FIRSTENERGY CORP. AND SUBSIDIARIES
1. 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.
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 combined Annual Report on Form 10-K for the year ended December 31, 2016. These Notes to the Consolidated Financial Statements are combined for FirstEnergy2023.
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.appropriate and permitted pursuant to GAAP. FE and its subsidiaries consolidate a VIEvariable interest entity when it is determined that it is the primary beneficiary (see Note 6, "Variable Interest Entities").beneficiary. Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but do not have a controlling financial interest, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage of FE'sFE’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.
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:
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.
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. A more detailed description of FirstEnergy's valuation process for FTRs and NUGs follows:
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'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'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, significantSignificant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. See Note 8, "Derivative Instruments," for additional information regarding FirstEnergy's FTRs.
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 September 30, 2017,March 31, 2024, from those used as of December 31, 2016.2023. 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.
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| | NUG Contracts(1) | | FTRs |
| | Derivative Assets | | Derivative Liabilities | | Net | | Derivative Assets | | Derivative Liabilities | | Net |
| | (In millions) |
| January 1, 2016 Balance | $ | 1 |
| | $ | (137 | ) | | $ | (136 | ) | | $ | 8 |
| | $ | (13 | ) | | $ | (5 | ) |
| Unrealized gain (loss) | 2 |
| | (17 | ) | | (15 | ) | | (6 | ) | | (4 | ) | | (10 | ) |
| Purchases | — |
| | — |
| | — |
| | 16 |
| | (7 | ) | | 9 |
|
| Settlements | (2 | ) | | 46 |
| | 44 |
| | (11 | ) | | 18 |
| | 7 |
|
| December 31, 2016 Balance | $ | 1 |
| | $ | (108 | ) | | $ | (107 | ) | | $ | 7 |
| | $ | (6 | ) | | $ | 1 |
|
| Unrealized loss | — |
| | (14 | ) | | (14 | ) | | — |
| | (2 | ) | | (2 | ) |
| Purchases | — |
| | — |
| | — |
| | 5 |
| | (2 | ) | | 3 |
|
| Settlements | (1 | ) | | 30 |
| | 29 |
| | (7 | ) | | 8 |
| | 1 |
|
| September 30, 2017 Balance | $ | — |
| | $ | (92 | ) | | $ | (92 | ) | | $ | 5 |
| | $ | (2 | ) | | $ | 3 |
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(1)
| NUG contracts are subject to regulatory accounting treatment and 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 September 30, 2017:
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| | | Fair Value, Net (In millions) | | Valuation
Technique | | Significant Input | | Range | | Weighted Average | | Units |
| FTRs | | $ | 3 |
| | Model | | RTO auction clearing prices | | $(5.00) to $4.60 | | $0.60 | | Dollars/MWH |
| | | | | | | | | | | | | |
| NUG Contracts | | $ | (92 | ) | | Model | | Generation | | 400 to 2,322,000 | | 470,000 |
| | MWH |
| | | | Regional electricity prices | | $29.90 to $31.40 | | $29.90 | | Dollars/MWH |
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| FES | | | | | | | | | | | | | | | |
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| Recurring Fair Value Measurements | September 30, 2017 | | December 31, 2016 |
| | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | (In millions) |
| Corporate debt securities | $ | — |
| | $ | 722 |
| | $ | — |
| | $ | 722 |
| | $ | — |
| | $ | 726 |
| | $ | — |
| | $ | 726 |
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| Derivative assets - commodity contracts | — |
| | 35 |
| | — |
| | 35 |
| | 10 |
| | 200 |
| | — |
| | 210 |
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| Derivative assets - FTRs | — |
| | — |
| | 1 |
| | 1 |
| | — |
| | — |
| | 4 |
| | 4 |
|
Equity securities(1) | 765 |
| | — |
| | — |
| | 765 |
| | 634 |
| | — |
| | — |
| | 634 |
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| Foreign government debt securities | — |
| | 65 |
| | — |
| | 65 |
| | — |
| | 58 |
| | — |
| | 58 |
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| U.S. government debt securities | — |
| | 138 |
| | — |
| | 138 |
| | — |
| | 48 |
| | — |
| | 48 |
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| U.S. state debt securities | — |
| | 21 |
| | — |
| | 21 |
| | — |
| | 3 |
| | — |
| | 3 |
|
Other(2) | 2 |
| | 120 |
| | — |
| | 122 |
| | 2 |
| | 81 |
| | — |
| | 83 |
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| Total assets | $ | 767 |
| | $ | 1,101 |
| | $ | 1 |
| | $ | 1,869 |
| | $ | 646 |
| | $ | 1,116 |
| | $ | 4 |
| | $ | 1,766 |
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| Liabilities | | | | | | | | | | | | | | | |
| Derivative liabilities - commodity contracts | $ | — |
| | $ | (12 | ) | | $ | — |
| | $ | (12 | ) | | $ | (6 | ) | | $ | (118 | ) | | $ | — |
| | $ | (124 | ) |
| Derivative liabilities - FTRs | — |
| | — |
| | (1 | ) | | (1 | ) | | — |
| | — |
| | (5 | ) | | (5 | ) |
| Total liabilities | $ | — |
| | $ | (12 | ) | | $ | (1 | ) | | $ | (13 | ) | | $ | (6 | ) | | $ | (118 | ) | | $ | (5 | ) | | $ | (129 | ) |
| | | | | | | | | | | | | | | | |
Net assets (liabilities)(3) | $ | 767 |
| | $ | 1,089 |
| | $ | — |
| | $ | 1,856 |
| | $ | 640 |
| | $ | 998 |
| | $ | (1 | ) | | $ | 1,637 |
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(1)
| NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. |
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(2)
| Primarily consists of short-term cash investments. |
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(3)
| Excludes $(8) million and $2 million as of September 30, 2017 and December 31, 2016, respectively, of receivables, payables, taxes and accrued income associated with the 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 FTRs held by FES and classified as Level 3 in the fair value hierarchy for the periods ended September 30, 2017 and December 31, 2016:
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| | | Derivative Asset | | Derivative Liability | | Net Asset (Liability) |
| | | (In millions) |
| January 1, 2016 Balance | | $ | 5 |
| | $ | (11 | ) | | $ | (6 | ) |
| Unrealized loss | | (4 | ) | | (3 | ) | | (7 | ) |
| Purchases | | 10 |
| | (5 | ) | | 5 |
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| Settlements | | (7 | ) | | 14 |
| | 7 |
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| December 31, 2016 Balance | | $ | 4 |
| | $ | (5 | ) | | $ | (1 | ) |
| Unrealized loss | | — |
| | (1 | ) | | (1 | ) |
| Purchases | | 1 |
| | (1 | ) | | — |
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| Settlements | | (4 | ) | | 6 |
| | 2 |
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| September 30, 2017 Balance | | $ | 1 |
| | $ | (1 | ) | | $ | — |
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Level 3 Quantitative Information
The following table provides quantitative information for FTRs held by FES that are classified as Level 3 in the fair value hierarchy for the period ended September 30, 2017:
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| | Fair Value, Net (In millions) | | Valuation
Technique | | Significant Input | | Range | | Weighted Average | | Units |
FTRs | | $ | — |
| | Model | | RTO auction clearing prices | | ($5.00) to $2.60 | | $0.20 | | 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 held-to-maturityequity securities, AFS debt securities and AFS securities.
At the end of each reporting period,other investments. FirstEnergy evaluates its investments for OTTI. Investments classified as AFS securities are evaluated to determine whether a decline in fair value below the cost basis is other than temporary. FirstEnergy considers its intent and ability to hold an equity security until recovery and then considers, among other factors, the duration and the extent to which the security's fair value has been less than its cost and the near-term financial prospects of the security issuer when evaluating an investment for impairment. Forno debt securities FirstEnergy considers its intent to hold the securities, the likelihood that it will be required to sell the securities before recovery of its cost basis and the likelihood of recovery of the securities' entire amortized cost basis. If the decline in fair value is determined to be other than temporary, the cost basis of the securities is written down to fair value.held for trading purposes.
UnrealizedGenerally, 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, unrealized losses held in the NDTs of FES, OE and TE are recognized in earnings since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of OTTI. The NDTsspent nuclear fuel disposal trusts of JCP&L ME and PN are subject to regulatory accounting with unrealizedall gains and losses on equity and AFS debt securities offset against regulatory assets.
During the second quarter of 2017, in connection with NG purchasing the lessor equity interests of the remaining non-affiliated leasehold interests from an owner participant in the Beaver Valley Unit 2 and the expiration of the leases, OE and TE transferred NDT assets of $189 million associated with their leasehold interests to NG. See Note 9, "Asset Retirement Obligations," for additional information.Spent Nuclear Fuel Disposal Trusts
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.
AFS Securities
FirstEnergyJCP&L holds debt and equity securities within its NDT andthe spent nuclear fuel disposal trusts. These trust, investmentswhich are consideredclassified as AFS securities, recognized at fair market value. FirstEnergy has no securities heldThe trust is intended for trading purposes.funding spent nuclear fuel disposal fees to the United States Department of Energy associated with the previously owned Oyster Creek and Three Mile Island Unit 1 nuclear power plants.
The following table summarizes the amortized cost basis, unrealized gains, (there were no unrealized losses)losses and fair values of investments held in NDT andspent nuclear fuel disposal trusts as of September 30, 2017March 31, 2024, and December 31, 2016:2023:
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| | March 31, 2024(1) | | December 31, 2023(1) |
| | Cost Basis | | Unrealized Gains | | Unrealized Losses | | Fair Value | | Cost Basis | | Unrealized Gains | | Unrealized Losses | | Fair Value |
| | (In millions) |
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| Debt securities | | $ | 303 | | | $ | — | | | $ | (29) | | | $ | 274 | | | $ | 301 | | | $ | 1 | | | $ | (27) | | | $ | 275 | |
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(1) Excludes short-term cash investments of $6 million as of March 31, 2024 and December 31, 2023. |
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| | | September 30, 2017(1) | | December 31, 2016(2) |
| | | Cost Basis | | Unrealized Gains | | Fair Value | | Cost Basis | | Unrealized Gains | | Fair Value |
| | | (In millions) |
| Debt securities | | | | | | | | | | | | |
| FirstEnergy | | $ | 1,701 |
| | $ | 42 |
| | $ | 1,743 |
| | $ | 1,735 |
| | $ | 38 |
|
| $ | 1,773 |
|
| FES | | 942 |
| | 27 |
| | 969 |
| | 847 |
| | 27 |
| | 874 |
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| Equity securities | | | | | | | | | | | | |
| FirstEnergy | | $ | 927 |
| | $ | 118 |
| | $ | 1,045 |
| | $ | 822 |
| | $ | 103 |
| | $ | 925 |
|
| FES | | 675 |
| | 90 |
| | 765 |
| | 564 |
| | 70 |
| | 634 |
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(1)
| Excludes short-term cash investments: FirstEnergy - $100 million; FES - $89 million. |
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(2)
| Excludes short-term cash investments: FirstEnergy - $61 million; FES - $44 million. |
Proceeds from the sale of investments in AFS debt securities, realized gains and losses on those sales OTTI and interest and dividend income for the three and nine months ended September 30, 2017March 31, 2024 and 20162023, were as follows:
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| | | | For the Three Months Ended March 31, |
| | | | | | 2024 | | 2023 |
| | | | | | (In millions) |
| Sale proceeds | | | | | | $ | 13 | | | $ | 1 | |
| Realized gains | | | | | | — | | | — | |
| Realized losses | | | | | | (1) | | | (1) | |
| | | | | | | | |
| Interest and dividend income | | | | | | 3 | | | 3 | |
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| For the Three Months Ended |
| September 30, 2017 | | Sale Proceeds | | Realized Gains | | Realized Losses | | OTTI | | Interest and Dividend Income |
| | | (In millions) |
| FirstEnergy | | $ | 666 |
| | $ | 93 |
| | $ | (53 | ) | | $ | (3 | ) | | $ | 24 |
|
| FES | | 397 |
| | 73 |
| | (42 | ) | | (3 | ) | | 15 |
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| September 30, 2016 | | Sale Proceeds | | Realized Gains | | Realized Losses | | OTTI | | Interest and Dividend Income |
| | | (In millions) |
| FirstEnergy | | $ | 337 |
| | $ | 36 |
| | $ | (15 | ) | | $ | (3 | ) | | $ | 27 |
|
| FES | | 135 |
| | 23 |
| | (6 | ) | | (3 | ) | | 16 |
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| For the Nine Months Ended |
| September 30, 2017 | | Sale Proceeds | | Realized Gains | | Realized Losses | | OTTI | | Interest and Dividend Income |
| | | (In millions) |
| FirstEnergy | | $ | 1,923 |
| | $ | 276 |
| | $ | (207 | ) | | $ | (10 | ) | | $ | 72 |
|
| FES | | 834 |
| | 206 |
| | (152 | ) | | (10 | ) | | 44 |
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| September 30, 2016 | | Sale Proceeds | | Realized Gains | | Realized Losses | | OTTI | | Interest and Dividend Income |
| | | (In millions) |
| FirstEnergy | | $ | 1,361 |
| | $ | 131 |
| | $ | (88 | ) | | $ | (13 | ) | | $ | 75 |
|
| FES | | 576 |
| | 90 |
| | (49 | ) | | (12 | ) | | 42 |
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Held-To-Maturity Securities
Unrealized gains (thereOther investments include employee benefit trusts, which are primarily invested in corporate-owned life insurance policies, and equity method investments. Earnings and losses associated with corporate-owned life insurance policies are reflected in “Miscellaneous income, net” on FirstEnergy’s Consolidated Statements of Income. The total carrying value of other investments were no unrealized losses)$408 million and approximate fair values of investments in held-to-maturity securities$382 million as of September 30, 2017March 31, 2024, and December 31, 2016 are immaterial to FirstEnergy. Investments in employee benefit trusts2023, respectively, and equity method investments totaling $255 million as of September 30, 2017 and $266 million as of December 31, 2016, are excluded from the amounts reported above. See Note 1, "Organization and Basis of Presentation," for additional information on FirstEnergy's equity method investments.
Pre-tax income related to corporate-owned life insurance policies was $9 million and $7 million for the three months ended March 31, 2024 and 2023, respectively. Corporate-owned life insurance policies are valued using the cash surrender value and any changes in value during the period are recognized as income or expense.
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS
All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported as Short-term borrowings on the Consolidated Balance Sheets at cost. Since these borrowings are short-term in nature, FirstEnergy believes that their costs approximate their fair market value. The following table provides the approximate fair value and related carrying amounts of long-term debt, which excludes capitalfinance lease obligations and net unamortized debt issuance costs, unamortized fair value adjustments, premiums and discounts:discounts as of March 31, 2024 and December 31, 2023:
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| March 31, 2024 | | December 31, 2023 |
| (In millions) |
| Carrying value | $ | 24,381 | | | $ | 24,254 | |
| Fair value | $ | 22,904 | | | $ | 23,003 | |
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| | September 30, 2017 | | December 31, 2016 |
| | Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
| | (In millions) |
| FirstEnergy | $ | 22,218 |
| | $ | 22,994 |
| | $ | 19,885 |
| | $ | 19,829 |
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| FES | 2,837 |
| | 1,620 |
| | 3,000 |
| | 1,555 |
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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 September 30, 2017March 31, 2024, and December 31, 2016.2023.
8. DERIVATIVE INSTRUMENTS
FirstEnergy is exposed to financial risks resulting from fluctuating interest rateshad the following issuances and commodity prices, including prices for electricity, natural gas, 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 cash flow hedges for risk management purposes to manage the volatility related to exposures associated with fluctuating commodity prices and interest rates.
Total pre-tax net unamortized losses included in AOCI associated with instruments previously designated as cash flow hedges totaled $11 million as of September 30, 2017 and $12 million as of December 31, 2016. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Approximately $2 million of net unamortized losses is expected to be amortized to income during the next twelve months.
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 $27 million (FES $3 million) and $33 million (FES $3 million) as of September 30, 2017 and December 31, 2016, respectively. Based on current estimates, approximately $8 million of these unamortized losses are expected to be amortized to interest expense during the next twelve months.
Refer to Note 4, "Accumulated Other Comprehensive Income," for reclassifications from AOCI during the three and nine months ended September 30, 2017 and 2016.
As of September 30, 2017 and December 31, 2016, 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 September 30, 2017 and December 31, 2016, 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 $4 million and $10 million as of September 30, 2017 and December 31, 2016, respectively. During the next twelve months, approximately $2 million of unamortized gains are expected to be amortized to interest expense. Amortization of unamortized gains included in long-term debt totaled approximately $1 millionredemptions during the three months ended September 30, 2017 and $2 million during the three months ended September 30, 2016. AmortizationMarch 31, 2024:
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| Company | Type | Issuance Date | Interest Rate | Maturity | Amount (In millions) | Description |
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| Issuance |
| ATSI | Senior Unsecured Note | March, 2024 | 5.63% | 2034 | $150 | Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes. |
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In March 2024, notice of unamortized gains included in long-term debt totaled approximately $6 million during the nine months ended September 30, 2017 and $8 million during the nine months ended September 30, 2016.
Commodity Derivatives
FirstEnergy uses both physically and financially settled derivatives to manage its exposure to volatility in commodity prices. Commodity derivatives are usedredemption was provided for risk management purposes to hedge exposures when it makes economic sense to do so, including circumstances where the hedging relationship does not qualify for hedge accounting.
Electricity forwards are used to balance expected sales with expected generation and purchased power. Natural gas futures are entered into based on expected consumption of natural gas primarily for use in FirstEnergy’s combustion turbine units. Derivative instruments are not used in quantities greater than forecasted needs.
As of September 30, 2017, FirstEnergy’s net asset position under commodity derivative contracts was $23 million, which related to FES positions. Under these commodity derivative contracts, FES posted less than $1all remaining $463 million of collateral.
BasedFE’s 7.375% Notes, due 2031, which was completed on commodity derivative contracts held asApril 15, 2024, with a make-whole premium of September 30, 2017, an increase in commodity prices of 10% would decrease net income by approximately $6$80 million. Due to the redemption, the $463 million during the next twelve months.
NUGs
As of September 30, 2017, FirstEnergy's net liability position under NUG contracts was $92 million, representing contracts held at JCP&L, ME and PN. Changes in the fair value of NUG contractsremaining notes are subject to regulatory accounting treatment and do not impact earnings.
FTRs
As of September 30, 2017, FirstEnergy's net asset position associated with FTRs was $3 million and FES' net liability was less than $1 million. As of December 31, 2016, FirstEnergy's net asset position associated with FTRs was $1 million and FES' net liability was $1 million. 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.
The future obligations for the FTRs acquired at auction are reflectedincluded within currently payable long-term debt on the Consolidated Balance Sheets as of March 31, 2024.
On April 1, 2024, JCP&L redeemed its $500 million 4.70% unsecured notes that became due.
On April 15, 2024, MP redeemed its $400 million 4.10% FMBs that became due.
On April 18, 2024, MAIT agreed to sell $250 million of new 5.94% Unsecured Notes due May 1, 2031. The sale is expected to settle on May 2, 2024. Proceeds are expected to be used to repay short-term borrowings, to finance capital expenditures and have not been designatedfor other general corporate purposes.
7. VARIABLE INTEREST ENTITIES
FirstEnergy performs qualitative analyses to determine whether a variable interest qualifies FirstEnergy as cash flow hedge instruments. FirstEnergy initially records these FTRs at the auction price lessprimary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both: (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance; and (ii) the obligation due to PJM,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 subsequently adjustsentities for which FirstEnergy has an interest, FirstEnergy aggregates variable interests into categories based on similar risk characteristics and significance.
Consolidated VIEs
Total assets on the FirstEnergy consolidated balance sheets include approximately $11,156 million and $11,024 million of consolidated VIE assets, as of March 31, 2024 and December 31, 2023, respectively, that can only be used to settle the liabilities of the applicable VIE. Total liabilities include approximately $8,184 million and $7,835 million as of March 31, 2024 and December 31, 2023, respectively, of consolidated VIE liabilities for which the VIE's creditors do not have recourse to FirstEnergy.
VIEs in which FirstEnergy is the primary beneficiary consist of the following (included in FirstEnergy’s consolidated financial statements):
Securitization Companies
•Ohio Securitization Companies - In June 2013, the SPEs formed by the Ohio Companies issued approximately $445 million of pass-through trust certificates supported by phase-in recovery bonds to securitize the recovery of certain all-electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds are payable only from, and secured by, phase in recovery property owned by the SPEs. The bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and administers the phase in recovery property including the billing, collection and remittance of usage-based charges payable by retail electric customers. The SPEs are considered VIEs and each one is consolidated into its applicable utility. As of March 31, 2024 and December 31, 2023, $183 million and $191 million of the phase-in recovery bonds were outstanding, respectively.
•MP and PE Environmental Funding Companies - The consolidated financial statements of FirstEnergy include environmental control bonds issued by two bankruptcy remote, special purpose limited liability companies that are indirect subsidiaries of MP and PE. Proceeds from the bonds were used to construct environmental control facilities. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. Creditors of FirstEnergy, other than the limited liability company SPEs, have no recourse to any assets or revenues of the special purpose limited liability companies. As of March 31, 2024 and December 31, 2023, $203 million and $218 million of environmental control bonds were outstanding, respectively.
Restricted cash included on the FirstEnergy Consolidated Balance Sheets of $25 million and $40 million as of March 31, 2024 and December 31, 2023, respectively, relates to cash collected from MP, PE and the Ohio Companies' customers that is specifically used to service debt of their respective funding companies.
FET
FET is a holding company that owns equity interests in ATSI, MAIT, TrAIL and PATH. As further discussed above, on February 2, 2023, FE entered into an agreement with Brookfield to sell an incremental 30% equity interest in FET, which closed on March 25, 2024. As of March 31, 2024, FE’s equity ownership in FET is 50.1% and Brookfield’s is 49.9%. FirstEnergy has concluded that FET is a VIE and that FE is the primary beneficiary because FE has exposure to the economics of FET and the power to direct significant activities of FET through the FESC services agreement, which represents a separate variable interest.
Although Brookfield was granted incremental consent rights upon the closing of the FET Equity Interest Sale, Brookfield will not have unilateral control over any activities that most significantly impact FET’s economic performance. However, FE will continue to retain power over the activities that most significantly impact FET’s economic performance through its incremental decision making rights under the existing FESC services agreement, through which executive management and workforce services are provided to FET. As a result, FE is the primary beneficiary of FET and FET will continue to be consolidated in FirstEnergy’s financial statements.
The following shows the carrying value of remaining FTRs to their estimated fair value at the end of each accounting period prior to settlement. Changes in the fair value of FTRs held by FES and AE Supply are included in other operating expenses as unrealized gains or losses. Unrealized gains or losses on FTRs held by the Utilities are recorded as regulatory assets or liabilities. Directly allocated FTRs are accounted for under the accrual method of accounting, and their effects are included in earnings at the time of contract performance.
FirstEnergy records the fair value of derivative instruments on a gross basis. The following table summarizes the fair valueamounts and classification of derivative instruments on FirstEnergy’s Consolidated Balance Sheets:
|
| | | | | | | | | | | | | | | | |
| Derivative Assets | | Derivative Liabilities |
| | Fair Value | | | Fair Value |
| | September 30,
2017 | | December 31,
2016 | | | September 30,
2017 | | December 31,
2016 |
| | (In millions) | | | (In millions) |
| Current Assets - Derivatives | | | | | Current Liabilities - Other | | | |
| Commodity Contracts | $ | 30 |
| | $ | 133 |
| | Commodity Contracts | $ | (11 | ) | | $ | (72 | ) |
| FTRs | 5 |
| | 7 |
| | FTRs | (2 | ) | | (6 | ) |
| | 35 |
| | 140 |
| | | (13 | ) | | (78 | ) |
| | | | | | | | | |
| | | | | | Noncurrent Liabilities - Adverse Power Contract Liability | | | |
| | | | | | NUGs(1) | (92 | ) | | (108 | ) |
| Deferred Charges and Other Assets - Other | | | | | Noncurrent Liabilities - Other | | | |
| Commodity Contracts | 5 |
| | 77 |
| | Commodity Contracts | (1 | ) | | (52 | ) |
NUGs(1) | — |
| | 1 |
| | | | | |
| | 5 |
| | 78 |
| | | (93 | ) | | (160 | ) |
| Derivative Assets | $ | 40 |
| | $ | 218 |
| | Derivative Liabilities | $ | (106 | ) | | $ | (238 | ) |
| |
(1)
| NUG contracts are subject to regulatory accounting treatment and do not impact earnings. |
FES records the fair value of derivative instruments on a gross basis. The following table summarizes the fair value and classification of derivative instruments on FES' Consolidated Balance Sheets:
|
| | | | | | | | | | | | | | | | |
| Derivative Assets | | Derivative Liabilities |
| | Fair Value | | | Fair Value |
| | September 30,
2017 | | December 31,
2016 | | | September 30,
2017 | | December 31,
2016 |
| | (In millions) | | | (In millions) |
| Current Assets - Derivatives | | | | | Current Liabilities - Derivatives | | | |
| Commodity Contracts | $ | 30 |
| | $ | 133 |
| | Commodity Contracts | $ | (11 | ) | | $ | (72 | ) |
| FTRs | 1 |
| | 4 |
| | FTRs | (1 | ) | | (5 | ) |
| | 31 |
| | 137 |
| | | (12 | ) | | (77 | ) |
| | | | | | | | | |
| Deferred Charges and Other Assets - Derivatives | | | | | Noncurrent Liabilities - Other | | | |
| Commodity Contracts | 5 |
| | 77 |
| | Commodity Contracts | (1 | ) | | (52 | ) |
| | 5 |
| | 77 |
| | | (1 | ) | | (52 | ) |
| Derivative Assets | $ | 36 |
| | $ | 214 |
| | Derivative Liabilities | $ | (13 | ) | | $ | (129 | ) |
| | | | | | | | | |
FirstEnergy enters into contracts with counterparties that allow for the offsetting of derivativeFET assets and derivative liabilities under netting arrangements withincluded in the same counterparty. Certain of these contracts contain margining provisions that require the use of collateral to mitigate credit exposure between FirstEnergy and these counterparties. In situations where collateral is pledged to mitigate exposures related to derivative and non-derivative instruments with the same counterparty, FirstEnergy allocates the collateral based on the percentage of the net fair value of derivative instruments to the total fair value of the combined derivative and non-derivative instruments. The following tables summarize the fair value of derivative assets and derivative liabilities on FirstEnergy’s Consolidated Balance Sheets and the effect of netting arrangements and collateral on itsconsolidated financial position:
|
| | | | | | | | | | | | | | | | |
| | | | | Amounts Not Offset in Consolidated Balance Sheet | | |
| September 30, 2017 | | Fair Value | | Derivative Instruments | | Cash Collateral Pledged | | Net Fair Value |
| | | (In millions) |
| Derivative Assets | | | | | | | | |
| Commodity contracts | | $ | 35 |
| | $ | (9 | ) | | $ | — |
| | $ | 26 |
|
| FTRs | | 5 |
| | (2 | ) | | — |
| | 3 |
|
| | | $ | 40 |
| | $ | (11 | ) | | $ | — |
| | $ | 29 |
|
| | | | | | | | | |
Derivative Liabilities | | | | | | | | |
| Commodity contracts | | $ | (12 | ) | | $ | 9 |
| | $ | — |
| | $ | (3 | ) |
| FTRs | | (2 | ) | | 2 |
| | — |
| | — |
|
| NUG contracts | | (92 | ) | | — |
| | — |
| | (92 | ) |
| | | $ | (106 | ) | | $ | 11 |
| | $ | — |
| | $ | (95 | ) |
| | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | | | Amounts Not Offset in Consolidated Balance Sheet | | |
| December 31, 2016 | | Fair Value | | Derivative Instruments | | Cash Collateral Pledged | | Net Fair Value |
| | | (In millions) |
| Derivative Assets | | | | | | | | |
| Commodity contracts | | $ | 210 |
| | $ | (117 | ) | | $ | — |
| | $ | 93 |
|
| FTRs | | 7 |
| | (6 | ) | | — |
| | 1 |
|
| NUG contracts | | 1 |
| | — |
| | — |
| | 1 |
|
| | | $ | 218 |
| | $ | (123 | ) | | $ | — |
| | $ | 95 |
|
| | | | | | | | | |
| Derivative Liabilities | | | | | | | | |
| Commodity contracts | | $ | (124 | ) | | $ | 117 |
| | $ | 1 |
| | $ | (6 | ) |
| FTRs | | (6 | ) | | 6 |
| | — |
| | — |
|
| NUG contracts | | (108 | ) | | — |
| | — |
| | (108 | ) |
| | | $ | (238 | ) | | $ | 123 |
| | $ | 1 |
| | $ | (114 | ) |
The following tables summarize the fair value of derivative assets and derivative liabilities on FES’ Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position:
|
| | | | | | | | | | | | | | | | |
| | | | | Amounts Not Offset in Consolidated Balance Sheet | | |
| September 30, 2017 | | Fair Value | | Derivative Instruments | | Cash Collateral Pledged | | Net Fair Value |
| | | (In millions) |
| Derivative Assets | | | | | | | | |
| Commodity contracts | | $ | 35 |
| | $ | (9 | ) | | $ | — |
| | $ | 26 |
|
| FTRs | | 1 |
| | (1 | ) | | — |
| | — |
|
| | | $ | 36 |
| | $ | (10 | ) | | $ | — |
| | $ | 26 |
|
| | | | | | | | | |
Derivative Liabilities | | | | | | | | |
| Commodity contracts | | $ | (12 | ) | | $ | 9 |
| | $ | — |
| | $ | (3 | ) |
| FTRs | | (1 | ) | | 1 |
| | — |
| | — |
|
| | | $ | (13 | ) | | $ | 10 |
| | $ | — |
| | $ | (3 | ) |
| | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | | | Amounts Not Offset in Consolidated Balance Sheet | | |
| December 31, 2016 | | Fair Value | | Derivative Instruments | | Cash Collateral Pledged | | Net Fair Value |
| | | (In millions) |
| Derivative Assets | | | | | | | | |
| Commodity contracts | | $ | 210 |
| | $ | (117 | ) | | $ | — |
| | $ | 93 |
|
| FTRs | | 4 |
| | (4 | ) | | — |
| | — |
|
| | | $ | 214 |
| | $ | (121 | ) | | $ | — |
| | $ | 93 |
|
| | | | | | | | | |
| Derivative Liabilities | | | | | | | | |
| Commodity contracts | | $ | (124 | ) | | $ | 117 |
| | $ | 1 |
| | $ | (6 | ) |
| FTRs | | (5 | ) | | 4 |
| | 1 |
| | — |
|
| | | $ | (129 | ) | | $ | 121 |
| | $ | 2 |
| | $ | (6 | ) |
The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactionsstatements as of September 30, 2017:
|
| | | | | | | | | | |
| | Purchases | | Sales | | Net | | Units |
| | (In millions) |
| Power Contracts | 1 |
| | 8 |
| | (7 | ) | | MWH |
| FTRs | 14 |
| | — |
| | 14 |
| | MWH |
| NUGs | 2 |
| | — |
| | 2 |
| | MWH |
The following table summarizes the volumes associated with FES' outstanding derivative transactions as of September 30, 2017:
|
| | | | | | | | | | |
| | Purchases | | Sales | | Net | | Units |
| | (In millions) |
| Power Contracts | 1 |
| | 8 |
| | (7 | ) | | MWH |
| FTRs | 7 |
| | — |
| | 7 |
| | MWH |
The effect of active derivative instruments not in a hedging relationship on FirstEnergy's Consolidated Statements of Income (Loss) during the three and nine months ended September 30, 2017 and 2016, are summarized in the following tables: |
| | | | | | | | | | | |
| | For the Three Months Ended September 30 |
| | Commodity Contracts | | FTRs | | Total |
| | (In millions) |
| 2017 | |
| | |
| | |
|
| Unrealized Loss Recognized in: | |
| | |
| | |
|
| Other Operating Expense | $ | (11 | ) | | $ | — |
| | $ | (11 | ) |
| | | | | | |
| Realized Gain (Loss) Reclassified to: | |
| | |
| | |
|
| Revenues | $ | 8 |
| | $ | (1 | ) | | $ | 7 |
|
| Purchased Power Expense | (3 | ) | | — |
| | (3 | ) |
| Other Operating Expense | — |
| | (1 | ) | | (1 | ) |
| | | | | | |
| | | | | | |
| | For the Three Months Ended September 30 |
| | Commodity Contracts | | FTRs | | Total |
| | (In millions) |
| 2016 | |
| | |
| | |
|
| Unrealized Gain (Loss) Recognized in: | |
| | |
| | |
|
| Other Operating Expense | $ | 19 |
| | $ | (3 | ) | | $ | 16 |
|
| | | | | | |
| Realized Gain (Loss) Reclassified to: | |
| | |
| | |
|
| Revenues | $ | 32 |
| | $ | 1 |
| | $ | 33 |
|
| Purchased Power Expense | (22 | ) | | — |
| | (22 | ) |
| Other Operating Expense | — |
| | (6 | ) | | (6 | ) |
| Fuel Expense | (2 | ) | | — |
| | (2 | ) |
| | | | | | |
|
| | | | | | | | | | | |
| | For the Nine Months Ended September 30 |
| | Commodity Contracts | | FTRs | | Total |
| | (In millions) |
| 2017 | |
| | |
| | |
|
| Unrealized Gain (Loss) Recognized in: | |
| | |
| | |
|
| Other Operating Expense | $ | (65 | ) | | $ | 1 |
| | $ | (64 | ) |
| | | | | | |
| Realized Gain (Loss) Reclassified to: | |
| | |
| | |
|
| Revenues | $ | 48 |
| | $ | — |
| | $ | 48 |
|
| Purchased Power Expense | (14 | ) | | — |
| | (14 | ) |
| Other Operating Expense | — |
| | (14 | ) | | (14 | ) |
| Fuel Expense | 5 |
| | — |
| | 5 |
|
| | | | | | |
| | | | | | |
| | For the Nine Months Ended September 30 |
| | Commodity Contracts | | FTRs | | Total |
| | (In millions) |
| 2016 | |
| | |
| | |
|
| Unrealized Gain Recognized in: | |
| | |
| | |
|
| Other Operating Expense | $ | 2 |
| | $ | 8 |
| | $ | 10 |
|
| | | | | | |
| Realized Gain (Loss) Reclassified to: | |
| | |
| | |
|
| Revenues | $ | 162 |
| | $ | 5 |
| | $ | 167 |
|
| Purchased Power Expense | (105 | ) | | — |
| | (105 | ) |
| Other Operating Expense | — |
| | (28 | ) | | (28 | ) |
| Fuel Expense | (9 | ) | | — |
| | (9 | ) |
| | | | | | |
The effect of active derivative instruments not in a hedging relationship on FES' Consolidated Statements of Income (Loss) during the three and nine months ended September 30, 2017 and 2016, are summarized in the following tables:
|
| | | | | | | | | | | | |
| | | | | | | |
| | For the Three Months Ended September 30 |
| | Commodity Contracts | | FTRs | | | Total |
| 2017 | (In millions) |
| Unrealized Loss Recognized in: | |
| | |
| | | |
|
| Other Operating Expense | $ | (11 | ) | | $ | — |
| | | $ | (11 | ) |
| | | | | | |
|
|
| Realized Gain (Loss) Reclassified to: | |
| | |
| | | |
|
| Revenues | $ | 8 |
| | $ | (1 | ) | | | $ | 7 |
|
| Purchased Power Expense | (3 | ) | | — |
| | | (3 | ) |
| Other Operating Expense | — |
| | (1 | ) | | | (1 | ) |
| | | | | | | |
| | | | | | | |
| | For the Three Months Ended September 30 |
| | Commodity Contracts | | FTRs | | | Total |
| | (In millions) |
| 2016 | |
| | |
| | | |
|
| Unrealized Gain (Loss) Recognized in: | |
| | |
| | | |
|
| Other Operating Expense | $ | 19 |
| | $ | (3 | ) | | | $ | 16 |
|
| | | | | | | |
| Realized Gain (Loss) Reclassified to: | |
| | |
| | | |
|
| Revenues | $ | 32 |
| | $ | 1 |
| | | $ | 33 |
|
| Purchased Power Expense | (22 | ) | | — |
| | | (22 | ) |
| Other Operating Expense | — |
| | (6 | ) | | | (6 | ) |
| | | | | | | |
|
| | | | | | | | | | | | |
| | | | | | | |
| | For the Nine Months Ended September 30 |
| | Commodity Contracts | | FTRs | | | Total |
| 2017 | (In millions) |
| Unrealized Gain (Loss) Recognized in: | |
| | |
| | | |
|
| Other Operating Expense | $ | (65 | ) | | $ | 1 |
| | | $ | (64 | ) |
| | | | | | |
|
|
| Realized Gain (Loss) Reclassified to: | |
| | |
| | | |
|
| Revenues | $ | 48 |
| | $ | — |
| | | $ | 48 |
|
| Purchased Power Expense | (14 | ) | | — |
| | | (14 | ) |
| Other Operating Expense | — |
| | (14 | ) | | | (14 | ) |
| | | | | | | |
| | | | | | | |
| | For the Nine Months Ended September 30 |
| | Commodity Contracts | | FTRs | | | Total |
| | (In millions) |
| 2016 | |
| | |
| | | |
|
| Unrealized Gain Recognized in: | |
| | |
| | | |
|
| Other Operating Expense | $ | 2 |
| | $ | 8 |
| | | $ | 10 |
|
| | | | | | | |
| Realized Gain (Loss) Reclassified to: | |
| | |
| | | |
|
| Revenues | $ | 162 |
| | $ | 5 |
| | | $ | 167 |
|
| Purchased Power Expense | (105 | ) | | — |
| | | (105 | ) |
| Other Operating Expense | — |
| | (28 | ) | | | (28 | ) |
| | | | | | | |
The following table provides a reconciliation of changes in the fair value of FirstEnergy's derivative instruments subject to regulatory accounting during the three and nine months ended September 30, 2017 and 2016. Changes in the value of these instruments are deferred for future recovery from (or credit to) customers:
|
| | | | | | | | | | | | |
| | | For the Three Months Ended September 30 |
| Derivatives Not in a Hedging Relationship with Regulatory Offset | | NUGs | | Regulated FTRs | | Total |
| | | (In millions) |
| Outstanding net asset (liability) as of July 1, 2017 | | $ | (98 | ) | | $ | 3 |
| | $ | (95 | ) |
| Unrealized loss | | (4 | ) | | — |
| | (4 | ) |
| Settlements | | 10 |
| | — |
| | 10 |
|
| Outstanding net asset (liability) as of September 30, 2017 | | $ | (92 | ) | | $ | 3 |
| | $ | (89 | ) |
| | | | | | | |
| Outstanding net asset (liability) as of July 1, 2016 | | $ | (124 | ) | | $ | 4 |
| | $ | (120 | ) |
| Unrealized loss | | (6 | ) | | — |
| | (6 | ) |
| Settlements | | 12 |
| | — |
| | 12 |
|
| Outstanding net asset (liability) as of September 30, 2016 | | $ | (118 | ) | | $ | 4 |
| | $ | (114 | ) |
| | | | | | | |
|
| | | | | | | | | | | | | | |
| | | For the Nine Months Ended September 30 |
| Derivatives Not in a Hedging Relationship with Regulatory Offset | | NUGs | | | Regulated FTRs | | | Total |
| | | (In millions) |
| Outstanding net asset (liability) as of January 1, 2017 | | $ | (107 | ) | | | $ | 2 |
| | | $ | (105 | ) |
| Unrealized loss | | (14 | ) | | | (1 | ) | | | (15 | ) |
| Purchases | | — |
| | | 3 |
| | | 3 |
|
| Settlements | | 29 |
| | | (1 | ) | | | 28 |
|
| Outstanding net asset (liability) as of September 30, 2017 | | $ | (92 | ) | | | $ | 3 |
| | | $ | (89 | ) |
| | | | | | | | | |
| Outstanding net asset (liability) as of January 1, 2016 | | $ | (136 | ) | | | $ | 1 |
| | | $ | (135 | ) |
| Unrealized loss | | (17 | ) | | | (1 | ) | | | (18 | ) |
| Purchases | | — |
| | | 4 |
| | | 4 |
|
| Settlements | | 35 |
| | | — |
| | | 35 |
|
| Outstanding net asset (liability) as of September 30, 2016 | | $ | (118 | ) | | | $ | 4 |
| | | $ | (114 | ) |
| | | | | | | | | |
9. ASSET RETIREMENT OBLIGATIONS
FirstEnergy has recognized applicable legal obligations for AROs and their associated cost primarily for nuclear power plant decommissioning, reclamation of sludge disposal ponds, closure of coal ash disposal sites, underground and above-ground storage tanks, wastewater treatment lagoons and transformers containing PCBs. In addition, FirstEnergy has recognized conditional retirement obligations, primarily for asbestos remediation. FirstEnergy and FES use an expected cash flow approach to measure the fair value of their nuclear decommissioning AROs.
The ARO liabilities for FES primarily relate to the decommissioning of the Beaver Valley, Davis-Besse and Perry nuclear generating facilities, which aggregate to approximately $800 million and $713 million, as of September 30, 2017 2024 and December 31, 2016, respectively.2023. Amounts exclude intercompany balances which were eliminated in consolidation. The assets of FET can only be used to settle its obligations, and creditors of FET do not have recourse to the general credit of FirstEnergy.
During | | | | | | | | | | | | | | |
| Assets | | March 31,
2024 | | December 31,
2023 |
| | (In millions) |
| Cash and cash equivalents | | $ | 77 | | | $ | 76 | |
| Receivables | | 117 | | 88 |
| Materials and supplies, at average cost | | 1 | | | 1 | |
| Prepaid taxes and other | | 24 | | | 23 | |
| Total current assets | | 219 | | | 188 | |
| Property, plant and equipment, net | | 10,426 | | | 10,227 | |
| Goodwill | | 224 | | | 224 | |
| Investments | | 19 | | | 19 | |
| Regulatory assets | | 9 | | | 16 | |
| Other | | 234 | | | 310 | |
| Total noncurrent assets | | 10,912 | | | 10,796 | |
| TOTAL ASSETS | | $ | 11,131 | | | $ | 10,984 | |
| | | | | | | | | | | | | | |
| Liabilities | | March 31,
2024 | | December 31,
2023 |
| | (In millions) |
| | | | |
| Currently payable long-term debt | | 600 | | | — | |
| Short-term borrowings | | 250 | | | — | |
| Accounts payable | | — | | | 2 | |
| Accrued interest | | 61 | | | 63 | |
| Accrued taxes | | 276 | | | 262 | |
| Other | | 7 | | | 14 | |
| Total current liabilities | | 1,194 | | | 341 | |
| Long-term debt and other long-term obligations | | 4,825 | | | 5,275 | |
| Accumulated deferred income taxes | | 1,289 | | | 1,218 | |
| Regulatory liabilities | | 342 | | | 307 | |
| Other | | 148 | | | 285 | |
| Total noncurrent liabilities | | 6,604 | | | 7,085 | |
| TOTAL LIABILITIES | | $ | 7,798 | | | $ | 7,426 | |
Unconsolidated VIEs
FirstEnergy is not the second quarterprimary beneficiary of 2017,its equity method investments in connectionGlobal Holding and PATH WV, as further discussed above, or its PPAs.
FirstEnergy evaluated its PPAs and determined that certain Non-Utility Generation entities 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 NG purchasing the lessor equity interestsplant’s variable costs of production. As of March 31, 2024, FirstEnergy maintains four long-term PPAs with Non-Utility Generation entities that were entered into pursuant to the remaining non-affiliated leasehold interests from an owner participantPublic Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the Beaver Valley Unit 2 sale leasebackcreation of, and has no equity or debt invested in, any of these entities. FirstEnergy has determined that, it does not have a variable interest, or the expiration ofentities do not meet the leases, OE and TE transferred an ARO of $49 million and NDT assets associated with their leaseholdcriteria to be considered a VIE.
Because FirstEnergy has no equity or debt interests in the Non-Utility Generation entities, its maximum exposure to NG, with the difference of $73 million creditedloss relates primarily to the common stock of FES.above-market costs incurred for power, which are expected to be recovered from customers.
During the second quarter of 2016, in connection with NG purchasing the lessor equity interests of the remaining non-affiliated leasehold interests from an owner participant in the Perry Unit 1 sale leaseback, OE transferred the ARO and related NDT assets associated with the leasehold interest to NG, with the difference of $28 million credited to the common stock of FES.
10.8. 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 Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE and TrAIL in Virginia, ATSI in Ohio, the Transmission Companies in Pennsylvania, PE and MP in West Virginia, and PE in Maryland are subject to certain regulations of the VSCC.VSCC, PUCO, PPUC, WVPSC, and MDPSC, respectively. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility.
As competitive retail electric suppliers serving retail customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland, FES and AE Supply are subject to state laws applicable to competitive electric suppliers in those states, including affiliate codes of conduct that apply to FES, AE Supply and their public utility affiliates. In addition, Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission or generation facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission or generation facility.
MARYLAND
PE operates under MDPSC approved base rates that were effective as of October 19, 2023, and that were subsequently modified by an MDPSC order dated January 3, 2024, which became effective as of March 1, 2024. PE also provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third-party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS.
The Maryland legislature adopted a statute in 2008 codifying the EmPOWER Maryland goals to reduce electric consumption and demand and requiringprogram requires each electric utility to file a plan every three years. PE's current plan, covering the three-year period 2015-2017, was approved by the MDPSC on December 23, 2014. On July 16, 2015, the MDPSC issued an order setting new incremental energy savings goals for 2017to reduce electric consumption and beyond, beginning with the goal of 0.97% savings achieved under PE's current plan for 2016, and increasingdemand 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 program cycles, to the extent the MDPSC determines that cost-effective programs and services are available. The costs of the 2015-2017 plan are expected to be approximately $70 million,of which approximately $56 million was incurred through September 30, 2017. PE filed its 2018-2020 EmPOWER plan on August 31, 2017. The 2018-2020 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. The MDPSC will consider the 2018-2020 plan in hearings scheduled to begin on October 25, 2017, with a decision expected by December 31, 2017.savings. PE recovers program investments with a return through an annually reconciled surcharge, with most costs subject to recovery over a five-year amortization.period with a return on the unamortized balance. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding,proceeding. On August 1, 2023, PE filed its proposed plan for the 2024-2026 cycle as required by the MDPSC. Consistent with a December 29, 2022, order by the MDPSC phasing out the ability of Maryland utilities to earn a return on EmPOWER investments, PE will be required to expense 33% of its EmPOWER program costs in 2024, 67% in 2025 and 100% in 2026. Notwithstanding the order to date, such recovery has not been sought or obtainedphase out PE’s ability to earn a return on its EmPOWER investments, all previously unamortized costs for prior cycles will continue to earn a return and be collected by PE. the end of 2029, consistent with the plan PE submitted on January 11, 2023. In the 2024-2026 order issued on December 29, 2023, the period to pay down the
amortized balances was extended through the end of 2031. Additionally at the direction of the MDPSC, PE together with other Maryland utilities are required to address GHG reductions in addition to energy efficiency. In compliance with the MDPSC directive, PE submitted three scenarios with projected costs over a three-year cycle of $310 million, $354 million, and $510 million, respectively. The MDPSC conducted hearings on the proposed plans for all Maryland utilities on November 6-8, 2023. On February 27, 2013,December 29, 2023, the MDPSC issued an order requiringapproving 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$310 million scenario for most programs, with some modifications. On 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 of21, 2024, the MDPSC issued a set of reports that recommended the imposition of extensive additional requirementsapproved PE’s tariff to recover costs 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,2024 but directed PE to analyze alternative amortization methods 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 yet issued a ruling on any of those matters.possible use in later years.
