy savings goal in the next 12 months (percent) | 0.97% | ||||||||
Incremental energy savings goal per year (percent) | 0.00% | ||||||||
Incremental energy savings goal thereafter (percent) | 2.00% | ||||||||
Expenditures for cost recovery program incurred | $ 60 | ||||||||
Amortization period | 5 years | ||||||||
PE | MPSC | |||||||||
Regulatory Matters [Line Items] | |||||||||
Number of residential charging equipment rebates | rebate | 2,000 | ||||||||
Number of commercial charging equipment rebates | rebate | 259 | ||||||||
Cost of charging equipment rebates | $ 12 | ||||||||
Charging equipment rebates amortization period | 5 years | ||||||||
JCP&L | NJBPU | New Jersey | |||||||||
Regulatory Matters [Line Items] | |||||||||
Approved amount of annual increase (decrease) | $ (28.6) | $ 80 | |||||||
Approved rider due to change in tax rate | $ 1.3 | ||||||||
Scenario, Forecast | PE | Maryland | |||||||||
Regulatory Matters [Line Items] | |||||||||
Recovery period for expenditures for cost recovery program | 3 years | ||||||||
Expenditures for cost recovery program | $ 116 | ||||||||
Minimum | PE | MPSC | Maryland | |||||||||
Regulatory Matters [Line Items] | |||||||||
Impact on base rate | $ 7 | ||||||||
Maximum | PE | MPSC | Maryland | |||||||||
Regulatory Matters [Line Items] | |||||||||
Impact on base rate | $ 8 |
Regulatory Matters - Ohio (Deta
Regulatory Matters - Ohio (Details) $ in Millions | Mar. 12, 2018 | Dec. 01, 2017USD ($) | Oct. 12, 2016USD ($) | Apr. 15, 2016 | Aug. 07, 2013USD ($)auction | Mar. 31, 2018USD ($) | Feb. 15, 2018USD ($) |
Regulatory Matters [Line Items] | |||||||
Proposed goal to reduce CO2 pollution (percent) | 90.00% | ||||||
Ohio | |||||||
Regulatory Matters [Line Items] | |||||||
Energy efficient portfolio plan term | 3 years | ||||||
Estimated cost of plans | $ 268 | ||||||
Credit to non-shopping customers | $ 43.4 | ||||||
Ohio | PUCO | |||||||
Regulatory Matters [Line Items] | |||||||
Proposed goal to reduce CO2 pollution (percent) | 90.00% | ||||||
Requested removal of cost cap | 4.00% | ||||||
Number of renewable energy auctions | auction | 1 | ||||||
Ohio | Distribution Modernization Rider | |||||||
Regulatory Matters [Line Items] | |||||||
Amount of rider valuation | $ 558 | ||||||
Period of rider valuation | 8 years | ||||||
Ohio | Distribution Modernization Rider | PUCO | |||||||
Regulatory Matters [Line Items] | |||||||
Annual revenue cap for rider | $ 132.5 | ||||||
Recovery period | 3 years | ||||||
Possible extension period | 2 years | ||||||
Approved amount for rider | $ 168 | ||||||
Excessive earnings test exclusion period | 3 years | ||||||
Renewal period for excessive earnings test exclusion period | 2 years | ||||||
Ohio | Delivery Capital Recovery Rider | PUCO | |||||||
Regulatory Matters [Line Items] | |||||||
Annual revenue cap for rider | $ 30 | ||||||
Annual revenue cap for rider for years three through six | 20 | ||||||
Annual revenue cap for rider for years six through eight | 15 | ||||||
Ohio | Distribution Platform Modernization Plan | PUCO | |||||||
Regulatory Matters [Line Items] | |||||||
Amount of requested rate increase (decrease) | $ 450 | ||||||
Ohio | Energy Conservation, Economic Development and Job Retention | PUCO | |||||||
Regulatory Matters [Line Items] | |||||||
Contribution amount | $ 51 | ||||||
The Ohio Companies | Ohio | PUCO | |||||||
Regulatory Matters [Line Items] | |||||||
Impact on base rate | $ 40 |
Regulatory Matters - Pennsylvan
Regulatory Matters - Pennsylvania and West Virginia (Details) $ in Millions | Mar. 09, 2018USD ($) | Sep. 01, 2017USD ($) | Jun. 14, 2017USD ($) | Jan. 19, 2017USD ($) | Dec. 09, 2016USD ($) | Jun. 19, 2015 | Mar. 31, 2016USD ($) | Mar. 31, 2018proposal | Dec. 31, 2019USD ($) | Dec. 31, 2017USD ($) | Mar. 06, 2017USD ($)MW | Sep. 23, 2016program |
Pennsylvania | DSP June 2017- May 2019 | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Number of RFP's | proposal | 1 | |||||||||||
RFP term | 2 years | |||||||||||
Pennsylvania | DSP June 2019- May 2023 | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Number of RFP's | proposal | 2 | |||||||||||
RFP term | 2 years | |||||||||||
Pennsylvania | Three Month Period | DSP June 2019- May 2023 | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Term of energy contract | 3 months | |||||||||||
Pennsylvania | Twelve month period | DSP June 2017- May 2019 | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Term of energy contract | 12 months | |||||||||||
Pennsylvania | Twelve month period | DSP June 2019- May 2023 | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Term of energy contract | 12 months | |||||||||||
Pennsylvania | Twenty-four month period | DSP June 2017- May 2019 | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Term of energy contract | 24 months | |||||||||||
Pennsylvania | Twenty-four month period | DSP June 2019- May 2023 | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Term of energy contract | 24 months | |||||||||||
Pennsylvania | Pennsylvania Companies | PPUC | EE&C Phase III | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Approved amount of annual increase | $ 390 | |||||||||||
Pennsylvania | ME | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Approved amount of annual increase | $ 96 | |||||||||||
Pennsylvania | ME | PPUC | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Demand reduction targets proposed | 1.80% | |||||||||||
Energy consumption reduction targets proposed | 4.00% | |||||||||||
Amount of requested rate increase (decrease) | $ (51.3) | |||||||||||
Net annual effect on rates | $ 37 | |||||||||||
Pennsylvania | Penn | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Approved amount of annual increase | 29 | |||||||||||
Pennsylvania | Penn | PPUC | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Demand reduction targets proposed | 1.70% | |||||||||||
Energy consumption reduction targets proposed | 3.30% | |||||||||||
Amount of requested rate increase (decrease) | (33.2) | |||||||||||
Net annual effect on rates | 9 | |||||||||||
Pennsylvania | WP | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Approved amount of annual increase | 66 | |||||||||||
Pennsylvania | WP | PPUC | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Demand reduction targets proposed | 1.80% | |||||||||||
Energy consumption reduction targets proposed | 2.60% | |||||||||||
Amount of requested rate increase (decrease) | (50.1) | |||||||||||
Net annual effect on rates | 30 | |||||||||||
Pennsylvania | PN | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Approved amount of annual increase | $ 100 | |||||||||||
Pennsylvania | PN | PPUC | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Demand reduction targets proposed | 0.00% | |||||||||||
Energy consumption reduction targets proposed | 3.90% | |||||||||||
Amount of requested rate increase (decrease) | $ (44.8) | |||||||||||
Net annual effect on rates | $ 40 | |||||||||||
West Virginia | WVPSC | VMP Surcharge Rates | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Amount of requested rate increase (decrease) | $ (15) | |||||||||||
Requested rate decrease | 1.00% | |||||||||||
West Virginia | MP and PE | WVPSC | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Number of proposed efficient programs | program | 3 | |||||||||||
Energy efficient reduction requirement (percent) | 0.50% | |||||||||||
Expenditures for cost recovery program | $ 10.4 | |||||||||||
West Virginia | MP and PE | WVPSC | ENEC | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Amount of requested rate increase (decrease) | $ (25) | |||||||||||
Rate stabilization period | 2 years | |||||||||||
Scenario, Forecast | West Virginia | WVPSC | VMP Surcharge Rates | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Amount of additional requested rate increase (decrease) | $ 15 | |||||||||||
Pleasants Power Station | ||||||||||||
Regulatory Matters [Line Items] | ||||||||||||
Plant capacity (in MW's) | MW | 1,300 | |||||||||||
Consideration transferred | $ 195 |
Regulatory Matters - Reliabilit