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. Initial comments in the proceeding were filed on October 28, 2016, and the MDPSC held an initial hearing on the matter on December 8-9, 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.
NEW JERSEY
JCP&L currentlyoperates under NJBPU approved rates that took effect as of February 15, 2024, and will become effective for customers as of June 1, 2024. JCP&L provides BGS for retail customers who do not choose a third-party EGS and for customers of third-partythird- 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 wereThe base rate increase, which was approved by the NJBPU on February 14, 2024, took effect on February 15, 2024, and is effective for customers on June 1, 2024. Until those new rates became effective for customers, JCP&L is amortizing an existing regulatory liability totaling approximately $18 million to offset the base rate increase that otherwise would have occurred in this period. Under the base rate case settlement agreement, JCP&L also agreed to a two-phase reliability improvement plan to enhance the reliability related to 18 high-priority circuits, the first phase of which began on February 14, 2024, and represents an approximate investment of $95 million. Additionally, JCP&L recognized a $53 million pre-tax charge in the first quarter 2024 at the Integrated segment within “Other operating expenses” on the FirstEnergy Consolidated Statements of Income, associated with certain corporate support costs recorded to capital accounts from the FERC Audit that were determined, as a result of the settlement agreement, to be disallowed from future recovery.
JCP&L has implemented energy efficiency and peak demand reduction programs in accordance with the New Jersey Clean Energy Act as approved by the NJBPU in April 2021. The NJBPU approved plans include recovery of lost revenues resulting from the programs and a three-year plan (July 2021-June 2024) including total program costs of $203 million, of which $160 million of investment is recovered over a ten-year amortization period with a return as well as $43 million in operations and maintenance expenses and financing costs recovered on an annual basis. On December 12, 2016, effective as5, 2023, JCP&L filed a petition with the NJBPU for a six-month extension of EE&C Plan I, which was originally scheduled to end on June 30, 2024, but would end on December 31, 2024, with the extension. The proposed budget for the extension period would add approximately $69 million to the original program cost. Under the proposal, JCP&L would recover the costs of the extension period and the revenue impact of sales losses resulting therefrom through two separate tariff riders. On December 1, 2023, JCP&L filed a related petition with the NJBPU requesting approval of its EE&C Plan II, which covers the January 1, 2017. These rates provide an annual increase in operating revenues2025 through June 30, 2027 period and has a proposed budget of approximately $80$964 million. EE&C Plan II consists of a portfolio of ten energy efficiency programs, one peak demand reduction program and one building decarbonization program. Under the proposal, JCP&L would recover its EE&C Plan II revenue requirements and lost revenues from reduced electricity sales associated with EE&C Plan II. Evidentiary hearings are scheduled to begin August 19, 2024, with a final NJBPU decision and order required no later than October 15, 2024.
The settlement of the distribution rate case in 2020, provided among other things, that JCP&L would be subject to a management audit, which began in May 2021. On April 12, 2023, the NJBPU accepted the final management audit report for filing purposes and ordered that interested stakeholders file comments on the report by May 22, 2023, which deadline was extended until July 31, 2023. JCP&L filed its comments on July 31, 2023. The parties have filed responses.
On September 17, 2021, in connection with Mid-Atlantic Offshore Development, LLC, a transmission company jointly owned by Shell New Energies US and EDF Renewables North America, JCP&L submitted a proposal to the NJBPU and PJM to build transmission infrastructure connecting offshore wind-generated electricity to the New Jersey power grid. On October 26, 2022, the JCP&L proposal was accepted, in part, in an order issued by NJBPU. The proposal, as accepted, included approximately $723 million in investments for JCP&L to both build new and upgrade existing transmission infrastructure. JCP&L’s proposal projects an investment ROE of 10.2% and includes the option for JCP&L to acquire up to a 20% equity stake in Mid-Atlantic Offshore Development, LLC. The resulting rates associated with the project are expected to be shared among the ratepayers of all New Jersey electric utilities. On April 17, 2023, JCP&L applied for the FERC “abandonment” transmission rates incentive, which would provide for recovery of 100% of the cancelled prudent project costs that are incurred after the incentive is approved, and 50% of the costs incurred prior to that date, in the event that some or all of the project is cancelled for reasons beyond JCP&L’s control. FERC staff subsequently requested additional information on JCP&L’s application, which JCP&L provided. On August 21, 2023, FERC approved JCP&L’s application, effective August 22, 2023. On October 31, 2023, offshore wind developer, Orsted, announced plans to cease development of two offshore wind projects in New Jersey—Ocean Wind 1 and 2—having a combined planned capacity of 2,248 MWs. At this time, Orsted’s announcement does not affect JCP&L’s awarded projects and JCP&L is moving forward with preconstruction activities for the planned transmission infrastructure. Construction is expected to begin in 2025.
Consistent with the commitments made in its proposal to the NJBPU, JCP&L formally submitted in November 2023 the first part of its application to the United States Department of Energy to finance a portion of the project using low-interest rate loans
available under the United States Department of Energy’s Energy Infrastructure Reinvestment Program of the IRA of 2022. JCP&L submitted the second part of its two-part application on March 13, 2024.
On April 3, 2024, Mid-Atlantic Offshore Development, LLC submitted a bid application for the NJBPU Prebuild Infrastructure Solicitation to the NJBPU which outlines its proposal to construct infrastructure connecting the identified landing point for offshore wind generation off the coast of New Jersey with the high-voltage electric grid at Larrabee Collector Station. JCP&L is described in the application as a joint developer with Mid-Atlantic Offshore Development, LLC, subject to the execution of a joint development agreement by the parties. Mid-Atlantic Offshore Development, LLC will be the party responsible for the project.
On November 9, 2023, JCP&L filed a petition for approval of its second EnergizeNJ with the NJBPU that would, among other things, support grid modernization, system resiliency and substation modernization in technologies designed to provide enhanced customer benefits. JCP&L proposes EnergizeNJ will be implemented over a five-year budget period with estimated costs of approximately $935 million over the deployment period, of which, $906 million is capital investments and $29 million is operating and maintenance expenses. Under the proposal, the costs of EnergizeNJ would be recovered through JCP&L’s base rates via annual and semi-annual base rate adjustment filings. Public hearings have been requested but are not yet scheduled. JCP&L has requested that the NJBPU issue a final decision and order no later than May 22, 2024, based on a June 1, 2024, commencement date for EnergizeNJ. JCP&L anticipates filing amendments to the EnergizeNJ program after receipt of approval from those previously in place and are intended to improve service and benefit customers by supporting equipment maintenance, tree trimming, and inspectionsthe NJBPU of lines, poles and substations, while also compensating for other business and operating expenses. In addition,the base rate case stipulation that was filed on January 25, 2017,February 2, 2024. On February 14, 2024, the NJBPU approved the accelerationstipulated settlement between JCP&L and various parties, resolving JCP&L’s request for a distribution base rate increase. On February 27, 2024, as part of the amortizationstipulated settlement, JCP&L amended its pending EnergizeNJ petition following receipt of JCP&L’s 2012 major storm expenses that are recovered throughNJBPU approval of 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 2012base rate case proceeding directingsettlement, to include the second phase of its reliability improvement plan 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 partiesexpected 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 companiesany remaining high-priority circuits not addressed in the savings calculation. On November 5, 2014,first phase. EnergizeNJ, as amended, if approved will result in the Divisioninvestment of Rate Counsel appealed the NJBPU Order regarding the generic CTA proceeding to the Superior Courtapproximately $930.5 million 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 October 20, 2017, the NJBPU directed its staff to begin a formal rulemaking process to modify its CTA methodology.total estimated costs over five years.
OHIO
The Ohio Companies operate under PUCO-approved base distribution rates that became effective in 2009. 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. The Rider DMR will be grossed up for federal income taxes, resulting in an approved amount of approximately $204 million annually. Revenues from the 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 continues2024, that provides for the supply of power to non-shopping customers at a market-based price set through an auction process.
ESP IV also continues the Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $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 ofIn addition, ESP IV include:includes: (1) the collectioncontinuation of losta base distribution revenues associated with energy efficiency and peak demand reduction programs;rate freeze through May 31, 2024; (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 CO2 emissions by 90% below 2005 levels by 2045; (4)and (3) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio; 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 onOhio.
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, 2017,5, 2023, the Ohio Companies filed an application with the PUCO for rehearingapproval of ESP V, for an eight-year term beginning June 1, 2024, and continuing through May 31, 2032. ESP V proposes to continue providing power to non-shopping customers at market-based prices set through an auction process, with process enhancements designed to reduce costs to customers. ESP V also proposes to continue riders supporting investment in the Ohio Companies’ distribution system, including Rider DCR with annual revenue cap increases of $15 million to $21 million per year, based on reliability performance, and Rider AMI for recovery of approved grid modernization investments. ESP V proposes new riders to support continued maintenance of the PUCO’s August 16, 2017 rulingdistribution system, including vegetation management and storm restoration operating expense. In addition, ESP V proposes four-year energy efficiency and peak demand reduction programs for residential and commercial customers, with cost recovery spread over eight years. ESP V further includes a commitment to spend $52 million in total over the eight-year term, without recovery from customers, on the issuesinitiatives to assist low-income customers, education and incentives to help ensure customers have good experiences with electric vehicles. Hearings commenced on November 7, 2023 and concluded on December 6, 2023. On December 6, 2023, certain intervenors filed a motion requesting a limited stay of the third-party monitor andOhio Companies’ proposal to continue Rider DCR. The Ohio Companies contested the ROE calculation for advanced metering infrastructure. motion, which is pending.
On October 11, 2017, the PUCO denied the Ohio Companies' application for rehearing on both issues. On OctoberMay 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. For additional information, see “FERC Matters - Ohio ESP IV PPA” below.
Under ORC 4928.66,2022, the Ohio Companies are required to implement energy efficiency programsfiled their application for determination of the existence of SEET under ESP IV for calendar year 2021, which demonstrated that achieve certain annual energy savings and total peak demand reductions. Starting in 2017, ORC 4928.66 requireseach of the energy savings benchmark to increase by 1% andindividual Ohio Companies did not have significantly excessive earnings. This matter remains pending before 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. PUCO.
On AprilJuly 15, 2016,2022, the Ohio Companies filed an application with the PUCO for approval of phase two of their three-year energy efficiency portfolio plansdistribution grid modernization plan that would, among other things, provide for the period from January 1, 2017 through December 31, 2019. The plans as proposed comply with benchmarks contemplated by ORC 4928.66installation of an additional 700 thousand smart meters, distribution automation equipment on approximately 240 distribution circuits, voltage regulating equipment on approximately 220 distribution circuits, and provisions of the ESP IV,other investments and include a portfolio of energy efficiencypilot programs targetedin related technologies designed to a variety ofprovide enhanced 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.benefits. The Ohio Companies anticipate the cost of the planspropose that phase two will be implemented over a four-year budget period with estimated capital investments of approximately $268$626 million and operations and maintenance expenses of approximately $144 million over the lifedeployment period. Under the proposal, costs of phase two of the portfolio plans and such costs are expected togrid modernization plan would be recovered through the Ohio Companies’ existing rate mechanisms.AMI rider, pursuant to the terms and conditions approved in ESP IV. On April 12, 2024, the Ohio Companies and certain of the parties filed a stipulation that modified the Ohio Companies’ application for phase two of its grid modernization plan. The hearingsstipulation, which is subject to PUCO approval, provides for the deployment of smart meters to the balance of the Ohio Companies’ customers or approximately 1.4 million meters. Phase two of the distribution grid modernization plan, as modified by
the stipulation would be completed over a four-year budget period with estimated capital investments of approximately $421 million. On April 16, 2024, the PUCO scheduled the stipulation hearing for June 5, 2024.
On September 8, 2020, the OCC filed motions in the Ohio Companies’ corporate separation audit and DMR audit dockets, requesting the PUCO to open an investigation and management audit, hire an independent auditor, and require FirstEnergy to show it did not improperly use money collected from consumers or violate any utility regulatory laws, rules or orders in its activities regarding HB 6. On December 30, 2020, in response to the OCC's motion, the PUCO reopened the DMR audit docket, and directed PUCO staff to solicit a third-party auditor and conduct a full review of the DMR to ensure funds collected from customers through the DMR were heldonly used for the purposes established in ESP IV. On June 2, 2021, the PUCO selected an auditor, and the auditor filed the final audit report on January 2017.
14, 2022, which made certain findings and recommendations. The report found that spending of DMR revenues was not required to be tracked, and that DMR revenues, like all rider revenues, are placed into the regulated money pool as a matter of routine, where the funds lose their identity. Therefore, the report could not suggest that DMR funds were used definitively for direct or indirect support for grid modernization. The report also concluded that there was no documented evidence that ties revenues from the DMR to lobbying for the passage of HB 6, but also could not rule out with certainty uses of DMR funds to support the passage of HB 6. The report further recommended that the regulated companies' money pool be audited more frequently and the Ohio law requires electric utilitiesCompanies adopt formal dividend policies. Final comments and electric service companiesresponses were filed by parties during the second quarter of 2022. The proceeding was stayed 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 2015its entirety, including discovery and 2016motions, continuously at the 2014 level (2.5%), pushing back scheduled increases,request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner consolidated this proceeding with the expanded Rider DCR audit proceeding described below and set a procedural schedule, which resumed in 2017 (3.5%), and increases 1% each year through 2026 (to 12.5%) and shall remainwas vacated on March 15, 2024. A new procedural schedule will be set 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. Ina May 21, 2024 prehearing conference.
On September 2011,15, 2020, the PUCO opened a docketnew proceeding to review the Ohio Companies' alternative energy recovery rider through whichpolitical and charitable spending by the Ohio Companies recoverin support of HB 6 and the costs of acquiring these RECs. The PUCO issued an Opinionsubsequent referendum effort, 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 directeddirecting the Ohio Companies to credit non-shoppingshow cause, demonstrating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by customers. The Ohio Companies initially filed a response stating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by customers, but on August 6, 2021, filed a supplemental response explaining that, in light of the facts set forth in the amountDPA and the findings of $43.4 million, plus interest, on the basis thatRider DCR audit report further discussed below, political or charitable spending in support of HB 6, or the subsequent referendum effort, affected pole attachment rates paid by approximately $15 thousand. On October 26, 2021, the OCC filed a motion requesting the PUCO to order an independent external audit to investigate FE’s political and charitable spending related to HB 6, and to appoint an independent review panel to retain and oversee the auditor. In November and December 2021, parties filed comments and reply comments regarding the Ohio Companies’ original and supplemental responses to the PUCO’s September 15, 2020, show cause directive. On May 4, 2022, the PUCO selected a third-party auditor to determine whether the show cause demonstration submitted by the Ohio Companies didis sufficient to ensure that the cost of any political or charitable spending in support of HB 6 or the subsequent referendum effort was not prove such purchasesincluded, directly or indirectly, in any rates or charges paid by ratepayers. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner directed the third-party auditor to file its report by August 28, 2024.
In connection with an ongoing audit of the Ohio Companies’ policies and procedures relating to the code of conduct rules between affiliates, on November 4, 2020, the PUCO initiated an additional corporate separation audit as a result of the FirstEnergy leadership transition announcement made on October 29, 2020, as further discussed below. The additional audit is to ensure compliance by the Ohio Companies and their affiliates with corporate separation laws and the Ohio Companies’ corporate separation plan. The additional audit is for the period from November 2016 through October 2020. The final audit report was filed on September 13, 2021. The audit report makes no findings of major non-compliance with Ohio corporate separation requirements, minor non-compliance with eight requirements, and findings of compliance with 23 requirements. Parties filed comments and reply comments on the audit report. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner set a procedural schedule, which was vacated on March 15, 2024. A new procedural schedule will be set at an April 25, 2024 prehearing conference.
In connection with an ongoing annual audit of the Ohio Companies’ Rider DCR for 2020, and as a result of disclosures in FirstEnergy’s Form 10-K for the year ended December 31, 2020 (filed on February 18, 2021), the PUCO expanded the scope of the audit on March 10, 2021, to include a review of certain transactions that were prudent.either improperly classified, misallocated, or lacked supporting documentation, and to determine whether funds collected from customers were used to pay the vendors, and if so, whether or not the funds associated with those payments should be returned to customers through Rider DCR or through an alternative proceeding. On August 3, 2021, the auditor filed its final report on this phase of the audit, and the parties submitted comments and reply comments on this audit report in October 2021. Additionally, on September 29, 2021, the PUCO expanded the scope of the audit in this proceeding to determine if the costs of the naming rights for FirstEnergy Stadium have been recovered from the Ohio Companies’ customers. On November 19, 2021, the auditor filed its final report, in which the auditor concluded that the FirstEnergy Stadium naming rights expenses were not recovered from Ohio customers. On December 24, 2013, following15, 2021, the denialPUCO further expanded the scope of theirthe audit to include an investigation into an apparent nondisclosure of a side agreement in the Ohio Companies’ ESP IV settlement proceedings, but stayed its expansion of the audit until otherwise ordered
by the PUCO. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner consolidated this proceeding with the Rider DMR audit proceeding described above, further lifted the stay of the portion of the investigation relating to an apparent nondisclosure of a side agreement, and set a procedural schedule, which was vacated on March 15, 2024. A new procedural schedule will be set at a May 21, 2024 prehearing conference.
On March 1, 2024, the Attorney Examiner issued an Entry in all four PUCO investigations that, among other things, precluded taking or offering the testimony of Charles E. Jones, Michael J. Dowling, or Samuel Randazzo through deposition or other means, or requiring these individuals to produce documents, in any PUCO proceeding, until otherwise ordered.
On September 22, 2023, OCC filed an application for rehearing challenging the PUCO’s August 23, 2023, order to stay the pending HB 6 related matters above, which the PUCO denied on October 18, 2023. On November 17, 2023, OCC filed an application for rehearing challenging the October 18, 2023 entry to the extent the PUCO decided not to stay pending proceedings regarding ESP V as well as phases one and two of the Ohio Companies’ distribution grid modernization plans. On November 27, 2023, the Ohio Companies filed a noticememorandum contra OCC’s application for rehearing.
In the fourth quarter of appeal and a motion for stay of the PUCO's order2020, motions were filed with the Supreme CourtPUCO requesting that the PUCO amend the Ohio Companies’ riders for collecting the OVEC-related charges required by HB 6 to provide for refunds in the event such provisions of HB 6 are repealed. Neither the Ohio which was granted. On February 18, 2014,Companies nor FE benefit from the OCC andOVEC-related charges the ELPC also filed appeals ofOhio Companies collect. Instead, the PUCO's order.Ohio Companies are further required by HB 6 to remit all the OVEC-related charges they collect to non-FE Ohio electric distribution utilities. The Ohio Companies timelycontested the motions, which are pending before the PUCO.
On May 15, 2023, the Ohio Companies filed their merit brief withapplication for determination of the Supreme Courtexistence of SEET under ESP IV for calendar year 2022, which demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings. This matter remains pending before the PUCO.
See Note 9, “Commitments, Guarantees and Contingencies” below for additional details on the briefing process has concluded. Oral argument on this matter was held on June 21, 2017.
On April 9, 2014,government investigations and subsequent litigation surrounding the PUCO initiated a generic investigation of marketing practices in the competitive retail electric service market, with a focus on the marketing of fixed-price or guaranteed percent-off SSO rate contracts where there is a provision that permits the pass-through of new or additional charges. On November 18, 2015, the PUCO ruled that on a going-forward basis, pass-through clauses may not be included in fixed-price contracts for all customer classes. On December 18, 2015, FES filed an Application for Rehearing seeking to change the ruling or have it only apply to residential and small commercial customers. On January 13, 2016, the PUCO granted reconsideration for further consideration of the matters specified in the applications for rehearing. On March 29, 2017, the PUCO issued a Second Entry on Rehearing that granted, in part, the applications for rehearing filed by FES and other parties, finding that the PUCO’s guidelines regarding fixed-price contracts should not apply to large mercantile customers. This finding changes the original order, which applied the guidelines to all customers, including mercantile customers. The PUCO also reaffirmed several provisions of the original order, including that the fixed-price guidelines only apply on a going-forward basis and not to existing contracts and that regulatory-out clauses in contracts are permissible.HB 6.
PENNSYLVANIA
The Pennsylvania Companies operateoperated 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.
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 increasesOn January 1, 2024, each of the Pennsylvania Companies merged with and into FE PA. As a result of the PA Consolidation, FE PA will have five rate districts in operating revenues of approximately $96 million atPennsylvania – four that correspond to the territories previously serviced by ME, $100 million at PN, $29 million at Penn, and $66 million at WP and are intendedone rate district that corresponds to benefit customersWP’s service provided to The Pennsylvania State University. The rate districts created by modernizing the grid with smart technologies, increasing vegetation management activities, and continuing other customer service enhancements.PA Consolidation will not reach full rate unity until the earlier of 2033 or the conclusion of three base rate cases filed after January 1, 2025.
Pursuant to Pennsylvania's EE&C legislation inPennsylvania Act 129 of 2008 and PPUC orders, the Pennsylvania EDCs implementCompanies implemented energy efficiency and peak demand reduction programs. On June 19, 2015, the PPUC issued a Phase III Final Implementation Order setting:programs with demand reduction targets, relative to each Pennsylvania Companies' 2007-2008 peak demand (in MW),demands, at 1.8%2.9% MW for ME, 1.7%3.3% MW for PN, 2.0% MW for Penn, 1.8%and 2.5% MW for WP, and 0% for PN;WP; and energy consumption reduction targets, as a percentage of eachthe Pennsylvania Companies’ historic 2009 to 2010 forecasts (in MWH),reference load at 4.0%3.1% MWh for ME, 3.9%3.0% MWh for PN, 3.3%2.7% MWh for Penn, and 2.6%2.4% MWh for WP. The Pennsylvania Companies' Phase III EE&C plansfourth phase of FE PA’s energy efficiency and peak demand reduction program, which runs for the five-year period beginning June 20161, 2021 through May 2021 period, which were31, 2026, was approved in March 2016, with expected costs up toby the PPUC on June 18, 2020, providing through cost recovery of approximately $390 million are designed to achieve the targets established in the PPUC'sbe recovered through Energy Efficiency and Conservation Phase III Final Implementation Order with full recovery through the reconcilable EE&C riders.IV Riders for each FE PA rate district.
Pursuant to Act 11 of 2012, Pennsylvania EDCs may establish a DSICare permitted to recover costsseek PPUC approval of an LTIIP for 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 priorafter which a DSIC may be approved to approval of a DSIC.recover LTIIP costs. On February 11, 2016,January 16, 2020, the PPUC approved LTIIPs for each of the Pennsylvania Companies. On June 14, 2017, the PPUC approved modifiedCompanies’ 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 five-year period beginning January 1, 2020 and ending December 31, 2024 for a total capital investment of 2016approximately $572 million for certain infrastructure improvement initiatives. FE PA expects to 2020, as modified, are: WP $88.3 million; PN $60.0 million; Penn $58.9 million; and ME $51.6 million.
On February 16, 2016, the Pennsylvania Companies filed DSIC riders for PPUCseek approval for quarterly cost recovery, which were approvedthe next phase of its LTIIP program 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, inend of the PPUC’s order approvingthird quarter of 2024.
Following the Pennsylvania Companies’ general2016 base rate cases,proceedings, the PPUC added an additional issueruled in a separate proceeding related 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, which is pending PPUC approval. The ADIT issue is subject to further litigation and a hearing was held on May 12, 2017. On August 31, 2017, the ALJ issued a decision recommending that the complaint of the Pennsylvania Office of Consumer Advocate be granted by the PPUC suchmechanisms that the Pennsylvania Companies were not required to reflect all federal and state income tax deductions related to DSIC-eligible property in the currently effective DSIC rates. IfThe decision was appealed to the Pennsylvania Supreme Court and in July 2021 the court upheld the Pennsylvania Commonwealth Court’s reversal of the PPUC’s decision isand remanded the matter back to the PPUC for determination as to how DSIC calculations shall account for accumulated deferred income taxes and state taxes. The PPUC issued the order as directed.
On May 5, 2023, FirstEnergy and Brookfield submitted applications to FERC and to the PPUC to facilitate the FET Equity Interest Sale. On May 12, 2023, the parties also filed an application with the VSCC, which was approved on June 20, 2023. On August 14, 2023, FERC issued an order approving the FET Equity Interest Sale. On November 24, 2023, CFIUS notified FET, Brookfield and the Abu Dhabi Investment Authority, as an indirect investor in FET through Brookfield, that it had determined that there were no unresolved national security issues and its review of the transaction was concluded. On November 29, 2023, the
parties filed a settlement agreement recommending that the PPUC approve the transaction subject to the terms of the settlement, which includes among other things, a number of ring-fencing provisions and a commitment to improve transmission reliability over the next five years. The settlement was approved by the PPUC on March 14, 2024. The transaction closed on March 25, 2024.
On April 2, 2024, FE PA filed a base rate case with the PPUC, based on a projected 2025 annual test year. The rate case requests a net increase in base distribution revenues of approximately $502 million with a return on equity of 11.3% and capital structure of 46.2% debt and 53.8% equity, and reflects a roll-in of several current riders such as DSIC, Tax Act and smart meter. The increase represents an overall net average rate increase in FE PA rates by approximately 7.7%, and a 10.5% average residential rate increase. Key components of the base rate case filing include a proposal to change pension and OPEB recovery to the delayed recognition method and to implement a mechanism to establish a regulatory asset (or liability) to recover (or refund) net differences between the amount of pension and OPEB expense requested in the proceeding and the actual annual amount each year using this method. Additionally, FE PA requests recovery of certain incurred costs, including the impact of major storms, COVID-19, a program to convert streetlights to LEDs, and others. The PPUC issued an order on April 25, 2024, deferring, by operation of law, the June 1, 2024 statutory effective date to January 1, 2025. A pre-hearing conference is notscheduled for May 2, 2024. A PPUC decision is expected to be material to FirstEnergy. The Pennsylvania Companies filed exceptions to the decision on September 20, 2017, and reply exceptions on October 2, 2017.in December 2024, with new rates becoming effective in January 2025.
WEST VIRGINIA
MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking.ratemaking and operate under WVPSC-approved rates. 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'sMP’s and PE'sPE’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 by the parties to the proceeding, 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 MayAugust 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 October 6, 2017, MP and PE proposed an annual decrease in their EE&C rates, effective January 1, 2018, which is not expected to be material to FirstEnergy.
On December 9, 2016, the WVPSC approved the annual ENEC case for MP and PE as reflected in a unanimous settlement by the parties to the proceeding, 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.
On December 30, 2015, MP and PE filed an IRP with the WVPSC identifying a capacity shortfall starting in 2016 and exceeding 700 MWs by 2020 and 850 MWs by 2027. On June 3, 2016, the WVPSC accepted the IRP. On December 16, 2016, MP issued an RFP to address its generation shortfall, along with issuing a second RFP to sell its interest in Bath County. Bids were received by an independent evaluator in February 2017 for both RFPs. AE Supply was the winning bidder of the 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 MW) for approximately $195 million, subject to customary and other closing conditions, including regulatory approvals. In addition, on March 7, 2017, MP and PE filed an application with the WVPSC and MP and AE Supply filed an application with FERC requesting authorization for such purchase. The WVPSC held an evidentiary hearing commencing on September 26, 2017, and public hearings were held on September 6, 11, and 12, 2017. An order is anticipated by early 2018. On June 27, 2017, FERC issued a deficiency letter requesting additional information to facilitate FERC���s review of the transaction. MP responded to the deficiency letter on July 18, 2017, and to related protests and comments on August 28, 2017. The applications remain pending before the WVPSC and FERC, respectively. With respect to the Bath County RFP, MP does not plan to move forward with that sale of its ownership interest. In the future, MP may re-evaluate its options with respect to its interest in Bath County.
On September 1, 2017,2023, MP and PE filed with the WVPSC their annual ENEC case requesting an increase in ENEC rates of $167.5 million beginning January 1, 2024, which represents a 9.9% increase in overall rates. This increase, which was driven primarily by higher fuel expenses, includes the approximate $92 million carried over from the 2022 ENEC proceeding and a portion of the approximately $267 million under recovery balance at the end of the review period (July 1, 2022 to June 30, 2023). The remaining $75.6 million of the under recovery balance not recovered in 2024 will be deferred for collection during 2025, with an annual carrying charge of 4%. A hearing was held on November 30, 2023, at which time a joint stipulation for settlement that was agreed to by all but one party was presented to the WVPSC. The settlement provides for a reconciliationnet $55.4 million increase in ENEC rates beginning March 27, 2024 with the net deferred ENEC balance of their VMSapproximately $255 million to confirm that rate recovery matches VMP costs and for a regular review of that program.be recovered through 2026. There will be no 2024 ENEC case unless MP and PE proposedover or under recover more than $50 million than the 2024 ENEC balance and a $15 million annual decreaseparty elects to invoke a case filing. An order was issued on March 26, 2024 approving the settlement without modification and rates became effective on March 27, 2024.
On April 21, 2022, the WVPSC issued an order approving, effective May 1, 2022, a tariff to offer solar power to West Virginia customers and requiring MP and PE to subscribe at least 85% of the planned 50 MWs of solar generation before seeking final tariff approval. MP and PE must seek separate approval from the WVPSC to recover any solar generation costs in VMS rates effectiveexcess of the approved tariff. On April 24, 2023, MP and PE sought final tariff approval from the WVPSC for three of the five solar sites, representing 30 MWs of generation, and requested approval of a surcharge to recover any costs above the final approved tariff. The first solar generation site went into service in January 2024 and construction of the remaining four sites are expected to be completed no later than the end of 2025 at a total investment cost of approximately $110 million. On August 23, 2023, the WVPSC approved the customer surcharge and granted approval to construct three of the five solar sites. The surcharge went into effect January 1, 2018,2024.
On January 13, 2023, MP and an additional $15 million decrease inPE filed a request with the WVPSC seeking approval of new depreciation rates for 2019. This is an overall decreaseexisting and future capital assets. Specifically, MP and PE are seeking to increase depreciation expense by approximately $76 million per year, primarily for regulated generation-related assets. Any depreciation rates approved by the WVPSC would not become effective until new base rates were established. On August 22, 2023, a unanimous settlement of the case was filed recommending a $33 million per year increase in depreciation expense, effective April 1, 2024. An order from the WVPSC was issued on March 26, 2024 approving the settlement without modification and became effective on March 27, 2024.
On May 31, 2023, MP and PE filed a base rate case with the WVPSC requesting a total revenue increase of approximately $207 million utilizing a test year of 2022 with adjustments plus a request to establish a regulatory asset (or liability) to recover (or refund) in a subsequent base rate case the net differences between the amount of pension and OPEB expense requested in the proceeding (based on average expense from 2018 to 2022) and the actual annual amount each year using the delayed recognition method. Among other things, the increase includes the approximate $76 million requested in a depreciation case filed on January 13, 2023 and described above, and amounts to support a new low-income customer advocacy program, storm restoration work and service reliability investments. On January 23, 2024, MP, PE and various parties filed a joint settlement agreement with the WVPSC, which recommended a base rate increase of $105 million, inclusive of the $33 million increase in depreciation expense. Additionally, the settlement includes a new low-income customer advocacy program, a pilot program for service reliability investments and recovery of costs related to storm restoration, retired generation assets and COVID-19. The settlement did not include the request to establish a regulatory asset (or liability) for recover (or refund) associated with pension and OPEB expense, however, it did not preclude MP and PE from pursuing that in a future separate proceeding. On February 16, 2024, interested parties filed a settlement on the net energy metering credit for consideration by the WVPSC. An order was
issued on March 26, 2024 approving the $105 million increase and accepting the settlement with slight non-material modifications with new rates going into effect on March 27, 2024. Additionally, due to the order including approval by the WVPSC to recover certain costs associated with retired generation assets, MP recognized a $60 million pre-tax benefit in the first quarter of 1%.2024 to establish a regulatory asset.
RELIABILITYFERC REGULATORY MATTERS
Federally-enforceableUnder the Federal Power Act, FERC regulates rates for interstate wholesale sales and transmission of electric power, regulatory accounting and reporting under the Uniform System of Accounts, and other matters, including construction and operation of hydroelectric projects. With respect to their wholesale services and rates, the Utilities, AE Supply and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE and the Transmission Companies are subject to functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff. On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo.
FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers to entry into markets. The Utilities and AE Supply each have the necessary authorization from FERC to sell their wholesale power, if any, in interstate commerce at market-based rates, although in the case of the Utilities major wholesale purchases remain subject to review and regulation by the relevant state commissions.
Federally enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES and certain of its subsidiaries, AE Supply, FENOC, ATSI, MAIT and TrAIL.the Transmission Companies. NERC is the EROElectric Reliability Organization 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 eightsix regional entities, including RFC. All of FirstEnergy'sthe facilities that FirstEnergy operates 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 including FES, believes that it is in material compliance with all currently-effectivecurrently effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy including FES, occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy including FES, develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy's, including FES,FirstEnergy’s part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, andor obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations, and cash flows.
FERC MATTERSAudit
Ohio ESP IV PPA
FERC’s Division of Audits and Accounting initiated a nonpublic audit of FESC in February 2019. Among other matters, the audit is evaluating FirstEnergy’s compliance with certain accounting and reporting requirements under various FERC regulations. On AugustFebruary 4, 2014,2022, FERC filed the Ohio Companies filed an application withfinal audit report for the PUCO seeking approvalperiod of their ESP IV. ESP IVJanuary 1, 2015 through September 30, 2021, which included several findings and recommendations that FirstEnergy has accepted. The audit report included a proposed Rider RRS, which would flow throughfinding and related recommendation on FirstEnergy’s methodology for allocation of certain corporate support costs to customers either charges or credits representing the net result of the price paid to FES through an eight-year FERC-jurisdictional PPA, referred to as the ESP IV PPA, against the revenues received from selling such output into the PJM markets. The Ohio Companies entered into stipulations which modified ESP IV,regulatory capital accounts under certain FERC regulations and on March 31, 2016, the PUCO issued an Opinion and Order adopting and approving the Ohio Companies’ stipulated ESP IV with modifications. FES and the Ohio Companies entered into the ESP IV PPA on April 1, 2016, but subsequently agreed to suspend it and advised FERC of this course of action.
On March 21, 2016, a number of generation owners filed with FERC a complaint against PJM requesting that FERC expand the MOPRreporting. Effective in the PJM Tariff to prevent the alleged artificial suppressionfirst quarter of prices2022 and in the PJM capacity markets by state-subsidized generation, in particular alleged price suppression that could result from the ESP IV PPA and other similar agreements. The complaint requested that FERC direct PJM to initiate a stakeholder process to develop a long-term MOPR reform for existing resources that receive out-of-market revenue. On January 9, 2017, the generation owners filed to amend their complaint to include challenges to certain legislation and regulatory programs in Illinois. On January 24, 2017, FESC, acting on behalf of its affected affiliates and along with other utility companies, filed a motion to dismiss the amended complaint for various reasons, including that the ESP IV PPA matter is now moot. In addition, on January 30, 2017, FESC along with other utility companies filed a substantive protestresponse to the amended complaint, demonstrating thatfinding, FirstEnergy had implemented a new methodology for the questionallocation of the proper rolethese corporate support costs to regulatory capital accounts for state participation in generation development should be addressed in the PJM stakeholder process. On August 30, 2017, the generation owners requested expedited action by FERC. This proceeding remains pending before FERC.
PJM Transmission Rates
PJMits regulated distribution and its stakeholders have been debating the proper method to allocate costs for certain transmission facilities. While FirstEnergy and other parties advocate for a traditional "beneficiary pays" (or usage based) approach, others advocate for “socializing” the costscompanies on a load-ratio share basis, where each customer inprospective basis. With the zone would pay based on its total usageassistance of energy within PJM. This question has beenan independent outside firm, FirstEnergy completed an analysis during the subjectthird quarter of extensive litigation before FERC and the appellate courts, including before the Seventh Circuit. On June 25, 2014, a divided three-judge panel of the Seventh Circuit ruled that FERC had not quantified the benefits that western PJM utilities would derive from certain new 500 kV or higher lines and thus had not adequately supported its decision to socialize the costs2022 of these lines. The majority found that eastern PJM utilities are the primary beneficiaries of the lines, while western PJM utilities are only incidental beneficiaries,costs and that, while incidental beneficiaries should pay some share of the costs of the lines, that share should be proportionate to the benefit they derive from the lines, and not on load-ratio share in PJM as a whole. The court remanded the case to FERC, which issued an order setting the issue of cost allocation for hearing and settlement proceedings. On June 15, 2016, various parties, including ATSI and the Utilities, filed a settlement agreement at FERC agreeing to apply a combined usage based/socialization approach to cost allocation for charges tohow it impacted certain FERC-jurisdictional wholesale transmission customers in the PJM Region for transmission projects operating at or above 500 kV. Certain other parties in the proceeding did not agree to the settlement and filed protests to the settlement seeking, among other issues, to strike certain of the evidence advanced by FirstEnergy and certain of the other settling parties in support of the settlement, as well as provided further comments in opposition to the settlement. FirstEnergy and certain of the other parties responded to such opposition. The settlement is pending before FERC.
RTO Realignment
On June 1, 2011, ATSI and the ATSI zone transferred from MISO to PJM. While many of the matters involved with the move have been resolved, FERC denied recovery under ATSI's transmission rate for certain charges that collectively can be described as "exit fees" and certain other transmission cost allocation charges totaling approximately $78.8 million until such time as ATSI submits a cost/benefit analysis demonstrating net benefits to customers from the transfer to PJM. Subsequently, FERC rejected a proposed settlement agreement to resolve the exit fee and transmission cost allocation issues, stating that its action is without prejudice to ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh the exit fee and transmission cost allocation charges. On March 17, 2016, FERC denied FirstEnergy's request for rehearing of FERC's earlier order rejecting the settlement agreement and affirmed its prior ruling that ATSI must submit the cost/benefit analysis.
Separately, ATSI resolved a dispute regarding responsibility for certain costscustomer rates for the “Michigan Thumb” transmission project. Potential responsibility arises under the MISO MVP tariff, which has been litigated in complex proceedings before FERC and certain U.S. appellate courts. On October 29,audit period of 2015 FERC issued an order finding that ATSI and the ATSI zone do not have to pay MISO MVP charges for the Michigan Thumb transmission project. MISO and the MISO TOs filed a request for rehearing, which FERC denied on May 19, 2016. The MISO TOs subsequently filed an appeal of FERC's orders with the Sixth Circuit. FirstEnergy intervened and participated in the proceedings on behalf of ATSI, the Ohio Companies and PP. On June 21, 2017, the Sixth Circuit issued its decision denying the MISO TOs' appeal request. September 19, 2017 was the deadline for MISO and the MISO TOs to seek review by the U.S. Supreme Court. They did not file for review, effectively resolving the dispute over the "Michigan Thumb" transmission project. On a related issue, FirstEnergy joined certain other PJM TOs in a protest of MISO's proposal to allocate MVP costs to energy transactions that cross MISO's borders into the PJM Region. On July 13, 2016, FERC issued its order finding it appropriate for MISO to assess an MVP usage charge for transmission exports from MISO to PJM. Various parties, including FirstEnergy and the PJM TOs, requested rehearing or clarification of FERC’s order. The requests for rehearing remain pending before FERC.
In addition, in a May 31, 2011 order, FERC ruled that the costs for certain "legacy RTEP" transmission projects in PJM approved before ATSI joined PJM could be charged to transmission customers in the ATSI zone. The amount to be paid, and the question of derived benefits, is pending before FERC as a result of the Seventh Circuit's June 25, 2014 order described above under "PJM Transmission Rates."
The outcome of the proceedings that address the remaining open issues related to MVP costs and "legacy RTEP" transmission projects cannot be predicted at this time.
MAIT Transmission Formula Rate
On October 28, 2016, MAIT submitted an application to FERC requesting authorization to implement a forward-looking formula transmission rate to recover and earn a return on transmission assets effective January 1, 2017. Various intervenors submitted protests of the proposed MAIT formula rate. Among other things, the protest asked FERC to suspend the proposed effective date for the formula rate until June 1, 2017. On March 10, 2017, FERC issued an order accepting the MAIT formula transmission rate for filing, suspending it for five months, and establishing hearing and settlement judge procedures. On April 10, 2017, MAIT requested rehearing of FERC’s decision to suspend the effective date of the formula rate. FERC's order on rehearing remains pending. MAIT’s rates went into effect on July 1, 2017, subject to refund pending the outcome of the hearing and settlement procedures. On October 13, 2017, MAIT and certain parties filed a settlement agreement with FERC. The settlement agreement provides for certain changes to MAIT's formula rate template and protocols, changes MAIT's ROE from 11% to 10.3%, sets the recovery amount for certain regulatory assets, and establishes that MAIT's capital structure will not exceed 60% equity over the period ending December 31,through 2021. The settlement agreement further provides that the ROE and the 60% cap on the equity component of MAIT's capital structure will remain in effect unless changed pursuant to section 205 or 206 of the FPA provided the effective date for any change shall be no earlier than January 1, 2022. The settlement agreement currently is pending at FERC. As a result of the settlement agreement, MAIT recognized a pre-tax impairment charge of $13 millionthis analysis, FirstEnergy recorded in the third quarter of 2017.2022 approximately $45 million ($34 million after-tax) in expected customer refunds, plus interest, due to its wholesale transmission customers and reclassified approximately $195 million of certain transmission capital assets to operating expenses for the audit period, of which $90 million ($67 million after-tax) are not expected to be recoverable and impacted FirstEnergy’s earnings since they relate to costs capitalized during stated transmission rate time periods. FirstEnergy is currently recovering approximately $105 million of costs reclassified to operating expenses in its transmission formula rate revenue requirements, of which $39 million of costs have been recovered as of March 31, 2024. On December 8, 2023, FERC audit staff issued a letter advising that two unresolved audit matters, primarily related to FirstEnergy’s plan to recover the reclassified operating expenses in formula transmission rates, were being referred to other offices within FERC for further review. These reclassifications also resulted in a reduction to the Regulated Transmission segment’s rate base by approximately $160 million, which is not expected to materially impact FirstEnergy or the segment’s future earnings. The expected wholesale transmission customer refunds were recognized as a reduction to revenue, and the amount of reclassified transmission capital assets that are not expected to be recoverable were recognized within “Other operating expenses” at the Regulated Transmission segment and on FirstEnergy’s Consolidated Statements of Income. Furthermore, FirstEnergy’s Utilities are in the
JCP&L Transmission Formula Rate24
process of addressing the outcomes of the FERC Audit with the applicable state commissions and proceedings, which includes seeking continued rate base treatment of approximately $200 million of certain corporate support costs allocated to distribution capital assets in Ohio and Pennsylvania. If FirstEnergy is unable to recover these transmission or distribution costs, it could result in future charges and/or adjustments and have an adverse impact on FirstEnergy’s financial condition.
ATSI ROE – Ohio Consumers Counsel v. ATSI, et al.
On October 28, 2016, after withdrawing its requestFebruary 24, 2022, the OCC filed a complaint with FERC against ATSI, AEP’s Ohio affiliates and American Electric Power Service Corporation, and Duke Energy Ohio, LLC asserting that FERC should reduce the ROE utilized in the utilities’ transmission formula rates by eliminating the 50 basis point adder associated with RTO membership, effective February 24, 2022. The OCC contends that this result is required because Ohio law mandates that transmission owning utilities join an RTO and that the 50 basis point adder is applicable only where RTO membership is voluntary. On December 15, 2022, FERC denied the complaint as to ATSI and Duke, but granted it as to AEP. AEP and OCC appealed FERC’s orders to the NJBPUSixth Circuit and the case remains pending. FirstEnergy is unable to transfer its transmission assetspredict the outcome of this proceeding, but it is not expected to MAIT, JCP&L submitted an application to FERC requesting authorization to implementhave a forward-looking formulamaterial impact.
Transmission ROE Methodology
A proposed rulemaking proceeding concerning transmission rate to recover and earn a return on transmission assets effective January 1, 2017. A groupincentives provisions of intervenors, including the NJBPU and New Jersey Division of Rate Counsel, filed a protestSection 219 of the proposed JCP&L transmission rate.2005 Energy Policy Act was initiated in March of 2020 remains pending before FERC. Among other things, the protest asked FERC to suspendrulemaking explored whether utilities should collect an “RTO membership” ROE incentive adder for more than three years. FirstEnergy is a member of PJM and its transmission subsidiaries could be affected by the proposed effective date forrulemaking. FirstEnergy participated in comments on the formula rate until June 1, 2017. On March 10, 2017, FERC issued an order accepting the JCP&L formulasupplemental rulemaking that were submitted by a group of PJM transmission rate for filing, suspending it for five months,owners and establishing hearing and settlement judge procedures. On April 10, 2017, JCP&L requested rehearing of FERC’s decisionby various industry trade groups. If there were to suspend the effective date of the formula rate. FERC's orderbe any changes to FirstEnergy's transmission incentive ROE, such changes will be applied on rehearing remains pending. JCP&L’s rates went into effect on June 1, 2017, subject to refund pending the outcome of the hearing and settlement procedures. The settlement process is ongoing.a prospective basis.
DOE NOPR: Grid Reliability and Resilience Pricing, FERC Docket No. RM18-1Transmission Planning Supplemental Projects: Ohio Consumers Counsel v ATSI, et al.
On September 28, 2017,27, 2023, the SecretaryOCC filed a complaint against ATSI, PJM and other transmission utilities in Ohio alleging that the PJM Tariff and operating agreement are unjust, unreasonable, and unduly discriminatory because they include no provisions to ensure PJM’s review and approval for the planning, need, prudence and cost-effectiveness of Energy releasedthe PJM Tariff Attachment M-3 “Supplemental Projects.” Supplemental Projects are projects that are planned and constructed to address local needs on the transmission system. The OCC demands that FERC: (i) require PJM to review supplemental projects for need, prudence and cost-effectiveness; (ii) appoint an independent transmission monitor to assist PJM in such review; and (iii) require that Supplemental Projects go into rate base only through a NOPR requesting“stated rate” procedure whereby prior FERC to issue rules directing RTOs to incorporate pricingapproval would be needed for defined “eligible grid reliability and resiliency resources” into wholesale energy markets. Specifically, as proposed, RTOs would develop and implement tariffs providing a just and reasonable rate for energy purchases from eligible grid reliability and resiliency resourcesprojects with costs that exceed an established threshold. ATSI and the recovery of fully allocated costsother transmission utilities in Ohio and a fair ROE. This NOPR follows the August 23, 2017 release of the DOE’s study regarding whether federally controlled wholesale energy markets properly recognize the importance of coal and nuclear plants for the reliability of the high-voltage grid, as well as whether federal policies supporting renewable energy sources have harmed the reliability of the energy grid. The DOE has requested for the final rules to be effective in January 2018.
FERC is not required to adopt the rules proposed by the DOE in the NOPR. FERC could take other actions as it deems fit pursuant to its statutory authority. On October 2, 2017, FERC established a docket and requestedPJM filed comments on the NOPR. On October 23, 2017, FESC and certain of its affiliates submitted comments. Reply comments are due November 7, 2017. At this time, we are uncertain as to the potential impact that final rules adopted by FERC, if any, would have on FES and our strategic options, and the timing thereof, with respect to the competitive business.complaint is pending before FERC.