Regulatory Matters - Reliability Matters and FERC (Details) - FERC $ in Millions | Dec. 21, 2017USD ($) | Oct. 13, 2017 | Mar. 10, 2017 | Feb. 20, 2017 | Jan. 19, 2017 | Jun. 15, 2016kv | Aug. 04, 2014 | Aug. 24, 2012USD ($) | Mar. 31, 2018USD ($) | Sep. 30, 2017USD ($) | Apr. 10, 2018condition |
Regulatory Matters [Line Items] | |||||||||||
Power threshold | kv | 500 | ||||||||||
Denied recovery charges of exit fees | $ 78.8 | ||||||||||
Subsequent Event | |||||||||||
Regulatory Matters [Line Items] | |||||||||||
Number of alternative proposals filed | condition | 2 | ||||||||||
PATH-Allegheny | |||||||||||
Regulatory Matters [Line Items] | |||||||||||
Cost recovery, PP&E reclassified to Regulatory Assets | $ 62 | ||||||||||
Path-WV | |||||||||||
Regulatory Matters [Line Items] | |||||||||||
Cost recovery, PP&E reclassified to Regulatory Assets | $ 59 | ||||||||||
PATH | |||||||||||
Regulatory Matters [Line Items] | |||||||||||
Proposed return on equity | 10.90% | ||||||||||
Base return on equity | 10.40% | 8.11% | 10.40% | ||||||||
Return on equity granted for regional transmission organization participation | 0.50% | ||||||||||
Remaining recovery period of regulatory assets | 5 years | ||||||||||
The Ohio Companies | ESP IV PPA | |||||||||||
Regulatory Matters [Line Items] | |||||||||||
Term of proposed purchase power agreement | 8 years | ||||||||||
MAIT | |||||||||||
Regulatory Matters [Line Items] | |||||||||||
Approved suspension period | 5 months | ||||||||||
Approved ROE | 10.30% | 11.00% | |||||||||
Approved equity capital structure | 60.00% | ||||||||||
Impairment of assets and related charges | |||||||||||
JCP&L | |||||||||||
Regulatory Matters [Line Items] | |||||||||||
Approved suspension period | 5 months | ||||||||||
JCP&L | NITS | |||||||||||
Regulatory Matters [Line Items] | |||||||||||
Annual revenue requirement | $ 135 | ||||||||||
JCP&L | PJM Tariff | |||||||||||
Regulatory Matters [Line Items] | |||||||||||
Annual revenue requirement | $ 20 |
Commitments, Guarantees and C60
Commitments, Guarantees and Contingencies (Details) $ in Millions | 3 Months Ended |
Mar. 31, 2018USD ($) | |
Guarantor Obligations [Line Items] | |
Guarantor obligations | $ 393 |
Curing period | 30 days |
At Current Credit Rating | |
Guarantor Obligations [Line Items] | |
Guarantor obligations | $ 1 |
Upon Further Downgrade | |
Guarantor Obligations [Line Items] | |
Guarantor obligations | 46 |
Surety Bond (Collateralized Amount) | |
Guarantor Obligations [Line Items] | |
Guarantor obligations | 346 |
Regulated | |
Guarantor Obligations [Line Items] | |
Guarantor obligations | 155 |
Regulated | At Current Credit Rating | |
Guarantor Obligations [Line Items] | |
Guarantor obligations | 0 |
Regulated | Upon Further Downgrade | |
Guarantor Obligations [Line Items] | |
Guarantor obligations | 46 |
Regulated | Surety Bond (Collateralized Amount) | |
Guarantor Obligations [Line Items] | |
Guarantor obligations | 109 |
FirstEnergy | |
Guarantor Obligations [Line Items] | |
Guarantor obligations | 236 |
FirstEnergy | At Current Credit Rating | |
Guarantor Obligations [Line Items] | |
Guarantor obligations | 0 |
FirstEnergy | Upon Further Downgrade | |
Guarantor Obligations [Line Items] | |
Guarantor obligations | 0 |
FirstEnergy | Surety Bond (Collateralized Amount) | |
Guarantor Obligations [Line Items] | |
Guarantor obligations | 236 |
AE Supply | |
Guarantor Obligations [Line Items] | |
Guarantor obligations | 2 |
AE Supply | At Current Credit Rating | |
Guarantor Obligations [Line Items] | |
Guarantor obligations | 1 |
AE Supply | Upon Further Downgrade | |
Guarantor Obligations [Line Items] | |
Guarantor obligations | 0 |
AE Supply | Surety Bond (Collateralized Amount) | |
Guarantor Obligations [Line Items] | |
Guarantor obligations | $ 1 |
Commitments, Guarantees and C61
Commitments, Guarantees and Contingencies (Details Textuals) | Apr. 06, 2018USD ($) | Feb. 18, 2018USD ($) | May 01, 2017USD ($)installment | Mar. 31, 2018USD ($) | Dec. 31, 2017USD ($) |
Guarantor Obligations [Line Items] | |||||
Outstanding guarantees and other assurances aggregated | $ 1,900,000,000 | ||||
New syndicated senior secured term loan facility | $ 393,000,000 | ||||
Curing period | 30 days | ||||
Settlement amount awarded to other party | $ 93,000,000 | ||||
Proposed goal to reduce CO2 pollution (percent) | 90.00% | ||||
Nuclear plant decommissioning trusts | $ 800,000,000 | $ 822,000,000 | |||
Clean Water Act | |||||
Guarantor Obligations [Line Items] | |||||
Waste water discharge permit renewal cycle | 5 years | ||||
Regulation of Waste Disposal | |||||
Guarantor Obligations [Line Items] | |||||
Bond closure and post closure period | 45 years | ||||
Period to complete closure | 12 years | ||||
Accrual for environmental loss contingencies | $ 125,000,000 | ||||
Environmental liabilities former gas facilities | 85,000,000 | ||||
Nuclear Plant Matters | |||||
Guarantor Obligations [Line Items] | |||||
Nuclear plant decommissioning trusts | 800,000,000 | ||||
Regulated Distribution | |||||
Guarantor Obligations [Line Items] | |||||
Company posted collateral related to net liability positions | $ 6,000,000 | ||||
Global Holding | Senior Secured Term Loan | Senior Loans | Signal Peak, Global Rail and Affiliates | |||||
Guarantor Obligations [Line Items] | |||||
Investment ownership percentage | 69.99% | ||||
FEV | Senior Secured Term Loan | Senior Loans | Signal Peak | Global Holding | |||||
Guarantor Obligations [Line Items] | |||||
Investment ownership percentage | 33.33% | ||||
WMB Marketing Ventures, LLC | Senior Secured Term Loan | Senior Loans | Signal Peak | Global Holding | |||||
Guarantor Obligations [Line Items] | |||||
Investment ownership percentage | 33.33% | ||||
FG | Settled Litigation | Caa Compliance | |||||
Guarantor Obligations [Line Items] | |||||
Settlement amount | $ 109,000,000 | ||||
Number of installment payments | installment | 3 | ||||
AE Supply | |||||
Guarantor Obligations [Line Items] | |||||
Company posted collateral related to net liability positions | $ 0 | ||||
New syndicated senior secured term loan facility | 2,000,000 | ||||
Settlement amount awarded to other party | $ 93,000,000 | ||||
Minimum | Clean Water Act | |||||
Guarantor Obligations [Line Items] | |||||
Capital investment required to install technology to meet TDS and Sulfate limits | 150,000,000 | ||||
Maximum | Clean Water Act | |||||
Guarantor Obligations [Line Items] | |||||
Capital investment required to install technology to meet TDS and Sulfate limits | 300,000,000 | ||||
FES and FENOC | |||||
Guarantor Obligations [Line Items] | |||||
Outstanding guarantees and other assurances aggregated | 484,000,000 | ||||
FirstEnergy | |||||
Guarantor Obligations [Line Items] | |||||
Outstanding guarantees and other assurances aggregated | 1,007,000,000 | ||||
Other Guarantee | |||||
Guarantor Obligations [Line Items] | |||||
Outstanding guarantees and other assurances aggregated | 255,000,000 | ||||
Other Assurances | |||||
Guarantor Obligations [Line Items] | |||||
Outstanding guarantees and other assurances aggregated | 178,000,000 | ||||
Little Bull Run | Line of Credit | Surety Bond (Collateralized Amount) | |||||
Guarantor Obligations [Line Items] | |||||
Maximum amount borrowed under revolving credit facility | 169,000,000 | ||||
Hatfield Ferry | Line of Credit | Surety Bond (Collateralized Amount) | |||||
Guarantor Obligations [Line Items] | |||||
Maximum amount borrowed under revolving credit facility | $ 31,000,000 | ||||
Subsequent Event | FG | Settled Litigation | Caa Compliance | |||||
Guarantor Obligations [Line Items] | |||||
Settlement payments | $ 72,000,000 |
Segment Information (Details Te
Segment Information (Details Textuals) mi² in Thousands, customer in Millions, $ in Millions | 3 Months Ended | |
Mar. 31, 2018USD ($)mi²customercompanyMW | Aug. 31, 2017MW | |
Purchase Agreement with Subsidiary of LS Power | ||
Segment Reporting Information [Line Items] | ||
Megawatts of net demonstrated capacity of competitive segment | 1,615 | |
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 | |
Number of square miles in service area | mi² | 65 | |