PATH Transmission Project
In 2012, the PJM Board of Managers canceled the PATH project, a proposed transmission line from West Virginia through Virginia and into Maryland. As a result of PJM canceling the project, approximately $62 million and approximately $59 million in costs incurred by PATH-Allegheny and PATH-WV, respectively, were reclassified from net property, plant and equipment to a regulatory asset for future recovery. PATH-Allegheny and PATH-WV requested authorization from FERC to recover the costs with a proposed ROE of 10.9% (10.4% base plus 0.5% for RTO membership) from PJM customers over five years. FERC issued an order denying the 0.5% ROE adder for RTO membership and allowing the tariff changes enabling recovery of these costs to become effective on December 1, 2012, subject to hearing and settlement procedures. On January 19, 2017, FERC issued an order reducing the PATH formula rate ROE from 10.4% to 8.11% effective January 19, 2017 and allowing recovery of certain related costs. On February 21, 2017, PATH filed a request for rehearing with FERC seeking recovery of disallowed costs and requesting that the ROE be reset to 10.4%. The Edison Electric Institute submitted an amicus curiae request for reconsideration in support of PATH. On March 20, 2017, PATH also submitted a compliance filing implementing the January 19, 2017 order. Certain affected ratepayers commented on the compliance filing, alleging inaccuracies in and lack of transparency of data and information in the compliance filing, and requested that PATH be directed to recalculate the refund provided in the filing. PATH responded to these comments in a filing that was submitted on May 22, 2017. On July 27, 2017, FERC Staff issued a letter to PATH requesting additional information on, and edits to, the compliance filing, as directed by the January 19, 2017 order. PATH filed its response on September 27, 2017.FERC orders on PATH's requests for rehearing and compliance filing remain pending.
Market-Based Rate Authority, Triennial Update
The Utilities, AE Supply, FES and its subsidiaries, Buchanan Generation, LLC, and Green Valley Hydro, LLC each hold authority from FERC to sell electricity at market-based rates. One condition for retaining this authority is that every three years each entity must file an update with the FERC that demonstrates that each entity continues to meet FERC’s requirements for holding market-based rate authority. On December 23, 2016, FESC, on behalf of its affiliates with market-based rate authority, submitted to FERC the most recent triennial market power analysis filing for each market-based rate holder for the current cycle of this filing requirement. On July 27, 2017, FERC accepted the triennial filing as submitted.
11.9. 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,LOCs, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party.
As of September 30, 2017, FirstEnergy'sMarch 31, 2024, outstanding guarantees and other assurances aggregated approximately $3.3 billion,$820 million, consisting of parental guarantees on behalf of its consolidated subsidiaries ($649 million), subsidiaries' guarantees ($1.9 billion), other guarantees ($300520 million) and other assurances ($457300 million).
Of the aggregate amount, substantially all relates to guarantees of wholly-owned consolidated entities of FirstEnergy. FES' debt obligations are generally guaranteed by its subsidiaries, FG and NG, and FES guarantees the debt obligations of each of FG and NG. Accordingly, present and future holders of indebtedness of FES, FG and NG would have claims against each of FES, FG and NG, regardless of whether their primary obligor is FES, FG or NG.
COLLATERAL AND CONTINGENT-RELATED FEATURES
In the normal course of business, FE and its subsidiaries routinelymay 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'sFE’s or its subsidiaries'subsidiaries’ credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental
As of March 31, 2024, $119 million of net cash 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 intohas been posted by FE andor its subsidiaries have margining provisions that require postingand is included in “Prepaid taxes and other current assets” on FirstEnergy’s Consolidated Balance Sheets. FE or its subsidiaries are holding $33 million of collateral. Based on CES' power portfolio exposurenet cash collateral as of September 30, 2017, FES has posted collateral of $128 millionMarch 31, 2024, from certain generation suppliers, and AE Supply has posted collateral of $2 million. The Regulated Distribution Segment has posted collateral of $3 million.such amount is included in “Other current liabilities” on FirstEnergy’s Consolidated Balance Sheets.
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 September 30, 2017.March 31, 2024:
|
| | | | | | | | | | | | | | | | | | | | |
| Potential Collateral Obligations | | FES | | AE Supply | | Regulated | | FE Corp | | Total |
| | | | (In millions) |
| Contractual Obligations for Additional Collateral | | | | | | | | | | |
| At Current Credit Rating | | $ | 6 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 8 |
|
| Upon Further Downgrade | | — |
| | — |
| | 42 |
| | — |
| | 42 |
|
Surety Bonds (Collateralized Amount)(1) | | 48 |
| | 24 |
| | 105 |
| | 185 |
| | 362 |
|
| Total Exposure from Contractual Obligations | | $ | 54 |
| | $ | 26 |
| | $ | 147 |
| | $ | 185 |
| | $ | 412 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Potential Collateral Obligations | | | | | | Utilities and Transmission Companies | | FE | | Total |
| | | | (In millions) |
| Contractual obligations for additional collateral | | | | | | | | | | |
| | | | | | | | | | |
| Upon further downgrade | | | | | | $ | 63 | | | $ | — | | | $ | 63 | |
| | | | | | | | | | |
Surety bonds (collateralized amount)(1) | | | | | | 87 | | | 79 | | | 166 | |
| Total Exposure from Contractual Obligations | | | | | | $ | 150 | | | $ | 79 | | | $ | 229 | |
(1)Surety Bonds are not tied to a credit rating. Surety Bonds'Bonds’ impact assumes maximum contractual obligations, (typicalwhich is ordinarily 100% of the face amount of the surety bond except with respect to $39 million of surety bond obligations for which the collateral obligation is capped at 60% of the face amount, and typical obligations require 30 days to cure). FE provides credit support for $169 million of FG surety bonds for the benefit of the PA DEP with respect to LBR.cure.
Excluded from the preceding table are the potential collateral obligations due to affiliate transactions between the Regulated Distribution segment and CES segment. As of September 30, 2017, FES has $2 million of collateral posted with its affiliates.
OTHER COMMITMENTS AND CONTINGENCIES
FE is a guarantor under a syndicated senior secured term loan facility due March 3, 2020, under which Global Holding borrowed $300 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 guaranties 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, hazardous and solid waste disposal, and other environmental matters. PursuantWhile FirstEnergy’s environmental policies and procedures are designed to a March 28, 2017 executive order,achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and potential revision by 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.implementing agencies. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof in particular with respect to existing environmental regulations, may materially 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 SO2 and NOx emission reduction requirements under the CAA and SIP(s)SIP by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls generating more electricity from lower or non-emitting plants and/or using emission allowances.
CSAPR requires reductions of NOx and SO2 emissions in two phases (2015 and 2017), ultimately capping SO2 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 SO2 emission allowances between power plants located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. The U.S. Court of Appeals forOn July 28, 2015, the D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO2 emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia. This followsfollowed 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 ruleUpdate 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 ruleUpdate to the D.C. Circuit in November and December 2016. On September 6, 2017,13, 2019, 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, EPA’s reconsideration ofremanded the CSAPR update rule and how EPA and the states ultimately implement CSAPR, the future cost of compliance may be material and changesUpdate to FirstEnergy's and FES' 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 countiesciting that failthe rule did not eliminate upwind states’ significant contributions to attain the new 2015 ozone NAAQS by October 1, 2017. The EPA missed the October 1, 2017 deadline and has not yet promulgated thedownwind states’ air quality attainment designations. States will then have roughly threeyears to develop implementation plans to attain 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 and FES’ operations may result. In August 2016,requirements within applicable attainment deadlines.
Also in March 2018, 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 Delaware's CAA Section 126 petition by six months to April 7, 2017 but has not taken any further action. In November 2016, the State of MarylandNew York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from 36 EGUs, including Harrison Units 1, 2 and 3, Mansfield Unit 1 and Pleasants Units 1 and 2,nine states (including West Virginia) significantly contribute to Maryland'sNew York’s inability to attain the ozone NAAQS.National Ambient Air Quality Standards. The petition seeks NOxsought suitable emission rate limits for large stationary sources that are allegedly affecting New York’s air quality within the 36 EGUsthree years allowed by May 1, 2017.CAA Section 126. On January 3, 2017,September 20, 2019, the EPA extended the time frame for acting on thedenied New York’s CAA Section 126 petition by six months to July 15, 2017 but has not taken any further action.petition. On September 27, 2017 and October 4, 2017,29, 2019, the State of Maryland and various environmental organizations filed complaints inNew York appealed the U.S. District Court for the Districtdenial of Maryland seeking an order that EPA either approve or deny the CAA Section 126its petition of November 16, 2016. 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 electric generating units 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 August 3, 2015, FG, a wholly owned subsidiary of FES, submitted to the AAA office inD.C. Circuit. On July 14, 2020, the D.C. Circuit reversed and remanded the New York N.Y., a demand for arbitration and statement of claim against BNSF and CSX seeking a declaration that MATS constituted a force majeure event that excuses FG’s performance under its coal transportation contract with these parties. Specifically, the dispute arose from a contract for the transportation by BNSF and CSX of a minimum of 3.5 million tons of coal annually through 2025 to certain coal-fired power plants owned by FG that are located in Ohio. As a result of and in compliance with MATS, all plants covered by this contract were deactivated by April 16, 2015. Separately, on August 4, 2015, BNSF and CSX submittedpetition to the AAA office in Washington, D.C.,EPA for further consideration. On March 15, 2021, the EPA issued a demand for arbitration and statement of claim against FG allegingrevised CSAPR Update that FG breached the contract and that FG’s declaration of a force majeure under the contract is not valid and seeking damages under the contract through 2025. On May 31, 2016, the parties agreed to a stipulation that if FG’s force majeure defense is determined to be wholly or partially invalid, liquidated damages are the sole remedy available to BNSF and CSX. The arbitration panel consolidated the claims and held a hearing in November and December 2016. On April 12, 2017, the arbitration panel ruled on liability in favor of BNSF and CSX. In the liability award, the panel found,addressed, among other things, that FG’s demand for declaratory judgment that force majeure excused FG’s performancethe remands of the prior CSAPR Update and the New York Section 126 petition. In December 2021, MP purchased NOx emissions allowances to comply with 2021 ozone season requirements. On April 6, 2022, the EPA published proposed rules seeking to impose further significant reductions in EGU NOx emissions in 25 upwind states, including West Virginia, with the stated purpose of allowing downwind states to attain or maintain compliance with the 2015 ozone National Ambient Air Quality Standards. On February 13, 2023, the EPA disapproved 21 SIPs, which was denied, that FG breached and repudiated the coal transportation contract and that the panel retains jurisdiction of claims for liquidated damagesa prerequisite for the years 2015-2025.EPA to issue a final Good Neighbor Plan or FIP. On May 1, 2017, FEJune 5, 2023, the EPA issued the final Good Neighbor Plan with an effective date 60 days thereafter. Certain states, including West Virginia, have appealed the disapprovals of their respective SIPs, and FGsome of those states have obtained stays of those disapprovals precluding the Good Neighbor Plan from taking effect in those states. On August 10, 2023, the 4th Circuit granted West Virginia an interim stay of the disapproval of its SIP and CSXon January 10, 2024, after a hearing held on October 27, 2023, granted a full stay which precludes the Good Neighbor Plan from going into effect in West Virginia. In addition to West Virginia, certain other states, and BNSF entered into a definitive settlement agreement, which resolved all claims related to this consolidated proceeding oncertain trade organizations, including the terms and conditions set forth below. Pursuant to the settlement agreement, FG will pay CSX and BNSF an aggregate amount equal to $109 million which is payable in three annual installments, the firstMidwest Ozone Group of which was made on May 1, 2017. FE agreedis a member, have separately appealed and filed motions to unconditionally and continually guaranteestay the settlement payments due by FG pursuantGood Neighbor Plan itself at the D.C. Circuit. On September 25, 2023, the D.C. Circuit denied the motions to stay the termsGood
Neighbor Plan. On October 13, 2023, the aggrieved parties filed an Emergency Application for an Immediate Stay of the settlement agreement. The settlement agreement further providesGood Neighbor Plan with the U.S. Supreme Court, which remains pending. Oral argument was heard on February 21, 2024.
Climate Change
In March 2024, the SEC issued final rules to require public companies to disclose certain climate-related information in registration statements and annual reports filed with the SEC. As adopted, the final climate disclosure rules mandate the disclosure of climate-related risks and the material impacts 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. Further, FE and FG, and CSX and BNSF, agreed to release, waive and discharge each other from any further obligations under the claims covered by the settlement agreement upon payment in full of the settlement amount. Until such time, CSX and BNSF will retain the claims covered by the settlement agreement and in the event of a bankruptcy proceeding with respect to FG, to the extent the remaining settlement payments are not paid in full by FG or FE, CSX and BNSF shall be entitled to seek damages for such claims in an amount to be determined by the arbitration panel or otherwise agreed by the parties.
On December 22, 2016, FG, a wholly owned subsidiary of FES, received a demand for arbitration and statement of claim from BNSF and NS, which are the counterparties to the coal transportation contract covering the delivery of 2.5 million tons annually through 2025, for FG’s coal-fired Bay Shore Units 2-4, deactivated on September 1, 2012, as a result of the EPA’s MATS and for FG’s W.H. Sammis generating station. The demand for arbitration was submitted to the AAA office in Washington, D.C. against FG alleging, among other things, that FG breached the agreement in 2015 and 2016 and repudiated the agreement for 2017-2025. The counterparties are seeking, among other things, damages, including lost profits through 2025, and a declaratory judgment that FG's claim of force majeure is invalid. The arbitration hearing is scheduled for June 2018. The parties have exchanged settlement proposals to resolve all claims related to this proceeding and all remaining claims. FirstEnergy and FES recorded a pre-tax charge of$55 million in the first quarter of 2017 based on an estimated settlement. If the dispute with BNSF and NS is not settled, the amount of damages owed to BNSF and NS could be materially higher and may cause FES to seek protection under U.S. bankruptcy laws. Absent a settlement, FG intends to vigorously assert its position in this arbitration proceeding, and if it were ultimately determined that the force majeure provisions or other defenses do not excuse the delivery shortfalls, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted.
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. AE Supply filed an answer denying any liability related to the termination. On May 1, 2017, the complaint was amended to add FE, FES and FG, although not parties to the underlying contract, as defendants and to seek additional damages based on new claims of fraud, unjust enrichment, promissory estoppel and alter ego. On June 27, 2017, after oral argument, defendants' preliminary objections to the amended complaint were denied. FE, FES, FG and AE Supply believe the merits of this case are distinguishable from the rail arbitration proceedings above based on the contract termssevere weather events and other elements of the case. There were approximately 5.5 million tons remaining under the contract for delivery. This matter is in the discovery phase of litigation and no trial date has been established. FE, FES, FG and AE Supply dispute the allegations and intendnatural conditions have had, or are reasonably likely to vigorously defend the merits of the lawsuit. At this time, FE, FES, FG and AE Supply cannot estimate the loss or range of loss regarding the ongoing litigation with respect to this agreement. Damages, if any, are yet to be determined, but an adverse outcome could be material.
In September 2007, AE received an NOV from the EPA alleging NSR and PSD violations under the CAA,have, on FirstEnergy, as well as Pennsylvaniadisclosures related to management and West Virginia state laws atFE Board oversight of such risks. In April 2024, the coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania andSEC voluntarily stayed the coal-fired Fort Martin and Willow Island plants in West Virginia. The EPA's NOV alleges equipment replacements during maintenance outages triggeredfinal climate disclosure rules pending resolution of legal challenges. FirstEnergy currently is assessing the pre-construction permitting requirements underimpact of the NSR and PSD programs. On June 29, 2012, January 31, 2013, March 27, 2013 and October 18, 2016, EPA issued CAA section 114 requests for the Harrison coal-fired plant seeking information and documentation relevant tofinal climate disclosure rules on its operation and maintenance, including capital projects undertaken since 2007. On December 12, 2014, EPA issued a CAA section 114 request for the Fort Martin coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2009. FirstEnergy intends to comply with the CAA but, at this time, is unable to predict the outcome of this matter or estimate the loss or range of loss.
Climate Change
FirstEnergy has established a goal to reduce CO2 emissions by 90% below 2005 levels by 2045.business. There are a number ofseveral initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the RGGIRegional Greenhouse Gas Initiative 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.
TheFirstEnergy has pledged to achieve carbon neutrality by 2050 in GHGs within FirstEnergy’s direct operational control (Scope 1). With respect to our coal-fired plants in West Virginia, we have identified that the end of the useful life date is 2035 for Fort Martin and 2040 for Harrison. Determination of the useful life of the regulated coal-fired generation could result in changes in depreciation, and/or continued collection of net plant in rates after retirement, securitization, sale, impairment, or regulatory disallowances. If MP is unable to recover these costs, it could have a material adverse effect on FirstEnergy’s and/or MP’s financial condition, results of operations, and cash flow. Furthermore, FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations.
In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse GasesGHGs under the Clean Air Act” in December 2009,Act,” concluding that concentrations of several key GHGs constitutesconstitute an "endangerment"“endangerment” and may be regulated as "air pollutants"“air pollutants” under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. On June 23, 2014,Subsequently, the U.S. Supreme Court decided that CO2 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 CO2CO2 emissions from existing fossil fuel fired electric generating units that would require each state to develop SIPs by September 6, 2016, to meet the EPA’s state specific CO2 emission rate goals. The EPA’s CPP allows states to request a two-year extension to finalize SIPs by September 6, 2018. If states fail to develop SIPs, the EPA also proposed a federal implementation plan that can be implemented by the EPA that included model emissions trading rules which states can also adopt in their SIPs. The EPA alsofuel-fired EGUs and finalized separate regulations imposing CO2CO2 emission limits for new, modified, and reconstructed fossil fuel fired electric generating units.fuel-fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the U.S. Court of Appeals for 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.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,June 19, 2019, the EPA issuedrepealed the CPP and replaced it with the ACE rule that established guidelines for states to develop standards of performance to address GHG emissions from existing coal-fired generation. On January 19, 2021, the D.C. Circuit vacated and remanded the ACE rule declaring that the EPA was “arbitrary and capricious” in its rule making and, as such, the ACE rule is no longer in effect and all actions thus far taken by states to implement the federally mandated rule are now null and void. Vacating the ACE rule had the unintended effect of reinstating the CPP because the repeal of the CPP was a provision within the ACE rule. The D.C. Circuit decision was appealed by several states and interested parties, including West Virginia, arguing that the EPA did not have the authorization under Section 111(d) of the CAA to require “generation shifting” as a way to limit GHGs. On June 30, 2022, the U.S. Supreme Court in West Virginia v. Environmental Protection Agency held that the method the EPA used to regulate GHGs (generation shifting) under Section 111(d) of the CAA (the CPP) was not authorized by Congress and remanded the rule to the EPA for further reconsideration. In response, on May 23, 2023, the EPA published a proposed rule pursuant to repealCAA Section 111 (b) and (d) in line with the CPP.decision in West Virginia v. Environmental Protection Agency intended to reduce power sector GHG emissions (primarily CO2 emissions) from fossil fuel based EGUs. The rule, which proposed stringent emissions limitations based on fuel type and unit retirement date, was issued as final by the EPA on April 25, 2024. FirstEnergy is currently assessing the impact of the final rule. Depending on the outcomesoutcome of the review pursuant to the executive order, of furtherany 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 resultedwith these standards could require additional capital expenditures or changes 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 joined in adopting the agreement reached on December 12, 2015operation 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 2016Ft. Martin 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 CO2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.Harrison power stations.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal CWAClean Water Act and its amendments, apply to FirstEnergy's plants.FirstEnergy’s facilities. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy'sFirstEnergy’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. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore plant's cooling water intake channel to divert fish away from the plant's cooling water intake system. Depending on the results of such studies and any final action taken by the states based on those studies, 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 were to 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 basedHowever, 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. DependingOn August 31, 2020, the EPA issued a final rule revising the effluent limits for discharges from wet scrubber systems, retaining the zero-discharge standard for ash transport water, (with some limited discharge allowances), and extending the deadline for compliance to December 31, 2025 for both. In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system,
and unit retirement date. On March 29, 2023, the EPA published proposed revised ELGs applicable to coal-fired power plants that include more stringent effluent limitations for wet scrubber systems and ash transport water, and new limits on landfill leachate. The rule was issued as final by the EPA on April 25, 2024 and depending on the outcome of appeals and how any final revised rules are ultimately implemented, the future costs of compliance with these standards may be substantialcould require additional capital expenditures or changes in operation at closed and changesactive landfills, and at the Ft. Martin and Harrison power stations from what was approved by the WVPSC in September 2022 to FirstEnergy's and FES' 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. Concurrentcomply with the issuance2020 ELG rule. FirstEnergy is currently assessing the impact 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.rule.
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,Resource Conservation and Recovery Act, as amended, and the Toxic Substances Control Act. Certain coal combustion residuals,CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA'sEPA’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 regardingfor 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 onOn July 29, 2020, the EPA published a final rule again revising the date that certain CCR impoundments must cease accepting waste and initiate closure to April 11, 2021. The final rule allowed for an assessmentextension of the finalized regulations,closure deadline based on meeting identified site-specific criteria. On November 30, 2020, AE Supply submitted a closure deadline extension request to the future cost of compliance and expected timing of spend had no significant impact on FirstEnergy's or FES' existing AROs associated with CCRs. Although not currently expected, any changes in timing and closure plan requirements inEPA seeking to extend the future, including changes resulting from the strategic review at CES, could materially and adversely impact FirstEnergy's and FES' AROs.
Pursuant to a 2013 consent decree, PA DEP issued a 2014 permitcease accepting waste date for the Little BlueMcElroy's Run CCR impoundment requiringfacility to October 2024, which request is pending technical review by the Bruce Mansfield plantEPA. AE Supply continues to ceaseoperate McElroy’s Run as a disposal of CCRs by December 31, 2016facility for Pleasants Power Station and FGcontinues to provide bondingevaluate closure options. Also, on April 25, 2024, the EPA issued rules as final addressing, 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 dewateringthe first time, certain legacy CCR disposal sites. FirstEnergy is currently assessing the impact 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 should 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. On September 14, 2017, 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, which is subject to a thirty-day comment period with final approval expected in November 2017.rule.
FirstEnergyFE 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 theFirstEnergy’s Consolidated Balance Sheets as of September 30, 2017March 31, 2024, based on estimates of the total costs of cleanup, FE's and its subsidiaries'FirstEnergy’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $131$97 million have been accrued through September 30, 2017. Included in the totalMarch 31, 2024, of which approximately $70 million are accrued liabilities of approximately $84 million for environmental remediation of former manufactured gas plantsMGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. FirstEnergysocietal benefits charge. 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 MattersUnited States v. Larry Householder, et al.
On July 21, 2020, a complaint and supporting affidavit containing federal criminal allegations were unsealed against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. In March 2023, a jury found Mr. Householder and his co-defendant, Matthew Borges, guilty and in June 2023, the two were sentenced to prison for 20 and 5 years, respectively. Messrs. Householder and Borges have appealed their sentences. Also, on July 21, 2020, and in connection with the DOJ’s investigation, FirstEnergy received subpoenas for records from the U.S. Attorney’s Office for the Southern District Ohio. FirstEnergy was not aware of the criminal allegations, affidavit or subpoenas before July 21, 2020.
On July 21, 2021, FE entered into a three-year DPA with the U.S. Attorney’s Office that, subject to court proceedings, resolves this matter. Under NRC regulations,the DPA, FE has agreed to the filing of a criminal information charging FE with one count of conspiracy to commit honest services wire fraud. The DPA requires that FirstEnergy, must ensure that adequate fundsamong other obligations: (i) continue to cooperate with the U.S. Attorney’s Office in all matters relating to the conduct described in the DPA and other conduct under investigation by the U.S. government; (ii) pay a criminal monetary penalty totaling $230 million within sixty days, which shall consist of (x) $115 million paid by FE to the United States Treasury and (y) $115 million paid by FE to the ODSA to fund certain assistance programs, as determined by the ODSA, for the benefit of low-income Ohio electric utility customers; (iii) publish a list of all payments made in 2021 to either 501(c)(4) entities or to entities known by FirstEnergy to be operating for the benefit of a public official, either directly or indirectly, and update the same on a quarterly basis during the term of the DPA; (iv) issue a public statement, as dictated in the DPA, regarding FE’s use of 501(c)(4) entities; and (v) continue to implement and review its compliance and ethics program, internal controls, policies and procedures designed, implemented and enforced to prevent and detect violations of the U.S. laws throughout its operations, and to take certain related remedial measures. The $230 million payment will neither be recovered in rates or charged to FirstEnergy customers, nor will FirstEnergy seek any tax deduction related to such payment. The entire amount of the monetary penalty was recognized as expense in the second quarter of 2021 and paid in the third quarter of 2021. Under the terms of the DPA, the criminal information will be availabledismissed after FirstEnergy fully complies with its obligations under the DPA.
Legal Proceedings Relating to decommissionUnited States v. Larry Householder, et al.
On August 10, 2020, the SEC, through its nuclear facilities. AsDivision of Enforcement, issued an order directing an investigation of possible securities laws violations by FE, and on September 30, 2017,1, 2020, issued subpoenas to FE and certain FE officers. On April 28, 2021, July 11, 2022, and May 25, 2023, the SEC issued additional subpoenas to FE, with which FE has complied. While no contingency has been reflected in its consolidated financial statements, FE believes that it is probable that it will incur a loss in connection with the resolution of the SEC investigation. Given the ongoing nature and complexity of the investigation, FE cannot yet reasonably estimate a loss or range of loss that may arise from the resolution of the SEC investigation.
On June 29, 2023, the OOCIC served FE a subpoena, seeking information relating to the conduct described in the DPA. FirstEnergy had approximately $2.6 billion (FES $1.8 billion) investedwas not aware of the OOCIC’s investigation prior to receiving the subpoena and understands that the OOCIC’s investigation is also focused on the conduct described in external truststhe DPA, other than with respect to the March 25, 2024, felony indictment of Mr. Householder brought in Cuyahoga County, Ohio. FirstEnergy is cooperating with the OOCIC in its investigation. On February 12, 2024, and in connection with the OOCIC’s ongoing investigation, an indictment by a grand jury of Summit County, Ohio was unsealed against the former chairman of the PUCO, Samuel Randazzo, and two former FirstEnergy senior officers, Charles E. Jones, and Michael J. Dowling, charging each of them with several felony counts, including bribery, telecommunications fraud, money laundering and aggravated theft, related to payments described in the DPA. FirstEnergy continues to both cooperate with the OOCIC in its investigation and discuss an appropriate resolution of the investigation with respect to FE. While no contingency has been reflected in FirstEnergy’s consolidated financial statements, FE believes that it is reasonably possible that it will incur a loss in connection with the resolution of the OOCIC investigation. Given the ongoing nature of the discussions, while FE cannot yet reasonably estimate a loss or range of loss that may arise from any resolution of the OOCIC investigation with respect to FE, any such payment by FE associated with an OOCIC resolution is not expected to be usedmaterial.
In addition to the subpoenas referenced above under “United States v. Larry Householder, et. al.” and the SEC investigation, certain FE stockholders and FirstEnergy customers filed several lawsuits against FirstEnergy and certain current and former directors, officers and other employees, and the complaints in each of these suits is related to allegations in the complaint and supporting affidavit relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. The plaintiffs in each of the below cases seek, among other things, to recover an unspecified amount of damages (unless otherwise noted). Unless otherwise indicated, no contingency has been reflected in FirstEnergy’s consolidated financial statements with respect to these lawsuits as a loss is neither probable, nor is a loss or range of a loss reasonably estimable.
•In re FirstEnergy Corp. Securities Litigation (S.D. Ohio); on July 28, 2020 and August 21, 2020, purported stockholders of FE filed putative class action lawsuits alleging violations of the federal securities laws. Those actions have been consolidated and a lead plaintiff, the Los Angeles County Employees Retirement Association, has been appointed by the court. A consolidated complaint was filed on February 26, 2021. The consolidated complaint alleges, on behalf of a proposed class of persons who purchased FE securities between February 21, 2017 and July 21, 2020, that FE and certain current or former FE officers violated Sections 10(b) and 20(a) of the Exchange Act by issuing misrepresentations or omissions concerning FE’s business and results of operations. The consolidated complaint also alleges that FE, certain current or former FE officers and directors, and a group of underwriters violated Sections 11, 12(a)(2) and 15 of the Securities Act of 1933 as a result of alleged misrepresentations or omissions in connection with offerings of senior notes by FE in February and June 2020. On March 30, 2023, the court granted plaintiffs’ motion for class certification. On April 14, 2023, FE filed a petition in the U.S. Court of Appeals for the decommissioning and environmental remediation of its nuclear generating facilities. The values of FirstEnergy's NDTs also fluctuate basedSixth Circuit seeking to appeal that order, which the Sixth Circuit granted on market conditions. IfNovember 16, 2023. On November 30, 2023, FE filed a motion with the valueS.D. Ohio to stay all proceedings pending the circuit court appeal. All discovery is stayed during the pendency of the trusts declinedistrict court motion. FE believes that it is probable that it will incur a loss in connection with the resolution of this lawsuit. Given the ongoing nature and complexity of such litigation, FE cannot yet reasonably estimate a loss or range of loss.
•MFS Series Trust I, et al. v. FirstEnergy Corp., et al. and Brighthouse Funds II – MFS Value Portfolio, et al. v. FirstEnergy Corp., et al. (S.D. Ohio) on December 17, 2021 and February 21, 2022, purported stockholders of FE filed complaints against FE, certain current and former officers, and certain current and former officers of EH. The complaints allege that the defendants violated Sections 10(b) and 20(a) of the Exchange Act by issuing alleged misrepresentations or omissions regarding FE’s business and its results of operations, and seek the same relief as the In re FirstEnergy Corp. Securities Litigation described above. All discovery is stayed during the pendency of the district court motion in In re FirstEnergy Corp. Securities Litigation described above. FE believes that it is probable that it will incur losses in connection with the resolution of these lawsuits. Given the ongoing nature and complexity of such litigation, FE cannot yet reasonably estimate a material amount, FirstEnergy's obligationloss or range of loss.
•State of Ohio ex rel. Dave Yost, Ohio Attorney General v. FirstEnergy Corp., et al. and City of Cincinnati and City of Columbus v. FirstEnergy Corp. (Common Pleas Court, Franklin County, OH, all actions have been consolidated); on September 23, 2020 and October 27, 2020, the OAG and the cities of Cincinnati and Columbus, respectively, filed complaints against several parties including FE, each alleging civil violations of the Ohio Corrupt Activity Act and related claims in connection with the passage of HB 6. On January 13, 2021, the OAG filed a motion for a temporary restraining order and preliminary injunction against FirstEnergy seeking to fundenjoin FirstEnergy from collecting the trusts may increase. DisruptionsOhio Companies' decoupling rider. On January 31, 2021, FE reached a partial settlement with the OAG and the cities of Cincinnati and
Columbus with respect to the temporary restraining order and preliminary injunction request and related issues. In connection with the partial settlement, the Ohio Companies filed an application on February 1, 2021, with the PUCO to set their respective decoupling riders (Conservation Support Rider) to zero. On February 2, 2021, the PUCO approved the application of the Ohio Companies setting the rider to zero, and no additional customer bills will include new decoupling rider charges after February 8, 2021. On August 13, 2021, new defendants were added to the complaint, including two former officers of FirstEnergy. On December 2, 2021, the cities and FE entered a stipulated dismissal with prejudice of the cities’ suit. This matter was stayed through a criminal trial in United States v. Larry Householder, et al. described above, but resumed pursuant to an order, dated March 15, 2023. On July 31, 2023, FE and other defendants filed motions to dismiss in part the OAG’s amended complaint, which the OAG opposed. On February 16, 2024, the OAG moved to stay discovery in the capital markets and their effectscase in light of the February 9, 2024, indictments against defendants in this action, which the court granted on particular businessesMarch 14, 2024. In connection with the ongoing OOCIC resolution discussions, FE is also discussing an appropriate settlement of this civil action with the OAG. As such, FE believes it is reasonably possible that it will incur a loss in connection with this civil action. Given the ongoing nature of these discussions, FE cannot yet reasonably estimate a loss or range of loss from any possible settlement of this civil action, however, any such settlement payment by FE is not expected to be material.
On February 9, 2022, FE, acting through the SLC, agreed to a settlement term sheet to resolve the following shareholder derivative lawsuits relating to HB 6 and the economy could also affectnow former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder that were filed in the valuesS.D. Ohio, the N.D. Ohio, and the Ohio Court of Common Pleas, Summit County:
•Gendrich v. Anderson, et al. and Sloan v. Anderson, et al. (Common Pleas Court, Summit County, Ohio, all actions have been consolidated); on July 26, 2020 and July 31, 2020, respectively, purported stockholders of FE filed shareholder derivative action lawsuits against certain current and former FE directors and officers, alleging, among other things, breaches of fiduciary duty.
•Miller v. Anderson, et al. (N.D. Ohio); Bloom, et al. v. Anderson, et al.; Employees Retirement System of the NDTs.
As partCity of routine inspectionsSt. Louis v. Jones, et al.; Electrical Workers Pension Fund, Local 103, I.B.E.W. v. Anderson et al.; Massachusetts Laborers Pension Fund v. Anderson et al.; The City of Philadelphia Board of Pensions and Retirement v. Anderson et al.; Atherton v. Dowling et al.; Behar v. Anderson, et al. (S.D. Ohio, all actions have been consolidated); beginning on August 7, 2020, purported stockholders of FE filed shareholder derivative actions alleging the FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the concrete shield building at Davis-BesseExchange Act.
On March 11, 2022, the parties executed a stipulation and agreement of settlement, and filed a motion the same day requesting preliminary settlement approval in 2013, FENOC identified changesthe S.D. Ohio, which the S.D. Ohio granted on May 9, 2022. Subsequently, following a hearing on August 4, 2022, the S.D. Ohio granted final approval of the settlement on August 23, 2022.
The settlement includes a series of corporate governance enhancements and a payment to FE of $180 million, to be paid by insurance after the judgment has become final, less approximately $36 million in court-ordered attorney’s fees awarded to plaintiffs. On September 20, 2022, a purported FE stockholder filed a motion for reconsideration of the S.D. Ohio’s final settlement approval. The parties filed oppositions to that motion on October 11, 2022, and the S.D. Ohio denied that motion on May 22, 2023. On June 15, 2023, the purported FE stockholder filed an appeal in the U.S. Court of Appeals for the Sixth Circuit. On February 16, 2024, the U.S. Court of Appeals for the Sixth Circuit affirmed the district court’s final settlement approval. Once all appeal options are exhausted the judgment will become final. The settlement agreement is expected to resolve fully these shareholder derivative lawsuits.
On June 2, 2022, the N.D. Ohio entered an order to show cause why the court should not appoint new plaintiffs’ counsel, and thereafter, on June 10, 2022, the parties filed a joint motion to dismiss the matter without prejudice, which the N.D. Ohio denied on July 5, 2022. On August 15, 2022, the N.D. Ohio issued an order stating its intention to appoint one group of applicants as new plaintiffs’ counsel, and on August 22, 2022, the N.D. Ohio ordered that any objections to the subsurface laminar cracking condition originally discovered in 2011. These inspections revealedappointment be submitted by August 26, 2022. The parties filed their objections by that deadline, and on September 2, 2022, the applicants responded to those objections. In the meantime, on August 25, 2022, a purported FE stockholder represented by the applicants filed a motion to intervene, attaching a proposed complaint-in-intervention purporting to assert claims that the cracking condition had propagatedFE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act as well as a small amountclaim against a third party for professional negligence and malpractice. The parties filed oppositions to that motion to intervene on September 8, 2022, and the proposed intervenor's reply in select areas. FENOC's analysis confirmssupport of his motion to intervene was filed on September 22, 2022. On August 24, 2022, the parties filed a joint motion to dismiss the action pending in the N.D. Ohio based upon and in light of the approval of the settlement by the S.D. Ohio. On August 30, 2022, the parties filed a joint motion to dismiss the state court action, which the court granted on September 2, 2022. On September 29, 2023, the N.D. Ohio issued a stay of the case pending the appeal in the U.S. Court of Appeals for the Sixth Circuit. On April 12, 2024, the N.D. Ohio acknowledged the completion of the appeal and instructed the parties to file any further argument or information they wish to be considered by the N.D. Ohio no later than April 25, 2024.
In letters dated January 26, and February 22, 2021, staff of FERC's Division of Investigations notified FirstEnergy that the building continuesDivision was conducting an investigation of FirstEnergy’s lobbying and governmental affairs activities concerning HB 6, and staff directed FirstEnergy to preserve and maintain its structural integrity,all documents and its ability to safely perform all of its functions. In a May 28, 2015, Inspection Report regarding the apparent cause evaluation on crack propagation, the NRC issued a non-cited violation for FENOC’s failure to request and obtain a license amendment for its method of evaluating the significance of the shield building cracking. The NRC also concluded that the shield building remained capable of performing its design safety functions despite the identified laminar cracking and that this issue was of very low safety significance.FENOC plans to submit a license amendment application to the NRCinformation related to the laminar cracking in the Shield Building.
On March 12, 2012, the NRC issued orders requiring safety enhancements at U.S. reactors based on recommendations from the lessons learned Task Force review of the accident at Japan's Fukushima Daiichi nuclear power plant. These orders require additional mitigation strategies for beyond-design-basis external events, and enhanced equipment for monitoring water levels in spent fuel pools. The NRC also requested that licensees including FENOC: re-analyze earthquake and flooding risks using the latest information available; conduct earthquake and flooding hazard walkdowns at their nuclear plants; assess the ability of current communications systems and equipment to perform under a prolonged loss of onsite and offsite electrical power; and assess plant staffing levels needed to fill emergency positions. Although a majority of the necessary modifications and evaluations at FirstEnergy’s nuclear facilitiessame as such have been completed, some still remain subjectdeveloped
as part of an ongoing non-public audit being conducted by FERC's Division of Audits and Accounting. On December 30, 2022, FERC approved a Stipulation and Consent Agreement that resolves the investigation. The agreement includes a FirstEnergy admission of violating FERC’s “duty of candor” rule and related laws, and obligates FirstEnergy to regulatory reviewpay a civil penalty of $3.86 million, and to submit two annual compliance monitoring reports to FERC’s Office of Enforcement regarding improvements to FirstEnergy’s compliance programs. FE paid the civil penalty on January 4, 2023 and it will not be recovered from customers. The first annual compliance monitoring report was submitted in December 2023.
The outcome of any of these lawsuits, governmental investigations and audit is uncertain and could have a material adverse effect on FE’s or approval.its subsidiaries’ reputation, business, financial condition, results of operations, liquidity, and cash flows.
FES provides a parental support agreement to NG of up to $400 million. The NRC typically relies on such parental support agreements to provide additional assurance that U.S. merchant nuclear plants, including NG's nuclear units, have the necessary financial resources to maintain safe operations, particularly in the event of extraordinary circumstances. So long as FES remains in the unregulated companies’ money pool, the $500 million secured line of credit with FE discussed in Note 1, "Organization and Basis of Presentation - Going Concern at FES" above provides FES the needed liquidity in order for FES to satisfy its nuclear support obligations to NG.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy'sFirstEnergy’s normal business operations pending against FirstEnergy andFE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to FirstEnergyFE or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 10, "Regulatory Matters" of the Combined Notes to Consolidated Financial Statements.8, “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 FirstEnergyFE 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 FirstEnergy'sFE’s or its subsidiaries'subsidiaries’ financial condition, results of operations, and cash flows.
12. SUPPLEMENTAL GUARANTOR INFORMATION
In 2007, FG, a 100% owned subsidiary of FES, completed a sale and leaseback transaction for a 93.83% undivided interest in Bruce Mansfield Unit 1. FG's parent company, FES, has fully and unconditionally and irrevocably guaranteed all of FG's obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FG or its parent company, but the notes are secured by, among other things, each lessor trust's undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES' lease guaranty. This transaction is classified as an operating lease for FES and FirstEnergy and as a financing lease for FG.
The Condensed Consolidating Statements of Income (Loss) and Comprehensive Income (Loss) for the three and nine months ended September 30, 2017 and 2016, Condensed Consolidating Balance Sheets as of September 30, 2017 and December 31, 2016, and Condensed Consolidating Statements of Cash Flows for the nine months ended September 30, 2017 and 2016, for the parent and guarantor and non-guarantor subsidiaries are presented below. These statements are provided as FG's parent company fully and unconditionally guarantees outstanding registered securities of FG as well as FG's obligations under the facility lease for the Bruce Mansfield sale and leaseback that underlie outstanding registered pass-through trust certificates. Investments in wholly owned subsidiaries are accounted for by the parent company using the equity method. Results of operations for FG and NG are, therefore, reflected in their parent company's investment accounts and earnings as if operating lease treatment was achieved. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and the entries required to reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.
|
| | | | | | | | | | | | | | | | | | | | |
| FIRSTENERGY SOLUTIONS CORP. |
| CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME |
| |
| | | | | | | | | | | |
| For the Three Months Ended September 30, 2017 | | FES | | FG | | NG | | Eliminations | | Consolidated |
| | | (In millions) |
| STATEMENTS OF INCOME | | | | | | | | | | |
| | | | | | | | | | | |
| REVENUES | | $ | 741 |
| | $ | 231 |
| | $ | 292 |
| | $ | (521 | ) | | $ | 743 |
|
| | | | | | | | | | | |
| OPERATING EXPENSES: | | |
| | |
| | |
| | |
| | |
|
| Fuel | | — |
| | 108 |
| | 57 |
| | — |
| | 165 |
|
| Purchased power from affiliates | | 520 |
| | — |
| | 1 |
| | (521 | ) | | — |
|
| Purchased power from non-affiliates | | 152 |
| | — |
| | — |
| | — |
| | 152 |
|
| Other operating expenses | | 70 |
| | 62 |
| | 147 |
| | 12 |
| | 291 |
|
| Provision for depreciation | | 3 |
| | 8 |
| | 18 |
| | (1 | ) | | 28 |
|
| General taxes | | 4 |
| | 3 |
| | (2 | ) | | — |
| | 5 |
|
| Total operating expenses | | 749 |
| | 181 |
| | 221 |
| | (510 | ) | | 641 |
|
| | | | | | | | | | | |
| OPERATING INCOME (LOSS) | | (8 | ) | | 50 |
| | 71 |
| | (11 | ) | | 102 |
|
| | | | | | | | | | |
|
|
| OTHER INCOME (EXPENSE): | | |
| | |
| | |
| | |
| | |
|
| Investment income (loss), including net income from equity investees | | 106 |
| | 11 |
| | 43 |
| | (121 | ) | | 39 |
|
| Miscellaneous income | | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
| Interest expense — affiliates | | (20 | ) | | (3 | ) | | 1 |
| | 16 |
| | (6 | ) |
| Interest expense — other | | (12 | ) | | (25 | ) | | (11 | ) | | 14 |
| | (34 | ) |
| Capitalized interest | | — |
| | — |
| | 6 |
| | — |
| | 6 |
|
| Total other income (expense) | | 75 |
| | (17 | ) | | 39 |
| | (91 | ) | | 6 |
|
| | | | | | | | | | |
|
|
| INCOME BEFORE INCOME TAXES (BENEFITS) | | 67 |
| | 33 |
| | 110 |
| | (102 | ) | | 108 |
|
| | | | | | | | | | |
|
|
| INCOME TAXES (BENEFITS) | | (9 | ) | | 6 |
| | 34 |
| | 1 |
| | 32 |
|
| | | | | | | | | | |
|
|
| NET INCOME | | $ | 76 |
| | $ | 27 |
| | $ | 76 |
| | $ | (103 | ) | | $ | 76 |
|
| | | | | | | | | | |
|
|
| STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | | | | | | | | | |
|
|
| | | | | | | | | | |
|
|
| NET INCOME | | $ | 76 |
| | $ | 27 |
| | $ | 76 |
| | $ | (103 | ) | | $ | 76 |
|
| | | | | | | | | | |
|
|
| OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | |
|
|
| Pension and OPEB prior service costs | | (3 | ) | | (3 | ) | | — |
| | 3 |
| | (3 | ) |
| Amortized gains on derivative hedges | | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
| Change in unrealized gains on available-for-sale securities | | (6 | ) | | — |
| | (6 | ) | | 6 |
| | (6 | ) |
| Other comprehensive loss | | (8 | ) | | (3 | ) | | (6 | ) | | 9 |
| | (8 | ) |
| Income tax benefits on other comprehensive loss | | (3 | ) | | (1 | ) | | (2 | ) | | 3 |
| | (3 | ) |
| Other comprehensive loss, net of tax | | (5 | ) | | (2 | ) | | (4 | ) | | 6 |
| | (5 | ) |
| COMPREHENSIVE INCOME | | $ | 71 |
| | $ | 25 |
| | $ | 72 |
| | $ | (97 | ) | | $ | 71 |
|
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| FIRSTENERGY SOLUTIONS CORP. |
| CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME |
| |
| | | | | | | | | | | |
| For the Nine Months Ended September 30, 2017 | | FES | | FG | | NG | | Eliminations | | Consolidated |
| | | (In millions) |
| STATEMENTS OF INCOME | | | | | | | | | | |
| | | | | | | | | | | |
| REVENUES | | $ | 2,338 |
| | $ | 941 |
| | $ | 988 |
| | $ | (1,869 | ) | | $ | 2,398 |
|
| | | | | | | | | | | |
| OPERATING EXPENSES: | | |
| | |
| | |
| | |
| | |
|
| Fuel | | — |
| | 312 |
| | 151 |
| | — |
| | 463 |
|
| Purchased power from affiliates | | 1,994 |
| | — |
| | 77 |
| | (1,869 | ) | | 202 |
|
| Purchased power from non-affiliates | | 468 |
| | — |
| | — |
| | — |
| | 468 |
|
| Other operating expenses | | 247 |
| | 345 |
| | 467 |
| | 36 |
| | 1,095 |
|
| Provision for depreciation | | 9 |
| | 24 |
| | 49 |
| | (2 | ) | | 80 |
|
| General taxes | | 15 |
| | 16 |
| | 13 |
| | — |
| | 44 |
|
| Total operating expenses | | 2,733 |
| | 697 |
| | 757 |
| | (1,835 | ) | | 2,352 |
|
| | | | | | | | | | | |
| OPERATING INCOME (LOSS) | | (395 | ) | | 244 |
| | 231 |
| | (34 | ) | | 46 |
|
| | | | | | | | | | | |
| OTHER INCOME (EXPENSE): | | |
| | |
| | |
| | |
| | |
|
| Investment income (loss), including net income (loss) from equity investees | | 335 |
| | 31 |
| | 91 |
| | (383 | ) | | 74 |
|
| Miscellaneous income | | 1 |
| | — |
| | 5 |
| | — |
| | 6 |
|
| Interest expense — affiliates | | (58 | ) | | (9 | ) | | (1 | ) | | 55 |
| | (13 | ) |
| Interest expense — other | | (35 | ) | | (78 | ) | | (33 | ) | | 42 |
| | (104 | ) |
| Capitalized interest | | — |
| | 1 |
| | 19 |
| | — |
| | 20 |
|
| Total other income (expense) | | 243 |
| | (55 | ) | | 81 |
| | (286 | ) | | (17 | ) |
| | | | | | | | | | | |
| INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) | | (152 | ) | | 189 |
| | 312 |
| | (320 | ) | | 29 |
|
| | | | | | | | | | | |
| INCOME TAXES (BENEFITS) | | (167 | ) | | 66 |
| | 112 |
| | 3 |
| | 14 |
|
| | | | | | | | | | | |
| NET INCOME | | $ | 15 |
|
| $ | 123 |
| | $ | 200 |
| | $ | (323 | ) | | $ | 15 |
|
| | | | | | | | | | | |
| STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | |
| | | | | | | | | | | |
| NET INCOME | | $ | 15 |
| | $ | 123 |
| | $ | 200 |
| | $ | (323 | ) | | $ | 15 |
|
| | | | | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | |
| Pension and OPEB prior service costs | | (10 | ) | | (10 | ) | | — |
| | 10 |
| | (10 | ) |
| Amortized gains on derivative hedges | | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
| Change in unrealized gains on available-for-sale securities | | 16 |
| | — |
| | 16 |
| | (16 | ) | | 16 |
|
| Other comprehensive income (loss) | | 7 |
| | (10 | ) | | 16 |
| | (6 | ) | | 7 |
|
| Income taxes (benefits) on other comprehensive income (loss) | | 2 |
| | (4 | ) | | 6 |
| | (2 | ) | | 2 |
|
| Other comprehensive income (loss), net of tax | | 5 |
| | (6 | ) | | 10 |
| | (4 | ) | | 5 |
|
| COMPREHENSIVE INCOME | | $ | 20 |
| | $ | 117 |
| | $ | 210 |
| | $ | (327 | ) | | $ | 20 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| FIRSTENERGY SOLUTIONS CORP. |
| CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME |
| |
| | | | | | | | | | | |
| For the Three Months Ended September 30, 2016 | | FES | | FG | | NG | | Eliminations | | Consolidated |
| | | (In millions) |
| STATEMENTS OF INCOME | | | | | | | | | | |
| | | | | | | | | | | |
| REVENUES | | $ | 1,065 |
| | $ | 494 |
| | $ | 400 |
| | $ | (859 | ) | | $ | 1,100 |
|
| | | | | | | | | | | |
| OPERATING EXPENSES: | | |
| | |
| | |
| | |
| | |
| Fuel | | — |
| | 149 |
| | 53 |
| | — |
| | 202 |
|
| Purchased power from affiliates | | 1,011 |
| | — |
| | 39 |
| | (859 | ) | | 191 |
|
| Purchased power from non-affiliates | | 186 |
| | — |
| | — |
| | — |
| | 186 |
|
| Other operating expenses | | 95 |
| | 61 |
| | 149 |
| | 11 |
| | 316 |
|
| Provision for depreciation | | 4 |
| | 28 |
| | 51 |
| | — |
| | 83 |
|
| General taxes | | 8 |
| | 7 |
| | 6 |
| | — |
| | 21 |
|
| Total operating expenses | | 1,304 |
| | 245 |
| | 298 |
| | (848 | ) | | 999 |
|
| | | | | | | | | | | |
| OPERATING INCOME (LOSS) | | (239 | ) | | 249 |
| | 102 |
| | (11 | ) | | 101 |
|
| | | | | | | | | | | |
| OTHER INCOME (EXPENSE): | | |
| | |
| | |
| | |
| | |
|
| Investment income, including net income from equity investees | | 224 |
| | 8 |
| | 28 |
| | (236 | ) | | 24 |
|
| Miscellaneous income | | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
| Interest expense — affiliates | | (13 | ) | | (3 | ) | | (2 | ) | | 15 |
| | (3 | ) |
| Interest expense — other | | (14 | ) | | (27 | ) | | (9 | ) | | 14 |
| | (36 | ) |
| Capitalized interest | | — |
| | 3 |
| | 6 |
| | — |
| | 9 |
|
| Total other income (expense) | | 197 |
| | (18 | ) | | 23 |
| | (207 | ) | | (5 | ) |
| | | | | | | | | | | |
| INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) | | (42 | ) | | 231 |
| | 125 |
| | (218 | ) | | 96 |
|
| | | | | | | | | | | |
| INCOME TAXES (BENEFITS) | | (82 | ) | | 87 |
| | 49 |
| | 2 |
| | 56 |
|
| | | | | | | | | | | |
| NET INCOME | | $ | 40 |
| | $ | 144 |
| | $ | 76 |
| | $ | (220 | ) | | $ | 40 |
|
| | | | | | | | | | | |
| STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | |
| | | | | | | | | | | |
| NET INCOME | | $ | 40 |
| | $ | 144 |
| | $ | 76 |
| | $ | (220 | ) | | $ | 40 |
|
| | | | | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | |
| Pension and OPEB prior service costs | | (3 | ) | | (3 | ) | | — |
| | 3 |
| | (3 | ) |
| Amortized gains on derivative hedges | | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
| Change in unrealized gains on available for sale securities | | 5 |
| | — |
| | 5 |
| | (5 | ) | | 5 |
|
| Other comprehensive income (loss) | | 3 |
| | (3 | ) | | 5 |
| | (2 | ) | | 3 |
|
| Income taxes (benefits) on other comprehensive income (loss) | | 1 |
| | (1 | ) | | 2 |
| | (1 | ) | | 1 |
|
| Other comprehensive income (loss), net of tax | | 2 |
| | (2 | ) | | 3 |
| | (1 | ) | | 2 |
|
| COMPREHENSIVE INCOME | | $ | 42 |
| | $ | 142 |
| | $ | 79 |
| | $ | (221 | ) | | $ | 42 |
|
| | | | | | | | | | | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| FIRSTENERGY SOLUTIONS CORP. |
| CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) |
| |
| | | | | | | | | | | |
| For the Nine Months Ended September 30, 2016 | | FES | | FG | | NG | | Eliminations | | Consolidated |
| | | (In millions) |
| STATEMENTS OF INCOME (LOSS) | | | | | | | | | | |
| | | | | | | | | | | |
| REVENUES | | $ | 3,281 |
| | $ | 1,309 |
| | $ | 1,404 |
| | $ | (2,593 | ) | | $ | 3,401 |
|
| | | | | | | | | | | |
| OPERATING EXPENSES: | | |
| | |
| | |
| | |
| | |
|
| Fuel | | — |
| | 449 |
| | 146 |
| | — |
| | 595 |
|
| Purchased power from affiliates | | 2,888 |
| | — |
| | 145 |
| | (2,593 | ) | | 440 |
|
| Purchased power from non-affiliates | | 829 |
| | — |
| | — |
| | — |
| | 829 |
|
| Other operating expenses | | 218 |
| | 220 |
| | 450 |
| | 37 |
| | 925 |
|
| Provision for depreciation | | 10 |
| | 91 |
| | 151 |
| | (2 | ) | | 250 |
|
| General taxes | | 23 |
| | 23 |
| | 20 |
| | — |
| | 66 |
|
| Impairment of assets | | 23 |
| | 517 |
| | — |
| | — |
| | 540 |
|
| Total operating expenses | | 3,991 |
| | 1,300 |
| | 912 |
| | (2,558 | ) | | 3,645 |
|
| | | | | | | | | | | |
| OPERATING INCOME (LOSS) | | (710 | ) | | 9 |
| | 492 |
| | (35 | ) | | (244 | ) |
| | | | | | | | | | | |
| OTHER INCOME (EXPENSE): | | |
| | |
| | |
| | |
| | |
|
| Investment income, including net income (loss) from equity investees | | 310 |
| | 21 |
| | 67 |
| | (342 | ) | | 56 |
|
| Miscellaneous income | | 3 |
| | 1 |
| | — |
| | — |
| | 4 |
|
| Interest expense — affiliates | | (34 | ) | | (7 | ) | | (4 | ) | | 39 |
| | (6 | ) |
| Interest expense — other | | (40 | ) | | (79 | ) | | (33 | ) | | 43 |
| | (109 | ) |
| Capitalized interest | | — |
| | 7 |
| | 20 |
| | — |
| | 27 |
|
| Total other income (expense) | | 239 |
| | (57 | ) | | 50 |
| | (260 | ) | | (28 | ) |
| | | | | | | | | | | |
| INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) | | (471 | ) | | (48 | ) | | 542 |
| | (295 | ) | | (272 | ) |
| | | | | | | | | | | |
| INCOME TAXES (BENEFITS) | | (204 | ) | | (1 | ) | | 196 |
| | 4 |
| | (5 | ) |
| | | | | | | | | | | |
| NET INCOME (LOSS) | | $ | (267 | ) | | $ | (47 | ) | | $ | 346 |
| | $ | (299 | ) | | $ | (267 | ) |
| | | | | | | | | | | |
| STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | | | | | | | | | | |
| | | | | | | | | | | |
| NET INCOME (LOSS) | | $ | (267 | ) | | $ | (47 | ) | | $ | 346 |
| | $ | (299 | ) | | $ | (267 | ) |
| | | | | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS) | | | | | | | | | | |
| Pension and OPEB prior service costs | | (10 | ) | | (10 | ) | | — |
| | 10 |
| | (10 | ) |
| Amortized gains on derivative hedges | | — |
| | — |
| | — |
| | — |
| | — |
|
| Change in unrealized gains on available-for-sale securities | | 61 |
| | — |
| | 60 |
| | (60 | ) | | 61 |
|
| Other comprehensive income (loss) | | 51 |
| | (10 | ) | | 60 |
| | (50 | ) | | 51 |
|
| Income taxes (benefits) on other comprehensive income (loss) | | 20 |
| | (4 | ) | | 23 |
| | (19 | ) | | 20 |
|
| Other comprehensive income (loss), net of tax | | 31 |
| | (6 | ) | | 37 |
| | (31 | ) | | 31 |
|
| COMPREHENSIVE INCOME (LOSS) | | $ | (236 | ) | | $ | (53 | ) | | $ | 383 |
| | $ | (330 | ) | | $ | (236 | ) |
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
|
| | | | | | | | | | | | | | | | | | | | |
| As of September 30, 2017 | | FES | | FG | | NG | | Eliminations | | Consolidated |
| | | (In millions) |
| ASSETS | | | | | | | | | | |
| CURRENT ASSETS: | | | | | | | | | | |
| Cash and cash equivalents | | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
| Receivables- | | |
| | |
| | |
| | |
| | |
|
| Customers | | 171 |
| | — |
| | — |
| | — |
| | 171 |
|
| Affiliated companies | | 194 |
| | 175 |
| | 193 |
| | (235 | ) | | 327 |
|
| Other | | 9 |
| | 4 |
| | — |
| | — |
| | 13 |
|
| Notes receivable from affiliated companies | | 364 |
| | 1,765 |
| | 1,481 |
| | (3,610 | ) | | — |
|
| Materials and supplies | | 34 |
| | 147 |
| | 82 |
| | — |
| | 263 |
|
| Derivatives | | 31 |
| | — |
| | — |
| | — |
| | 31 |
|
| Collateral | | 101 |
| | 25 |
| | — |
| | — |
| | 126 |
|
| Prepaid taxes and other | | 12 |
| | 16 |
| | 1 |
| | — |
| | 29 |
|
| | | 916 |
| | 2,134 |
| | 1,757 |
| | (3,845 | ) | | 962 |
|
| PROPERTY, PLANT AND EQUIPMENT: | | |
| | |
| | |
| | |
| | |
|
| In service | | 121 |
| | 2,587 |
| | 5,016 |
| | (281 | ) | | 7,443 |
|
| Less — Accumulated provision for depreciation | | 61 |
| | 1,942 |
| | 4,309 |
| | (189 | ) | | 6,123 |
|
| | | 60 |
| | 645 |
| | 707 |
| | (92 | ) | | 1,320 |
|
| Construction work in progress | | 2 |
| | 45 |
| | 241 |
| | — |
| | 288 |
|
| | | 62 |
| | 690 |
| | 948 |
| | (92 | ) | | 1,608 |
|
| INVESTMENTS: | | |
| | |
| | |
| | |
| | |
|
| Nuclear plant decommissioning trusts | | — |
| | — |
| | 1,823 |
| | — |
| | 1,823 |
|
| Investment in affiliated companies | | 3,347 |
| | — |
| | — |
| | (3,347 | ) | | — |
|
| Other | | — |
| | 9 |
| | — |
| | — |
| | 9 |
|
| | | 3,347 |
| | 9 |
| | 1,823 |
| | (3,347 | ) | | 1,832 |
|
| | | | | | | | | | | |
| DEFERRED CHARGES AND OTHER ASSETS: | | |
| | |
| | |
| | |
| | |
|
| Property taxes | | — |
| | 2 |
| | 4 |
| | — |
| | 6 |
|
| Accumulated deferred income tax benefits | | 428 |
| | 1,212 |
| | 690 |
| | (273 | ) | | 2,057 |
|
| Derivatives | | 5 |
| | — |
| | — |
| | — |
| | 5 |
|
| Other | | 31 |
| | 328 |
| | — |
| | 10 |
| | 369 |
|
| | | 464 |
| | 1,542 |
| | 694 |
| | (263 | ) | | 2,437 |
|
| | | $ | 4,789 |
| | $ | 4,375 |
| | $ | 5,222 |
| | $ | (7,547 | ) | | $ | 6,839 |
|
| | | | | | | | | | | |
| LIABILITIES AND CAPITALIZATION | | |
| | |
| | |
| | |
| | |
|
| CURRENT LIABILITIES: | | |
| | |
| | |
| | |
| | |
|
| Currently payable long-term debt | | $ | — |
| | $ | 180 |
| | $ | 114 |
| | $ | (27 | ) | | $ | 267 |
|
| Short-term borrowings - affiliated companies | | 3,299 |
| | 497 |
| | — |
| | (3,610 | ) | | 186 |
|
| Accounts payable- | | |
| | |
| | |
| | |
| | |
|
| Affiliated companies | | 329 |
| | 87 |
| | 143 |
| | (329 | ) | | 230 |
|
| Other | | 11 |
| | 87 |
| | — |
| | — |
| | 98 |
|
| Accrued taxes | | 16 |
| | 12 |
| | 19 |
| | (15 | ) | | 32 |
|
| Derivatives | | 10 |
| | 2 |
| | — |
| | — |
| | 12 |
|
| Other | | 28 |
| | 92 |
| | 14 |
| | 33 |
| | 167 |
|
| | | 3,693 |
| | 957 |
| | 290 |
| | (3,948 | ) | | 992 |
|
| CAPITALIZATION: | | |
| | |
| | |
| | |
| | |
|
| Total equity | | 328 |
| | 946 |
| | 2,301 |
| | (3,247 | ) | | 328 |
|
| Long-term debt and other long-term obligations | | 691 |
| | 1,941 |
| | 1,006 |
| | (1,079 | ) | | 2,559 |
|
| | | 1,019 |
| | 2,887 |
| | 3,307 |
| | (4,326 | ) | | 2,887 |
|
| NONCURRENT LIABILITIES: | | |
| | |
| | |
| | |
| | |
|
| Deferred gain on sale and leaseback transaction | | — |
| | — |
| | — |
| | 732 |
| | 732 |
|
| Accumulated deferred income taxes | | 5 |
| | — |
| | — |
| | (5 | ) | | — |
|
| Retirement benefits | | 26 |
| | 181 |
| | — |
| | — |
| | 207 |
|
| Asset retirement obligations | | — |
| | 187 |
| | 801 |
| | — |
| | 988 |
|
| Other | | 46 |
| | 163 |
| | 824 |
| | — |
| | 1,033 |
|
| | | 77 |
| | 531 |
| | 1,625 |
| | 727 |
| | 2,960 |
|
| | | $ | 4,789 |
| | $ | 4,375 |
| | $ | 5,222 |
| | $ | (7,547 | ) | | $ | 6,839 |
|
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
|
| | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2016 | | FES | | FG | | NG | | Eliminations | | Consolidated |
| | | (In millions) |
| ASSETS | | | | | | | | | | |
| CURRENT ASSETS: | | | | | | | | | | |
| Cash and cash equivalents | | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
| Receivables- | | |
| | |
| | |
| | |
| | |
|
| Customers | | 213 |
| | — |
| | — |
| | — |
| | 213 |
|
| Affiliated companies | | 332 |
| | 315 |
| | 417 |
| | (612 | ) | | 452 |
|
| Other | | 17 |
| | 2 |
| | 8 |
| | — |
| | 27 |
|
| Notes receivable from affiliated companies | | 501 |
| | 1,585 |
| | 1,294 |
| | (3,351 | ) | | 29 |
|
| Materials and supplies | | 45 |
| | 142 |
| | 80 |
| | — |
| | 267 |
|
| Derivatives | | 137 |
| | — |
| | — |
| | — |
| | 137 |
|
| Collateral | | 157 |
| | — |
| | — |
| | — |
| | 157 |
|
| Prepaid taxes and other | | 38 |
| | 24 |
| | 1 |
| | — |
| | 63 |
|
| | | 1,440 |
| | 2,070 |
| | 1,800 |
| | (3,963 | ) | | 1,347 |
|
| PROPERTY, PLANT AND EQUIPMENT: | | |
| | |
| | |
| | |
| | |
|
| In service | | 120 |
| | 2,524 |
| | 4,703 |
| | (290 | ) | | 7,057 |
|
| Less — Accumulated provision for depreciation | | 52 |
| | 1,920 |
| | 4,144 |
| | (187 | ) | | 5,929 |
|
| | | 68 |
| | 604 |
| | 559 |
| | (103 | ) | | 1,128 |
|
| Construction work in progress | | 2 |
| | 67 |
| | 358 |
| | — |
| | 427 |
|
| | | 70 |
| | 671 |
| | 917 |
| | (103 | ) | | 1,555 |
|
| INVESTMENTS: | | |
| | |
| | |
| | |
| | |
|
| Nuclear plant decommissioning trusts | | — |
| | — |
| | 1,552 |
| | — |
| | 1,552 |
|
| Investment in affiliated companies | | 2,923 |
| | — |
| | — |
| | (2,923 | ) | | — |
|
| Other | | — |
| | 9 |
| | 1 |
| | — |
| | 10 |
|
| | | 2,923 |
| | 9 |
| | 1,553 |
| | (2,923 | ) | | 1,562 |
|
| | | | | | | | | | | |
| DEFERRED CHARGES AND OTHER ASSETS: | | |
| | |
| | |
| | |
| | |
|
| Property taxes | | — |
| | 12 |
| | 28 |
| | — |
| | 40 |
|
| Accumulated deferred income tax benefits | | 395 |
| | 1,271 |
| | 883 |
| | (270 | ) | | 2,279 |
|
| Derivatives | | 77 |
| | — |
| | — |
| | — |
| | 77 |
|
| Other | | 33 |
| | 327 |
| | — |
| | 21 |
| | 381 |
|
| | | 505 |
| | 1,610 |
| | 911 |
| | (249 | ) | | 2,777 |
|
| | | $ | 4,938 |
| | $ | 4,360 |
| | $ | 5,181 |
| | $ | (7,238 | ) | | $ | 7,241 |
|
| | | | | | | | | | | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | | | |
| CURRENT LIABILITIES: | | |
| | |
| | |
| | |
| | |
|
| Currently payable long-term debt | | $ | — |
| | $ | 200 |
| | $ | 5 |
| | $ | (26 | ) | | $ | 179 |
|
| Short-term borrowings - affiliated companies | | 2,969 |
| | 483 |
| | — |
| | (3,351 | ) | | 101 |
|
| Accounts payable- | | |
| | |
| | |
| | |
| | |
|
| Affiliated companies | | 743 |
| | 107 |
| | 406 |
| | (706 | ) | | 550 |
|
| Other | | 17 |
| | 93 |
| | — |
| | — |
| | 110 |
|
| Accrued taxes | | 50 |
| | 48 |
| | 61 |
| | (16 | ) | | 143 |
|
| Derivatives | | 71 |
| | 6 |
| | — |
| | — |
| | 77 |
|
| Other | | 56 |
| | 54 |
| | 10 |
| | 36 |
| | 156 |
|
| | | 3,906 |
| | 991 |
| | 482 |
| | (4,063 | ) | | 1,316 |
|
| CAPITALIZATION: | | |
| | |
| | |
| | |
| | |
|
| Total equity | | 218 |
| | 828 |
| | 2,006 |
| | (2,834 | ) | | 218 |
|
| Long-term debt and other long-term obligations | | 691 |
| | 2,093 |
| | 1,120 |
| | (1,091 | ) | | 2,813 |
|
| | | 909 |
| | 2,921 |
| | 3,126 |
| | (3,925 | ) | | 3,031 |
|
| NONCURRENT LIABILITIES: | | |
| | |
| | |
| | |
| | |
|
| Deferred gain on sale and leaseback transaction | | — |
| | — |
| | — |
| | 757 |
| | 757 |
|
| Accumulated deferred income taxes | | 4 |
| | 3 |
| | — |
| | (7 | ) | | — |
|
| Retirement benefits | | 25 |
| | 172 |
| | — |
| | — |
| | 197 |
|
| Asset retirement obligations | | — |
| | 188 |
| | 713 |
| | — |
| | 901 |
|
| Other | | 94 |
| | 85 |
| | 860 |
| | — |
| | 1,039 |
|
| | | 123 |
| | 448 |
| | 1,573 |
| | 750 |
| | 2,894 |
|
| | | $ | 4,938 |
| | $ | 4,360 |
| | $ | 5,181 |
| | $ | (7,238 | ) | | $ | 7,241 |
|
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
|
| | | | | | | | | | | | | | | | | | | | |
| For the Nine Months Ended September 30, 2017 | | FES | | FG | | NG | | Eliminations | | Consolidated |
| | | (In millions) |
| | | | | | | | | | | |
| NET CASH (USED FOR) PROVIDED FROM OPERATING ACTIVITIES | | $ | (463 | ) | | $ | 387 |
| | $ | 547 |
| | $ | (13 | ) | | $ | 458 |
|
CASH FLOWS FROM FINANCING ACTIVITIES: | | |
| | |
| | |
| | |
| | |
|
| New Financing- | | |
| | |
| | |
| | |
| | |
|
| Short-term borrowings, net | | 330 |
| | 14 |
| | — |
| | (259 | ) | | 85 |
|
| Redemptions and Repayments- | | |
| | |
| | |
| | |
| |
|
|
| Long-term debt | | — |
| | (171 | ) | | (5 | ) | | 13 |
| | (163 | ) |
| Other | | — |
| | (5 | ) | | — |
| | — |
| | (5 | ) |
| Net cash (used for) provided from financing activities | | 330 |
| | (162 | ) | | (5 | ) | | (246 | ) | | (83 | ) |
CASH FLOWS FROM INVESTING ACTIVITIES: | | |
| | |
| | |
| | |
| | |
|
| Property additions | | (1 | ) | | (46 | ) | | (154 | ) | | — |
| | (201 | ) |
| Nuclear fuel | | — |
| | — |
| | (156 | ) | | — |
| | (156 | ) |
| Sales of investment securities held in trusts | | — |
| | — |
| | 834 |
| | — |
| | 834 |
|
| Purchases of investment securities held in trusts | | — |
| | — |
| | (878 | ) | | — |
| | (878 | ) |
| Loans to affiliated companies, net | | 137 |
| | (179 | ) | | (188 | ) | | 259 |
| | 29 |
|
| Other | | (3 | ) | | — |
| | — |
| | — |
| | (3 | ) |
| Net cash (used for) provided from investing activities | | 133 |
| | (225 | ) | | (542 | ) | | 259 |
| | (375 | ) |
Net change in cash and cash equivalents | | — |
| | — |
| | — |
| | — |
| | — |
|
| Cash and cash equivalents at beginning of period | | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
| Cash and cash equivalents at end of period | | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
|
| | | | | | | | | | | | | | | | | | | | |
| For the Nine Months Ended September 30, 2016 | | FES | | FG | | NG | | Eliminations | | Consolidated |
| | | (In millions) |
| | | | | | | | | | | |
| NET CASH (USED FOR) PROVIDED FROM OPERATING ACTIVITIES | | $ | (605 | ) | | $ | 402 |
| | $ | 820 |
| | $ | (12 | ) | | $ | 605 |
|
CASH FLOWS FROM FINANCING ACTIVITIES: | | |
| | |
| | |
| | |
| | |
|
| New Financing- | | |
| | |
| | |
| | |
| | |
|
| Long-term debt | | — |
| | 186 |
| | 285 |
| | — |
| | 471 |
|
| Short-term borrowings, net | | 701 |
| | 92 |
| | — |
| | (692 | ) | | 101 |
|
| Redemptions and Repayments- | | |
| | |
| | |
| | |
| |
|
|
| Long-term debt | | — |
| | (211 | ) | | (304 | ) | | 12 |
| | (503 | ) |
| Other | | — |
| | (6 | ) | | (2 | ) | | — |
| | (8 | ) |
| Net cash (used for) provided from financing activities | | 701 |
| | 61 |
| | (21 | ) | | (680 | ) | | 61 |
|
| | | | | | | | | | | |
|
| CASH FLOWS FROM INVESTING ACTIVITIES: | | |
| | |
| | |
| | |
| |
|
|
| Property additions | | (28 | ) | | (171 | ) | | (233 | ) | | — |
| | (432 | ) |
| Nuclear fuel | | — |
| | — |
| | (195 | ) | | — |
| | (195 | ) |
| Sales of investment securities held in trusts | | — |
| | — |
| | 576 |
| | — |
| | 576 |
|
| Purchases of investment securities held in trusts | | — |
| | — |
| | (619 | ) | | — |
| | (619 | ) |
| Loans to affiliated companies, net | | (87 | ) | | (292 | ) | | (328 | ) | | 692 |
| | (15 | ) |
| Other | | 19 |
| | — |
| | — |
| | — |
| | 19 |
|
| Net cash (used for) provided from investing activities | | (96 | ) | | (463 | ) | | (799 | ) | | 692 |
| | (666 | ) |
Net change in cash and cash equivalents | | — |
| | — |
| | — |
| | — |
| | — |
|
| Cash and cash equivalents at beginning of period | | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
| Cash and cash equivalents at end of period | | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
13.10. SEGMENT INFORMATION
On January 1, 2024, FirstEnergy changed its reportable segments to include the following and continues to evaluate segment performance based on earnings attributable to FE:
•Distribution Segment, which consists of the Ohio Companies and FE PA;
•Integrated Segment, which consists of MP, PE and JCP&L; and
•Stand-Alone Transmission Segment, which consists of FE's ownership in FET and KATCo.
FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity through its reportable segments: Distribution, Integrated and Stand-Alone Transmission.
The segment reporting structure was modified to increase transparency for leadership and investors, simplify the presentation to corresponding legal entities, and align FirstEnergy’s earnings, cash flows and balance sheets at the business unit level. In accordance with GAAP, the modification to the segments in the first quarter of 2024 resulted in a transfer of goodwill between the segments based on the relative fair value of the reporting units, and as such, the segment goodwill balances do not necessarily represent the goodwill balances of the specific legal entities within the segments. The external segment reporting is consistent with the internal financial reports used by FirstEnergy's Chief Executive Officer (its chief operating decision maker) to regularly assess performance of the business and allocate resources. Disclosures for FirstEnergy's reportable operating segments are as follows: Regulated Distribution, Regulated Transmission, and CES.
Financial information for each of FirstEnergy’s2023 have been reclassified to conform to the current presentation reflecting the new reportable segments is presented in the tables below. FES does not have separate reportable operating segments.
The Regulated Distribution segment, which consists of the Ohio Companies and FE PA, representing $10.9 billion in 2023 rate base, distributes electricity through FirstEnergy’s ten utility operating companies servingin Ohio and Pennsylvania. The Distribution segment serves approximately six4.2 million customers within 65,000 square miles ofin Ohio and Pennsylvania West Virginia, Maryland, New Jersey and New York,across its distribution footprint and purchases power for its POLR,provider of last resort, SOS, SSOstandard service offer and default service requirementsrequirements. The segment’s results reflect the costs of securing and delivering electric generation from transmission facilities to customers, including the deferral and amortization of certain costs.
The Integrated segment includes the distribution and transmission operations under JCP&L, MP and PE, as well as MP’s regulated generation operations, representing $8.7 billion in Ohio, Pennsylvania,2023 rate base. The Integrated segment distributes electricity to approximately 2 million customers in New Jersey, West Virginia and Maryland. This segment also controls 3,790Maryland across its distribution footprint; provides transmission infrastructure in New Jersey, West Virginia, Maryland and Virginia to transmit electricity and operates 3,599 MWs of regulated electric generationnet maximum capacity located primarily in West Virginia and Virginia. The segment will also include MP and PE’s 50 MWs of solar generation at five sites in West Virginia once complete. The first solar generation site, located in Maidsville, West Virginia, was completed and New Jersey.placed in-service on January 8, 2024, representing 19 MWs of net maximum capacity. Construction of the remaining four sites is expected to be completed no later than the end of 2025. The segment's results reflect the commodity costsremaining four sites are expected to provide 31 MWs of securing electric generationnet maximum capacity.
The Stand-Alone Transmission segment, which consists of FE's ownership in FET and the deferral and amortization of certain fuel costs.
The Regulated Transmission segment transmits electricity throughKATCo, representing $7.7 billion in 2023 rate base, includes transmission facilitiesinfrastructure owned and operated by ATSI, TrAIL, MAIT (effective January 31, 2017)the Transmission Companies and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP).used to transmit electricity. The segment'ssegment’s revenues are primarily derived from forward-looking formula rates, at ATSI and TrAIL, as well as stated transmission rates at certain of FirstEnergy’s utilities. As discussed in Note 10, "Regulatory Matters - FERC Matters" above, MAIT and JCP&L submitted applicationspursuant to FERC requesting authorization to implement forward-looking formula transmission rates. In March 2017, FERC approved JCP&L's and MAIT's forward-looking formula rate with effective dates of June 1, 2017, and July 1, 2017, respectively, both subject to refund pending the outcome of settlement and hearing proceedings and a final order by FERC. Both the forward-looking and stated rates recover costs and provide a return on transmission capital investment. Under forward-looking rates,which the revenue
requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual rate base and costs. The segment'ssegment’s results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy'sFirstEnergy’s transmission facilities.
The CES segment, through FES and AE Supply, primarily supplies electricity to end-use customers through retail and wholesale arrangements, including competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland, and the provision of partial POLR and default service for some utilities in Ohio, Pennsylvania and Maryland, including the Utilities. As of September 30, 2017, this business segment controlled 13,162 MWs of electric generating capacity, including, as discussed in Note 14, "Asset Impairments," 1,615 MWs of natural gas and hydroelectric generating capacity subject to an asset purchase agreement with KATCo, which was a subsidiary of LS Power and the 1,300 MW Pleasants power station subject to an asset purchase agreement with MP resulting from MP's RFP process to address its generation shortfall, as discussed in Note 10, "Regulatory Matters - State Regulation - West Virginia." The CES segment’s operating results are primarily derived from electric generation sales less the related costsFET, became a wholly owned subsidiary of electricity generation, including fuel, purchased power and net transmission (including congestion) and ancillary costs and capacity costs charged by PJM to deliver energyFE prior to the segment’s customers, as well asclosing of the FET P&SA I and remains in the Stand-Alone Transmission segment. On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo and for comparability, prior year results in the Stand-Alone Transmission segment reflects the earnings and results of those WP transmission assets.
Corporate/Other reflects corporate support and other operating and maintenance costs including costs incurred by FENOC.
Corporate support not charged or attributable to FE'sthe Utilities or Transmission Companies, including FE’s retained pension and OPEB assets and liabilities of former subsidiaries, interest expense on stand-aloneFE’s holding company debt corporate income taxes and other investments or businesses that do not constitute an operating segment, are categorized as Corporate/Other for reportable business segment purposes. Additionally, reconcilingincluding FEV’s investment of 33-1/3% equity ownership in Global Holding. Reconciling adjustments for the elimination of inter-segment transactions are shown separately in the following table of Segment Financial Information. Also included in Corporate/Other.Other for segment reporting is 67 MWs of net maximum capacity, representing AE Supply’s OVEC capacity entitlement. As of September 30, 2017,March 31, 2024, Corporate/Other had $6.8approximately $6.5 billion of stand-aloneFE’s holding company long-term debt, of which $1.45 billion was subject to variable-interest rates, and $500 million was borrowed by FE under its revolving credit facility.
debt.
Financial information for FirstEnergy’s reportable segments and reconciliations to consolidated amounts is presented below:
Segment Financial Information | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(In millions) For the Three Months Ended | | Distribution | | Integrated | | Stand-Alone Transmission | | Total Reportable
Segments | | Corporate/ Other | | Reconciling Adjustments | | FirstEnergy Consolidated |
| | |
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| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| March 31, 2024 | | | | | | | | | | | | | | |
| External revenues | | $ | 1,756 | | | $ | 1,094 | | | $ | 434 | | | $ | 3,284 | | | $ | 3 | | | $ | — | | | $ | 3,287 | |
| Internal revenues | | 11 | | | 1 | | | 4 | | | 16 | | | — | | | (16) | | | — | |
| Total revenues | | $ | 1,767 | | | $ | 1,095 | | | $ | 438 | | | $ | 3,300 | | | $ | 3 | | | $ | (16) | | | $ | 3,287 | |
| Depreciation | | 161 | | | 122 | | | 81 | | | 364 | | | 17 | | | — | | | 381 | |
| Amortization (deferral) of regulatory assets, net | | (88) | | | (78) | | | 2 | | | (164) | | | — | | | — | | | (164) | |
| | | | | | | | | | | | | | |
| Equity method investment earnings | | — | | | — | | | — | | | — | | | 21 | | | — | | | 21 | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| Interest expense | | 116 | | | 71 | | | 65 | | | 252 | | | 117 | | | (64) | | | 305 | |
| Income taxes (benefits) | | 41 | | | 35 | | | 60 | | | 136 | | | (1) | | | — | | | 135 | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| Earnings (losses) attributable to FE | | $ | 165 | | | $ | 82 | | | $ | 84 | | | $ | 331 | | | $ | (78) | | | $ | — | | | $ | 253 | |
| Cash Flows from Investing Activities: | | | | | | | | | | | | | | |
| Capital investments | | $ | 215 | | | $ | 313 | | | $ | 258 | | | $ | 786 | | | $ | 4 | | | $ | — | | | $ | 790 | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| March 31, 2023 | | | | | | | | | | | | | | |
| External revenues | | $ | 1,807 | | | $ | 1,026 | | | $ | 396 | | | $ | 3,229 | | | $ | 2 | | | $ | — | | | $ | 3,231 | |
| Internal revenues | | 10 | | | 2 | | | 4 | | | 16 | | | — | | | (16) | | | — | |
| Total revenues | | $ | 1,817 | | | $ | 1,028 | | | $ | 400 | | | $ | 3,245 | | | $ | 2 | | | $ | (16) | | | $ | 3,231 | |
| Depreciation | | 153 | | | 113 | | | 75 | | | 341 | | | 20 | | | — | | | 361 | |
| Amortization (deferral) of regulatory assets, net | | (41) | | | (40) | | | 1 | | | (80) | | | — | | | — | | | (80) | |
| | | | | | | | | | | | | | |
| Equity method investment earnings | | — | | | — | | | — | | | — | | | 56 | | | — | | | 56 | |
| | | | | | | | | | | | | | |
| Interest expense | | 94 | | | 59 | | | 58 | | | 211 | | | 77 | | | (25) | | | 263 | |
| Income taxes (benefits) | | 44 | | | 20 | | | 33 | | | 97 | | | (7) | | | — | | | 90 | |
| | | | | | | | | | | | | | |
| Earnings (losses) attributable to FE | | $ | 186 | | | $ | 70 | | | $ | 96 | | | $ | 352 | | | $ | (60) | | | $ | — | | | $ | 292 | |
| Cash Flows from Investing Activities: | | | | | | | | | | | | | | |
| Capital investments | | $ | 193 | | | $ | 237 | | | $ | 212 | | | $ | 642 | | | $ | 7 | | | $ | — | | | $ | 649 | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| As of March 31, 2024 | | | | | | | | | | | | | | |
| Total assets | | $ | 20,144 | | | $ | 17,627 | | | $ | 12,389 | | | $ | 50,160 | | | $ | 4,398 | | | $ | (3,259) | | | $ | 51,299 | |
Total goodwill(1) | | $ | 3,222 | | | $ | 1,953 | | | $ | 443 | | | $ | 5,618 | | | $ | — | | | $ | — | | | $ | 5,618 | |
| | | | | | | | | | | | | | |
| As of December 31, 2023 | | | | | | | | | | | | | | |
| Total assets | | $ | 19,235 | | | $ | 17,466 | | | $ | 12,142 | | | $ | 48,843 | | | $ | 2,372 | | | $ | (2,448) | | | $ | 48,767 | |
Total goodwill(1) | | $ | 3,222 | | | $ | 1,953 | | | $ | 443 | | | $ | 5,618 | | | $ | — | | | $ | — | | | $ | 5,618 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended | | Regulated Distribution | | Regulated Transmission | | Competitive Energy Services | | Corporate/ Other | | Reconciling Adjustments | | Consolidated |
| | | (In millions) |
| | | | | | | | | | | | | |
| September 30, 2017 | | | | | | | | | | | | |
| External revenues | | $ | 2,610 |
| | $ | 342 |
| | $ | 796 |
| | $ | — |
| | $ | (34 | ) | | $ | 3,714 |
|
| Internal revenues | | — |
| | — |
| | 93 |
| | — |
| | (93 | ) | | — |
|
| Total revenues | | 2,610 |
| | 342 |
| | 889 |
| | — |
| | (127 | ) | | 3,714 |
|
| Depreciation | | 183 |
| | 59 |
| | 30 |
| | 17 |
| | — |
| | 289 |
|
| Amortization of regulatory assets, net | | 85 |
| | 6 |
| | — |
| | — |
| | — |
| | 91 |
|
| Impairment of assets (Note 14) | | — |
| | 13 |
| | 18 |
| | — |
| | — |
| | 31 |
|
| Investment income | | 13 |
| | — |
| | 34 |
| | 3 |
| | (13 | ) | | 37 |
|
| Interest expense | | 133 |
| | 38 |
| | 44 |
| | 90 |
| | — |
| | 305 |
|
| Income taxes (benefits) | | 183 |
| | 49 |
| | 40 |
| | (33 | ) | | — |
| | 239 |
|
| Net income (loss) | | 314 |
| | 84 |
| | 66 |
| | (68 | ) | | — |
| | 396 |
|
| Total assets | | 27,866 |
| | 9,356 |
| | 5,814 |
| | 613 |
| | — |
| | 43,649 |
|
| Total goodwill | | 5,004 |
| | 614 |
| | — |
| | — |
| | — |
| | 5,618 |
|
| Property additions | | 286 |
| | 248 |
| | 45 |
| | 14 |
| | — |
| | 593 |
|
| | | | | | | | | | | | | |
| September 30, 2016 | | |
| | |
| | |
| | |
| | | | |
|
| External revenues | | $ | 2,691 |
| | $ | 294 |
| | $ | 998 |
| | $ | — |
| | $ | (66 | ) | | $ | 3,917 |
|
| Internal revenues | | — |
| | — |
| | 117 |
| | — |
| | (117 | ) | | — |
|
| Total revenues | | 2,691 |
| | 294 |
| | 1,115 |
| | — |
| | (183 | ) | | 3,917 |
|
| Depreciation | | 169 |
| | 47 |
| | 79 |
| | 16 |
| | — |
| | 311 |
|
| Amortization of regulatory assets, net | | 98 |
| | — |
| | — |
| | — |
| | — |
| | 98 |
|
| Investment income | | 13 |
| | — |
| | 23 |
| | 2 |
| | (10 | ) | | 28 |
|
| Interest expense | | 143 |
| | 39 |
| | 48 |
| | 56 |
| | — |
| | 286 |
|
| Income taxes (benefits) | | 162 |
| | 50 |
| | 49 |
| | (10 | ) | | — |
| | 251 |
|
| Net income (loss) | | 276 |
| | 85 |
| | 86 |
| | (67 | ) | | — |
| | 380 |
|
| Total assets | | 27,818 |
| | 8,492 |
| | 15,165 |
| | 486 |
| | — |
| | 51,961 |
|
| Total goodwill | | 5,004 |
| | 614 |
| | — |
| | — |
| | — |
| | 5,618 |
|
| Property additions | | 281 |
| | 268 |
| | 110 |
| | 5 |
| | — |
| | 664 |
|
| | | | | | | | | | | | | |
| For the Nine Months Ended | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| September 30, 2017 | | | | | | | | | | | | |
| External revenues | | $ | 7,362 |
| | $ | 982 |
| | $ | 2,388 |
| | $ | — |
| | $ | (157 | ) | | $ | 10,575 |
|
| Internal revenues | | — |
| | — |
| | 296 |
| | — |
| | (296 | ) | | — |
|
| Total revenues | | 7,362 |
| | 982 |
| | 2,684 |
| | — |
| | (453 | ) | | 10,575 |
|
| Depreciation | | 540 |
| | 164 |
| | 87 |
| | 54 |
| | — |
| | 845 |
|
| Amortization of regulatory assets, net | | 204 |
| | 11 |
| | — |
| | — |
| | — |
| | 215 |
|
| Impairment of assets (Note 14) | | — |
| | 13 |
| | 149 |
| | — |
| | — |
| | 162 |
|
| Investment income | | 41 |
| | — |
| | 66 |
| | 8 |
| | (37 | ) | | 78 |
|
| Interest expense | | 405 |
| | 116 |
| | 136 |
| | 225 |
| | — |
| | 882 |
|
| Income taxes (benefits) | | 442 |
| | 154 |
| | (25 | ) | | (89 | ) | | — |
| | 482 |
|
| Net income (loss) | | 756 |
| | 264 |
| | (57 | ) | | (188 | ) | | — |
| | 775 |
|
| Property additions | | 854 |
| | 717 |
| | 233 |
| | 43 |
| | — |
| | 1,847 |
|
| | | | | | | | | | | | | |
| September 30, 2016 | | | | | | | | | | | | |
| External revenues | | $ | 7,390 |
| | $ | 851 |
| | $ | 3,158 |
| | $ | — |
| | $ | (212 | ) | | $ | 11,187 |
|
| Internal revenues | | — |
| | — |
| | 377 |
| | — |
| | (377 | ) | | — |
|
| Total revenues | | 7,390 |
| | 851 |
| | 3,535 |
| | — |
| | (589 | ) | | 11,187 |
|
| Depreciation | | 504 |
| | 138 |
| | 284 |
| | 48 |
| | — |
| | 974 |
|
| Amortization of regulatory assets, net | | 218 |
| | 4 |
| | — |
| | — |
| | — |
| | 222 |
|
| Impairment of assets (Note 14) | | — |
| | — |
| | 1,447 |
| | — |
| | — |
| | 1,447 |
|
| Investment income | | 37 |
| | — |
| | 56 |
| | 13 |
| | (31 | ) | | 75 |
|
| Interest expense | | 441 |
| | 118 |
| | 143 |
| | 161 |
| | — |
| | 863 |
|
| Income taxes (benefits) | | 336 |
| | 143 |
| | (96 | ) | | (49 | ) | | — |
| | 334 |
|
| Net income (loss) | | 573 |
| | 244 |
| | (1,029 | ) | | (169 | ) | | — |
| | (381 | ) |
| Property additions | | 809 |
| | 824 |
| | 492 |
| | 31 |
| | — |
| | 2,156 |
|
14. ASSET IMPAIRMENTS
Competitive Generation Asset Sale
FirstEnergy announced in January 2017 that AE Supply and AGC had entered into an asset purchase agreement (which was subsequently amended and restated as described below) to sell four of AE Supply’s natural gas generating plants and approximately 59% of AGC’s interest in(1) In accordance with GAAP, the Bath County pumped hydro facility (1,572 MWs of combined capacity) to a subsidiary of LS Power for an all-cash purchase price of $925 million, subject to customary and other closing conditions, including receipt of regulatory approvals from FERC and the VSCC, as applicable, and various third-party consents. On February 17, 2017, AE Supply and AGC submitted a filing with FERC and on June 13, 2017, FERC issued an order authorizing such transaction as described in the January 2017 asset purchase agreement. On September 29, 2017, the parties filed a request with FERC for authorization to transfer the related hydroelectric license for Bath County under Part I of the FPA. Additional filings have been submitted to FERC for the purpose of amending affected FERC-jurisdictional rates and implementing the transaction once all regulatory approvals are obtained. Additionally, the consent of VEPCO is needed for the sale of AGC’s interest in the Bath County pumped hydro facility, as well as agreement among AGC, LS Power and VEPCO with respect to certain amendmentsmodification to the Bath County project agreements.
On August 30, 2017, the parties, along with AE Supply's subsidiary BU Energy, executed an amended and restated asset purchase agreement to (1) reduce the purchase price to $825 million, subject to adjustments, (2) add BU Energy’s 50% interest in a joint venture that owns the Buchanan Generating Facility (43 MWs) to the transaction and (3) provide that each component of the transaction (i.e., the AE Supply natural gas facilities, AGC’s interest in the Bath County hydroelectric power station and BU Energy’s interest in the Buchanan Generating Facility) may close independently. The sale of the AE Supply natural gas generating plants is expected to close in the fourth quarter of 2017 and the sale of approximately 59% of AGC’s interests in the Bath County hydroelectric power station and BU Energy’s 50% interest in the Buchanan Generating Facility are expected to closesegments in the first quarter of 2018, subject in each case to various customary and other closing conditions including, without limitation, receipt of regulatory approvals and third-party consents, including the consent of VEPCO2024, as discussed above. Underabove, resulted in a transfer of goodwill between the amended and restated purchase agreement, AE Supply has agreed to satisfy and discharge all of its approximately $305 million of currently outstanding senior notes, which is expected to require the payment of a “make-whole” premium currently estimated to be approximately $100 millionsegments based on current interest rates, upon both (i) the consummation of the sale of the natural gas generating plants and (ii) either (a) the consummation of the sale of approximately 59% of AGC's interest in the Bath County hydroelectric power station or (b) the consummation of the pending sale of the Pleasants Power Station by AE Supply to its affiliate, MP. As a further condition to closing, FE will provide the purchaser two limited three-year guarantees of certain obligations of AE Supply and AGC arising under the amended and restated purchase agreement. On September 29, 2017, the parties filed an application with FERC for authorization to complete the Buchanan Generating Facility sale. On October 20, 2017, the parties filed an application with the VSCC for approval of the sale of approximately 59% of AGC's interest in the Bath County hydroelectric power station. There can be no assurance that all regulatory approvals will be obtained and/or all closing conditions will be satisfied or that any of the transactions will be consummated.
As a result of the amended asset purchase agreement, CES recorded non-cash pre-tax impairment charges of $158 million in the nine-month period ended September 30, 2017.
Assets held for sale as of September 30, 2017, include property, plant and equipment (net of accumulated provision for depreciation) of $765 million, investments of $20 million, materials and supplies inventory of $4 million, and AROs of approximately $1 million.
MAIT Transmission Formula Rate Settlement
As described in Note 10, “Regulatory Matters,” on October 13, 2017, MAIT and certain parties filed a settlement agreement with FERC, which is subject to a final order. As a result of the settlement agreement, MAIT recorded a pre-tax impairment charge of $13 million in the third quarter of 2017.
Competitive Generation Deactivations and Other Exit Activities
On July 22, 2016, FirstEnergy and FES announced their intent to exit operations of the Bay Shore Unit 1 generating station (136 MWs) by October 1, 2020, through either sale or deactivation and to deactivate Units 1-4 of the W.H. Sammis generating station (720 MWs) by May 31, 2020. As a result, FirstEnergy recorded a non-cash pre-tax impairment charge of $647 million ($517 million - FES) in the second quarter of 2016. PJM and the Independent Market Monitor have approved the W.H. Sammis Units 1-4 and Bay Shore Unit 1 deactivations. In addition, FirstEnergy and FES recorded termination and settlement costs on fuel contracts of approximately $58 million (pre-tax) in the second quarter of 2016 resulting from plant retirements and deactivations, which is included in Fuel expense in the Consolidated Statement of Income (Loss).