Megawatts of net demonstrated capacity of competitive segment | 3,790 | |
Other/Corporate | ||
Segment Reporting Information [Line Items] | ||
Long-term debt and other long-term obligations | $ | $ 5,350 | |
FirstEnergy | Revolving Credit Facility | Other/Corporate | ||
Segment Reporting Information [Line Items] | ||
Long-term line of credit | $ | $ 1,200 | |
Corporate/Other | ||
Segment Reporting Information [Line Items] | ||
Megawatts of net demonstrated capacity of competitive segment | 2,123 | |
Corporate/Other | Purchase Agreement with Subsidiary of LS Power | Bath County Hydro | ||
Segment Reporting Information [Line Items] | ||
Megawatts of net demonstrated capacity of competitive segment | 713 |
Segment Information (Details)
Segment Information (Details) - USD ($) $ in Millions | 3 Months Ended | |||
Mar. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2017 | ||
Segment Financial Information | ||||
Revenues | [1] | $ 2,976 | $ 2,855 | |
Depreciation | 294 | 250 | ||
Amortization (deferral) of regulatory assets, net | (148) | 83 | ||
Miscellaneous income | 67 | 14 | ||
Interest expense | 250 | 245 | ||
Income taxes (benefits) | 252 | 152 | ||
Income (loss) from continuing operations | 177 | 257 | ||
Total assets | 38,795 | 43,212 | $ 42,257 | |
Goodwill | 5,618 | 5,618 | $ 5,618 | |
Property additions | 583 | 588 | ||
Regulated Distribution | ||||
Segment Financial Information | ||||
Revenues | 2,321 | |||
Regulated Transmission | ||||
Segment Financial Information | ||||
Income (loss) from continuing operations | 99 | 88 | ||
Operating Segments | Regulated Distribution | ||||
Segment Financial Information | ||||
Revenues | 2,576 | 2,500 | ||
Depreciation | 196 | 178 | ||
Amortization (deferral) of regulatory assets, net | (152) | 81 | ||
Miscellaneous income | 56 | 15 | ||
Interest expense | 128 | 138 | ||
Income taxes (benefits) | 93 | 138 | ||
Income (loss) from continuing operations | 322 | 237 | ||
Total assets | 27,504 | 27,826 | ||
Goodwill | 5,004 | 5,004 | ||
Property additions | 264 | 264 | ||
Operating Segments | Regulated Transmission | ||||
Segment Financial Information | ||||
Revenues | 323 | 313 | ||
Depreciation | 61 | 51 | ||
Amortization (deferral) of regulatory assets, net | 4 | 2 | ||
Miscellaneous income | 4 | 0 | ||
Interest expense | 39 | 39 | ||
Income taxes (benefits) | 32 | 52 | ||
Total assets | 9,681 | 8,938 | ||
Goodwill | 614 | 614 | ||
Property additions | 292 | 224 | ||
Corporate/Other | ||||
Segment Financial Information | ||||
Revenues | 125 | 92 | ||
Depreciation | 19 | 4 | ||
Amortization (deferral) of regulatory assets, net | 0 | 0 | ||
Miscellaneous income | 16 | 6 | ||
Interest expense | 92 | 75 | ||
Income taxes (benefits) | 127 | (38) | ||
Income (loss) from continuing operations | (244) | (68) | ||
Total assets | 1,255 | 1,160 | ||
Goodwill | 0 | 0 | ||
Property additions | 12 | 10 | ||
Reconciling Adjustments | ||||
Segment Financial Information | ||||
Revenues | (48) | (50) | ||
Depreciation | 18 | 17 | ||
Amortization (deferral) of regulatory assets, net | 0 | 0 | ||
Miscellaneous income | (9) | (7) | ||
Interest expense | (9) | (7) | ||
Income taxes (benefits) | 0 | 0 | ||
Income (loss) from continuing operations | 0 | 0 | ||
Total assets | 355 | 5,288 | ||
Goodwill | 0 | 0 | ||
Property additions | $ 15 | $ 90 | ||
[1] | Includes excise tax collections of $102 million and $100 million in the three months ended March 31, 2018 and 2017, respectively. |
Subsequent Events (Details)
Subsequent Events (Details) - Subsequent Event - FES and FENOC - Discontinued Operations, Disposed of by Means Other than Sale $ in Millions | Apr. 20, 2018USD ($) |
Subsequent Event [Line Items] | |
Cash payment to settle claims | $ 225 |
Reversal of NOL | 88 |
Line of Credit | Revolving Credit Facility | |
Subsequent Event [Line Items] | |
Face amount of debt | 500 |
Line of Credit | Surety Bond | |
Subsequent Event [Line Items] | |
Face amount of debt | 200 |
Promissory Notes | |
Subsequent Event [Line Items] | |
Face amount of debt | $ 628 |