Goodwill
As a result of low capacity prices associated with the 2019/2020 PJM Base Residual Auction in May 2016, as well as its annual update to its fundamental long-term capacity and energy price forecast, FirstEnergy determined that an interim impairment analysis of the CES reporting unit’s goodwill was necessary during the second quarter of 2016.
Consistent with FirstEnergy’s annual goodwill impairment test, a discounted cash flow analysis was used to determine therelative fair value of the CES reporting unit for purposes of step oneunits, and as such, the segment goodwill balances do not necessarily represent the goodwill balances of the interim goodwill impairment test. Key assumptions incorporated intospecific legal entities within the CES discounted cash flow analysis requiring significant management judgment included the following:
segments.
Future Energy and Capacity Prices: Observable market information for near-term forward power prices, PJM auction results for near term capacity pricing, and a longer-term fundamental pricing model for energy and capacity that considered the impact of key factors such as load growth, plant retirements, carbon and other environmental regulations, and natural gas pipeline construction, as well as coal and natural gas pricing.
33
Retail Sales and Margin: CES' current retail targeted portfolio to estimate future retail sales volume as well as historical financial results to estimate retail margins.
Operating and Capital Costs: Estimated future operating and capital costs, including the estimated impact on costs of pending carbon and other environmental regulations, as well as costs associated with capacity performance reforms in the PJM market.
Discount Rate: A discount rate of 9.50%, based on selected comparable companies' capital structure, return on debt and return on equity.
Terminal Value: A terminal value of 7.0x earnings before interest, taxes, depreciation and amortization based on consideration of peer group data and analyst consensus expectations.
Based on the impairment analysis, FirstEnergy determined that the carrying value of goodwill exceeded its fair value and recognized a non-cash pre-tax impairment charge of $800 million ($23 million - FES) in the second quarter of 2016, which is included in Impairment of assets in the Consolidated Statement of Income (Loss).
Termination of Customer Contract
During the third quarter of 2016, FES recorded a pre-tax charge of $32 million associated with the termination of a customer contract, which is included in Other operating expenses in the Consolidated Statement of Income (Loss).
ITEM 2. Management’s Discussion and Analysis of RegistrantFinancial Condition and SubsidiariesResults of Operations
FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FIRSTENERGY’S BUSINESS
EXECUTIVE SUMMARY AND RECENT DEVELOPMENTS
Company Overview
FirstEnergy is dedicated to integrity, safety, reliability and its subsidiaries areoperational excellence and is principally involved in the transmission, distribution and generation of electricity through its reportable segments: Distribution, Integrated and Stand-Alone Transmission. Its electric distribution companies form one of the nation's largest investor-owned electric systems, serving over six million customers in Ohio, Pennsylvania, New Jersey, West Virginia, Maryland and New York. FirstEnergy’s transmission subsidiaries operate more than 24,000 miles of transmission lines that connect the Midwest and Mid-Atlantic regions and two regional transmission operation centers. AGC and MP control 3,599 MWs net maximum capacity.
PA Consolidation
On January 1, 2024, FirstEnergy consolidated the Pennsylvania Companies into FE PA, including OE subsidiary, Penn, making FE PA a new, single operating entity and the successor-in-interest to all assets and liabilities of the Pennsylvania Companies. FE PA, as of January 1, 2024, is FE’s only regulated distribution utility in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies and FE PA serves an area with a population of electricity. Itsapproximately 4.5 million and operates under the rate districts of the former Pennsylvania Companies. FirstEnergy is also evaluating the legal, financial, operational and branding benefits of consolidating the Ohio Companies into a single Ohio utility company.
Also on January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo, and PN and ME contributed their respective Class B equity interests of MAIT to FE, which were ultimately contributed to FET in exchange for a special purpose membership interest in FET. So long as FE holds the FET special purpose membership interests, it will receive 100% of any Class B distributions made by MAIT.
Segment Change
As further discussed above, in 2024, FirstEnergy changed its reportable segments are as follows: Regulated to include the following:
The Distribution Regulated Transmission, segment, which consists of the Ohio Companies and CES.
The Regulated Distribution segmentFE PA, representing $10.9 billion in 2023 rate base, distributes electricity through FirstEnergy’s ten utility operating companies servingin Ohio and Pennsylvania. The Distribution segment serves approximately six4.2 million customers within 65,000 square miles ofin Ohio and Pennsylvania West Virginia, Maryland, New Jersey and New York,across its distribution footprint and purchases power for its POLR,provider of last resort, SOS, SSOstandard service offer and default service requirementsrequirements. The segment’s results reflect the costs of securing and delivering electric generation from transmission facilities to customers, including the deferral and amortization of certain costs.
The Integrated segment includes the distribution and transmission operations under JCP&L, MP and PE, as well as MP’s regulated generation operations, representing $8.7 billion in Ohio, Pennsylvania,2023 rate base. The Integrated segment distributes electricity to approximately 2 million customers in New Jersey, West Virginia and Maryland. This segment also controls 3,790Maryland across its distribution footprint; provides transmission infrastructure in New Jersey, West Virginia, Maryland and Virginia to transmit electricity and operates 3,599 MWs of regulated electric generationnet maximum capacity located primarily in West Virginia and Virginia. The segment will also include MP and PE’s 50 MWs of solar generation at five sites in West Virginia once complete. The first solar generation site, located in Maidsville, West Virginia, was completed and New Jersey.placed in-service on January 8, 2024, representing 19 MWs of net maximum capacity. Construction of the remaining four sites is expected to be completed no later than the end of 2025. The segment's results reflect the commodity costsremaining four sites are expected to provide 31 MWs of securing electric generationnet maximum capacity.
The Stand-Alone Transmission segment, which consists of FE's ownership in FET and the deferral and amortization of certain fuel costs.
The Regulated Transmission segment transmits electricity throughKATCo, representing $7.7 billion in 2023 rate base, includes transmission facilitiesinfrastructure owned and operated by ATSI, TrAIL, MAIT (effective January 31, 2017)the Transmission Companies and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP).used to transmit electricity. The segment'ssegment’s revenues are primarily derived from forward-looking formula rates, at ATSI and TrAIL, as well as stated transmission rates at certain of FirstEnergy’s utilities. As discussed in "Outlook - FERC Matters" below, MAIT and JCP&L submitted applicationspursuant to FERC requesting authorization to implement forward-looking formula transmission rates. In March 2017, FERC approved JCP&L's and MAIT's forward-looking formula rate with effective dates of June 1, 2017, and July 1, 2017, respectively, both subject to refund pending the outcome of settlement and hearing proceedings and a final order by FERC. Both the forward-looking and stated rates recover costs and provide a return on transmission capital investment. Under forward-looking rates,which the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual rate base and costs. The segment'ssegment’s results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy'sFirstEnergy’s transmission facilities.
The CES segment, through FESCorporate/Other reflects corporate support and AE Supply, primarily supplies electricity to end-use customers through retail and wholesale arrangements, including competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland, and the provision of partial POLR and default service for some utilities in Ohio, Pennsylvania and Maryland, including the Utilities. As of September 30, 2017, this business segment controlled 13,162 MWs of electric generating capacity, including, as further discussed below, 1,615 MWs of natural gas and hydroelectric generating capacity subject to an asset purchase agreement with a subsidiary of LS Power and the 1,300 MW Pleasants power station subject to an asset purchase agreement with MP resulting from MP's RFP process to address its generation shortfall. The CES segment’s operating results are primarily derived from electric generation sales less the relatedother costs of electricity generation, including fuel, purchased power and net transmission (including congestion) and ancillary costs and capacity costsnot charged by PJM to deliver energyor attributable to the segment’s customers, as well as other operatingUtilities or Transmission Companies, including FE’s retained pension and maintenance costs, including costs incurred by FENOC.
Corporate support not charged to FE'sOPEB assets and liabilities of former subsidiaries, interest expense on stand-aloneFE’s holding company debt corporate income taxes and other investments or businesses that do not constitute an operating segment, are categorized as Corporate/Other for reportable business segment purposes.including FEV’s investment of 33-1/3% equity ownership in Global Holding. Additionally, reconciling adjustments for the elimination of inter-segment transactions are included in Corporate/Other. Also included in Corporate/Other for segment reporting is 67 MWs of net
maximum capacity, representing AE Supply’s OVEC capacity entitlement. As of September 30, 2017,March 31, 2024, Corporate/Other had $6.8approximately $6.5 billion of stand-aloneFE’s holding company long-term debt, of which $1.45 billion was subject to variable-interest rates, and $500 million was borrowed by FE under its revolving credit facility.debt.
EXECUTIVE SUMMARY
FirstEnergy believes having a combination of distribution, transmission and generation assets in a regulated or regulated-like construct is the best waythat this segment reporting serves to serve customers. FirstEnergy’s strategy is to be a fully regulated utility, focusing on stable and predictable earnings andprovide:
•Greater transparency into our business unit performance;
•Alignment with our cash flow, from its regulated business units.
Over the past several years, CES has been impacted by a decrease in demandcredit metrics, balance sheet and excess generation supply in the PJM Region, which has resulted in low power and capacity prices, as well as significant environmental compliance costs. To address this, CES sold or deactivated more than 6,770 MWs of competitive generation from 2012 to 2015 and announced in 2016 plans to exit and/or deactivate an additional 856 MWs by 2020 relatedearnings to the Bay Shore Unit 1 generating stationcompanies comprising each segment;
•Simplification of our segment reporting so that each entire entity resides within a segment; and Units 1-4 of the W.H. Sammis generating station. Additionally, CES has continued to focus on cost reductions, including those identified as part of FirstEnergy’s previously disclosed cash flow improvement plan.
•Consistency with peers.
However, the energy and capacity markets remain weakFET Equity Interest Sale
On February 2, 2023, FE, along with significantly low capacity clearing prices and current forward pricing as well as the long-term fundamental view on energy and capacity prices. In order to focus on stable and predictable cash flow from its regulated business units, in November of 2016, FirstEnergy announced a strategic review of its competitive operations with a target to implement its exit from competitive operations by mid-2018.
In connection with this strategic review, AE Supply and AGCFET, entered into an asset purchase agreementthe FET P&SA II with a subsidiary of LS Power, as amendedBrookfield and restated in August 2017,the Brookfield Guarantors, pursuant to which FE agreed to sell four natural gas generating plants, AE Supply'sto Brookfield at the closing, and Brookfield agreed to purchase from FE, an incremental 30% equity interest in the Buchanan Generating Facility and approximately 59% of AGC’s interest in Bath County (1,615 MWs of combined capacity)FET for an all-casha purchase price of $825$3.5 billion. The FET Equity Interest Sale closed on March 25, 2024 and FET continues to be consolidated in FirstEnergy’s financial statements. The purchase price was paid in part by the issuance of two promissory notes at closing having an aggregate principal amount of $1.2 billion with: (i) one promissory note having an aggregate principal amount of $750 million, subjectat an interest rate of 5.75% per annum, with a maturity date of September 25, 2025 and (ii) one promissory note having an aggregate principal amount of $450 million, at an interest rate of 7.75% per annum, with a maturity date of December 31, 2024. Both notes are expected to adjustments. Closingbe repaid in 2024. The remaining $2.3 billion of the transaction is subject to customary and other closing conditions including receiptpurchase price was paid in cash at closing. Brookfield Corporation has guaranteed the full amount of regulatory approvals from FERC and the VSCC, third party consents and the satisfaction and dischargepromissory notes. As a result of $305 million of AE Supply’s senior notes, which is expected to require the payment of a “make-whole” premium currently estimated to be approximately $100 million based on current interest rates, upon both (i) the consummation of the sale of the natural gas generating plants and (ii) either (a) the consummation of the sale of approximately 59% of AGC'stransaction, Brookfield’s interest in FET increased from 19.9% to 49.9%, while FE retained the Bath County hydroelectric power stationremaining 50.1% ownership interests of FET.
FIRSTENERGY’S CONSOLIDATED RESULTS OF OPERATIONS
First Three Months of 2024 Compared with First Three Months of 2023
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | | For the Three Months Ended March 31, | | |
| | 2024 | | 2023 | | Change | | | | | | |
| | | | | | | | | | | | | | | | |
| Revenues | | $ | 3,287 | | | $ | 3,231 | | | $ | 56 | | | 2 | % | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Operating expenses | | 2,675 | | | 2,680 | | | (5) | | | — | % | | | | | | | | |
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| Other expenses, net | | (210) | | | (151) | | | (59) | | | (39) | % | | | | | | | | |
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| Income taxes | | 135 | | | 90 | | | 45 | | | 50 | % | | | | | | | | |
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| Income attributable to noncontrolling interest | | 14 | | | 18 | | | (4) | | | (22) | % | | | | | | | | |
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| Earnings attributable to FE | | $ | 253 | | | $ | 292 | | | $ | (39) | | | (13) | % | | | | | | | | |
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Earnings attributable to FE was $253 million or (b) the consummation of the pending sale of the Pleasants Power Station by AE Supply to its affiliate, MP, as discussed below. As a further condition to closing, FE will provide the purchaser two limited three-year guarantees of certain obligations of AE Supply$0.44 per share (basic and AGC arising under the amended and restated purchase agreement. The sale of the natural gas generating plants is expected to close in the fourth quarter of 2017 and the sale of approximately 59% of AGC’s interests in the Bath County hydroelectric power station and BU Energy’s 50% interest in the Buchanan Generating Facility are expected to closediluted) in the first quarter of 2018. For additional information see "Outlook" below.
Additionally, AE Supply’s Pleasants power station (1,300 MWs) was selected in MP's RFP seeking additional generation capacity,2024 compared to $292 million or $0.51 per share (basic and on March 6, 2017, MP and AE Supply signed an asset purchase agreement for MP to acquire the Pleasants power station for approximately $195 million, subject to customary and other closing conditions, including regulatory approvals as further discussed below.
The strategic options to exit the remaining portion of CES’ generation, which is primarily at FES, are still uncertain, but could include one or more of the following:
legislative or regulatory solutions for generation assets that recognize their environmental or energy security benefits;
restructuring FES debt with its creditors;
seeking protection under U.S. bankruptcy laws for FES and likely FENOC; and/or
additional asset sales and/or plant deactivations.
Furthermore, the implementation of various strategic options, and the timing thereof, could be impacted by various events, including, but not limited to the following:
The outcome of efforts related to the NOPR released by the Secretary of Energy and action by FERC to address critical issues central to protecting the long-term reliability and resiliency of the electric grid provided by traditional baseload resources, such as coal and nuclear generation;
The resolution of legislation before the Ohio General Assembly that would create a zero-emission nuclear (ZEN) program that would provide compensation to nuclear power plants for their fuel diversity, environmental and other benefits and the potential for similar legislative action in Pennsylvania; and/or
The inability to finalize and consummate a settlement agreement with BNSF and NS regarding a previously disclosed long-term coal transportation contract dispute as discussed in "Outlook - Environmental Matters" below, whereby FG could be subject to materially higher damages.
Today, the competitive generation portfolio is comprised of more than 13,000 MWs of generation, primarily from coal, nuclear and natural gas and oil fuel sources. The assets can generate approximately 70-75 million MWHs annually, with up to an additional five million MWHs available from purchased power agreements for wind, solar, and CES' entitlement in OVEC, of which a portion is sold through various retail channels and the remainder targeting forward wholesale or spot sales. Subject to the completion of the AE Supply and AGC asset sale discussed above as well as the transfer of the Pleasants Power station to MP, the size and generation capacity of CES’ portfolio will be reduced to approximately 10,000 MWs, primarily at FES, with up to approximately 65 million MWHs produced annually.
The competitive business continues to be managed conservatively due to the stress of weak energy prices, insufficient results from recent capacity auctions and anemic demand forecasts. Furthermore, the credit quality of CES, specifically FES' unsecured debt rating of Caa1 at Moody’s, CCC- at S&P and C at Fitch and a negative outlook from Moody's and S&P, has challenged its ability to hedge generation with retail and forward wholesale sales due to significant collateral requirements. As a result, CES' contract sales are expected to decline from 53 million MWHs in 2016 to 40-45 million MWHs in 2017 and to 30-35 million MWHs in 2018. While the reduced contract sales will decrease potential collateral requirements, market price volatility may significantly impact CES' financial results due to the increased exposure to the wholesale spot market.
Although FES has access to a $500 million secured line of credit with FE, all of which was available as of September 30, 2017, its current credit rating and the current forward wholesale pricing environment present significant challenges to FES. Furthermore, an inability to develop and execute upon viable alternative strategies for its competitive portfolio would continue to further stress the liquidity and financial condition of FES.
Cash flow from operations at FES is expected to be sufficient to fund capital expenditures, nuclear fuel purchases, and repay money pool borrowings through March 2018. However, as previously disclosed, FES has $515 million of maturing debt in 2018, beginning in the second quarter. Additionally, FES has $48 million of interest and lease payments in December 2017 and $38 million of interest paymentsdiluted) in the first quarter of 2018. Based on FES' current senior unsecured debt rating, capital structure and the forecasted decline in wholesale forward market prices over the next few years, the debt maturities are likely to be difficult to refinance. Furthermore, lack of clarity regarding the timing and viability of alternative strategies, including additional asset sales or deactivations and/or converting generation from competitive operations to a regulated or regulated-like construct in a way that provides FES with the means to satisfy its obligations over the long-term, may also require FES to restructure debt and other financial obligations with its creditors and/or seek protection under U.S. bankruptcy laws. In the event FES seeks protection under U.S. bankruptcy laws, FENOC will likely seek such protection. Although management is exploring capital and other cost reductions, asset sales, and other options to improve cash flow as well as continuing with efforts to explore legislative or regulatory solutions, these obligations and their impact to liquidity raise substantial doubt about FES’ ability to meet its obligations as they come due over the next twelve months and, as such, its ability to continue as a going concern.
As FirstEnergy continues to further evaluate and implement the strategic review for its competitive operations, management continues to focus on its two regulated businesses - Regulated Transmission and Regulated Distribution - which focus on delivering enhanced customer service and reliability, strengthening grid and cyber-security and adding resiliency and operating flexibility to the transmission and distribution infrastructure, as well as improving the reliability and efficiency of Regulated Distribution's generation capacity - all while delivering solid operating results.
Together, the Regulated Transmission and Distribution businesses are expected to provide stable, predictable earnings and cash flows to support FE’s dividend.
With more than 24,500 miles in operations, the transmission system is the centerpiece of FirstEnergy’s regulated investment strategy. Regulated Transmission's rate base compounded annual growth rate is expected to be 9% through 2021 as the company plans to invest $4.2 to $5.8 billion in capital from 2017 to 2021 as part of its Energizing the Future transmission plan, which began as a $4.2 billion investment plan from 2014 through 2017 to upgrade FirstEnergy's transmission system.
These investments continue to be focused in the stand-alone transmission companies with effective forward-looking formula rates including ATSI and TrAIL as well as forward-looking formula rates at MAIT and JCP&L, which FERC approved in March 2017 with effective dates of June 1, 2017 and July 1, 2017, respectively, both subject to refund pending further hearing and settlement proceedings and a final FERC order. FirstEnergy believes its existing transmission infrastructure creates incremental investment opportunities of approximately $20 billion beyond those identified through 2021 which will make the transmission system more reliable, robust, secure and resistant to extreme weather events, with improved operational flexibility. FirstEnergy plans to fund a portion of its long-term cash needs, including Regulated Transmission's capital program with at least $1.5 billion of equity through 2019, subject to market conditions and other factors, as discussed in "Capital Resources and Liquidity".
In addition to the significant opportunities at Regulated Transmission, the scale and diversity of the ten Utilities that comprise the Regulated Distribution segment uniquely position this business unit for growth and represents an additional investment opportunity. Last year, eight of the ten Utilities completed rate proceedings the results of which are expected to provide benefits to the customers and communities those Utilities serve while providing for additional growth opportunities. These may include future investments in smart meter technology and electric system improvement projects to increase reliability and improve service to their customers, as well as exploring future opportunities in customer engagement that focuses on the electrification of customers' homes and businesses by providing a full range of products and services.
Although weather adjusted distribution deliveries through 2019 are forecasted to be flat as compared to 2016, Regulated Distribution’s earnings over the next three years are anticipated to increase as a result of (i) the PUCO-approved ESP IV, which includes $204 million in additional annual revenue pursuant to DMR that became effective January 1, 2017, (ii) the PPUC-approved settlement agreements in the Pennsylvania Companies’ base rate cases, which include approximately $290 million in aggregate additional annual revenue, effective January 27, 2017, and (iii) the NJBPU-approved settlement in JCP&L’s base rate case, which provides for an $80 million annual revenue increase effective January 1, 2017.
FINANCIAL OVERVIEW
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| (In millions, except per share amounts) | | For the Three Months Ended September 30 | | For the Nine Months Ended September 30 |
| | | 2017 | | 2016 | | Change | | 2017 | | 2016 | | Change |
| | | | | | | | | | | | | | | | | |
| REVENUES: | | $ | 3,714 |
| | $ | 3,917 |
| | $ | (203 | ) | | (5 | )% | | $ | 10,575 |
| | $ | 11,187 |
| | $ | (612 | ) | | (5 | )% |
| | | | | | | | | | | | | | | | | |
| OPERATING EXPENSES: | | | | | | | | | | | | | | | | |
| Fuel | | 363 |
| | 450 |
| | (87 | ) | | (19 | )% | | 1,074 |
| | 1,269 |
| | (195 | ) | | (15 | )% |
| Purchased power | | 861 |
| | 979 |
| | (118 | ) | | (12 | )% | | 2,459 |
| | 2,992 |
| | (533 | ) | | (18 | )% |
| Other operating expenses | | 942 |
| | 953 |
| | (11 | ) | | (1 | )% | | 3,041 |
| | 2,835 |
| | 206 |
| | 7 | % |
| Provision for depreciation | | 289 |
| | 311 |
| | (22 | ) | | (7 | )% | | 845 |
| | 974 |
| | (129 | ) | | (13 | )% |
| Amortization of regulatory assets, net | | 91 |
| | 98 |
| | (7 | ) | | (7 | )% | | 215 |
| | 222 |
| | (7 | ) | | (3 | )% |
| General taxes | | 253 |
| | 265 |
| | (12 | ) | | (5 | )% | | 777 |
| | 786 |
| | (9 | ) | | (1 | )% |
| Impairment of assets | | 31 |
| | — |
| | 31 |
|
| NM |
| | 162 |
| | 1,447 |
| | (1,285 | ) |
| (89 | )% |
| Total operating expenses | �� | 2,830 |
| | 3,056 |
| | (226 | ) | | (7 | )% | | 8,573 |
| | 10,525 |
| | (1,952 | ) |
| (19 | )% |
| | | | | | | | | | | | | | | | | |
| OPERATING INCOME | | 884 |
| | 861 |
| | 23 |
| | 3 | % | | 2,002 |
| | 662 |
| | 1,340 |
| | NM |
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| OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
| Investment income | | 37 |
| | 28 |
| | 9 |
| | 32 | % | | 78 |
| | 75 |
| | 3 |
| | 4 | % |
| Interest expense | | (305 | ) | | (286 | ) | | (19 | ) | | 7 | % | | (882 | ) | | (863 | ) | | (19 | ) | | 2 | % |
| Capitalized financing costs | | 19 |
| | 28 |
| | (9 | ) | | (32 | )% | | 59 |
| | 79 |
| | (20 | ) | | (25 | )% |
| Total other expense | | (249 | ) | | (230 | ) | | (19 | ) | | 8 | % | | (745 | ) | | (709 | ) | | (36 | ) | | 5 | % |
| | | | | | | | | | | | | | | | | |
| INCOME (LOSS) BEFORE INCOME TAXES | | 635 |
| | 631 |
| | 4 |
| | 1 | % | | 1,257 |
| | (47 | ) | | 1,304 |
| | NM |
|
| | | | | | | | | | | | | | | | | |
| INCOME TAXES | | 239 |
| | 251 |
| | (12 | ) | | (5 | )% | | 482 |
| | 334 |
| | 148 |
| | 44 | % |
| | | | | | | | | | | | | | | | | |
| NET INCOME (LOSS) | | $ | 396 |
| | $ | 380 |
| | $ | 16 |
| | 4 | % | | $ | 775 |
| | $ | (381 | ) | | $ | 1,156 |
| | NM |
|
| | | | | | | | | | | | | | | | | |
| EARNINGS (LOSS) PER SHARE OF COMMON STOCK: | | | | | | | | | | | | | | | | |
| Basic | | $ | 0.89 |
| | $ | 0.89 |
| | $ | — |
| | — | % | | $ | 1.75 |
| | $ | (0.90 | ) | | $ | 2.65 |
| | NM |
|
| Diluted | | $ | 0.89 |
| | $ | 0.89 |
| | $ | — |
| | — | % | | $ | 1.74 |
| | $ | (0.90 | ) | | $ | 2.64 |
| | NM |
|
* NM = not meaningful
For the Three Months Ended September 30, 2017
FirstEnergy’s net income in the third quarter of 2017 was $396 million, or basic and diluted earnings of $0.89 per share of common stock, compared to net income of $380 million, or basic and diluted earnings of $0.89 per share of common stock in the third quarter of 2016.
During the third quarter of 2017, FirstEnergy's revenues decreased $203 million, as compared to the same period in 2016, resulting from a $226 million decrease at CES and a $81 million decrease at Regulated Distribution, partially offset by a $48 million increase at Regulated Transmission.
The decrease in revenue at CES was primarily due to lower contract sales volumes and lower retail prices partially offset by higher wholesale sales.
The decrease in revenue at Regulated Distribution was primarily due to the impact of lower weather-related usage and higher customer shopping partially offset by higher distribution revenues reflecting the implementation of new rates in January 2017.
The increase in revenue at Regulated Transmission resulted from a higher rate base at ATSI, JCP&L and TrAIL as well as recovery of incremental operating expenses.
Operating expenses decreased $226 million in the third quarter of 2017, as compared to the third quarter of 2016, primarily reflecting2023, a decrease of $184 million at CES and $131 million at Regulated Distribution. Changes in certain operating expenses include the following:
Purchased power decreased $118 million, primarily at Regulated Distribution as a result of lower volumes from increased customer shopping and lower weather-related usage as well as lower default service auction prices. The decline in purchased power at CES was due to lower capacity expenses and market prices.
Fuel expense decreased $87 million, primarily at CES due to lower generation associated with outages and economic dispatch of fossil units resulting from low wholesale spot market energy prices. The decline in fuel expense at Regulated Distribution resulted from lower unit costs.
Depreciation expense decreased $22 million, primarily due to a lower asset base at CES resulting from asset impairments recognized in 2016.
Other operating expenses decreased $11$39 million primarily due to the absence of a termination charge associated with an FES Governmental Aggregationfollowing:
•Lower weather-adjusted customer contract.usage and demand;
Impairment of assets increased $31 million, resulting primarily from purchase price adjustments pursuant•Higher net discrete income tax charges related to the termsPA Consolidation and updates to deferred taxes on the sale of the amended and restated asset purchase agreement between AE Supply, AGC, BU Energy and a subsidiary of LS Power.
Other expense increased $19 million primarily from higherequity interest expense.
FirstEnergy’s effective tax rate was 37.6% and 39.8% for the three months ended September 30, 2017 and 2016, respectively.
For the Nine Months Ended September 30, 2017
For the nine months ended September 30, 2017, FirstEnergy’s net income was $775 million, or basic earnings of $1.75 per share of common stock ($1.74 diluted), compared with a net loss of $(381) million, or a basic and diluted loss of $(0.90) per share of common stock, for the nine months ended September 30, 2016.
FirstEnergy's earnings for the nine months ended September 30, 2017, increased $1,156 million, as compared to the same period of 2016, primarily due to lower asset impairment and plant exit costs. In the second quarter of 2016, CES recognized pre-tax asset impairment and plant exit costs as follows:
Non-cash pre-tax impairment charges of $800 million associated with goodwill at CES;
Non-cash pre-tax impairment charges of $647 million associated with the announced plan to exit operations by 2020 of Units 1-4 of the W.H. Sammis generating station and the Bay Shore Unit 1 generating station;
Coal contract settlement and termination pre-tax costs of $58 million, and
Valuation allowances against state and local NOL carryforwards of $159 million.
During the first nine months of 2017, FirstEnergy’s revenues decreased $612 million, as compared to the same period in 2016, resulting from a $851 million decrease at CES and a $28 million decrease at Regulated Distribution, partially offset by a $131 million increase at Regulated Transmission.
The decrease in revenue at CES was primarily due to lower contract sales volumes at lower prices and lower capacity revenues, partially offset by an increase in wholesale sales.
The decrease in revenue at Regulated Distribution primarily resulted from lower weather-related usage and higher customer shopping partially offset by new rates implemented in January 2017.
The increase in revenue at Regulated Transmission resulted from a higher rate base at ATSI, JCP&L and TrAIL as well as recovery of incremental operating expenses.
Operating expenses decreased $1,952 million in the first nine months of 2017, as compared to the same period of 2016, primarily reflecting a decrease at CES of $1,884 million principally due to the asset impairment and plant exit costs discussed above. Changes in certain operating expenses include the following:
Fuel expense decreased $195 million, primarily due to the absence of approximately $58 million in settlement and termination costs on coal contracts in 2016 and lower generation associated with outages and economic dispatch of fossil units resulting from low wholesale spot market energy prices.
Purchased power decreased $533 million, primarily at CES, due to lower capacity expense as a result of lower contract sales and lower unit costs. At Regulated Distribution, the decline in purchased power was the result of lower volumes from increased customer shopping and lower weather-related usage as well as lower default service auction prices.
Other operating expenses increased $206 million, reflecting an increase of $117 million at CES, primarily associated with estimated losses on long-term coal transportation contract disputes recognizedFET in the first quarter of 20172024, partially offset by discrete benefits primarily associated with state NOL utilization;
•A charge at JCP&L in the first quarter 2024 associated with the disallowance of certain corporate support costs as a result of the NJBPU-approved settlement agreement;
•Lower earnings related to FEV’s equity method investment in Global Holding;
•Higher other operating expenses related to planned vegetation management, uncollectible expense, and non-deferred storm expense; and
•Higher interest expense associated with new long-term debt issuances, and higher non-cash mark-to-market losses on commodity contract positions. Operating expensesrevolver borrowings and interest rates.
These decreases were partially offset by the following:
•Increased earnings as a result of regulated distribution and transmission capital investments that increased $31 million at Regulated Distribution resulting primarily from higher operating and maintenance expenses, including increased storm restoration costs.rate base;
Depreciation expense decreased $129 million,•Higher customer usage, primarily due to a lower assetless mild weather temperatures;
•The implementation of base at CES resulting from asset impairments recognizedrate case settlements during the first quarter of 2024 in 2016.Maryland, New Jersey and West Virginia;
Other expense increased $36 million, primarily from higher interest expense and lower capitalized financing costs.
FirstEnergy’s effective tax•A credit in the first quarter of 2024 associated with the WVPSC base rate case settlement approval that allowed for the nine months ended September 30, 2017 was 38.3%. Forrecovery of certain retired generation stations costs;
•Higher pension and OPEB non-service credits; and
•The absence of expenses associated with the nine months ended September 30, 2017, the changecancellation of a sponsorship agreement in the effective tax rate,first quarter of 2023.
Distribution services by customer class are summarized in the following table:
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| | For the Three Months Ended March 31, | | | | | |
| (In thousands) | | Actual | | Weather-Adjusted | |
| Electric Distribution MWh Deliveries | | 2024 | | 2023 | |
Increase (Decrease) | | 2024 | | 2023 | | Increase (Decrease) | | | | | |
| | | | | | | | | | | | |
| Residential | | 14,087 | | | 13,941 | | | 1.0 | % | | 15,428 | | | 15,982 | | | (3.5) | % | | | | | |
Commercial(1) | | 8,614 | | | 8,632 | | | (0.2) | % | | 8,968 | | | 9,403 | | | (4.6) | % | | | | | |
| Industrial | | 13,925 | | | 13,511 | | | 3.1 | % | | 13,925 | | | 13,511 | | | 3.1 | % | | | | | |
| | | | | | | | | | | | | | | | | |
| Total Electric Distribution MWh Deliveries | | 36,626 | | | 36,084 | | | 1.5 | % | | 38,321 | | | 38,896 | | | (1.5) | % | | | | | |
(1) Includes street lighting.
Residential and commercial distribution deliveries were impacted by higher customer usage as compared toa result of the weather. Heating degree days in the first three months of 2024 were 5% above the same period for 2016, is primarily due to the impairment of $800 million of goodwill recognized in 2016, of which $433 million was non-deductible for tax purposes. Additionally, $159 million of valuation allowances were recorded in 2016 against state and municipal NOL carryforwards that also impacted the 2016 effective tax rate.2023 but 14% below normal.
RESULTS OF OPERATIONS
The financial results discussed below in Segment Results of Operations include revenues and expenses from transactions among FirstEnergy’s business segments. A reconciliation of segment financial results is provided in Note 13, "Segment10, “Segment Information,"” of the Combined Notes to Consolidated Financial Statements. Certain prior year amounts have been reclassified
Our Strategy
Powered by its employees and guided by its experienced leadership team and engaged FE Board, FirstEnergy is accelerating its transformation into a premier utility. The FE Board and FirstEnergy’s executive management team are aligned behind a business model grounded in investing, operating, recovering costs and financing our regulated utility operations. This business model aims to conformcreate a “virtuous cycle” that in turn serves to improve reliability and the customer experience, grow rate base, engage employees, improve returns and maintain a strong balance sheet. Along with an unwavering commitment to ethics and integrity, performance excellence and continuous improvement, FirstEnergy anticipates that strong execution of this model will help achieve its strategic objectives and deliver value to its investors.
With a diversified asset mix, improved balance sheet and a strong affordability position, FirstEnergy is well positioned to significantly enhance the customer experience and provide value to its investors.
Invest
FirstEnergy invests in its regulated operations to improve reliability and the customer experience, and in its people to attract, retain and develop talented, diverse and engaged employees to carry out its mission. It aims to do so through Energize365.
A robust plan for customer-focused growth, Energize365 is the centerpiece of FirstEnergy’s regulated distribution and transmission capital investment strategy that aims to utilize all investments to support our EESG and strategic priorities including clean energy, improving grid reliability and resiliency, and supports the clean energy transition. Through the Energize365 program, FirstEnergy expects to spend approximately $26 billion in system-wide capital investments from 2024 through 2028. FirstEnergy expects that these investments will comprise the Distribution segment (29%), the Integrated segment (39%), and the Stand-Alone Transmission segment (32%), focusing on the following:
•Energy Transition: FirstEnergy expects to make Distribution and Transmission investments in order to support improvements in grid reliability and resiliency and support interconnection of renewable sources, including:
▪Clean Energy: West Virginia solar generation, energy efficiency, electric vehicle infrastructure and energy storage; and
▪Grid Modernization: Programs to drive system resiliency through automation technology and communication, including Ohio's phases one and two of the Ohio Companies’ distribution grid modernization plans, Pennsylvania's LTIIP, New Jersey's EnergizeNJ, and implementing advanced metering infrastructure.
▪Transmission:
•Operational Flexibility Projects that build capacity and support the evolving grid such as interconnection of New Jersey offshore wind and data center load;
•Enhance system performance by implementing new designs and technologies to reduce load at risk; and
•Upgrade system conditions that enhance reliability.
•Infrastructure Renewal: Base distribution projects to address aging infrastructure
•Generation Maintenance: Projects to maintain operations of fossil fuel plants and remain compliant with environmental regulations through the end of their useful life
•FirstEnergy believes there is a continued long-term pipeline of investment opportunities for its existing distribution and transmission infrastructure beyond those identified through 2028, which are expected to strengthen grid and cyber security and make the transmission system more reliable, robust, secure and resistant to extreme weather events, with improved operational flexibility.
•Revitalizing its leadership team. FirstEnergy recently announced the hiring of John Combs as its Senior Vice President of Shared Services and FirstEnergy continues to make progress in filling several key executive positions in an organization that will be structured to allow greater execution at the business unit level.
Operate
FirstEnergy will continue to engage its skilled, trained, talented and diverse team of employees to effectively implement its investment plans, seek opportunities for continuous improvement as it delivers safe, reliable and affordable electricity to our customers, and deliver value to its investors. It aims to do so through the following:
•Enhancing the focus on the customer. FirstEnergy is shifting more decision-making and accountability for our operations closer to our customers, regulators and employees doing the work. FirstEnergy’s new operating structure is organized by: Ohio, Pennsylvania, New Jersey, West Virginia/Maryland and FirstEnergy’s standalone Transmission properties. This structure will foster better execution at the business unit level.
•Embracing a continuous improvement mindset. FirstEnergy faced numerous financial headwinds in 2023, including weather and the impact of market conditions on its pension plan. Through a determined effort by its employees, FirstEnergy focused on the things within its control: managing costs, enhancing the customer experience and seeking opportunities for continuous improvement.
Recover
FirstEnergy is working to establish a track record of strong execution. Operating effectively leads to strong, predictable results and enhances credibility with our stakeholders. In turn, FirstEnergy builds supportive relationships with regulators, customers and intervenors in an effort to drive positive rate outcomes that support recovery of its investments.
In order to achieve important regulatory milestones, FirstEnergy has an active regulatory calendar to support its regulated growth strategy and address the critical investments that support reliability and a smarter and cleaner electric grid. This includes the following:
•On January 13, 2023, MP and PE filed a request with the WVPSC seeking approval of new depreciation rates for existing and future capital assets. On August 22, 2023, the parties filed a unanimous settlement of the case recommending a $33 million annual increase in depreciation expense, effective April 1, 2024. An order was issued on March 26, 2024 approving the settlement without modification.
•On March 16, 2023, JCP&L filed a base rate case in New Jersey, requesting a $185 million increase in base distribution revenues to support investments to strengthen the energy grid, enhance the customer experience and provide assistance to low-income and senior citizen customers. February 1, 2024, JCP&L, joined by various parties, filed a stipulated settlement with the NJBPU resolving JCP&L’s request for a distribution base rate increase. The settlement, which was approved by the NJBPU on February 14, 2024, provides for an $85 million annual base distribution revenue increase for JCP&L, which will become effective for customers on June 1, 2024.
•On April 5, 2023, the Ohio Companies sought approval from the PUCO for its ESP V. The proposed plan would maintain an eight-year term beginning June 1, 2024, and seeks to continue riders recovering costs associated with distribution infrastructure investments and approved grid modernization investments. ESP V additionally proposes new riders that would support reliability, and includes provisions supporting affordability and enhancing the customer experience.
•On April 2, 2024, FE PA filed a base rate case with the PPUC seeking a net increase in base distribution revenues of approximately $502 million with a return on equity of 11.3% and capital structure of 46.2% debt and 53.8% equity, and reflects a roll-in of several current riders such as DSIC, Tax Act, and smart meter. Additionally, FE PA requests recovery of certain incurred costs, including the impact of major storms, COVID-19, a program to convert streetlights to LEDs, and others. A PPUC decision is expected in December 2024, with new rates becoming effective in January 2025. FE PA also plans to request approval for the continuation of its LTIIP program by the end of the third quarter of 2024.
•On April 12, 2024, the Ohio Companies and certain of the parties filed a stipulation that modified the Ohio Companies’ application for phase two of its grid modernization plan. The stipulation, which is subject to PUCO approval, provides for the deployment of smart meters to the balance of the Ohio Companies’ customers or approximately 1.4 million meters. Phase two of the distribution grid modernization plan, as modified by the stipulation would be completed over a four-year budget period with estimated capital investments of approximately $421 million. On April 16, 2024, the PUCO scheduled the stipulation hearing for June 5, 2024.
•The Ohio Companies plan to file a base rate case in the second quarter of 2024.
Finance
With sound capital allocation, enhanced reliability and better regulatory outcomes, FirstEnergy represents a compelling investment and expects to finance the business at a lower cost of capital, allowing it to begin the virtuous cycle all over again at “Invest.”
FirstEnergy aims to do this through a strengthened financial position. Since 2021, FirstEnergy has raised $7 billion in equity capital and issued $1.5 billion in convertible notes in May 2023 to significantly improve its balance sheet. The strength of FirstEnergy’s balance sheet supports its plan to fund Energize365 investments through organic internal cash flows and utility debt rather than incremental equity. FirstEnergy has also de-levered risk associated with its pension plan and optimized its financing plan to retain flexibility in an uncertain interest rate environment.
FirstEnergy also expects to continue returning value to shareholders. In March 2024, the FE Board declared a $0.015 per share increase to the quarterly common stock dividend payable June 1, 2024, to $0.425 per share, which represents an approximate 6% increase compared to dividends declared in 2023. Modest dividend growth is expected to enable enhanced shareholder returns, while still allowing for continued substantial regulated investments. Dividend payments are subject to declaration by the FE Board, and future dividend decisions determined by the FE Board may be impacted by earnings growth, credit metrics and other business conditions.
ClimateStrategy
Our commitment to climate is a significant component of our company’s overarching strategy, especially our desire to help enable the transition to a clean energy future. Executing our Climate Strategy requires addressing, among other things: emerging federal and state decarbonization goals; physical risks of climate change; industry trends and technology advancements; and customer expectations for cleaner energy, increased usage control, and more sustainable alternatives in transportation, manufacturing and industrial processes. Through our investment plan, we aim to enhance the resiliency, reliability and security of the electric system and support the integration of renewables, electric vehicles, grid modernization improvements and other emerging technologies.
As part of our Climate Strategy, we are committed to addressing company-wide emissions within our direct operational control, also known as Scope 1 emissions, across our transmission, distribution and regulated generation operations. Today, with the climate, our business, and our stakeholders in mind, our Climate Strategy is two-fold:
•Reduce our company’s Scope 1 GHG emissions and achieve carbon neutrality by 2050; and
•Support broader GHG reductions in our region by helping to enable the energy transition to a low-carbon future.
Currently, emissions from our West Virginia power stations – Fort Martin and Harrison – serve as the primary source of our Scope 1 emissions – representing approximately 99% of our overall GHG emissions as of December 31, 2023 – and greatly outnumber the emissions from our transmission and distribution operations. We have publicly stated through various filings with the WVPSC that the end of useful life date is 2035 for Fort Martin and 2040 for Harrison. These dates are based on our assessment of when it is projected to no longer be cost effective and beneficial to customers to make the capital investments needed to keep these facilities operating effectively and in compliance with evolving environmental regulations. FirstEnergy is currently assessing the impact of the final EPA rules issued on April 25, 2024, on these projected dates. In 2025, FirstEnergy will submit an Integrated Resource Plan to the WVPSC that will include our analysis of market conditions and identify how we believe we can best fulfill our obligation to supply our generation customers with reliable and cost-effective energy through 2040 (a requirement every five years in the state of West Virginia).
In the near-term, we continue our focus on GHG reduction in our transmission and distribution businesses. These emissions are within our control, pervasive in every state across our footprint, and aligned with our long-term, forward-looking transmission and distribution strategy to enable the energy transition.
In addition to moving beyond our two West Virginia power stations, key steps in working toward carbon neutrality by 2050 include:
•Reducing sulfur hexafluoride emissions: We're working to repair or replace, as appropriate, transmission breakers that leak sulfur hexafluoride, which is a gas commonly used by energy companies as an electrical insulating material and arc extinguisher in high-voltage circuit breakers and switchgear. If escaped to the atmosphere, it acts as a potent GHG with a global warming potential significantly greater than CO2; and
•Electrifying our vehicle fleet: We’re targeting 30% electrification of our light-duty and aerial truck fleet by 2030 and 100% electrification by 2050. To reach our electrification goal, we’re striving for 100% electric or hybrid vehicle purchases for our light-duty and aerial truck fleet moving forward.
Determination of the useful life of the regulated coal-fired generating facilities could result in changes in depreciation, and/or continued collection of net plant in rates after retirement, securitization, sale, impairment or regulatory disallowances. If MP is
unable to recover these costs, it could have a material adverse effect on FirstEnergy’s and/or MP’s financial condition, results of operations and cash flow.
HB 6 and Related Investigations
On July 21, 2021, FE entered into a three-year DPA with the U.S. Attorney’s Office that, subject to court proceedings, resolves the U.S. Attorney’s Office investigation into FirstEnergy relating to FirstEnergy’s lobbying and governmental affairs activities concerning HB 6 related to the federal criminal allegations made in July 2020, against former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. Among other things under the DPA, FE paid a $230 million monetary penalty in 2021 and agreed to the filing of a criminal information charging FE with one count of conspiracy to commit honest services wire fraud. The $230 million payment will neither be recovered in rates or charged to FirstEnergy customers, nor will FirstEnergy seek any tax deduction related to such payment. The criminal information will be dismissed after FirstEnergy fully complies with its obligations under the DPA, which is expected to be July 2024.
The OAG, certain FE shareholders and FE customers filed several lawsuits against FirstEnergy and certain current year presentation.and former directors, officers and other employees, each relating to the allegations against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. On February 9, 2022, FE, acting through the SLC, agreed to a settlement term sheet to resolve multiple shareholder derivative lawsuits that were filed in the S.D. Ohio, the N.D. Ohio, and the Ohio Court of Common Pleas, Summit County. On March 11, 2022, the parties executed a stipulation and agreement of settlement, and filed a motion the same day requesting preliminary settlement approval in the S.D. Ohio, which was granted on May 9, 2022. On August 23, 2022, the S.D. Ohio granted final approval of the settlement. On September 20, 2022, a purported FE stockholder filed a motion for reconsideration of the S.D. Ohio’s final settlement approval. The parties filed oppositions to that motion on October 11, 2022, and the S.D. Ohio denied that motion on May 22, 2023. On June 15, 2023, the purported FE stockholder filed an appeal in the U.S. Court of Appeals for the Sixth Circuit. The N.D. Ohio issued a stay of the case pending the appeal in the U.S. Court of Appeals for the Sixth Circuit. On February 16, 2024, the U.S. Court of Appeals for the Sixth Circuit affirmed the district court’s final settlement approval. On April 12, 2024, the N.D. Ohio acknowledged the completion of the appeal and instructed the parties to file any further argument or information they wish to be considered by the N.D. Ohio no later than April 25, 2024. Once all appeal options are exhausted the judgment will become final. The settlement agreement is expected to fully resolve these shareholder derivative lawsuits.
The settlement includes a series of corporate governance enhancements and a payment to FE of $180 million, to be paid by insurance after the judgment has become final, less approximately $36 million in court-ordered attorney’s fees awarded to plaintiffs.
In addition, on August 10, 2020, the SEC, through its Division of Enforcement, issued an order directing an investigation of possible securities laws violations by FE, and on September 1, 2020, issued subpoenas to FE and certain FE officers. Subsequently, on April 28, 2021, July 11, 2022, and May 25, 2023, the SEC issued additional subpoenas to FE. While no contingency has been reflected in its consolidated financial statements, FE believes that it is probable that it will incur a loss in connection with the resolution of the SEC investigation. Given the ongoing nature and complexity of the review, inquiries and investigations, FE cannot yet reasonably estimate a loss or range of loss that may arise from the resolution of the SEC investigation Further, in letters dated January 26, and February 22, 2021, staff of FERC's Division of Investigations notified FirstEnergy that it was investigating FirstEnergy’s lobbying and governmental affairs activities concerning HB 6. On December 30, 2022, FERC approved a Stipulation and Consent Agreement that resolves the investigation. The agreement obligates FE to pay a civil penalty of $3.86 million, which was paid in January 2023, and to submit two annual compliance monitoring reports to FERC’s Office of Enforcement regarding improvements to FirstEnergy’s compliance programs. The first compliance monitoring report was submitted in December 2023.
On June 29, 2023, the OOCIC served FE a subpoena, seeking information relating to the conduct described in the DPA. FirstEnergy was not aware of the OOCIC’s investigation prior to receiving the subpoena and understands that the OOCIC’s investigation is also focused on the conduct described in the DPA, other than with respect to the March 25, 2024, felony indictment of Mr. Householder brought in Cuyahoga County, Ohio. FirstEnergy is cooperating with the OOCIC in its investigation. On February 12, 2024, and in connection with the OOCIC’s ongoing investigation, an indictment by a grand jury of Summit County, Ohio was unsealed against the former chairman of the PUCO, Samuel Randazzo, and two former FirstEnergy senior officers, Charles E. Jones, and Michael J. Dowling, charging each of them with several felony counts, including bribery, telecommunications fraud, money laundering and aggravated theft, related to payments described in the DPA. FirstEnergy continues to both cooperate with the OOCIC in its investigation and discuss an appropriate resolution of the investigation with respect to FE. While no contingency has been reflected in FirstEnergy’s consolidated financial statements, FE believes that it is reasonably possible that it will incur a loss in connection with the resolution of the OOCIC investigation. Given the ongoing nature of the discussions, while FE cannot yet reasonably estimate a loss or range of loss that may arise from any resolution of the OOCIC investigation with respect to FE, any such payment by FE associated with an OOCIC resolution is not expected to be material.
FirstEnergy has taken numerous steps to address challenges posed by the HB 6 investigations and improve its compliance culture, including the refreshment of the FE Board, the hiring of key senior executives committed to supporting transparency and integrity, and strengthening and enhancing FirstEnergy’s compliance culture through several initiatives; however, the outcomes of the unresolved HB 6 investigations and state regulatory audits remain unknown.
Despite the many disruptions FirstEnergy has faced, and continues to currently face, the leadership team remains committed and focused on executing its strategy and running the business. See “Outlook - Other Legal Proceedings” below for additional details on the government investigations, the DPA, and subsequent litigation surrounding the investigation of HB 6. See also “Outlook - State Regulation - Ohio” below for details on the PUCO proceeding reviewing political and charitable spending and legislative activity in response to the investigation of HB 6. The outcome of the government investigations, PUCO proceedings, legislative activity, and any of these lawsuits is uncertain and could have a material adverse effect on FirstEnergy’s financial condition, results of operations and cash flows.
SEGMENTRESULTS OF OPERATIONS
Summary of Results of Operations — Third Quarter 2017First Three Months of 2024 Compared with Third Quarter 2016First Three Months of 2023
Financial results for FirstEnergy’s business segments in the third quarterfirst three months of 20172024 and 20162023 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
First Three Months 2024 Financial Results
(In millions) | Distribution | | Integrated | | Stand-Alone Transmission | | Corporate/Other and Reconciling Adjustments | | FirstEnergy Consolidated |
| Revenues: | | | | | | | | | |
| Electric | $ | 1,725 | | | $ | 1,082 | | | $ | 434 | | | $ | 3 | | | $ | 3,244 | |
| Other | 42 | | | 13 | | | 4 | | | (16) | | | 43 | |
| Total Revenues | 1,767 | | | 1,095 | | | 438 | | | (13) | | | 3,287 | |
| | | | | | | | | |
| Operating Expenses: | | | | | | | | | |
| Fuel | — | | | 105 | | | — | | | — | | | 105 | |
| Purchased power | 642 | | | 389 | | | — | | | 5 | | | 1,036 | |
| Other operating expenses | 587 | | | 354 | | | 76 | | | (11) | | | 1,006 | |
| | | | | | | | | |
| Provision for depreciation | 161 | | | 122 | | | 81 | | | 17 | | | 381 | |
| | | | | | | | | |
| Amortization (deferral) of regulatory assets, net | (88) | | | (78) | | | 2 | | | — | | | (164) | |
| General taxes | 192 | | | 38 | | | 69 | | | 12 | | | 311 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Total Operating Expenses | 1,494 | | | 930 | | | 228 | | | 23 | | | 2,675 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Other Income (Expense): | | | | | | | | | |
| | | | | | | | | |
| Equity method investment earnings | — | | | — | | | — | | | 21 | | | 21 | |
| Miscellaneous income, net | 44 | | | 12 | | | — | | | (12) | | | 44 | |
| | | | | | | | | |
| | | | | | | | | |
| Interest expense | (116) | | | (71) | | | (65) | | | (53) | | | (305) | |
| Capitalized financing costs | 5 | | | 11 | | | 13 | | | 1 | | | 30 | |
| Total Other Expense | (67) | | | (48) | | | (52) | | | (43) | | | (210) | |
| | | | | | | | | |
| | | | | | | | | |
| Income taxes (benefits) | 41 | | | 35 | | | 60 | | | (1) | | | 135 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Income attributable to noncontrolling interest | — | | | — | | | 14 | | | — | | | 14 | |
| | | | | | | | | |
| Earnings (Loss) Attributable to FE | $ | 165 | | | $ | 82 | | | $ | 84 | | | $ | (78) | | | $ | 253 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
First Three Months 2023 Financial Results
(In millions) | Distribution | | Integrated | | Stand-Alone Transmission | | Corporate/Other and Reconciling Adjustments | | FirstEnergy Consolidated |
| Revenues: | | | | | | | | | |
| | | | | | | | | |
| Electric | $ | 1,779 | | | $ | 1,012 | | | $ | 396 | | | $ | 2 | | | $ | 3,189 | |
| Other | 38 | | | 16 | | | 4 | | | (16) | | | 42 | |
| | | | | | | | | |
| Total Revenues | 1,817 | | | 1,028 | | | 400 | | | (14) | | | 3,231 | |
| | | | | | | | | |
| Operating Expenses: | | | | | | | | | |
| Fuel | — | | | 133 | | | — | | | — | | | 133 | |
| Purchased power | 717 | | | 402 | | | — | | | 5 | | | 1,124 | |
| Other operating expenses | 503 | | | 260 | | | 71 | | | 12 | | | 846 | |
| | | | | | | | | |
| Provision for depreciation | 153 | | | 113 | | | 75 | | | 20 | | | 361 | |
| | | | | | | | | |
| Amortization (deferral) of regulatory assets, net | (41) | | | (40) | | | 1 | | | — | | | (80) | |
| General taxes | 188 | | | 34 | | | 63 | | | 11 | | | 296 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Total Operating Expenses | 1,520 | | | 902 | | | 210 | | | 48 | | | 2,680 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Other Income (Expense): | | | | | | | | | |
| | | | | | | | | |
| Equity method investment earnings | — | | | — | | | — | | | 56 | | | 56 | |
| Miscellaneous income, net | 22 | | | 16 | | | 6 | | | (9) | | | 35 | |
| | | | | | | | | |
| | | | | | | | | |
| Interest expense | (94) | | | (59) | | | (58) | | | (52) | | | (263) | |
| Capitalized financing costs | 5 | | | 7 | | | 9 | | | — | | | 21 | |
| Total Other Expense | (67) | | | (36) | | | (43) | | | (5) | | | (151) | |
| | | | | | | | | |
| | | | | | | | | |
| Income taxes (benefits) | 44 | | | 20 | | | 33 | | | (7) | | | 90 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Income attributable to noncontrolling interest | — | | | — | | | 18 | | | — | | | 18 | |
| | | | | | | | | |
| Earnings (Loss) Attributable to FE | $ | 186 | | | $ | 70 | | | $ | 96 | | | $ | (60) | | | $ | 292 | |
| | | | | | | | | |
| | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2017 Financial Results | | Regulated Distribution | | Regulated Transmission | | Competitive
Energy Services | | Corporate/Other and Reconciling Adjustments | | FirstEnergy Consolidated |
| | | (In millions) |
| Revenues: | | |
| | | | |
| | |
| | |
|
| External | | |
| | | | |
| | |
| | |
|
| Electric | | $ | 2,563 |
| | $ | 342 |
| | $ | 790 |
| | $ | (44 | ) | | $ | 3,651 |
|
| Other | | 47 |
| | — |
| | 6 |
| | 10 |
| | 63 |
|
| Internal | | — |
| | — |
| | 93 |
| | (93 | ) | | — |
|
| Total Revenues | | 2,610 |
| | 342 |
| | 889 |
| | (127 | ) | | 3,714 |
|
| | | | | | | | | | | |
| Operating Expenses: | | |
| | |
| | |
| | |
| | |
|
| Fuel | | 126 |
| | — |
| | 237 |
| | — |
| | 363 |
|
| Purchased power | | 797 |
| | — |
| | 157 |
| | (93 | ) | | 861 |
|
| Other operating expenses | | 620 |
| | 55 |
| | 324 |
| | (57 | ) | | 942 |
|
| Provision for depreciation | | 183 |
| | 59 |
| | 30 |
| | 17 |
| | 289 |
|
| Amortization of regulatory assets, net | | 85 |
| | 6 |
| | — |
| | — |
| | 91 |
|
| General taxes | | 187 |
| | 45 |
| | 14 |
| | 7 |
| | 253 |
|
| Impairment of assets | | — |
| | 13 |
| | 18 |
| | — |
| | 31 |
|
| Total Operating Expenses | | 1,998 |
| | 178 |
| | 780 |
| | (126 | ) | | 2,830 |
|
| | | | | | | | | | | |
| Operating Income (Loss) | | 612 |
| | 164 |
| | 109 |
| | (1 | ) | | 884 |
|
| | | | | | | | | | | |
| Other Income (Expense): | | |
| | |
| | |
| | |
| | |
|
| Investment income (loss) | | 13 |
| | — |
| | 34 |
| | (10 | ) | | 37 |
|
| Interest expense | | (133 | ) | | (38 | ) | | (44 | ) | | (90 | ) | | (305 | ) |
| Capitalized financing costs | | 5 |
| | 7 |
| | 7 |
| | — |
| | 19 |
|
| Total Other Expense | | (115 | ) | | (31 | ) | | (3 | ) | | (100 | ) | | (249 | ) |
| | | | | | | | | | | |
| Income (Loss) Before Income Taxes (Benefits) | | 497 |
| | 133 |
| | 106 |
| | (101 | ) | | 635 |
|
| Income taxes (benefits) | | 183 |
| | 49 |
| | 40 |
| | (33 | ) | | 239 |
|
| Net Income (Loss) | | $ | 314 |
| | $ | 84 |
| | $ | 66 |
| | $ | (68 | ) | | $ | 396 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Changes Between First Three Months 2024 and First Three Months 2023 Financial Results
(In millions) | Distribution | | Integrated | | Stand-Alone Transmission | | Corporate/Other and Reconciling Adjustments | | FirstEnergy Consolidated |
| Revenues: | | | | | | | | | |
| | | | | | | | | |
| Electric | $ | (54) | | | $ | 70 | | | $ | 38 | | | $ | 1 | | | $ | 55 | |
| Other | 4 | | | (3) | | | — | | | — | | | 1 | |
| | | | | | | | | |
| Total Revenues | (50) | | | 67 | | | 38 | | | 1 | | | 56 | |
| | | | | | | | | |
| Operating Expenses: | | | | | | | | | |
| Fuel | — | | | (28) | | | — | | | — | | | (28) | |
| Purchased power | (75) | | | (13) | | | — | | | — | | | (88) | |
| Other operating expenses | 84 | | | 94 | | | 5 | | | (23) | | | 160 | |
| | | | | | | | | |
| Provision for depreciation | 8 | | | 9 | | | 6 | | | (3) | | | 20 | |
| | | | | | | | | |
| Amortization (deferral) of regulatory assets, net | (47) | | | (38) | | | 1 | | | — | | | (84) | |
| General taxes | 4 | | | 4 | | | 6 | | | 1 | | | 15 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Total Operating Expenses | (26) | | | 28 | | | 18 | | | (25) | | | (5) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Other Income (Expense): | | | | | | | | | |
| | | | | | | | | |
| Equity method investment earnings | — | | | — | | | — | | | (35) | | | (35) | |
| Miscellaneous income, net | 22 | | | (4) | | | (6) | | | (3) | | | 9 | |
| | | | | | | | | |
| | | | | | | | | |
| Interest expense | (22) | | | (12) | | | (7) | | | (1) | | | (42) | |
| Capitalized financing costs | — | | | 4 | | | 4 | | | 1 | | | 9 | |
| Total Other Expense | — | | | (12) | | | (9) | | | (38) | | | (59) | |
| | | | | | | | | |
| | | | | | | | | |
| Income taxes (benefits) | (3) | | | 15 | | | 27 | | | 6 | | | 45 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Income attributable to noncontrolling interest | — | | | — | | | (4) | | | — | | | (4) | |
| | | | | | | | | |
| Earnings (Loss) Attributable to FE | $ | (21) | | | $ | 12 | | | $ | (12) | | | $ | (18) | | | $ | (39) | |
| | | | | | | | | |
| | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| Third Quarter 2016 Financial Results | | Regulated Distribution | | Regulated Transmission | | Competitive
Energy Services | | Corporate/Other and Reconciling Adjustments | | FirstEnergy Consolidated |
| | | (In millions) |
| Revenues: | | |
| | | | |
| | |
| | |
|
| External | | |
| | | | |
| | |
| | |
|
| Electric | | $ | 2,638 |
| | $ | 294 |
| | $ | 959 |
| | $ | (44 | ) | | $ | 3,847 |
|
| Other | | 53 |
| | — |
| | 39 |
| | (22 | ) | | 70 |
|
| Internal | | — |
| | — |
| | 117 |
| | (117 | ) | | — |
|
| Total Revenues | | 2,691 |
| | 294 |
| | 1,115 |
| | (183 | ) | | 3,917 |
|
| | | | | | | | | | | |
| Operating Expenses: | | |
| | |
| | |
| | |
| | |
|
| Fuel | | 156 |
| | — |
| | 294 |
| | — |
| | 450 |
|
| Purchased power | | 902 |
| | — |
| | 194 |
| | (117 | ) | | 979 |
|
| Other operating expenses | | 614 |
| | 45 |
| | 367 |
| | (73 | ) | | 953 |
|
| Provision for depreciation | | 169 |
| | 47 |
| | 79 |
| | 16 |
| | 311 |
|
| Amortization of regulatory assets, net | | 98 |
| | — |
| | — |
| | — |
| | 98 |
|
| General taxes | | 190 |
| | 37 |
| | 30 |
| | 8 |
| | 265 |
|
| Impairment of assets | | — |
| | — |
| | — |
| | — |
| | — |
|
| Total Operating Expenses | | 2,129 |
| | 129 |
| | 964 |
| | (166 | ) | | 3,056 |
|
| | | | | | | | | | | |
| Operating Income (Loss) | | 562 |
| | 165 |
| | 151 |
| | (17 | ) | | 861 |
|
| | | | | | | | | | | |
| Other Income (Expense): | | |
| | |
| | |
| | |
| | |
|
| Investment income (loss) | | 13 |
| | — |
| | 23 |
| | (8 | ) | | 28 |
|
| Interest expense | | (143 | ) | | (39 | ) | | (48 | ) | | (56 | ) | | (286 | ) |
| Capitalized financing costs | | 6 |
| | 9 |
| | 9 |
| | 4 |
| | 28 |
|
| Total Other Expense | | (124 | ) | | (30 | ) | | (16 | ) | | (60 | ) | | (230 | ) |
| | | | | | | | | | | |
| Income (Loss) Before Income Taxes (Benefits) | | 438 |
| | 135 |
| | 135 |
| | (77 | ) | | 631 |
|
| Income taxes (benefits) | | 162 |
| | 50 |
| | 49 |
| | (10 | ) | | 251 |
|
| Net Income (Loss) | | $ | 276 |
| | $ | 85 |
| | $ | 86 |
| | $ | (67 | ) | | $ | 380 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| Changes Between Third Quarter 2017 and Third Quarter 2016 Financial Results | | Regulated Distribution | | Regulated Transmission | | Competitive
Energy Services | | Corporate/Other and Reconciling Adjustments | | FirstEnergy Consolidated |
| | | (In millions) |
| Revenues: | | |
| | | | |
| | |
| | |
|
| External | | |
| | | | |
| | |
| | |
|
| Electric | | $ | (75 | ) | | $ | 48 |
| | $ | (169 | ) | | $ | — |
| | $ | (196 | ) |
| Other | | (6 | ) | | — |
| | (33 | ) | | 32 |
| | (7 | ) |
| Internal | | — |
| | — |
| | (24 | ) | | 24 |
| | — |
|
| Total Revenues | | (81 | ) | | 48 |
| | (226 | ) | | 56 |
| | (203 | ) |
| | | | | | | | | | | |
| Operating Expenses: | | |
| | |
| | |
| | |
| | |
|
| Fuel | | (30 | ) | | — |
| | (57 | ) | | — |
| | (87 | ) |
| Purchased power | | (105 | ) | | — |
| | (37 | ) | | 24 |
| | (118 | ) |
| Other operating expenses | | 6 |
| | 10 |
| | (43 | ) | | 16 |
| | (11 | ) |
| Provision for depreciation | | 14 |
| | 12 |
| | (49 | ) | | 1 |
| | (22 | ) |
| Amortization of regulatory assets, net | | (13 | ) | | 6 |
| | — |
| | — |
| | (7 | ) |
| General taxes | | (3 | ) | | 8 |
| | (16 | ) | | (1 | ) | | (12 | ) |
| Impairment of assets | | — |
| | 13 |
| | 18 |
| | — |
| | 31 |
|
| Total Operating Expenses | | (131 | ) | | 49 |
| | (184 | ) | | 40 |
| | (226 | ) |
| | | | | | | | | | | |
| Operating Income (Loss) | | 50 |
| | (1 | ) | | (42 | ) | | 16 |
| | 23 |
|
| | | | | | | | | | | |
| Other Income (Expense): | | |
| | |
| | |
| | |
| | |
|
| Investment income (loss) | | — |
| | — |
| | 11 |
| | (2 | ) | | 9 |
|
| Interest expense | | 10 |
| | 1 |
| | 4 |
| | (34 | ) | | (19 | ) |
| Capitalized financing costs | | (1 | ) | | (2 | ) | | (2 | ) | | (4 | ) | | (9 | ) |
| Total Other Expense | | 9 |
| | (1 | ) | | 13 |
| | (40 | ) | | (19 | ) |
| | | | | | | | | | | |
| Income (Loss) Before Income Taxes (Benefits) | | 59 |
| | (2 | ) | | (29 | ) | | (24 | ) | | 4 |
|
| Income taxes (benefits) | | 21 |
| | (1 | ) | | (9 | ) | | (23 | ) | | (12 | ) |
| Net Income (Loss) | | $ | 38 |
| | $ | (1 | ) | | $ | (20 | ) | | $ | (1 | ) | | $ | 16 |
|
Regulated Distribution Segment — Third Quarter 2017First Three Months of 2024 Compared with Third Quarter 2016First Three Months of 2023
Regulated Distribution's operating results increased$38Distribution’s earnings attributable to FE decreased $21 million in the third quarterfirst three months of 2017,2024, as compared to the same period of 2016, reflecting implementation of approved rates in Ohio, Pennsylvania,2023, primarily resulting from lower weather-adjusted customer usage and New Jersey, as further described below,demand, and higher other operating expenses, partially offset by lower weather-relatedhigher customer usage.usage as a result of the weather and higher revenues from regulated investment programs.
Revenues —
The $81 million decrease inDistribution’s total revenues resulted fromdecreased by $50 million as a result of the following sources:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended March 31, |
| Revenues by Type of Service | | 2024 | | 2023 | | Increase
(Decrease) | | | | | | |
| | (In millions) | | | | | | |
| Distribution services | | $ | 1,020 | | | $ | 968 | | | $ | 52 | | | | | | | |
| Generation sales: | | | | | | | | | | | | |
| Retail | | 704 | | | 809 | | | (105) | | | | | | | |
| Wholesale | | 1 | | | 2 | | | (1) | | | | | | | |
| Total generation sales | | 705 | | | 811 | | | (106) | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Other | | 42 | | | 38 | | | 4 | | | | | | | |
| Total Revenues | | $ | 1,767 | | | $ | 1,817 | | | $ | (50) | | | | | | | |
|
| | | | | | | | | | | | |
| | | For the Three Months Ended September 30 | | Increase |
| Revenues by Type of Service | | 2017 | | 2016 | | (Decrease) |
| | | (In millions) |
| Distribution services | | $ | 1,441 |
| | $ | 1,363 |
| | $ | 78 |
|
| | | | | | | |
| Generation sales: | | | | | | |
| Retail | | 990 |
| | 1,133 |
| | (143 | ) |
| Wholesale | | 132 |
|
| 142 |
|
| (10 | ) |
| Total generation sales | | 1,122 |
| | 1,275 |
| | (153 | ) |
| | | | | | | |
| Other | | 47 |
|
| 53 |
|
| (6 | ) |
| Total Revenues | | $ | 2,610 |
| | $ | 2,691 |
| | $ | (81 | ) |
Distribution services revenues increased $78$52 million primarily resulting from the implementation of the DMR in Ohio, effective January 1, 2017, approved base distribution rate increases in Pennsylvania and New Jersey, effective January 27, 2017, and January 1, 2017, respectively, and higher revenue from the DCR in Ohio. Partially offsetting these rate increases was a decline in MWH deliveries, primarily resulting from lower weather-related usage, as described below. Distribution deliveries by customer class are summarized in the following table:
|
| | | | | | | | | |
| | | For the Three Months Ended September 30 | | Increase |
| Electric Distribution MWH Deliveries | | 2017 | | 2016 | | (Decrease) |
| | | (In thousands) | | |
| Residential | | 13,863 |
| | 16,138 |
| | (14.1 | )% |
| Commercial | | 11,228 |
| | 12,005 |
| | (6.5 | )% |
| Industrial | | 13,173 |
| | 13,023 |
| | 1.2 | % |
| Other | | 147 |
| | 144 |
| | 2.1 | % |
| Total Electric Distribution MWH Deliveries | | 38,411 |
| | 41,310 |
| | (7.0 | )% |
Lower distribution deliveries to residential and commercial customers primarily reflect lower weather-related usage resulting from cooling degree days that were 27% below 2016, and 3% above normal. Deliveries to industrial customers increased reflecting higher shale and steel customer usage.
The following table summarizes the price and volume factors contributing to the $153 million decrease in generation revenues for the third quarterfirst three months of 20172024, as compared to the same period of 2016:2023, primarily resulting from higher rider revenues associated with investment programs, higher customer usage as a result of the weather, lower customer refunds and credits associated with the PUCO-approved Ohio Stipulation and other rider rate adjustments at FE PA, which have no material impact to current period earnings, partially offset by lower weather-adjusted customer usage and demand.
|
| | | | |
| Source of Change in Generation Revenues | | Increase (Decrease) |
| | | (In millions) |
| Retail: | | |
|
| Effect of decrease in sales volumes | | $ | (121 | ) |
| Change in prices | | (22 | ) |
| | | (143 | ) |
| Wholesale: | | |
| Effect of decrease in sales volumes | | (4 | ) |
| Change in prices | | (8 | ) |
| Capacity Revenue | | 2 |
|
| | | (10 | ) |
| Decrease in Generation Revenues | | $ | (153 | ) |
The decreaseGeneration sales revenues decreased $106 million in the first three months of 2024, as compared to the same period in 2023, primarily due to lower retail generation sales volumes was primarily due to decreased weather-related usage, as described above, as well asa result of increased customer shopping in Ohio, Pennsylvania, and New Jersey.partially offset by higher non-shopping generation auction rates. Total generation provided by alternative suppliers as a percentage of total MWHMWh deliveries increased to 86% from 85% for the Ohio Companies, to 68% from 66% for the Pennsylvania Companies, and to 50% from 48% for JCP&L. The decrease in retail generation prices primarily resulted from lower default service auction prices in Pennsylvania and New Jersey.
Wholesale generation revenues decreased $10 million in the third quarterfirst three months of 2017, as compared to the same period in 2016, primarily due to lower spot market energy prices. The difference between current wholesale generation revenues and certain energy costs incurred are deferred for future recovery or refund, with no material impact to earnings.
Operating Expenses —
Total operating expenses decreased $131 million primarily due to the following:
Fuel expense decreased $30 million in the third quarter of 2017, as compared to the same period in 2016, primarily related to lower unit costs.
Purchased power costs were $105 millionlower in the third quarter of 2017, as compared to the same period in 2016, primarily due to lower default service auction prices as well as decreased volumes resulting from increased customer shopping and lower weather-related usage, as described above.
|
| | | | | |
| | Source of Change in Purchased Power | | Increase (Decrease) |
| |
| | | | (In millions) |
| | Purchases from non-affiliates: | | |
| | Change due to decreased unit costs | | $ | (30 | ) |
| | Change due to decreased volumes | | (85 | ) |
| | | | (115 | ) |
| | Purchases from affiliates: | | |
| | Change due to decreased unit costs | | (4 | ) |
| | Change due to decreased volumes | | (20 | ) |
| | | | (24 | ) |
| | Capacity Expense | | 12 |
|
| | Amortization of deferred costs | | 22 |
|
| | Decrease in Purchased Power Costs | | $ | (105 | ) |
Depreciation expense increased $14 million primarily due to a higher asset base as well as increased rates in Pennsylvania.
Amortization expense decreased $13 million primarily due to lower amortization of transition costs and non-utility generation costs, partially offset by lower deferral of storm costs.
Other Expense —
Total other expense decreased $9 million primarily due to lower interest expense resulting from various debt maturities at JCP&L and CEI.
Income Taxes —
Regulated Distribution’s effective tax rate was 36.8% and 37.0% for the quarter ended September 30, 2017 and 2016, respectively.
Regulated Transmission — Third Quarter 2017 Compared with Third Quarter 2016
Regulated Transmission's operating results decreased $1 million in the third quarter of 2017,2024, as compared to the same period of 2016, primarily resulting2023, increased to 89% from a pre-tax impairment charge of $13 million, as discussed below, partially offset by the58% in Ohio. Retail generation sales have no material impact of a higher rate base at ATSI and TrAIL. Additionally, JCP&L's and MAIT's forward-looking formula rates for their transmission assets were implemented on June 1, 2017, and July 1, 2017, respectively, subject to refund pending the outcome of settlement and hearing proceedings and a final FERC order.earnings.
Revenues —
Total revenues increased $48 million principally due to the recovery of incremental operating expenses and a higher rate base at ATSI, JCP&L, and TrAIL.
Revenues by transmission asset owner are shown in the following table:
|
| | | | | | | | | | | | |
| | | For the Three Months Ended September 30 | | |
| Revenues by Transmission Asset Owner | | 2017 | | 2016 | | Increase (Decrease) |
| | | (In millions) |
| ATSI | | $ | 167 |
| | $ | 139 |
| | $ | 28 |
|
| TrAIL | | 72 |
| | 67 |
| | 5 |
|
MAIT (1) | | 29 |
| | 25 |
| | 4 |
|
| JCP&L | | 35 |
| | 23 |
| | 12 |
|
| Other | | 39 |
| | 40 |
| | (1 | ) |
| Total Revenues | | $ | 342 |
| | $ | 294 |
| | $ | 48 |
|
| |
(1)
| Revenues in 2016 represent transmission revenues under stated rates at ME and PN. |
Operating Expenses —
Total operating expenses increased $49decreased $26 million, principallyprimarily due to higher operating and maintenance expenses as well as higher property taxes and depreciation due to higher asset base. Additionally, as a resultthe following:
•Purchased power costs, which have no material impact on current period earnings, decreased $75 million during the first three months of the settlement agreement between MAIT and certain parties, MAIT recorded a pre-tax impairment charge of $13 million in the third quarter of 2017. The settlement agreement is currently pending at FERC.
Income Taxes —
Regulated Transmission’s effective tax rate was 36.8% and 37.0% for the quarter ended September 30, 2017 and 2016, respectively.
CES — Third Quarter 2017 Compared with Third Quarter 2016
CES' operating results decreased $20 million in the third quarter of 2017,2024, as compared to the same period of 2016,2023, primarily due to an asset impairment chargedecreased generation sales volumes of $18$221 million as discussed below,described above and higher non-cash mark-to-market losses on commodity contract positions,decreased capacity expenses of $4 million, partially offset by an increase in short-term (net-hourly position) transactions, the absencehigher unit costs of a termination charge associated with an FES Governmental Aggregation customer contract, and lower depreciation expense.$150 million.
Revenues —
Total revenues decreased $226•Other operating expenses increased $84 million in the third quarterfirst three months of 2017,2024, as compared to the same period of 2016,2023, primarily due to lower contract sales volumes and lower retail prices, partially offset by an increase in short-term (net hourly position) transactions, as further described below.to:
The change in total revenues resulted from the following sources:
|
| | | | | | | | | | | | |
| | | For the Three Months Ended September 30 | | Increase (Decrease) |
| Revenues by Type of Service | | 2017 | | 2016 | |
| | | (In millions) |
| Contract Sales: | | | | | | |
| Direct | | $ | 173 |
| | $ | 207 |
| | $ | (34 | ) |
| Governmental Aggregation | | 109 |
| | 235 |
| | (126 | ) |
| Mass Market | | 32 |
| | 47 |
| | (15 | ) |
| POLR | | 120 |
| | 165 |
| | (45 | ) |
| Structured | | 97 |
| | 94 |
| | 3 |
|
| Total Contract Sales | | 531 |
| | 748 |
| | (217 | ) |
| Wholesale | | 342 |
| | 311 |
| | 31 |
|
| Transmission | | 10 |
| | 17 |
| | (7 | ) |
| Other | | 6 |
| | 39 |
| | (33 | ) |
| Total Revenues | | $ | 889 |
| | $ | 1,115 |
| | $ | (226 | ) |
| | | | | | | |
|
| | | | | | | | | |
| | | For the Three Months Ended September 30 | | Increase (Decrease) |
| MWH Sales by Channel | | 2017 | | 2016 | |
| | | (In thousands) |
| Contract Sales: | | | | | | |
| Direct | | 3,646 |
| | 3,913 |
| | (6.8 | )% |
| Governmental Aggregation | | 1,932 |
| | 4,238 |
| | (54.4 | )% |
| Mass Market | | 478 |
| | 673 |
| | (29.0 | )% |
| POLR | | 2,170 |
| | 2,893 |
| | (25.0 | )% |
| Structured | | 2,657 |
| | 2,437 |
| | 9.0 | % |
| Total Contract Sales | | 10,883 |
| | 14,154 |
| | (23.1 | )% |
| Wholesale | | 6,363 |
| | 4,447 |
| | 43.1 | % |
| Total MWH Sales | | 17,246 |
| | 18,601 |
| | (7.3 | )% |
| | | | | | | |
The following table summarizes the price and volume factors contributing to changes in revenues:
|
| | | | | | | | | | | | | | | | | | | | |
| | | Source of Change in Revenues |
| | | Increase (Decrease) |
| MWH Sales Channel: | | Sales Volumes | | Prices | | Gain on Settled Contracts | | Capacity Revenue | | Total |
| | | (In millions) |
| Direct | | $ | (14 | ) | | $ | (20 | ) | | $ | — |
| | $ | — |
| | $ | (34 | ) |
| Governmental Aggregation | | (128 | ) | | 2 |
| | — |
| | — |
| | (126 | ) |
| Mass Market | | (14 | ) | | (1 | ) | | — |
| | — |
| | (15 | ) |
| POLR | | (41 | ) | | (4 | ) | | — |
| | — |
| | (45 | ) |
| Structured | | 9 |
| | (6 | ) | | — |
| | — |
| | 3 |
|
| Wholesale | | 56 |
| | (10 | ) | | (24 | ) | | 9 |
| | 31 |
|
| | | | | | | | | | | |
The decrease in Direct, Governmental Aggregation and Mass Market revenues were primarily due to lower volumes. Lower sales volumes in the Governmental Aggregation channel primarily reflects the termination◦Higher network transmission expenses of an FES customer contract in 2016. The Direct, Governmental Aggregation and Mass Market customer base was approximately 842,000 as of September 30, 2017, compared to 1.4$35 million, as of September 30, 2016.
The decrease in POLR revenue of $45 million was primarily due to lower volumes.
Wholesale revenues increased $31 million, primarily due to an increase in short-term (net hourly position) transactions at lower market prices and higher capacity revenue, partially offset by lower net gains on financially settled contracts.
Other revenue decreased $33 million, primarily due to lower lease revenues from the expiration of a nuclear sale-leaseback agreement. CES earned lease revenue associated with the lessor equity interests it had purchased in sale-leaseback transactions, which expired in June 2017.
Operating Expenses —
Total operating expenses decreased $184 million in the third quarter of 2017 due to the following:
Fuel costs decreased $57 million, primarily due to lower generation associated with outages and economic dispatch of fossil units resulting from low wholesale spot market energy prices, as described above.
Purchased power costs decreased $37 million due to lower capacity expense ($20 million) and lower unit costs ($25 million), partially offset by higher volumes ($8 million). The decrease in capacity expense, which is a component of CES' retail price, was primarily the result of lower contract sales.
Transmission expenses decreased $25 million, primarily due to lower contract sales volumes.
Other operating expenses decreased $18 million, primarily due to the absence of a termination charge associated with an FES Governmental Aggregation customer contract, partially offset by higher non-cash mark-to-market losses on commodity contract positions.
Depreciation expense decreased $49 million, primarily due to a lower asset base resulting from asset impairments recognized in 2016, partially offset by the absence of an out-of-period adjustment to reduce the depreciation of a hydroelectric generating station in the third quarter of 2016.
General taxes decreased $16 million, primarily due to lower property taxes and reduced gross receipts taxes associated with lower retail sales volumes.
Impairment of assets were $18 million in the third quarter of 2017, primarily resulting from adjustments pursuant to the terms of the amended and restated asset purchase agreement between AE Supply, AGC, BU Energy and a subsidiary of LS Power as further discussed under "Outlook - Asset Impairment - Competitive Generation Asset Sale" below.
Other Expense —
Total other expense decreased $13 million in the third quarter of 2017, as compared to the same period of 2016, primarily due to higher investment income on NDT investments.
Income Taxes —
CES' effective tax rate was 37.7% and 36.3% for the quarter ended September 30, 2017 and 2016, respectively.
Corporate / Other — Third Quarter 2017 Compared with Third Quarter 2016
Financial results from the Corporate/Other operating segment and reconciling adjustments, including interest expense on holding company debt, corporate support services revenues and expenses and income taxes, resulted in a $1 million decrease in consolidated earnings in the third quarter of 2017, compared to the same period of 2016, primarily associated with higher interest expense, partially offset by a lower consolidated effective tax rate. Higher interest expense resulted from the issuance of $3 billion of senior notes in June of 2017, proceeds of which were used to repay short-term borrowings and redeem $650 million of notes due in 2018.
Summary of Results of Operations — First Nine Months of 2017 Compared with First Nine Months of 2016
Financial results for FirstEnergy’s business segments in the first nine months of 2017 and 2016 were as follows:
|
| | | | | | | | | | | | | | | | | | | | |
| First Nine Months 2017 Financial Results | | Regulated Distribution | | Regulated Transmission | | Competitive
Energy Services | | Corporate/Other and Reconciling Adjustments | | FirstEnergy Consolidated |
| | | (In millions) |
| Revenues: | | |
| | | | |
| | |
| | |
|
| External | | |
| | | | |
| | |
| | |
|
| Electric | | $ | 7,222 |
| | $ | 982 |
| | $ | 2,313 |
| | $ | (128 | ) | | $ | 10,389 |
|
| Other | | 140 |
| | — |
| | 75 |
| | (29 | ) | | 186 |
|
| Internal | | — |
| | — |
| | 296 |
| | (296 | ) | | — |
|
| Total Revenues | | 7,362 |
| | 982 |
| | 2,684 |
| | (453 | ) | | 10,575 |
|
| | | | | | | | | | | |
| Operating Expenses: | | |
| | |
| | |
| | |
| | |
|
| Fuel | | 388 |
| | — |
| | 686 |
| | — |
| | 1,074 |
|
| Purchased power | | 2,267 |
| | — |
| | 488 |
| | (296 | ) | | 2,459 |
|
| Other operating expenses | | 1,871 |
| | 150 |
| | 1,237 |
| | (217 | ) | | 3,041 |
|
| Provision for depreciation | | 540 |
| | 164 |
| | 87 |
| | 54 |
| | 845 |
|
| Amortization of regulatory assets, net | | 204 |
| | 11 |
| | — |
| | — |
| | 215 |
|
| General taxes | | 546 |
| | 130 |
| | 71 |
| | 30 |
| | 777 |
|
| Impairment of assets | | — |
| | 13 |
| | 149 |
| | — |
| | 162 |
|
| Total Operating Expenses | | 5,816 |
| | 468 |
| | 2,718 |
| | (429 | ) | | 8,573 |
|
| | | | | | | | | | | |
| Operating Income (Loss) | | 1,546 |
| | 514 |
| | (34 | ) | | (24 | ) | | 2,002 |
|
| | | | | | | | | | | |
| Other Income (Expense): | | |
| | |
| | |
| | |
| | |
|
| Investment income (loss) | | 41 |
| | — |
| | 66 |
| | (29 | ) | | 78 |
|
| Interest expense | | (405 | ) | | (116 | ) | | (136 | ) | | (225 | ) | | (882 | ) |
| Capitalized financing costs | | 16 |
| | 20 |
| | 22 |
| | 1 |
| | 59 |
|
| Total Other Expense | | (348 | ) | | (96 | ) | | (48 | ) | | (253 | ) | | (745 | ) |
| | | | | | | | | | | |
| Income (Loss) Before Income Taxes (Benefits) | | 1,198 |
| | 418 |
| | (82 | ) | | (277 | ) | | 1,257 |
|
| Income taxes (benefits) | | 442 |
| | 154 |
| | (25 | ) | | (89 | ) | | 482 |
|
| Net Income (Loss) | | $ | 756 |
| | $ | 264 |
| | $ | (57 | ) | | $ | (188 | ) | | $ | 775 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| First Nine Months 2016 Financial Results | | Regulated Distribution | | Regulated Transmission | | Competitive
Energy Services | | Corporate/Other and Reconciling Adjustments | | FirstEnergy Consolidated |
| | | (In millions) |
| Revenues: | | |
| | | | |
| | |
| | |
|
| External | | |
| | | | |
| | |
| | |
|
| Electric | | $ | 7,205 |
| | $ | 851 |
| | $ | 3,023 |
| | $ | (129 | ) | | $ | 10,950 |
|
| Other | | 185 |
| | — |
| | 135 |
| | (83 | ) | | 237 |
|
| Internal | | — |
| | — |
| | 377 |
| | (377 | ) | | — |
|
| Total Revenues | | 7,390 |
| | 851 |
| | 3,535 |
| | (589 | ) | | 11,187 |
|
| | | | | | | | | | | |
| Operating Expenses: | | |
| | |
| | |
| | |
| | |
|
| Fuel | | 436 |
| | — |
| | 833 |
| | — |
| | 1,269 |
|
| Purchased power | | 2,549 |
| | — |
| | 820 |
| | (377 | ) | | 2,992 |
|
| Other operating expenses | | 1,840 |
| | 115 |
| | 1,120 |
| | (240 | ) | | 2,835 |
|
| Provision for depreciation | | 504 |
| | 138 |
| | 284 |
| | 48 |
| | 974 |
|
| Amortization of regulatory assets, net | | 218 |
| | 4 |
| | — |
| | — |
| | 222 |
|
| General taxes | | 545 |
| | 114 |
| | 98 |
| | 29 |
| | 786 |
|
| Impairment of assets | | — |
| | — |
| | 1,447 |
| | — |
| | 1,447 |
|
| Total Operating Expenses | | 6,092 |
| | 371 |
| | 4,602 |
| | (540 | ) | | 10,525 |
|
| | | | | | | | | | | |
| Operating Income (Loss) | | 1,298 |
| | 480 |
| | (1,067 | ) | | (49 | ) | | 662 |
|
| | | | | | | | | | | |
| Other Income (Expense): | | |
| | |
| | |
| | |
| | |
|
| Investment income (loss) | | 37 |
| | — |
| | 56 |
| | (18 | ) | | 75 |
|
| Interest expense | | (441 | ) | | (118 | ) | | (143 | ) | | (161 | ) | | (863 | ) |
| Capitalized financing costs | | 15 |
| | 25 |
| | 29 |
| | 10 |
| | 79 |
|
| Total Other Expense | | (389 | ) | | (93 | ) | | (58 | ) | | (169 | ) | | (709 | ) |
| | | | | | | | | | | |
| Income (Loss) Before Income Taxes (Benefits) | | 909 |
| | 387 |
| | (1,125 | ) | | (218 | ) | | (47 | ) |
| Income taxes (benefits) | | 336 |
| | 143 |
| | (96 | ) | | (49 | ) | | 334 |
|
| Net Income (Loss) | | $ | 573 |
| | $ | 244 |
| | $ | (1,029 | ) | | $ | (169 | ) | | $ | (381 | ) |
|
| | | | | | | | | | | | | | | | | | | | |
| Changes Between First Nine Months 2017 and First Nine Months 2016 Financial Results | | Regulated Distribution | | Regulated Transmission | | Competitive
Energy Services | | Corporate/Other and Reconciling Adjustments | | FirstEnergy Consolidated |
| | | (In millions) |
| Revenues: | | |
| | | | |
| | |
| | |
|
| External | | |
| | | | |
| | |
| | |
|
| Electric | | $ | 17 |
| | $ | 131 |
| | $ | (710 | ) | | $ | 1 |
| | $ | (561 | ) |
| Other | | (45 | ) | | — |
| | (60 | ) | | 54 |
| | (51 | ) |
| Internal | | — |
| | — |
| | (81 | ) | | 81 |
| | — |
|
| Total Revenues | | (28 | ) | | 131 |
| | (851 | ) | | 136 |
| | (612 | ) |
| | | | | | | | | | | |
| Operating Expenses: | | |
| | |
| | |
| | |
| | |
|
| Fuel | | (48 | ) | | — |
| | (147 | ) | | — |
| | (195 | ) |
| Purchased power | | (282 | ) | | — |
| | (332 | ) | | 81 |
| | (533 | ) |
| Other operating expenses | | 31 |
| | 35 |
| | 117 |
| | 23 |
| | 206 |
|
| Provision for depreciation | | 36 |
| | 26 |
| | (197 | ) | | 6 |
| | (129 | ) |
| Amortization of regulatory assets, net | | (14 | ) | | 7 |
| | — |
| | — |
| | (7 | ) |
| General taxes | | 1 |
| | 16 |
| | (27 | ) | | 1 |
| | (9 | ) |
| Impairment of assets | | — |
| | 13 |
| | (1,298 | ) | | — |
| | (1,285 | ) |
| Total Operating Expenses | | (276 | ) | | 97 |
| | (1,884 | ) | | 111 |
| | (1,952 | ) |
| | | | | | | | | | | |
| Operating Income (Loss) | | 248 |
| | 34 |
| | 1,033 |
| | 25 |
| | 1,340 |
|
| | | | | | | | | | | |
| Other Income (Expense): | | |
| | |
| | |
| | |
| | |
|
| Investment income (loss) | | 4 |
| | — |
| | 10 |
| | (11 | ) | | 3 |
|
| Interest expense | | 36 |
| | 2 |
| | 7 |
| | (64 | ) | | (19 | ) |
| Capitalized financing costs | | 1 |
| | (5 | ) | | (7 | ) | | (9 | ) | | (20 | ) |
| Total Other Expense | | 41 |
| | (3 | ) | | 10 |
| | (84 | ) | | (36 | ) |
| | | | | | | | | | | |
| Income (Loss) Before Income Taxes (Benefits) | | 289 |
| | 31 |
| | 1,043 |
| | (59 | ) | | 1,304 |
|
| Income taxes (benefits) | | 106 |
| | 11 |
| | 71 |
| | (40 | ) | | 148 |
|
| Net Income (Loss) | | $ | 183 |
| | $ | 20 |
| | $ | 972 |
| | $ | (19 | ) | | $ | 1,156 |
|
Regulated Distribution — First Nine Months of 2017 Compared with First Nine Months of 2016
Regulated Distribution's operating results increased $183 million in the first nine months of 2017, as compared to the same period of 2016, reflecting implementation of approved rates in Ohio, Pennsylvania, and New Jersey, partially offset by lower weather-related customer usage, as further described below. Additionally, in the first quarter of 2016, the Ohio Companies recognized $51 million in regulatory charges resulting from the PUCO's March 31, 2016 Opinion and Order adopting and approving, with modifications, the Ohio Companies' ESP IV.
Revenues —
The $28 million decrease in total revenues resulted from the following sources:
|
| | | | | | | | | | | | |
| | | For the Nine Months Ended September 30 | | Increase |
| Revenues by Type of Service | | 2017 | | 2016 | | (Decrease) |
| | | (In millions) |
| Distribution services | | $ | 4,003 |
| | $ | 3,599 |
| | $ | 404 |
|
| | | | | | | |
| Generation sales: | | | | | | |
| Retail | | 2,851 |
| | 3,222 |
| | (371 | ) |
| Wholesale | | 368 |
| | 384 |
| | (16 | ) |
| Total generation sales | | 3,219 |
| | 3,606 |
| | (387 | ) |
| | | | | | | |
| Other | | 140 |
| | 185 |
| | (45 | ) |
| Total Revenues | | $ | 7,362 |
| | $ | 7,390 |
| | $ | (28 | ) |
Distribution services revenues increased $404 million primarily resulting from the implementation of the DMR in Ohio, effective January 1, 2017, approved base distribution rate increases in Pennsylvania and New Jersey, effective January 27, 2017, and January 1, 2017, respectively, and higher revenue from the DCR in Ohio. Partially offsetting these rate increases was a decline in MWH deliveries, primarily resulting from lower weather-related usage, as described below. Distribution deliveries by customer class are summarized in the following table:
|
| | | | | | | | | |
| | | For the Nine Months Ended September 30 | | Increase |
| Electric Distribution MWH Deliveries | | 2017 | | 2016 | | (Decrease) |
| | | (In thousands) | | |
| Residential | | 38,846 |
| | 42,130 |
| | (7.8 | )% |
| Commercial | | 31,693 |
| | 32,913 |
| | (3.7 | )% |
| Industrial | | 38,571 |
| | 37,746 |
| | 2.2 | % |
| Other | | 428 |
| | 437 |
| | (2.1 | )% |
| Total Electric Distribution MWH Deliveries | | 109,538 |
| | 113,226 |
| | (3.3 | )% |
Lower distribution deliveries to residential and commercial customers primarily reflect lower weather-related usage resulting from heating degree days that were 11% below 2016, and 17% below normal as well as cooling degree days that were 21% below 2016, and 5% above normal. Deliveries to industrial customers increased reflecting higher shale and steel customer usage.
The following table summarizes the price and volume factors contributing to the $387 million decrease in generation revenues for the first nine months of 2017 compared to the same period of 2016:
|
| | | | |
| Source of Change in Generation Revenues | | Increase (Decrease) |
| | | (In millions) |
| Retail: | | |
|
| Effect of decrease in sales volumes | | $ | (256 | ) |
| Change in prices | | (115 | ) |
| | | (371 | ) |
| Wholesale: | | |
| Effect of increase in sales volumes | | 12 |
|
| Change in prices | | (10 | ) |
| Capacity Revenue | | (18 | ) |
| | | (16 | ) |
| Decrease in Generation Revenues | | $ | (387 | ) |
The decrease in retail generation sales volumes was primarily due to increased customer shopping in Ohio and Pennsylvania as well as lower weather-related usage, as described above. Total generation provided by alternative suppliers as a percentage of total MWH deliveries increased to 85% from 82% for the Ohio Companies, to 68% from 67% for the Pennsylvania Companies, and to 52% from 51% for JCP&L. The decrease in retail generation prices primarily resulted from lower default service auction prices in Ohio, Pennsylvania, and New Jersey.
Wholesale generation revenues decreased $16 million in the first nine months of 2017, as compared to the same period in 2016, primarily due to lower spot market energy prices and capacity revenue, partially offset by higher wholesale sales. The difference between current wholesale generation revenues and certain energy costs incurred are deferred for future recovery, or refund, with no material impact to earnings.
Other revenues decreased $45 million primarily related to a $26 million gain on the sale of oil and gas rights at WP recognized in 2016 as well as $14 million in lower transition cost recovery revenues in New Jersey.
Operating Expenses —
Total operating expenses decreased $276 million primarily due to the following:
Fuel expense decreased $48 million in the first nine months of 2017, as compared to the same period in 2016, primarily related to lower unit costs.
Purchased power costs decreased $282 million during the first nine months of 2017, as compared to the same period of 2016, primarily due to decreased volumes resulting from increased customer shopping and lower weather-related usage, as described above, as well as lower default service auction prices. These lower costs were partially offset by recovery of previously deferred energy and fuel costs.
|
| | | | | |
| | Source of Change in Purchased Power | | Increase (Decrease) |
| |
| | | | (In millions) |
| | Purchases from non-affiliates: | | |
| | Change due to decreased unit costs | | $ | (125 | ) |
| | Change due to volumes | | (164 | ) |
| | | | (289 | ) |
| | Purchases from affiliates: | | |
| | Change due to decreased unit costs | | (21 | ) |
| | Change due to volumes | | (60 | ) |
| | | | (81 | ) |
| | Capacity Expense | | (1 | ) |
| | Amortization of deferred costs | | 89 |
|
| | Decrease in Purchased Power Costs | | $ | (282 | ) |
Other operating expenses increased $31 million primarily due to:
Higher network transmission expenses of $14 million. The difference between current revenues and transmission costs incurred are deferred for future recovery or refund, resulting in no material impact on current period earnings.earnings;
◦Higher operating and maintenancestorm expenses of $68$23 million, including increased expenses in Pennsylvania recovered through the new base distribution rates, effective January 27, 2017, and increased storm restoration costs, which were deferred for future recovery, resulting in no material impact on current period earnings.earnings;
Lower regulatory◦Higher planned vegetation management expenses of $13 million;
◦Higher energy efficiency and other state mandated program costs of $51$5 million, which were deferred for future recovery, resulting from the recognition in 2016no material impact on current period earnings; and
◦Higher uncollectible expenses of economic development and energy efficiency obligations in accordance with the PUCO's March 31, 2016 Opinion and Order adopting and approving, with modifications, the Ohio Companies' ESP IV.$8 million, of which $3 million was deferred for future recovery.
•Depreciation expense increased $36$8 million in the first three months of 2024, as compared to the same period of 2023, primarily due to a higher asset base.
•Deferral of regulatory assets increased $47 million in the first three months of 2024, as compared to the same period of 2023, primarily due to:
◦$57 million net increase due to higher generation and transmission related deferrals; and
◦$26 million increase due to higher deferral of storm related expenses;
partially offset by:
◦$19 million related to net decreases in other deferrals; and
◦$17 million decrease due to lower deferral of certain Tax Act savings to Pennsylvania customers.
•General taxes increased $4 million in the first three months of 2024, as compared to the same period of 2023, primarily due to higher gross receipts taxes.
Other Expense —
Other expense was flat in the first three months of 2024, as compared to the same period of 2023, primarily due to higher net interest expense associated with new long-term issuances and higher short-term borrowings being offset by higher interest income on investments in the regulated money pool.
Income Taxes —
Distribution’s effective tax rate was 19.9% and 19.1% for the three months ended March 31, 2024 and 2023, respectively.
Integrated Segment — First Three Months of 2024 Compared with First Three Months of 2023
Integrated’s earnings attributable to FE increased $12 million in the first three months of 2024, as compared to the same period of 2023, primarily from the implementation of base rate case settlements, higher customer usage as a result of weather, higher revenues from regulated investment programs, partially offset by lower weather-adjusted customer usage and demand, higher other operating expenses and a higher effective tax rate due to discrete tax charges discussed below.
Revenues —
Integrated’s total revenues increased $67 million as a result of the following sources:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended March 31, |
| Revenues by Type of Service | | 2024 | | 2023 | | Increase
(Decrease) | | | | | | |
| | (In millions) | | | | | | |
| Distribution services | | 339 | | | 334 | | | $ | 5 | | | | | | | |
| Generation sales: | | | | | | | | | | | | |
| Retail | | 632 | | | 569 | | | 63 | | | | | | | |
| Wholesale | | 30 | | | 45 | | | (15) | | | | | | | |
| Total generation sales | | 662 | | | 614 | | | 48 | | | | | | | |
| Transmission revenues: | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| JCP&L | | 52 | | | 43 | | | 9 | | | | | | | |
| MP & PE | | 29 | | | 21 | | | 8 | | | | | | | |
| Total Transmission Asset Owner Revenues | | 81 | | | 64 | | | 17 | | | | | | | |
| Other | | 13 | | | 16 | | | (3) | | | | | | | |
| Total Revenues | | $ | 1,095 | | | $ | 1,028 | | | $ | 67 | | | | | | | |
Distribution services revenues increased $5 million in the first three months of 2024, as compared to the same period of 2023, primarily resulting from higher customer usage as a result of the weather, higher revenues from the rate case settlement in Maryland, and higher rider revenues associated with certain investment programs, partially offset by lower weather-adjusted customer usage and demand.
Generation sales revenues increased $48 million in the first three months of 2024, as compared to the same period of 2023. primarily due to higher retail revenues, partially offset by lower wholesale revenues.
•Retail generation sales increased $63 million in the first three months of 2024, as compared to the same period in 2023 primarily due to higher customer usage as a result of the weather and higher non-shopping generation auction rates. Retail generation sales, other than those in West Virginia, have no material impact to earnings.
•Wholesale generation revenues decreased $15 million in the first three months of 2024, as compared to the same period in 2023, primarily due to lower capacity revenues and sales volumes, partially offset by higher market prices. The difference between current wholesale generation revenues and certain energy costs incurred is deferred for future recovery or refund, with no material impact to current period earnings.
Transmission revenues increased $17 million in the first three months of 2024, as compared to the same period of 2023, primarily due to higher rate base from regulated investment programs and higher transmission operating expenses.
Operating Expenses —
Total operating expenses increased $28 million, primarily due to the following:
•Fuel costs decreased $28 million during the first three months of 2024, as compared to the same period of 2023, primarily due to lower unit costs and generation output. Due to the ENEC, fuel expense has no material impact on current period earnings.
•Purchased power costs, which have no material impact on current period earnings, decreased $13 million during the first three months of 2024, as compared to the same period of 2023, primarily due to lower capacity expenses.
•Other operating expenses increased $94 million in the first three months of 2024, as compared to the same period of 2023.
•Distribution related other operating expenses increased $91 million primarily due to:
◦A $53 million pre-tax charge at JCP&L in the first quarter 2024 associated with certain corporate support costs recorded to capital accounts from the FERC Audit that were determined, as a result of the settlement agreement, to be disallowed from future recovery;
◦Higher storm expenses of $25 million, of which $18 million was deferred for future recovery;
◦Higher network transmission expenses of $10 million, which were deferred for future recovery, resulting in no material impact on current period earnings;
◦Higher planned vegetation management costs of $4 million, which were deferred for future recovery resulting in no material impact on current period earnings;
◦Higher other operating and maintenance expenses of $4 million, primarily due to regulated generation outage spend; and
◦Lower uncollectible expenses of $5 million, which were deferred for future recovery, resulting in no material impact on current period earnings.
•Transmission related other operating expenses increased $3 million primarily due to:
◦Higher operating and maintenance expenses. Nearly all transmission related operating expenses are recovered through formula rates, resulting in no material impact on current period earnings.
•Depreciation expense increased $9 million in the first three months of 2024, as compared to the same period of 2023, primarily due to a higher asset base.
•Deferral of regulatory assets increased $38 million in the first three months of 2024, as compared to the same period of 2023, primarily due to:
•$60 million increase due to the approval in the first quarter of 2024 to recover costs of certain retired generation stations by the WVPSC;
•$23 million increase due to higher deferral of storm related expenses;
•$19 million related to net increases in other deferrals; and
•$4 million increase due to higher energy efficiency related deferrals;
partially offset by:
•$63 million net decrease due to lower generation and transmission related deferrals; and
•$5 million decrease due to higher vegetation related amortizations.
•General taxes increased $4 million in the first three months of 2024, as compared to the same period of 2023, primarily due to higher gross receipts taxes.
Other Expense —
Other expense increased $12 million in the first three months of 2024, as compared to the same period of 2023, primarily due to higher net interest expense associated with new long-term issuances, higher short-term borrowings, and higher nonrecoverable charges.
Income Taxes —
Integrated’s effective tax rate was 29.9% and 22.2% for the three months ended March 31, 2024 and 2023, respectively, the increase was primarily due to an update to a valuation allowance associated with the expected utilization of certain state NOL carryforwards related to the sale of equity interest in FET.
Stand-Alone Transmission Segment — First Three Months of 2024 Compared with First Three Months of 2023
Stand-Alone Transmission’s earnings attributable to FE decreased $12 million in the first three months of 2024, as compared to the same period of 2023, primarily due to a discrete tax charge associated with the FET Equity Interest Sale and higher short-term borrowings and interest rates, partially offset by increased earnings as a result of regulated capital investments that increased rate base.
Revenues —
Stand-Alone Transmission’s total revenues increased $38 million, primarily due to a higher rate base as well as increased rates in Pennsylvania.and recovery of higher transmission operating expenses.
Amortization expense decreased $14 million primarily due to lower amortization of transition costs and non-utility generation costs, as well as higher deferral of storm restoration costs, partially offsetThe following table shows revenues by a lower deferral of transmission costs in Ohio.asset owner:
| | | | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended March 31, |
| Revenues by Transmission Asset Owner | | 2024 | | | 2023 | | | Increase |
| | (In millions) |
| ATSI | | 245 | | | | 228 | | | | $ | 17 | |
| TrAIL | | 68 | | | | 67 | | | | 1 | |
| MAIT | | 105 | | | | 90 | | | | 15 | |
| KATCo | | 20 | | | | 15 | | | | 5 | |
| Total Revenues | | $ | 438 | | | | $ | 400 | | | | $ | 38 | |
Other Expense
Operating Expenses —
Total other expense decreased $41 million primarily due to lower interest expense resulting from various debt maturities at JCP&L, CEI, and OE.
Income Taxes —
Regulated Distribution’s effective tax rate was 36.9% and 37.0% for the first nine months of 2017 and 2016, respectively.
Regulated Transmission — First Nine Months of 2017 Compared with First Nine Months of 2016
Regulated Transmission's operating resultsexpenses increased $20$18 million in the first ninethree months of 2017,2024, as compared to the same period of 2016,2023, primarily resultingdue to higher depreciation and property tax expenses from the impact of a higher rateasset base, at ATSI and TrAIL partially offset by a pre-tax impairment charge of $13 million, as discussed below. Additionally, JCP&L's and MAIT's forward-looking formula rates for their transmission assets were implemented on June 1, 2017, and July 1, 2017, respectively, subject to refund pending the outcome of settlement and hearing proceedings and a final FERC order.
Revenues —
Total revenues increased $131 million principally due to recovery of incremental operating expenses and a higher rate base at ATSI, JCP&L, and TrAIL.
Revenues by transmission asset owner are shown in the following table:
|
| | | | | | | | | | | | |
| | | For the Nine Months Ended September 30 | | Increase |
| Revenues by Transmission Asset Owner | | 2017 | | 2016 | | (Decrease) |
| | | (In millions) |
| ATSI | | $ | 485 |
| | $ | 401 |
| | $ | 84 |
|
| TrAIL | | 215 |
| | 187 |
| | 28 |
|
MAIT (1) | | 79 |
| | 75 |
| | 4 |
|
| JCP&L | | 86 |
| | 69 |
| | 17 |
|
| Other | | 117 |
| | 119 |
| | (2 | ) |
| Total Revenues | | $ | 982 |
| | $ | 851 |
| | $ | 131 |
|
| |
(1)
| Revenues in 2016 represent transmission revenues under stated rates at ME and PN. |
Operating Expenses —
Total operating expenses increased $97 million principally due towell as higher operating and maintenance expenses. Nearly all operating expenses as well as higher property taxes and depreciation due to higher asset base. Additionally, as a result of the settlement agreement between MAIT and certain parties, MAIT recorded a pre-tax impairment charge of $13 millionare recovered through formula rates, resulting in the third quarter of 2017. The settlement agreement is currently pending at FERC.no material impact on current period earnings.
Income TaxesOther Expense —
Regulated Transmission’s effective tax rate was 36.8% and 37.0% for the first nine months of 2017 and 2016, respectively.
CES — First Nine Months of 2017 Compared with First Nine Months of 2016
CES' operating resultsTotal other expense increased $972$9 million in the first ninethree months of 2017,2024, as compared to the same period of 2016, primarily due to lower asset impairment and plant exit costs, as discussed above, and lower depreciation expense, partially offset by a pre-tax charge of $164 million associated with estimated losses on long-term coal transportation contract disputes, as discussed in "Outlook - Environmental Matters" below, higher non-cash mark-to-market losses on commodity contract positions, and lower capacity revenue.
Revenues —
Total revenues decreased $851 million in the first nine months of 2017, as compared to the same period of 2016, primarily due to lower capacity auction prices, lower contract sales volumes at lower prices, and lower net gains on financially settled contracts, partially offset by an increase in short-term (net hourly position) transactions, as further described below.
The decrease in total revenues resulted from the following sources:
|
| | | | | | | | | | | | |
| | | For the Nine Months Ended September 30 | | Decrease |
| Revenues by Type of Service | | 2017 | | 2016 | |
| | | (In millions) |
| Contract Sales: | | | | | | |
| Direct | | $ | 560 |
| | $ | 610 |
| | $ | (50 | ) |
| Governmental Aggregation | | 302 |
| | 666 |
| | (364 | ) |
| Mass Market | | 97 |
| | 133 |
| | (36 | ) |
| POLR | | 389 |
| | 447 |
| | (58 | ) |
| Structured | | 255 |
| | 371 |
| | (116 | ) |
| Total Contract Sales | | 1,603 |
| | 2,227 |
| | (624 | ) |
| Wholesale | | 971 |
| | 1,117 |
| | (146 | ) |
| Transmission | | 35 |
| | 56 |
| | (21 | ) |
| Other | | 75 |
| | 135 |
| | (60 | ) |
| Total Revenues | | $ | 2,684 |
| | $ | 3,535 |
| | $ | (851 | ) |
| | | | | | | |
|
| | | | | | | | | |
| | | For the Nine Months Ended September 30 | | Increase (Decrease) |
| MWH Sales by Channel | | 2017 | | 2016 | |
| | | (In thousands) | | |
| Contract Sales: | | | | | | |
| Direct | | 11,504 |
| | 11,391 |
| | 1.0 | % |
| Governmental Aggregation | | 5,686 |
| | 10,798 |
| | (47.3 | )% |
| Mass Market | | 1,425 |
| | 1,912 |
| | (25.5 | )% |
| POLR | | 6,983 |
| | 7,526 |
| | (7.2 | )% |
| Structured | | 6,564 |
| | 9,175 |
| | (28.5 | )% |
| Total Contract Sales | | 32,162 |
| | 40,802 |
| | (21.2 | )% |
| Wholesale | | 16,753 |
| | 9,938 |
| | 68.6 | % |
| Total MWH Sales | | 48,915 |
| | 50,740 |
| | (3.6 | )% |
| | | | | | | |
The following table summarizes the price and volume factors contributing to changes in revenues:
|
| | | | | | | | | | | | | | | | | | | | |
| | | Source of Change in Revenues |
| | | Increase (Decrease) |
| MWH Sales Channel: | | Sales Volumes | | Prices | | Gain on Settled Contracts | | Capacity Revenue | | Total |
| | | (In millions) |
| Direct | | $ | 6 |
| | $ | (56 | ) | | $ | — |
| | $ | — |
| | $ | (50 | ) |
| Governmental Aggregation | | (316 | ) | | (48 | ) | | — |
| | — |
| | (364 | ) |
| Mass Market | | (34 | ) | | (2 | ) | | — |
| | — |
| | (36 | ) |
| POLR | | (32 | ) | | (26 | ) | | — |
| | — |
| | (58 | ) |
| Structured | | (108 | ) | | (8 | ) | | — |
| | — |
| | (116 | ) |
| Wholesale | | 190 |
| | 11 |
| | (113 | ) | | (234 | ) | | (146 | ) |
Lower sales volumes in the Governmental Aggregation channel primarily reflects the termination of an FES customer contract in 2016. Although unit pricing in Direct, Governmental Aggregation and Mass Market was lower year-over-year, the decrease was primarily attributable to lower capacity expense as discussed below, which is a component of the retail price.
The decrease in POLR revenue of $58 million was primarily due to lower volumes and lower unit prices. Structured revenue decreased $116 million, primarily due to the impact of lower transaction volumes.
Wholesale revenues decreased $146 million, primarily due to a decrease in capacity revenue from lower capacity auction prices and lower net gains on financially settled contracts, partially offset by an increase in short-term (net hourly position) transactions at higher market prices.
Transmission revenue decreased $21 million, primarily due to lower congestion revenue.
Other revenue decreased $60 million, primarily due to lower lease revenues from the expiration of a nuclear sale-leaseback agreement. CES earned lease revenue associated with the lessor equity interests it has purchased in sale-leaseback transactions, one of which expired in June 2017 and another in May 2016.
Operating Expenses —
Total operating expenses decreased $1,884 million in the first nine months of 2017, compared to the same period of 2016, due to the following:
Fuel costs decreased $147 million, primarily due to the absence of approximately $58 million in settlement and termination costs on coal contracts recognized in 2016, as well as lower generation associated with outages and economic dispatch of fossil units resulting from low wholesale spot market energy prices, as described above, partially offset by higher unit costs.
Purchased power costs decreased $332 million, primarily due to lower capacity expenses ($254 million) and lower unit costs ($91 million), partially offset by higher volumes ($13 million). The decrease in capacity expense, which is a component of CES' retail price, was primarily the result of lower contract sales and lower capacity rates associated with CES' retail sales obligations. Lower unit costs primarily resulted from lower wholesale spot market prices, as discussed above.
A $164 million charge associated with estimated losses on long-term coal transportation contract disputes was recognized in the first quarter of 2017, as discussed in "Outlook - Environmental Matters" below.
Fossil operating and maintenance expenses decreased $42 million, primarily due to lower outage costs and the absence of plant demolition costs recognized in 2016.
Nuclear operating and maintenance expenses increased $18 million, primarily as a result of higher refueling outage costs, partially offset by lower non-outage maintenance costs. There were two refueling outages during the first nine months of 2017, as compared to one refueling outage during the same period of 2016.
Transmission expenses decreased $51 million, primarily due to lower contract sales volumes.
Other operating expenses increased $28 million,2023, primarily due to higher non-cash mark-to-market losses on commodity contract positions, partially offset by the absence of a termination charge associated with an FES Governmental Aggregation customer contract.
Depreciationshort-term borrowings and net interest expense decreased $197 million, primarily due to a lower asset base resulting from asset impairments recognized in 2016, partially offset by the absence of an out-of-period adjustment to reduce the depreciation of a hydroelectric generating station in the third quarter of 2016.
General taxes decreased $27 million, primarily due to lower property taxes and reduced gross receipts taxes associated with lower retail sales volumes.
Impairment of assets decreased $1,298 million primarily due to the absence of an $800 million impairment of goodwill and a $647 million impairment of Units 1-4 of the W.H. Sammis generating station and the Bay Shore Unit 1 generating station in 2016, partially offset by impairment charges recognized in 2017 resulting from the amended and restated asset purchase agreement between AE Supply, AGC, BU Energy and a subsidiary of LS Power as further discussed under "Outlook - Asset Impairment - Competitive Generation Asset Sale" below.new debt issuances.
Other Expense —
Total other expense decreased $10 million in the first nine months of 2017, as compared to the same period of 2016, primarily due to higher investment income on NDT investments.
Income Taxes (Benefits) —
CES'Stand-Alone Transmission’s effective tax rate was 30.5%38.0% and 8.5% on pre-tax losses22.4% for the first ninethree months of 2017ended March 31, 2024 and 2016,2023, respectively. The changeincrease in the effective tax rate is primarily due to a discrete tax charge related to updates to deferred taxes on the impairmentsale of $800 millionequity interest in FET in the first quarter of goodwill recognized in 2016, of which $433 million was non-deductible for tax purposes. Additionally, $159 million of valuation allowances were recognized in 2016 against state and municipal NOL carryforwards.2024.
Corporate / Other — First NineThree Months of 20172024 Compared with First NineThree Months of 20162023
Financial results from theat Corporate/Other operating segment and reconciling adjustments resulted in a $19an $18 million decreaseincrease in consolidated earningslosses attributable to FE in the first ninethree months of 20172024, as compared to the same period of 20162023, primarily due to:
•$21 million (after-tax) of lower other operating expenses related to the absence of expenses associated with the cancellation of a sponsorship agreement during the first quarter of 2023; and
•$8 million (after-tax) related to lower pension and OPEB service and non-service costs;
partially offset by:
•$26 million (after-tax) of lower investment earnings related to FEV’s equity method investment in Global Holding;
•$13 million (after-tax) of higher net interest expense associated with the 2026 Convertible Notes issuance in May 2023, and higher revolver borrowings and interest rate, partially offset by favorable money pool investments; and
•Higher net discrete income tax charges related to the PA Consolidation, partially offset by income tax benefits related to updates to deferred taxes on the sale of equity interest in FET in the first quarter of 2024 and other discrete benefits primarily associated with higher interest expense, partially offset by a change in consolidated effective tax rate. Higher interest expense resulted from higher average borrowings on the FE revolving credit facility and the issuance of $3 billion of senior notes in June of 2017.state NOL utilization.
Regulatory Assets
REGULATORY ASSETS AND LIABILITIES
Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent amounts that are expected to be credited to customers through future regulated rates or amounts collected from customers for costs not yet incurred. FirstEnergy, the Utilities and the UtilitiesTransmission Companies net their regulatory assets and liabilities based on federal and state jurisdictions.
Management assesses the probability of recovery of regulatory assets, and settlement of regulatory liabilities, at each balance sheet date and whenever new events occur. Factors that may affect probability relate to changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. Upon material changes to these factors, where applicable, FirstEnergy will record new regulatory assets and liabilities and will assess whether it is probable that currently recorded regulatory assets and liabilities will be recovered or settled in future rates.
The following table provides information about the composition of net regulatory assets and liabilities as of September 30, 2017March 31, 2024, and December 31, 2016,2023, and the changes during the ninethree months ended September 30, 2017:March 31, 2024:
| | | | | | | | | | | | | | | | | | | | |
| Net Regulatory Assets (Liabilities) by Source | | March 31,
2024 | | December 31,
2023 | | Change |
| | | (In millions) |
| Customer payables for future income taxes | | $ | (2,358) | | | $ | (2,382) | | | $ | 24 | |
| Spent nuclear fuel disposal costs | | (78) | | | (83) | | | 5 | |
| Asset removal costs | | (661) | | | (652) | | | (9) | |
| Deferred transmission costs | | 282 | | | 286 | | | (4) | |
| Deferred generation costs | | 631 | | | 572 | | | 59 | |
| Deferred distribution costs | | 291 | | | 247 | | | 44 | |
| | | | | | |
| Storm-related costs | | 867 | | | 799 | | | 68 | |
| | | | | | |
| Energy efficiency program costs | | 221 | | | 198 | | | 23 | |
| New Jersey societal benefit costs | | 76 | | | 79 | | | (3) | |
| | | | | | |
| Vegetation management costs | | 101 | | | 102 | | | (1) | |
| Other | | (3) | | | (11) | | | 8 | |
| Net Regulatory Liabilities included on the Consolidated Balance Sheets | | $ | (631) | | | $ | (845) | | | $ | 214 | |
The following is a description of the regulatory assets and liabilities described above:
Customer payables for future income taxes - Reflects amounts to be recovered or refunded through future rates to pay income taxes that become payable when rate revenue is provided to recover items such as AFUDC equity and depreciation of property, plant and equipment for which deferred income taxes were not recognized for ratemaking purposes, including amounts attributable to federal and state tax rate changes such as the Tax Act and Pennsylvania House Bill 1342. These amounts are being amortized over the period in which the related deferred tax assets reverse, which is generally over the expected life of the underlying asset.
|
| | | | | | | | | | | | |
| Net Regulatory Assets by Source | | September 30,
2017 | | December 31,
2016 | | Increase (Decrease) |
| | | (In millions) |
| Regulatory transition costs | | $ | 51 |
| | $ | 90 |
| | $ | (39 | ) |
| Customer receivables for future income taxes | | 375 |
| | 444 |
| | (69 | ) |
| Nuclear decommissioning and spent fuel disposal costs | | (174 | ) | | (304 | ) | | 130 |
|
| Asset removal costs | | (338 | ) | | (470 | ) | | 132 |
|
| Deferred transmission costs | | 173 |
| | 127 |
| | 46 |
|
| Deferred generation costs | | 209 |
| | 215 |
| | (6 | ) |
| Deferred distribution costs | | 240 |
| | 296 |
| | (56 | ) |
| Contract valuations | | 91 |
| | 153 |
| | (62 | ) |
| Storm-related costs | | 285 |
| | 353 |
| | (68 | ) |
| Other | | 17 |
| | 110 |
| | (93 | ) |
| Net Regulatory Assets included on the Consolidated Balance Sheets | | $ | 929 |
| | $ | 1,014 |
| | $ | (85 | ) |
RegulatoryAsset removal costs - Primarily represents the rates charged to customers that include a provision for the cost of future activities to remove assets, including obligations for which an asset retirement obligation has been recognized, that are expected to be incurred at the time of retirement.
Deferred transmission costs - Reflects differences between revenues earned based on actual costs for the formula-rate Transmission Companies and the amounts billed, including amounts expected to be refunded to, or recoverable from, wholesale transmission customers resulting from the FERC Audit, as further described below, which amounts are recorded as a regulatory asset or liability and recovered or refunded, respectively, in subsequent periods. Also included is the recovery of non-market based costs or fees charged to certain of the Utilities by various regulatory bodies including FERC and RTOs, which can include PJM charges and credits for service including, but not limited to, procuring transmission services and transmission enhancement.
Deferred generation costs - Primarily relates to regulatory assets associated with the securitized recovery of certain fuel and purchased power regulatory assets at the Ohio Companies (amortized through 2034) as well as the ENEC at MP and PE. 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. Generally, the ENEC rate is updated annually. Also included is a regulatory asset related to approval by the WVPSC in March 2024 to recover costs associated with certain retired generation plants in West Virginia (amortized through 2029).
Deferred distribution costs - Relates to the Ohio Companies' deferral of certain distribution-related expenses, including interest (amortized through 2034), AMI costs in New Jersey, and other distribution-related costs being recovered in West Virginia.
Storm-related costs - Relates to the deferral of storm costs, which vary by jurisdiction. Approximately $329 million and $254 million are currently being recovered through rates as of March 31, 2024 and December 31, 2023, respectively.
Energy efficiency program costs - Relates to the recovery of costs in excess of revenues associated with energy efficiency programs including, New Jersey energy efficiency and renewable energy programs, FE PA’s Energy Efficiency and Conservation programs, the Ohio Companies' Demand Side Management and Energy Efficiency Rider, and PE's EmPOWER Maryland Surcharge. Investments in certain of these energy efficiency programs earn a long-term return.
New Jersey societal benefit costs - Primarily relates to regulatory assets associated with MGP remediation, universal service and lifeline funds, and the New Jersey Clean Energy Program.
Vegetation management costs - Relates to regulatory assets associated with the recovery of certain distribution vegetation management costs in New Jersey and West Virginia as well as certain transmission vegetation management costs at MAIT, ATSI, KATCo and PE (amortized through 2024, 2030 and 2036, respectively).
The following table provides information about the composition of net regulatory assets that do not earn a current return totaled approximately $100 million and $153 million as of September 30, 2017March 31, 2024 and December 31, 2016,2023, of which approximately $692 million and $371 million, respectively, primarily related to storm damage costs and are currently being recovered through rates.
As of September 30, 2017, and December 31, 2016, FirstEnergy had approximately $305 million and $157 million, respectively, of net regulatory liabilities that are primarily related to asset removal costs. Net regulatory liabilities are classified within Other noncurrent liabilitiesrates over varying periods, through 2068, depending on the Consolidated Balance Sheets.nature of the deferral and the jurisdiction:
| | | | | | | | | | | | | | | | | | | | |
| Regulatory Assets by Source Not Earning a Current Return | | March 31,
2024 | | December 31,
2023 | | Change |
| | (In millions) |
| | | | | | |
| Deferred transmission costs | | $ | 5 | | | $ | 6 | | | $ | (1) | |
| Deferred generation costs | | 334 | | | 432 | | | (98) | |
| Deferred distribution costs | | 128 | | | 68 | | | 60 | |
| | | | | | |
| Storm-related costs | | 638 | | | 602 | | | 36 | |
| | | | | | |
| | | | | | |
| | | | | | |
| Vegetation management costs | | 14 | | | 21 | | | (7) | |
| Other | | 71 | | | 68 | | | 3 | |
| Regulatory Assets Not Earning a Current Return | | $ | 1,190 | | | $ | 1,197 | | | $ | (7) | |
82
CAPITAL RESOURCES AND LIQUIDITY
FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction and other investment expenditures, scheduled debt maturities and interest payments, dividend payments and potential contributions to its pension plan.
FE and its utility and transmission subsidiaries expect their existing sources of liquidity to remain sufficient to meet their respective anticipated obligations. In addition to internal sources to fund liquidity and capital requirements for 20172024 and beyond, FE and its utility and transmission subsidiaries expect to rely on external sources of funds. Short-term cash requirements not met by cash provided from operations are generally satisfied through short-term borrowings. Long-term cash needs may be met through a combinationthe issuance of equity and new long-term debt in each case, subject to market conditionsby FE and other factors. FirstEnergy also expects to issue long-term debt at certain Utilitiesof its subsidiaries to, among other things, fund capital expenditures and other capital-like investments, and refinance short-term and maturing long-term debt, subject to market conditions and other factors. FirstEnergy plansFE may utilize instruments other than senior notes to fund a portion of its long-term cash needs,liquidity and capital requirements, including Regulated Transmission's capital program discussed below, with at least $1.5 billion of equity through 2019, subject to market conditions and other factors.hybrid securities.
FirstEnergy’s unregulated subsidiaries, specifically FES and AE Supply, expect to rely on, in the case of AE Supply, internal sources, the unregulated companies' money pool, and proceeds generated from previously disclosed asset sales, subject to closing, and in the case of FES, its current access to the unregulated companies' money pool and a two-year secured line of credit from FE of up to $500 million, as further described below. Additionally, FES subsidiaries have debt maturities of $515 million in 2018, beginning in the second quarter, $48 million of interest and lease payments in December 2017 and $38 million of interest payments in the first quarter of 2018. Although management is exploring options to improve cash flow as well as continuing with efforts to explore legislative or regulatory solutions, these obligations and their impact to liquidity raise substantial doubt about FES’ ability to meet its obligations as they come due over the next twelve months and, as such, its ability to continue as a going concern. The inability to refinance the debt maturities or the lack of clarity regarding the timing and viability of alternative strategies could cause FES to take one or more of the following actions: (i) restructuring of debt and other financial obligations, (ii) additional borrowings under its secured credit facility with FE, (iii) further asset sales or plant deactivations, and/or (iv) seeking protection under U.S. bankruptcy laws. In the event FES seeks such protection, FENOC will likely seek protection under U.S. bankruptcy laws.
FirstEnergy's strategy is to focus on investments in its regulated operations. The centerpiece of this strategy is the Energizing the Future transmission plan, pursuant to which FirstEnergy plans to invest $4.2 to $5.8 billion in capital investments from 2017 to 2021, and which began as a $4.2 billion investment plan from 2014 through 2017 to upgrade FirstEnergy's transmission system. This program is focused on projects that enhance system performance, physical security and add operating flexibility and capacity starting with the ATSI system and moving east across FirstEnergy's service territory over time. In total, FirstEnergy has identified over $20 billion in transmission investment opportunities across the 24,500 mile transmission system, making this a continuing platform for investment in the years beyond 2021.
In alignment with FirstEnergy’s strategy to invest in its Regulated Transmission and Regulated Distribution segments as it transitions to a fully regulated company, FirstEnergy is also focused on improving themaintaining balance sheet over time consistent with its business profilestrength and maintaining investment grade ratings at its regulated businesses and FE.flexibility. Specifically, at the regulated businesses, regulatory authority has been obtained for various regulated distribution and transmission subsidiaries to issue and/or refinance debt.
Any financing plans by FE or any of its consolidated subsidiaries, including the issuance of equity and debt, and the refinancing of short-term and maturing long-term debt are subject to market conditions and other factors. No assurance can be given that any such issuances, financing or refinancing, as the case may be, will be completed as anticipated or at all. Any delay in the completion of financing plans could require FE or any of its consolidated subsidiaries to utilize short-term borrowing capacity, which could impact available liquidity. In particular, FES may borrow under its secured credit facility with FE, to the extent available, to refinance debt maturities and mandatory purchase obligations, which would impact available liquidity for FES and FE to the extent FE funds any such borrowings through its bank facility and/or cash. In addition, FE and its consolidated subsidiaries expect to continually evaluate any planned financings, which may result in changes from time to time.
On February 2, 2023, FE, along with FET, entered into the FET P&SA II with Brookfield and the Brookfield Guarantors, pursuant to which FE agreed to sell to Brookfield at the closing, and Brookfield agreed to purchase from FE, an incremental 30% equity interest in FET for a purchase price of $3.5 billion. The FET Equity Interest Sale closed on March 25, 2024 and FET continues to be consolidated in FirstEnergy’s financial statements. The purchase price was paid in part by the issuance of two promissory notes at closing having an aggregate principal amount of $1.2 billion with: (i) one promissory note having an aggregate principal amount of $750 million, at an interest rate of 5.75% per annum, with a maturity date of September 25, 2025 and (ii) one promissory note having an aggregate principal amount of $450 million, at an interest rate of 7.75% per annum, with a maturity date of December 31, 2024. Both notes are expected to be repaid in 2024. The remaining $2.3 billion of the purchase price was paid in cash at closing. Brookfield Corporation has guaranteed the full amount of the promissory notes. As a result of the consummation of the transaction, Brookfield’s interest in FET increased from 19.9% to 49.9%, while FE retained the remaining 50.1% ownership interests of FET.
On January 1, 2024, FirstEnergy consolidated the Pennsylvania Companies into FE PA, including OE subsidiary, Penn, making FE PA a new, single operating entity and the successor-in-interest to all assets and liabilities of the Pennsylvania Companies. FE PA, as of January 1, 2024, is FE’s only regulated distribution utility in Pennsylvania encompassing the operations previously conducted individually by the Pennsylvania Companies and FE PA serves an area with a population of approximately 4.5 million and operates under the rate districts of the former Pennsylvania Companies. FirstEnergy is also evaluating the legal, financial, operational and branding benefits of consolidating the Ohio Companies into a single Ohio utility company.
Also on January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo, and PN and ME contributed their respective Class B equity interests of MAIT to FE, which were ultimately contributed to FET in exchange for a special purpose membership interest in FET. So long as FE holds the FET special purpose membership interests, it will receive 100% of any Class B distributions made by MAIT.
Post-pandemic economic conditions have increased supply chain lead times across numerous material categories, with some as much as tripling from pre-pandemic lead times. Several key suppliers have struggled with labor shortages and raw material availability, which along with inflationary pressure that appears to be moderating, have increased costs and decreased the availability of certain materials, equipment and contractors. FirstEnergy has taken steps to mitigate these risks and does not currently expect service disruptions or any material impact on its capital spending plan. However, the situation remains fluid and a prolonged continuation or further increase in supply chain disruptions could have an adverse effect on FirstEnergy’s results of operations, cash flow and financial condition.
In December 2023, FirstEnergy, executed a lift-out transaction with Banner Life Insurance Company and Reinsurance Group of America that transferred approximately $683 million of plan assets and $719 million of plan obligations, associated with approximately 1,900 former FES and FENOC employees, who will assume future and full responsibility to fund and administer their benefit payments. There was no change to the pension benefits for any participants as a result of the transfer. The transaction was funded by pension plan assets and resulted in a pre-tax gain of approximately $36 million, which was included in the fourth quarter 2023 pension mark-to-market charge. FirstEnergy expects that the transaction further de-risked potential volatility with the pension plan assets and liabilities, and FirstEnergy will continue to evaluate other lift-outs in the future based on market and other conditions.
As of September 30, 2017,March 31, 2024, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was primarily due in large part to currently payable long-term debt. Currently payablecurrent portion of long-term debt, as of September 30, 2017, included the following:accounts payable, short-term borrowings and accrued interest, taxes, and compensation and benefits. FirstEnergy believes its cash from operations and available liquidity will be sufficient to meet its current working capital needs. See further discussion on cash from operations below.
|
| | | | |
| Currently Payable Long-Term Debt | | (In millions) |
| Unsecured notes | | $ | 150 |
|
| FMBs | | 575 |
|
| Secured PCRBs | | 141 |
|
| Unsecured PCRBs | | 114 |
|
| Sinking fund requirements | | 61 |
|
| Other notes | | 35 |
|
| | | $ | 1,076 |
|
Short-Term Borrowings / Revolving Credit Facilities
On October 18, 2021, FE, andFET, the Utilities, and FET and its subsidiaries participate in twothe Transmission Companies entered into the 2021 Credit Facilities, which were six separate senior unsecured five-year syndicated revolving credit facilities with JPMorgan Chase Bank, N.A., Mizuho Bank, Ltd. and PNC Bank, National Association that replaced the FE Revolving Facility and the FET Revolving Facility, and provide for aggregate commitments of $5.0$4.5 billion. Under the 2021 Credit Facilities, an aggregate amount of $4.5 billion (Facilities),is available to be borrowed, repaid and reborrowed, subject to each borrower’s respective sublimit under the respective facilities. These credit facilities provide substantial liquidity to support the Regulated businesses, and each of the operating companies within the businesses.
On October 20, 2023, FE and certain of its subsidiaries entered into the amendments to each of the 2021 Credit Facilities to, among other things; (i) amend the FE Revolving Facility to release FET as a borrower and (ii) extend the maturity date of the 2021 Credit Facilities for an additional one-year period, from October 18, 2026 to October 18, 2027. Also, on October 20, 2023, each of FET and KATCo entered into the 2023 Credit Facilities. In connection with PA Consolidation, the Pennsylvania Companies' rights and obligations under their revolving credit facility were assumed by FE PA on January 1, 2024.
Under the FET Revolving Facility, $1.0 billion is available to be borrowed, repaid and reborrowed until October 20, 2028. Under the KATCo Revolving Facility, (i) $150 million is available to be borrowed, repaid and reborrowed until October 20, 2027, (ii) borrowings will mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended; upon KATCo demonstrating to the administrative agent authorization to borrow amounts maturing more than 364 days from the date of borrowing, its borrowings will mature on the latest commitment termination date. KATCo may not draw on the KATCo Credit Facility until the satisfaction of certain conditions, including the availability of first quarter financial statements, which are available through December 6, 2021. expected to be completed during the second quarter of 2024.
The 2021 Credit Facilities and 2023 Credit Facilities are as follows:
•FE, $1.0 billion revolving credit facility;
•FET, $1.0 billion revolving credit facility;
•Ohio Companies, $800 million revolving credit facility;
•FE PA, $950 million revolving credit facility;
•JCP&L, $500 million revolving credit facility;
•MP and PE, $400 million revolving credit facility;
•Transmission Companies, $850 million revolving credit facility; and
•KATCo, $150 million revolving credit facility.
Borrowings under the Utilities2021 Credit Facilities and FET and its subsidiaries2023 Credit Facilities may use borrowings under their Facilitiesbe used for working capital and other general corporate purposes, including intercompany loans and advances by a borrower to any of its subsidiaries.purposes. Generally, borrowings under each of the Facilitiescredit facilities are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Each of the 2021 Credit Facilities containsand 2023 Credit Facilities contain financial covenants requiring each borrower, with the exception of FE, to maintain a consolidated debt to total capitalizationdebt-to-total-capitalization ratio (as defined under each of the 2021 Credit Facilities and 2023 Credit Facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter. FE is required under its 2021 Credit Facility to maintain a consolidated interest coverage ratio of not less than 2.50 times, measured at the end of each fiscal quarter for the last four fiscal quarters beginning with the quarter ending December 31, 2021.
FirstEnergy’s 2021 Credit Facilities and 2023 Credit Facilities bear interest at fluctuating interest rates, primarily based on SOFR, including term SOFR and daily simple SOFR. FirstEnergy has not hedged its interest rate exposure with respect to its floating rate debt. Accordingly, FirstEnergy’s interest expense for any particular period will fluctuate based on SOFR and other variable interest rates. The high interest rate environment has caused the rate and interest expense on borrowings under the various FirstEnergy credit facilities to be significantly higher. Restricted access to capital markets and/or increased borrowing costs could have an adverse effect on FirstEnergy’s results of operations, cash flows, financial condition and liquidity.
FirstEnergy had $500$250 million and $2,675$775 million of outstanding short-term borrowings as of September 30, 2017March 31, 2024 and December 31, 2016,2023, respectively. FirstEnergy’s available liquidity from external sources as of September 30, 2017April 22, 2024, was as follows:
|
| | | | | | | | | | | | |
| Borrower(s) | | Type | | Maturity | | Commitment | | Available Liquidity (3) |
| | | | | | | (In millions) |
FirstEnergy(1) | | Revolving | | December 2021 | | $ | 4,000 |
| | $ | 3,490 |
|
FET(2) | | Revolving | | December 2021 | | 1,000 |
| | 1,000 |
|
| | | | | Subtotal | | $ | 5,000 |
| | $ | 4,490 |
|
| | | | | Cash | | — |
| | 399 |
|
| | | | | Total | | $ | 5,000 |
| | $ | 4,889 |
|
| | | | | | | | | | | | | | | | | | | | | |
| Revolving Credit Facility | | Maturity | | Commitment | | Available Liquidity | |
| | | | | (In millions) | |
| FE | | October 2027 | | $ | 1,000 | | | $ | 717 | | |
| FET | | October 2028 | | 1,000 | | | 750 | | |
| Ohio Companies | | October 2027 | | 800 | | | 300 | | |
| FE PA | | October 2027 | | 950 | | | 950 | | |
| JCP&L | | October 2027 | | 500 | | | 499 | | |
| MP and PE | | October 2027 | | 400 | | | 400 | | |
| Transmission Companies | | October 2027 | | 850 | | | 850 | | |
KATCo(1) | | October 2027 | | 150 | | | 150 | | |
| | Subtotal | | $ | 5,650 | | | $ | 4,616 | | |
| Cash and cash equivalents | | — | | | 110 | | |
| | Total | | $ | 5,650 | | | $ | 4,726 | | |
| |
(1)
| FE and the Utilities. Available liquidity includes impact of $10 million of LOCs issued under various terms. |
| |
(2)
| Includes FET, ATSI, TrAIL and MAIT. |
| |
(3)
| As disclosed in "Long-term Debt Capacity" below, debt capacity is subject to the consolidated debt to total capitalization limits of each borrower as defined under each of the Facilities. As of September 30, 2017, FE and its subsidiaries could issue additional debt of approximately $4.8 billion and remain within the limitations of the financial covenants required by the FE Facility. |
FES had $186 million and $101 million(1) KATCo may not draw on the KATCo Credit Facility until the satisfaction of short-term borrowings ascertain conditions, including the availability of September 30, 2017 and December 31, 2016, respectively. Of such amounts, $102 million and $101 million, respectively, represents a currently outstanding promissory note due April 2, 2018 payablefirst quarter financial statements, which are expected to AE Supply with any additional short-term borrowings representing borrowings underbe completed during the unregulated companies' money pool. In addition to its access to the unregulated companies' money pool, FES' available liquidity assecond quarter of September 30, 2017 was as follows:2024.
|
| | | | | | | | |
| Type | | Commitment | | Available Liquidity |
| | | (In millions) |
| Two-year secured credit facility with FE | | $ | 500 |
| | $ | 500 |
|
| Cash | | — |
| | 2 |
|
| Total | | $ | 500 |
| | $ | 502 |
|
The following table summarizes the borrowing sub-limits for each borrower under the Facilities, the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of September 30, 2017:March 31, 2024:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Individual Borrower | | Regulatory Debt Limitations | | Credit Facility Limitations | | Debt-to-Total-Capitalization Ratio |
| | | (In millions) | | | |
| FE | | | N/A | | | $ | 1,000 | | | | N/A(2) |
ATSI(1) | | | $ | 500 | | | | 350 | | | | 41.1 | % |
CEI(1) | | | 500 | | | | 300 | | | | 48.3 | % |
| FET | | | N/A | | | 1,000 | | | | 64.5 | % |
| FE PA | | | 1,250 | | | | 950 | | | | 51.2 | % |
JCP&L(1) | | | 1,000 | | | | 500 | | | | 37.9 | % |
KATCo(1) | | | 200 | | | | 150 | | | | N/A(3) |
MAIT(1) | | | 400 | | | | 350 | | | | 39.8 | % |
MP(1) | | | 500 | | | | 250 | | | | 54.4 | % |
OE(1) | | | 500 | | | | 300 | | | | 55.9 | % |
PE(1) | | | 150 | | | | 150 | | | | 50.8 | % |
TE(1) | | | 300 | | | | 200 | | | | 48.1 | % |
TrAIL(1) | | | 400 | | | | 150 | | | | 39.2 | % |
| | | | | | | | | |
| | | |
(1) Includes amounts which may be borrowed under the regulated companies’ money pool.
(2) FE is not required to maintain a debt-to-total-capitalization ratio under the 2021 Credit Facilities and 2023 Credit Facilities. However, FE is required to maintain a consolidated interest coverage ratio of not less than 2.50 times, measured at the end of each fiscal quarter for the last four fiscal quarters beginning with the quarter ending December 31, 2021. FE's interest coverage ratio as of March 31, 2024 was 4.21.
(3) KATCo may not draw on the KATCo Credit Facility until the satisfaction of certain conditions, including the availability of first quarter financial statements, which are expected to be completed during the second quarter of 2024.
|
| | | | | | | | | | | | | | | | | |
| Borrower | | FirstEnergy Revolving Credit Facility Sub-Limit | | FET Revolving Credit Facility Sub-Limit | | Regulatory and Other Short-Term Debt Limitations | | |
| | | (In millions) | | |
| FE | | | $ | 4,000 |
| | | $ | — |
| | | $ | — |
| (1) | |
| FET | | | — |
| | | 1,000 |
| | | — |
| (1) | |
| OE | | | 500 |
| | | — |
| | | 500 |
| (2) | |
| CEI | | | 500 |
| | | — |
| | | 500 |
| (2) | |
| TE | | | 500 |
| | | — |
| | | 500 |
| (2) | |
| JCP&L | | | 600 |
| | | — |
| | | 500 |
| (2) | |
| ME | | | 300 |
| | | — |
| | | 500 |
| (2) | |
| PN | | | 300 |
| | | — |
| | | 300 |
| (2) | |
| WP | | | 200 |
| | | — |
| | | 200 |
| (2) | |
| MP | | | 500 |
| | | — |
| | | 500 |
| (2) | |
| PE | | | 150 |
| | | — |
| | | 150 |
| (2) | |
| ATSI | | | — |
| | | 500 |
| | | 500 |
| (2) | |
| Penn | | | 50 |
| | | — |
| | | 100 |
| (2) | |
| TrAIL | | | — |
| | | 400 |
| | | 400 |
| (2) | |
| MAIT | | | — |
| | | 400 |
| | | 400 |
| (2) | |
| |
(2)
| Includes amounts which may be borrowed under the regulated companies' money pool. |
$250 million of the FE Facility and $100 million of the FET Facility, subjectSubject to each borrower’s sub-limit, issublimit, the amounts noted below are available for the issuance of LOCs (subject to borrowings drawn under the 2021 Credit Facilities and 2023 Credit Facilities) expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under each of the 2021 Credit Facilities and 2023 Credit Facilities and against the applicable borrower’s borrowing sub-limit.sublimit. As of March 31, 2024, FirstEnergy had $4 million in outstanding LOCs.
| | | | | | | | |
| Revolving Credit Facility | | LOC Availability as of March 31, 2024 |
| | (In millions) |
| FE | | $ | 100 | |
| FET | | 100 | |
| Ohio Companies | | 150 | |
| FE PA | | 200 | |
| JCP&L | | 100 | |
| MP and PE | | 100 | |
| Transmission Companies | | 200 | |
KATCo(1) | | 35 | |
(1) KATCo may not draw on the KATCo Credit Facility until the satisfaction of certain conditions, including the availability of first quarter financial statements, which are expected to be completed during the second quarter of 2024.
The 2021 Credit Facilities and 2023 Credit Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances in the event of any change in credit ratings of the borrowers. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the facilities is2021 Credit Facilities and the 2023 Credit Facilities are related to the credit ratings of the company borrowing the funds, other than the FET facility, which is based on its subsidiaries' credit ratings.funds. Additionally, borrowings under each of the 2021 Credit Facilities and 2023 Credit Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of $100 million.
As of September 30, 2017,March 31, 2024, the borrowers were in compliance with the applicable debt to total capitalizationinterest coverage and debt-to-total-capitalization ratio covenants as well as in the case of FE, the minimum interest coverage ratio requirement, in each case as defined under the respective2021 Credit Facilities and 2023 Credit Facilities.
Separately, in December 2016, FE and FES entered into a two-year secured credit facility in which FE provides a committed line of credit to FES of up to $500 million and additional credit support of up to $200 million to cover a $169 million surety bond for the benefit of the PA DEP with respect to LBR. As of September 30, 2017, an additional $31 million of surety credit support remains available to FES from FE. So long as FES remains in the unregulated companies' money pool, the $500 million secured line of credit provides FES the needed liquidity in order for FES to satisfy its nuclear support obligation to NG in the event of extraordinary circumstances with respect to its nuclear facilities. The new facility matures on December 31, 2018, and is secured by FMBs issued by FG ($250 million) and NG ($450 million). Additionally, FES maintains access to the unregulated companies' money pool and continues to conduct its ordinary course business under that money pool in lieu of borrowing under the new facility.
Term Loans
FE has a $1.2 billion variable rate syndicated term loan credit agreement with a maturity date of December 6, 2021. The initial borrowing under the term loan, which took the form of a Eurodollar rate advance, may be converted from time to time, in whole or in part, to alternate base rate advances or other Eurodollar rate advances. The proceeds from this term loan refinanced terminated term loan facilities. Additionally, in February 2017, FE entered into two separate $125 million three-year term loan credit agreements with two banks providing for variable rate term loans with a maturity date of February 16, 2020. The proceeds from these term loans reduced borrowings under the FE Facility. Each of the term loans contains covenants and other terms and conditions substantially similar to those of the FE Facility described above, including the same consolidated debt to total capitalization ratio and interest coverage requirements.
As of September 30, 2017, FE was in compliance with the applicable consolidated debt to total capitalization ratio covenants as well as the interest coverage ratio requirement, as defined under these term loans.
FirstEnergy Money Pools
FirstEnergy’s utility operating subsidiary companies also have the ability to borrow from each other and the holding companyFE to meet their short-term working capital requirements. Similar but separate arrangements exist among FirstEnergy’s unregulated companies.companies with AE Supply, FE, FET, FEV and certain other unregulated subsidiaries. FESC administers these money pools and tracks surplus funds of FirstEnergyFE and the respective regulated and unregulated subsidiaries, as the case may be, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through suchthe pool. The averagehigh interest rate forenvironment has caused the rate and interest expense on borrowings in the first nine months of 2017 was 1.51% per annum for the regulated companies’ money pool and 2.44% per annum for the unregulated companies’ money pool.
As discussed above, FES currently maintains access to the unregulated companies' money pool in lieu of borrowing under its $500 million secured line of credit. FE expects to provide ongoing access to FES to the unregulated companies' money pool to allow time to evaluate its strategic alternatives including, among other things, the results of legislative and regulatory solutions, including the NOPR released by the Secretary of Energy and action by FERC. As of September 30, 2017, FES, and its subsidiaries, and FENOC had $67 million of net borrowings in the aggregate under the unregulated companies' money pool. Cash flow from operations at FES is expectedvarious FirstEnergy credit facilities to be sufficient to fund capital expenditures, nuclear fuel purchases, and repay money pool borrowings through March 2018.significantly higher.
| | | | | | | | | | | | | | | | | | | | | | | |
| Average Interest Rates | Regulated Companies’ Money Pool | | Unregulated Companies’ Money Pool |
| 2024 | | 2023 | | 2024 | | 2023 |
| For the Three Months Ended March 31, | 6.32 | % | | 5.84 | % | | 7.08 | % | | 5.19 | % |
| | | | | | | |
Long-Term Debt Capacity
FE'sFE’s and its subsidiaries'subsidiaries’ access to capital markets and costs of financing are influenced by the credit ratings of their securities. The following table displays FE’s and its subsidiaries’ credit ratings as of September 30, 2017:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Corporate Credit Rating | | Senior Secured | | Senior Unsecured | | Outlook/Credit/Watch(1) |
| Issuer | | S&P | | Moody’s | | Fitch | | S&P | | Moody’s | | Fitch | | S&P | | Moody’s | | Fitch | | S&P | | Moody’s | | Fitch |
| FE | | BBB | | Senior SecuredBaa3 | | BBB- | | Senior Unsecured— | | — | | — | | BBB- | | Baa3 | | BBB- | | P | | S | | S |
| Issuer
| Distribution: | | | | | | | | | | | | | | | | | | | | | | | | |
| CEI | | S&PBBB | | Baa3 | | Moody’sBBB | | A- | | FitchBaa1 | | A- | | S&PBBB | | Baa3 | | Moody’sBBB+ | | P | | FitchS | | S |
FEOE | | BBB+ | | —A3 | | BBB | | —A | | A1 | | —A- | | BBB+ | | BB+A3 | | BBB+ | | Baa3P | | S | | BBB-S |
FESTE | | BBB+ | | CCC+Baa2 | | BBB | | B1A | | A3 | | —A- | | — | | CCC-— | | — | | Caa1P | | S | | CS |
AE SupplyFE PA | | BBB+ | | BBA3 | | BBB | | —A | | A1 | | BBA- | | BBB+ | | BB-A3 | | BBB+ | | B1P | | S | | BB-S |
| AGC
| Integrated: | | | | | | | | | | | | | | | | | | | | | | | | |
| JCP&L | | —BBB | | A3 | | —BBB | | — | | — | | — | | BB-BBB | | A3 | | Baa3BBB+ | | P | | BBS | | S |
ATSIMP | | BBB | | —Baa2 | | BBB | | —A- | | A3 | | —A- | | BBB | | BBB-Baa2 | | — | | Baa1S | | S | | BBB+S |
CEIAGC | | BBB- | | BBB+Baa2 | | BBB | | Baa1— | | — | | A-— | | — | | BBB-— | | — | | Baa3S | | S | | BBB+S |
FETPE | | BBB | | —Baa2 | | BBB | | —A- | | A3 | | —A- | | — | | BB+— | | — | | Baa2S | | S | | BBB-S |
| JCP&L
| Transmission: | | | | | | | | | | | | | | | | | | | | | | | | |
| FET | | —BBB | | Baa2 | | —BBB- | | — | | — | | — | | BBB- | | Baa2 | | Baa2BBB- | | P | | BBBS | | S |
MEATSI | | BBB+ | | —A3 | | BBB | | — | | — | | — | | BBB+ | | BBB-A3 | | BBB+ | | A3P | | S | | BBB+S |
| MAIT | | BBB+ | | —A3 | | BBB | | — | | — | | — | | BBB+ | | BBB-A3 | | BBB+ | | Baa1P | | S | | —S |
MPTrAIL | | BBB+ | | BBB+A3 | | BBB | | A3— | | — | | BBB+— | | BBB+ | | —A3 | | BBB+ | | —P | | S | | —S |
OEKATCo | | — | | BBB+A3 | | BBB | | A2— | | — | | A-— | | — | | BBB-— | | — | | Baa1— | | S | | BBB+
PN | | — | | — | | — | | BBB- | | Baa1 | | BBB+ |
Penn | | — | | A2 | | A- | | — | | — | | — |
PE | | — | | — | | — | | — | | — | | — |
TE | | BBB+ | | Baa1 | | A- | | — | | — | | — |
TrAIL | | — | | — | | — | | BBB- | | A3 | | BBB+ |
WP
| | BBB+ | | A1 | | A- | | — | | — | | —S |
(1) S = Stable, P = Positive
On March 28, 2024, Moody’s upgraded FE’s corporate credit ratings from Ba1 to Baa3.
On April 23, 2024, S&P issued one-notch upgrades of FE and several subsidiaries.
The applicable undrawn and drawn margin on the 2021 Credit Facilities and 2023 Credit Facilities are subject to ratings-based pricing grids. The applicable fee paid on the undrawn commitments under the 2021 Credit Facilities and 2023 Credit Facilities are based on each borrower’s senior unsecured non-credit enhanced debt ratings as determined by S&P and Moody’s. The fees paid on actual borrowings are determined based on each borrower’s senior unsecured non-credit enhanced debt ratings as determined by S&P and Moody’s.
The interest rates payable on approximately $2.1 billion in FE’s senior unsecured notes are subject to adjustments from time to time if the ratings on the notes from any one or more of S&P, Moody’s and Fitch decreases to a rating set forth in the applicable governing documents. Generally, a one-notch downgrade by the applicable rating agency may result in a 25 basis point coupon rate increase beginning at BB, Ba1, and BB+ for S&P, Moody’s and Fitch, respectively, to the extent such rating is applicable to the series of outstanding senior unsecured notes, during the next interest period, subject to an aggregate cap of 2% from issuance interest rate.
Debt capacity is subject to the consolidated debt to total capitalization limitsinterest coverage ratio in the Facilities previously discussed.2021 Credit Facilities. As of September 30, 2017, FE and its subsidiariesMarch 31, 2024, FirstEnergy could issue additional debtincur approximately $800 million of approximately $4.8 billionincremental interest expense or incur a $2.6$2.0 billion reduction to equity,the consolidated interest coverage earnings numerator, as defined under the covenant, and FE would remain within the limitations of the financial covenants required bycovenant requirements of the FE Facility.2021 Credit Facilities.
Cash Requirements and Commitments
FirstEnergy has certain obligations and commitments to make future payments under contracts. For an in-depth discussion of FirstEnergy’s cash requirements and commitments, see “Capital Resources and Liquidity - Cash Requirements and Commitments" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" within FirstEnergy’s Form 10-K for the year ended December 31, 2023 (filed on February 13, 2024).
Changes in Cash Position
As of September 30, 2017,March 31, 2024, FirstEnergy had $399$888 million of cash and cash equivalents and $27 million of restricted cash as compared to $199$137 million of cash and cash equivalents and $42 million of restricted cash as of December 31, 2016. As of September 30, 2017 and December 31, 2016, FirstEnergy had approximately $36 million and $61 million, respectively, of restricted cash included in Other current assets2023, on the Consolidated Balance Sheets.
The following table summarizes the major classes of cash flow items:
86
| | | | | | | | | | | | | | |
| | For the Three Months Ended March 31, |
| (In millions) | | 2024 | | 2023 |
| | | | |
| Net cash used for operating activities | | $ | (40) | | | $ | (112) | |
| Net cash used for investing activities | | (870) | | | (716) | |
| Net cash provided from financing activities | | 1,646 | | | 828 | |
| Net change in cash, cash equivalents, and restricted cash | | 736 | | | — | |
| | | | |
| Cash, cash equivalents, and restricted cash at beginning of period | | 179 | | | 206 | |
| Cash, cash equivalents, and restricted cash at end of period | | $ | 915 | | | $ | 206 | |
Cash Flows From Operating Activities
FirstEnergy'sFirstEnergy’s most significant sources of cash are derived from electric service provided by its utility operating subsidiaries and the sales of energy and related products and services by its unregulated competitive subsidiaries. The most significant use of cash from operating activities is buying electricity to buy electricity in the wholesale marketserve non-shopping customers, return of cash collateral associated with certain generation suppliers that serve shopping customers, pension contributions and paypaying fuel suppliers, employees, tax authorities, lenders and others for a wide range of materialmaterials and services.
Net cash providedCash used for operating activities was $40 million and $112 million in the first three months of 2024 and 2023, respectively. Cash flows from operating activities was $2,762 million during the first nine months of 2017 compared with $2,592 million provided from operating activities during the first nine months of 2016. Key changes in cash flows from operationswere a net outflow in the first nine monthsquarter of 2017, compared2024, primarily due to working capital, including prepaid and accrued tax payments associated with Pennsylvania gross receipts tax payments and timing of property tax payments. Compared to the same period of 2016, primarily were as follows:
2023, the absence of $297 million contribution to the qualified pension plan in 2016;
higher distribution services retail receipts reflecting implementation of approved rates in Ohio, Pennsylvania and New Jersey, as further described above; partially offset by,
lower receipts from a decrease in capacity revenue and retail sales at CES.
Cash Flows From Financing Activities
In the first nine months of 2017, cash used for financingoperating activities is primarily due to:
•Lower payments, primarily on generation energy purchases for certain customers, net of related customer receivable receipts;
•The decrease in return of cash collateral to certain generation suppliers that serve shopping customers that was previously received as a result of changes in power prices;
•Higher net transmission revenue collection based on the timing of formula rate collections; and
•Higher returns from distribution, integrated, and transmission capital investments;
The decrease in cash used for operating activities was $381 million compared to $304 million of cash providedpartially offset by:
•Lower dividend distribution received by FEV from financing activities during the first nine months of 2016. The following table summarizes new debt financing, redemptions, repayments, short-term borrowingsits equity investments in Global Holding; and dividends:
•Higher payments associated with Pennsylvania gross receipts taxes.
|
| | | | | | | | |
| | | For the Nine Months Ended September 30 |
| Securities Issued or Redeemed / Repaid | | 2017 | | 2016 |
| | | (In millions) |
| New Issues | | |
| | |
|
| Term Loan | | $ | 250 |
| | $ | — |
|
| PCRBs | | — |
| | 471 |
|
| Unsecured notes | | 3,450 |
| | — |
|
| FMBs | | 350 |
| | 50 |
|
| | | $ | 4,050 |
| | $ | 521 |
|
| | | | | |
| Redemptions / Repayments | | |
| | |
|
| PCRBs | | (158 | ) | | (483 | ) |
| Unsecured notes | | (1,330 | ) | | (300 | ) |
| FMBs | | (150 | ) | | (145 | ) |
| Senior secured notes | | (73 | ) | | (89 | ) |
| | | $ | (1,711 | ) | | $ | (1,017 | ) |
| | | | | |
| Short-term borrowings (repayments), net | | $ | (2,175 | ) | | $ | 1,275 |
|
| | | | | |
| Common stock dividend payments | | $ | (478 | ) | | $ | (458 | ) |
On March 1, 2017, FG retired $28 million of PCRBs at maturity.
On March 15, 2017, MP retired $150 million of FMBs at maturity.
On May 16, 2017, MP issued $250 million of 3.55% FMBs due 2027. Proceeds received from the issuance of the FMBs were used: (i) to repay short-term borrowings, (ii) to fund capital expenditures and (iii) for working capital needs and other general business purposes.
On June 1, 2017, FG repurchased approximately $130 million of PCRBs, which were subject to a mandatory put on such date. FG is currently holding these PCRBs for remarketing subject to future market and other conditions.
On June 21, 2017, FE issued the aggregate principal amount of $3 billion of its senior notes in three series: $500 million of 2.85% notes due 2022; $1.5 billion of 3.90% notes due 2027; and $1 billion of 4.85% notes due 2047. Proceeds from the issuance of the notes were used: (i) to redeem $650 million of FE's 2.75% notes due in 2018 on July 25, 2017 and (ii) for general corporate purposes, including the repayment of short-term borrowings under the FE Facility.
On August 31, 2017, ATSI issued $150 million of 3.66% senior unsecured notes maturing in 2032. Proceeds from the issuance of the notes were used: (i) to repay short-term borrowings, (ii) to fund capital expenditures and (iii) for working capital needs and other general business purposes.
On September 8, 2017, PN issued $300 million of 3.25% senior notes maturing in 2028. Proceeds from the issuance of the notes were used: (i) to repay short-term borrowings and (ii) for working capital needs and other general business purposes.
On September 15, 2017, WP issued $100 million of 4.09% FMBs due 2047. Proceeds from the issuance of the FMBs were used: (i) to repay short-term borrowings, (ii) to fund capital expenditures and (iii) for other general business purposes.
On October 5, 2017, CEI issued $350 million of 3.50% senior notes maturing in 2028. Proceeds from the issuance of the notes were used: (i) to refinance existing indebtedness, including 7.88% FMBs due November 1, 2017 and borrowings outstanding under FirstEnergy's regulated utility money pool and the Facility, (ii) to fund capital expenditures and (iii) for working capital and other general business purposes.
Cash Flows From Investing Activities
Cash used for investing activities in the first ninethree months of 20172024 principally represented cash used for property additions.capital investments. The following table summarizes investing activities for the first ninethree months of 20172024 and the comparable period of 2016:2023:
|
| | | | | | | | | | | | |
| | | For the Nine Months Ended September 30 | | |
| Cash Used for Investing Activities | | 2017 | | 2016 | | Increase (Decrease) |
| | | (In millions) |
| Property Additions: | | | | | | |
| Regulated Distribution | | $ | 854 |
| | $ | 809 |
| | $ | 45 |
|
| Regulated Transmission | | 717 |
| | 824 |
| | (107 | ) |
| Competitive Energy Services | | 233 |
| | 492 |
| | (259 | ) |
| Corporate / Other | | 43 |
| | 31 |
| | 12 |
|
| Nuclear fuel | | 156 |
| | 195 |
| | (39 | ) |
| Investments | | 72 |
| | 76 |
| | (4 | ) |
| Asset removal costs | | 130 |
| | 101 |
| | 29 |
|
| Other | | (24 | ) | | (52 | ) | | 28 |
|
| | | $ | 2,181 |
| | $ | 2,476 |
| | $ | (295 | ) |
| | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended March 31, |
| Cash Used for Investing Activities | | 2024 | | 2023 | | Increase (Decrease) |
| | (In millions) |
| Capital investments: | | | | | | |
| Distribution Segment | | $ | 215 | | | $ | 193 | | | $ | 22 | |
| Integrated Segment | | 313 | | | 237 | | | 76 | |
| Stand-Alone Transmission Segment | | 258 | | | 212 | | | 46 | |
| Corporate / Other Segment | | 4 | | | 7 | | | (3) | |
| | | | | | |
| | | | | | |
| | | | | | |
| Asset removal costs | | 78 | | | 60 | | | 18 | |
| Other | | 2 | | | 7 | | | (5) | |
| | $ | 870 | | | $ | 716 | | | $ | 154 | |
| | | | | | |
Cash used for investing activities for the first ninethree months of 2017 decreased $2952024 increased $154 million, compared to the same period of 2016,2023, primarily due to lower property additions.capital investments.
Cash Flows From Financing Activities
In the first three months of 2024 and 2023, cash provided from financing activities was $1,646 million and $828 million, respectively. The decline in property additions werefollowing table summarizes financing activities for the first three months of 2024 and 2023:
| | | | | | | | | | | | | | |
| | For the Three Months Ended March 31, |
| Financing Activities | | 2024 | | 2023 |
| | | (In millions) |
| | | | |
| New Issues: | | | | |
| Unsecured notes | | $ | 150 | | | $ | 900 | |
| | | | |
| | | | |
| FMBs | | — | | | 50 | |
| | | | |
| | $ | 150 | | | $ | 950 | |
| | | | |
| Redemptions / Repayments: | | | | |
| | | | |
| Unsecured notes | | $ | — | | | $ | (300) | |
| | | | |
| | | | |
| Senior secured notes | | (23) | | | (21) | |
| | | $ | (23) | | | $ | (321) | |
| | | | |
| Proceeds from FET Equity Interest Sale | | $ | 2,300 | | | $ | — | |
| Noncontrolling interest cash distributions | | (8) | | | (17) | |
| | | | |
| | | | |
| Short-term borrowings, net | | (525) | | | 450 | |
| | | | |
| | | | |
| Common stock dividend payments | | (235) | | | (223) | |
| Other | | (13) | | | (11) | |
| | $ | 1,646 | | | $ | 828 | |
FirstEnergy had the following issuances and redemptions during the three months ended March 31, 2024:
| | | | | | | | | | | | | | | | | | | | |
| Company | Type | Issuance Date | Interest Rate | Maturity | Amount (In millions) | Description |
|
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| Issuance |
| ATSI | Senior Unsecured Note | March, 2024 | 5.63% | 2034 | $150 | Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes. |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
In March 2024, notice of redemption was provided for all remaining $463 million of FE’s 7.375% Notes, due 2031, which was completed on April 15, 2024, with a make-whole premium of approximately $80 million. Due to the following:redemption, the $463 million remaining notes are included within currently payable long-term debt on the Consolidated Balance Sheets as of March 31, 2024.
a decrease
On April 1, 2024, JCP&L redeemed its $500 million 4.70% unsecured notes that became due.
On April 15, 2024, MP redeemed its $400 million 4.10% FMBs that became due.
On April 18, 2024, MAIT agreed to sell $250 million of $259 millionnew 5.94% Unsecured Notes due May 1, 2034. The sale is expected to settle on May 2, 2024. Proceeds are expected to be used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
FE or its affiliates may, from time to time, seek to retire or purchase outstanding debt through open-market purchases, privately negotiated transactions or otherwise. Such repurchases, if any, will be upon such terms and at CES, resulting from lower capital investments associated with outages, MATS compliancesuch prices as FE or its affiliates may determine, and the Mansfield dewatering facility,will depend on prevailing market conditions, liquidity requirements, contractual restrictions and other factors.
a decrease of $107 million at Regulated Transmission due to timing of capital investments associated with its Energizing the Future investment program; partially offset by,
an increase of $45 million at Regulated Distribution due to an increase in storm restoration work and smart meter investments in Pennsylvania.
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,LOCs, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. The maximum potential amount of future payments FirstEnergyFE and its subsidiaries could be required to make under these guarantees as of September 30, 2017,March 31, 2024, was approximately $3.3 billion,$820 million, as summarized below:
|
| | | | |
| Guarantees and Other Assurances | | Maximum Exposure |
| | | (In millions) |
| FE's Guarantees on Behalf of its Subsidiaries | | |
|
Energy and Energy-Related Contracts(1) | | $ | 5 |
|
Deferred compensation arrangements(2) | | 568 |
|
Fuel Related(3) | | 72 |
|
Other(4) | | 4 |
|
| | | 649 |
|
| Subsidiaries’ Guarantees | | |
Energy and Energy-Related Contracts(5) | | 265 |
|
| FES’ guarantee of FG’s sale and leaseback obligations | | 1,600 |
|
| | | 1,865 |
|
| | | |
| FE's Guarantees on Behalf of Business Ventures | | |
| Global Holding facility | | 300 |
|
| | | |
| Other Assurances | | |
Surety Bonds - Wholly Owned Subsidiaries(6) | | 177 |
|
| Surety Bonds | | 212 |
|
| Sale leaseback indemnity | | 58 |
|
LOCs(7) | | 10 |
|
| | | 457 |
|
| Total Guarantees and Other Assurances | | $ | 3,271 |
|
| | | | | | | | |
| Guarantees and Other Assurances | | Maximum Exposure |
(1)
| | Issued for open-ended terms, with a 10-day termination right by FirstEnergy.
| (In millions) |
| (2)
| CES-related portion is $143 million, including $56 million and $87 million at FES and FENOC, respectively. |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
(3)FE’s Guarantees on Behalf of its Consolidated Subsidiaries(1)
| | FE is the guarantor of the remaining payments due to CSX/BNSF in connection with the definitive settlement |
| Deferred compensation arrangements | | $ | 430 | |
| Vehicle leases | | 75 | |
| | |
| Other | | 15 | |
| | 520 | |
| | |
FE’s Guarantees on a transportation agreement. |
| Other Assurances | | |
(4)Surety Bonds(2)
| | Includes guarantees of $1 million for railcar leases182 | |
| | |
| Deferred compensation arrangements | | 114 | |
| LOCs | | 4 | |
| | 300 | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
Total Guarantees and $3 million for various leases.Other Assurances | | $ | 820 | |
| |
(5)
| Includes energy and energy-related contracts associated with FES. |
| |
(6)
| FE provides credit support for $169 million of FG surety bonds for the benefit of the PA DEP with respect to LBR. As of September 30, 2017, an additional $31 million of surety credit support remains available to FES from FE under this facility. |
| |
(7)
| Includes $10 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facilities. |
FES' debt obligations are generally guaranteed(1) During the third quarter of 2023, FE was required by PJM to issue a guarantee to cover non-performance until FE PA is able to provide audited financial statements to PJM, which is expected to occur in early 2025. The guarantee is expected to be immaterial to FE.
(2) During the second quarter of 2023, FE was released from its subsidiaries, FG and NG, and FES guarantees$169 million surety bond to the debt obligationsPennsylvania Department of each of FG and NG. Accordingly, present and future holders of indebtedness of FES, FG and NG would have claims against each of FES, FG and NG, regardless of whether their primary obligor is FES, FG or NG.Environmental Protection related to the Little Blue Run Disposal Impoundment.
Collateral and Contingent-Related Features
In the normal course of business, FE and its subsidiaries routinelymay 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'sFE’s or its subsidiaries'subsidiaries’ credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental
As of March 31, 2024, $119 million of net cash collateral requirement allows for the offsettinghas been posted by FE or its subsidiaries and is included in “Prepaid taxes and other current assets” on FirstEnergy’s Consolidated Balance Sheets. FE or its subsidiaries are holding $33 million of assetsnet cash collateral as of March 31, 2024, from certain generation suppliers, and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements.such amount is included in “Other current liabilities” on FirstEnergy’s Consolidated Balance Sheets.
Bilateral agreements and derivative instruments entered into by FE and its subsidiaries have margining provisions that require posting of collateral. Based on CES' power portfolio exposure as of September 30, 2017, FES has posted collateral of $128 million and AE Supply has posted collateral of $2 million. The Regulated Distribution Segment has posted collateral of $3 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 September 30, 2017.March 31, 2024:
|
| | | | | | | | | | | | | | | | | | | | |
| Potential Collateral Obligations | | FES | | AE Supply | | Regulated | | FE Corp | | Total |
| | | | (In millions) |
| Contractual Obligations for Additional Collateral | | | | | | | | | | |
| At Current Credit Rating | | $ | 6 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 8 |
|
| Upon Further Downgrade | | — |
| | — |
| | 42 |
| | — |
| | 42 |
|
Surety Bonds (Collateralized Amount)(1) | | 48 |
| | 24 |
| | 105 |
| | 185 |
| | 362 |
|
| Total Exposure from Contractual Obligations | | $ | 54 |
| | $ | 26 |
| | $ | 147 |
| | $ | 185 |
| | $ | 412 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Potential Collateral Obligations | | | | | | Utilities and Transmission Companies | | FE | | Total |
| | | (In millions) |
| Contractual obligations for additional collateral | | | | | | | | | | |
| | | | | | | | | | |
| Upon further downgrade | | | | | | $ | 63 | | | $ | — | | | $ | 63 | |
| | | | | | | | | | |
Surety bonds (collateralized amount)(1) | | | | | | 87 | | | 79 | | | 166 | |
| Total Exposure from Contractual Obligations | | | | | | $ | 150 | | | $ | 79 | | | $ | 229 | |
(1)Surety Bondsbonds are not tied to a credit rating. Surety Bonds'bonds’ impact assumes maximum contractual obligations, (typicalwhich is ordinarily 100% of the face amount of the surety bond except with respect to $39 million of surety bond obligations for which the collateral obligation is capped at 60% of the face amount, and typical obligations require 30 days to cure). FE provides credit support for $169 million of FG surety bonds for the benefit of the PA DEP with respect to LBR.cure.
Excluded from the preceding table are the potential collateral obligations due to affiliate transactions between the Regulated Distribution segment and CES segment. As of September 30, 2017, FES has $2 million of collateral posted with its affiliates.
Other Commitments and Contingencies
FE is a guarantor under a syndicated senior secured term loan facility due March 3, 2020, under which Global Holding borrowed $300 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 guaranties 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.
OFF-BALANCE SHEET ARRANGEMENTS
FES has obligations that are not included on its Consolidated Balance Sheet related to the 2007 Bruce Mansfield Unit 1 sale and leaseback arrangements (expiring in 2040), which are satisfied through operating lease payments. The total present value of these sale and leaseback operating lease commitments, net of trust investments, was $873 million as of September 30, 2017. From time to time FirstEnergy and FES enter into discussions with certain parties to the arrangements regarding acquisition of owner participant and other interests. However, FirstEnergy cannot provide assurance that any such acquisitions will occur on satisfactory terms or at all. As of September 30, 2017, FES' leasehold interest was 93.83% of Bruce Mansfield Unit 1.
On June 1, 2017, NG completed the purchase of the 2.60% lessor equity interests of the remaining non-affiliated leasehold interests in Beaver Valley Unit 2 for $38 million. In addition, the Beaver Valley Unit 2 leases expired in accordance with their terms on June 1, 2017, resulting in NG being the sole owner of Beaver Valley Unit 2.
MARKET RISK INFORMATION
FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Enterprise Risk PolicyManagement Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.FirstEnergy.
Commodity Price Risk
FirstEnergy is exposedhas limited exposure to financial risks resulting from fluctuating commodity prices, includingsuch as prices for electricity, natural gas, coal and energy transmission. FirstEnergy'sFirstEnergy’s Risk Management Department and Enterprise Risk Management Committee isare responsible for promoting the effective design and implementation of sound risk management programs and overseesoverseeing compliance with corporate risk management policies and established risk management practice. FirstEnergy uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
The valuation of derivative contracts is based on observable market informationinformation. As of March 31, 2024, FirstEnergy has a net liability of $1 million in non-hedge derivative contracts that are related to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of
future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 7, "Fair Value Measurements,"FTRs at certain of the CombinedUtilities. FTRs are subject to regulatory accounting and do not impact earnings. See Note 6, “Fair Value Measurements,” of the Notes to Consolidated Financial Statements). Sources of informationStatements for the valuation of net commodity derivative assets and liabilities as of September 30, 2017 are summarized by year in the following table:additional details on FirstEnergy’s FTRs.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Source of Information- Fair Value by Contract Year | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | Thereafter | | Total |
| | | (In millions) |
Other external sources(1) | | $ | — |
| | $ | (19 | ) | | $ | (36 | ) | | $ | (12 | ) | | $ | — |
| | $ | — |
| | $ | (67 | ) |
| Prices based on models | | (2 | ) | | 3 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
|
Total(2) | | $ | (2 | ) | | $ | (16 | ) | | $ | (36 | ) | | $ | (12 | ) | | $ | — |
| | $ | — |
| | $ | (66 | ) |
| |
(1)
| Primarily represents contracts based on broker and ICE quotes. |
| |
(2)
| Includes $(92) million in non-hedge derivative contracts that are primarily related to NUG contracts at certain of the Utilities. NUG contracts are subject to regulatory accounting and do not impact earnings. |
FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of September 30, 2017, not subject to regulatory accounting, an increase in commodity prices of 10% would decrease net income by approximately $6 million during the next twelve months.
Equity Price Risk
As of September 30, 2017,March 31, 2024, the FirstEnergy pension plan assets were allocated approximately as follows: 41%30% in equity securities, 36%22% in fixed income securities, 9%7% in absolute return strategies, 9%alternatives, 11% in real estate, 1%19% in private debt/equity, 5% in derivatives and 4%6% in cash and short-term securities. A decline inAs discussed above, FirstEnergy made a $750 million voluntary cash contribution to the value ofqualified pension plan assets could result in additional funding requirements. FirstEnergy’s funding policy ison May 12, 2023. FirstEnergy does not currently expect to have a required contribution to the pension plan until 2028, which based on actuarial computations usingvarious assumptions, including an expected rate of return on assets of 8.0%, is expected to be approximately $260 million. However, FirstEnergy may elect to contribute to the projected unit credit method. During the nine months ended September 30, 2017, FirstEnergy made no contributions to its qualified pension plan.plan voluntarily.
As of March 31, 2024, FirstEnergy’s OPEB plan assets were allocated approximately as follows: 51% in equity securities, 43% in fixed income securities and 6% in cash and short-term securities. See Note 3, "Pension4, “Pension and Other PostemploymentPost-Employment Benefits,"” of the Combined Notes to Consolidated Financial Statements for additional details on FirstEnergy'sFirstEnergy’s pension plans and OPEB. Through September 30, 2017, FirstEnergy's pensionOPEB plans.
In the three months ended March 31, 2024, FirstEnergy’s OPEB plan assets earnedhave gained approximately 12.5%4.9% as compared to an annualannualized expected return on plan assets of 7.5%7.0%.
As of September 30, 2017, FirstEnergy's OPEB plans were invested in fixed income and equity securities. Through September 30, 2017 FirstEnergy's OPEB plans In the three months ended March 31, 2024, FirstEnergy’s pension plan assets have earnedlost approximately 8.6%0.1% as compared to an annualannualized expected return on plan assets of 7.5%8.0%.
NDT funds have been established to satisfy NG’s and other FirstEnergy subsidiaries' nuclear decommissioning obligations. As of September 30, 2017, approximately 56% of the funds were invested in fixed income securities, 40% of the funds were invested in equity securities and 4% were invested in short-term investments, with limitations related to concentration and investment grade ratings. The investments are carried at their market values of approximately $1,490 million, $1,045 million and $112 million for fixed income securities, equity securities and short-term investments, respectively, as of September 30, 2017, excluding $(15) million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $105 million reduction in fair value as of September 30, 2017. Certain FirstEnergy subsidiaries recognize in earnings the unrealized losses on AFS securities held in its NDT as OTTI. A decline in the value of FirstEnergy’s NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During the nine months ended September 30, 2017, FirstEnergy made no contributions to the NDTs.
Interest Rate Risk
FirstEnergy recognizes net actuarial gains or losses for its pension and OPEB plans in the fourth quarter of each fiscal year.year and whenever a plan is determined to qualify for a remeasurement. A primary factor contributing to these actuarial gains and losses are changes in the discount rates used to value pension and OPEB obligations as of the measurement date of December 31 and the difference between expected and actual returns on the plans'plans’ assets. FirstEnergy would anticipate a pre-tax mark-to-market loss (net
The remaining components of amounts capitalized) to be in the range of approximately $40 million to $260 million assuming a discount rate of approximately 4.00% to 3.75% for the pension plans and 3.75% to 3.50% for the OPEB plans, respectively, and a return on the pension and OPEB plans'expense, primarily service costs, interest cost on obligations, expected return on plan assets and amortization of 12.5%prior service costs, are set at the beginning of the calendar year (unless a remeasurement is triggered) and 8.6%,are recorded on a monthly basis. Changes in asset performance and discount rates will not impact these pension costs for 2024, unless an additional remeasurement were to be triggered during the year, however, future years could be impacted by changes in the market.
FirstEnergy utilizes a spot rate approach in the estimation of the components of benefit cost by applying specific spot rates along the full yield curve to the relevant projected cash flows. As of March 31, 2024, the spot rate was 5.28% and 5.22% for pension and OPEB obligations, respectively, as compared to 5.05% and 4.97% as of December 31, 2023, respectively.
The final discount rate and return or loss on plan assets as of the year-end remeasurement date is difficult to predict based on actual investment performance through September 30, 2017.the currently volatile equity markets and interest rate environment. As a result, FirstEnergy is unable to determine or meaningfully project the mark-to-market adjustment, or estimate a reasonable range of adjustment, that will be recorded as of December 31, 2024.
FirstEnergy’s 2021 Credit Facilities and 2023 Credit Facilities bear interest at fluctuating interest rates, primarily based on SOFR, including term SOFR and daily simple SOFR. FirstEnergy has not hedged its interest rate exposure with respect to its floating rate debt. Accordingly, FirstEnergy’s interest expense for any particular period will fluctuate based on SOFR and other variable interest rates. The high interest rate environment has caused the rate and interest expense on borrowings under the various FirstEnergy credit facilities to be significantly higher.
Economic Conditions
Post-pandemic economic conditions have increased supply chain lead times across numerous material categories, with some as much as tripling from pre-pandemic lead times. Several key suppliers have struggled with labor shortages and raw material availability, which along with inflationary pressure that appears to be moderating, have increased costs and decreased the availability of certain materials, equipment and contractors. FirstEnergy has taken steps to mitigate these risks and does not currently expect service disruptions or any material impact on its capital spending plan. However, the situation remains fluid and a prolonged continuation or further increase in supply chain disruptions could have an adverse effect on FirstEnergy’s results of operations, cash flow and financial condition.
CREDIT RISK
Credit risk is defined as the risk that FirstEnergy would incur a counterparty toloss as a transaction will be unable to fulfill itsresult of nonperformance by counterparties of their contractual obligations. FirstEnergy evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. FirstEnergy may impose specific collateral requirements and use standardized agreements that facilitate the netting of cash flows. FirstEnergy monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.
Wholesale Credit Risk
FirstEnergy measures wholesale credit risk as the replacement cost for derivatives in power, natural gas, coal and emission allowances, adjusted for amounts owed to, or due from, counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, where FirstEnergy has a legally enforceable right of offset. FirstEnergy monitors and manages the credit risk of wholesale marketing, risk management and energy transacting operations throughmaintains credit policies and procedures whichwith respect to counterparty credit (including a requirement that counterparties maintain specified credit ratings) and requires other assurances in the form of credit support or collateral in certain circumstance in order to limit counterparty credit risk. FirstEnergy has concentrations of suppliers and customers among electric utilities, financial institutions and energy marketing and trading companies. These concentrations may impact FirstEnergy’s overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions. In the event an energy supplier of the Ohio Companies, FE PA, JCP&L or PE defaults on its obligation, the affected company would be required to seek replacement power in the market. In general, subject to regulatory review or other processes, it is expected that appropriate incremental costs incurred by these entities would be recoverable from customers through applicable rate mechanisms, thereby mitigating the financial risk for these entities. FirstEnergy’s credit policies to manage credit risk include the use of an established credit approval process, daily monitoring of counterparty credit limits, the use of credit mitigation measuresprovisions, such as margin, prepayment or collateral requirements. FirstEnergy and its subsidiaries may request additional credit assurance, in certain circumstances, in the event that the counterparties’ credit ratings fall below investment grade, their tangible net worth falls below specified percentages or their exposures exceed an established credit limit.
OUTLOOK
INCOME TAXES
On August 16, 2022, President Biden signed into law the IRA of 2022, which, among other things, imposes a new 15% corporate AMT based on AFSI applicable to corporations with a three-year average AFSI over $1 billion. The AMT is effective for the 2023 tax year and, if applicable, corporations must pay the greater of the regular corporate income tax or the AMT. Although NOL carryforwards created through the regular corporate income tax system cannot be used to reduce the AMT, financial statement net operating losses can be used to reduce AFSI and the useamount of master netting agreements.AMT owed. The IRA of 2022 as enacted requires the U.S. Treasury to provide regulations and other guidance necessary to administer the AMT, including further defining allowable adjustments to determine AFSI, which directly impacts the amount of AMT to be paid. Based on interim guidance issued by the U.S. Treasury during 2022 and 2023, FirstEnergy continues to believe that it is more likely than not it will be subject to the AMT beginning with 2023. Accordingly, FirstEnergy made a first quarter estimated payment of AMT of approximately $49 million in April 2023, however, made no additional payments in 2023 based on various factors, including additional guidance from the U.S. Treasury that eliminated the requirement of corporations to include AMT in quarterly estimated tax payments. Until final U.S. Treasury regulations are issued, the amount of AMT FirstEnergy pays could be significantly different than current estimates or it may not be a payer at all. The regulatory treatment of the impacts of this legislation may also be subject to regulation by FERC and/or applicable state regulatory authorities. Any adverse development in this legislation, including guidance from the U.S. Treasury and/or the IRS or unfavorable regulatory treatment, could negatively impact FirstEnergy’s cash flows, results of operations and financial condition.
As discussed above, on March 25, 2024, FirstEnergy closed on the sale of an additional 30% interest in FET, realizing an approximate $7.3 billion tax gain from the combined sale of 49.9% of the membership interests in FET for the consideration received and recapture of negative tax basis in FET. In the first quarter of 2024, FirstEnergy recognized a net tax charge of approximately $46 million, comprised of updates to estimated deferred tax liability for the deferred gain from the 19.9% sale of FET in May 2022, deferred tax liability related to its ongoing investment in FET, and valuation allowance associated with the expected utilization of certain state NOL carryforwards impacted by the sale and the PA Consolidation. During the first quarter of 2024, FirstEnergy also recognized a reduction to OPIC of approximately $797 million for federal and state income tax associated with the tax gain from closing on the 30% interest sale. As of December 31, 2023, FirstEnergy had approximately $8.1 billion of gross federal NOL carryforwards which will be used to offset a majority of FirstEnergy's energy contract counterparties maintain investment-grade credit ratings.
Retail Credit Risk
FirstEnergy's principal retail credit risk exposure relates to its competitive electricity activities, which serve residential, commercialthe tax gain from the FET Equity Interest Sale and industrial companies. Retail credit risk results when customers default on contractual obligations or fail to pay for service rendered. This risk represents the loss that may be incurredexpected taxable income in 2024, however due to the nonpayment of customer accounts receivable balances, as well as the loss from the resale of energy previously committed to serve customers.
Retail credit risk is managed through established credit approval policies, monitoring customer exposures and the use of credit mitigation measures such as depositscertain limitations on utilization enacted in the formTax Act, a portion of LOCs, cash or prepayment arrangements.the NOL will carry into 2025 and possibly beyond. As a result of the additional 30% sale, FET and its subsidiaries deconsolidated from FirstEnergy’s consolidated federal income tax group and now constitute their own consolidated federal income tax group subject to their own income tax allocation agreement.
Retail credit quality is affected by the economy and the ability of customers to manage through unfavorable economic cycles and other market changes. If the business environment were to be negatively affected by changes in economic or other market conditions, FirstEnergy's retail credit risk may be adversely impacted.
OUTLOOK
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 Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE and TrAIL in Virginia, ATSI in Ohio, the Transmission Companies in Pennsylvania, PE and MP in West Virginia, and PE in Maryland are subject to certain regulations of the VSCC.VSCC, PUCO, PPUC, WVPSC, and MDPSC, respectively. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility.
As competitive retail electric suppliers serving retail customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland, FES and AE Supply are subject to state laws applicable to competitive electric suppliers in those states, including affiliate codes of conduct that apply to FES, AE Supply and their public utility affiliates. In addition, Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission or generation facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission or generation facility.
MARYLAND
PE operates under MDPSC approved base rates that were effective as of October 19, 2023, and that were subsequently modified by an MDPSC order dated January 3, 2024, which became effective as of March 1, 2024. PE also provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third-party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS.
The Maryland legislature adopted a statute in 2008 codifying the EmPOWER Maryland goals to reduce electric consumption and demand and requiringprogram requires each electric utility to file a plan every three years. PE's current plan, covering the three-year period 2015-2017, was approved by the MDPSC on December 23, 2014. On July 16, 2015, the MDPSC issued an order setting new incremental energy savings goals for 2017to reduce electric consumption and beyond, beginning with the goal of 0.97% savings achieved under PE's current plan for 2016, and increasingdemand 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 program cycles, to the extent the MDPSC determines that cost-effective programs and services are available. The costs of the 2015-2017 plan are expected to be approximately $70 million,of which approximately $56 million was incurred through September 30, 2017. PE filed its 2018-2020 EmPOWER plan on August 31, 2017. The 2018-2020 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. The MDPSC will consider the 2018-2020 plan in hearings scheduled to begin on October 25, 2017, with a decision expected by December 31, 2017.savings. PE recovers program investments with a return through an annually reconciled surcharge, with most costs subject to recovery over a five-year amortization.period with a return on the unamortized balance. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding,proceeding. On August 1, 2023, PE filed its proposed plan for the 2024-2026 cycle as required by the MDPSC. Consistent with a December 29, 2022, order by the MDPSC phasing out the ability of Maryland utilities to earn a return on EmPOWER investments, PE will be required to expense 33% of its EmPOWER program costs in 2024, 67% in 2025 and 100% in 2026. Notwithstanding the order to date, such recovery has not been sought or obtainedphase out PE’s ability to earn a return on its EmPOWER investments, all previously unamortized costs for prior cycles will continue to earn a return and be collected by PE.
the end of 2029, consistent with the plan PE submitted on January 11, 2023. In the 2024-2026 order issued on December 29, 2023, the period to pay down the amortized balances was extended through the end of 2031. Additionally at the direction of the MDPSC, PE together with other Maryland utilities are required to address GHG reductions in addition to energy efficiency. In compliance with the MDPSC directive, PE submitted three scenarios with projected costs over a three-year cycle of $310 million, $354 million, and $510 million, respectively. The MDPSC conducted hearings on the proposed plans for all Maryland utilities on November 6-8, 2023. On February 27, 2013,December 29, 2023, the MDPSC issued an order requiringapproving 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$310 million scenario for most programs, with some modifications. On 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 of21, 2024, the MDPSC issued a set of reports that recommended the imposition of extensive additional requirementsapproved PE’s tariff to recover costs 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,2024 but directed PE to analyze alternative amortization methods 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 yet issued a ruling on any of those matters.possible use in later years.
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. Initial comments in the proceeding were filed on October 28, 2016, and the MDPSC held an initial hearing on the matter on December 8-9, 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.
NEW JERSEY
JCP&L currentlyoperates under NJBPU approved rates that took effect as of February 15, 2024, and will become effective for customers as of June 1, 2024. JCP&L provides BGS for retail customers who do not choose a third-party EGS and for customers of third-partythird- 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 wereThe base rate increase, which was approved by the NJBPU on February 14, 2024, took effect on February 15, 2024, and is effective for customers on June 1, 2024. Until those new rates became effective for customers, JCP&L is amortizing an existing regulatory liability totaling approximately $18 million to offset the base rate increase that otherwise would have occurred in this period. Under the base rate case settlement agreement, JCP&L also agreed to a two-phase reliability improvement plan to enhance the reliability related to 18 high-priority circuits, the first phase of which began on February 14, 2024, and represents an approximate investment of $95 million. Additionally, JCP&L recognized a $53 million pre-tax charge in the first quarter 2024 at
the Integrated segment within “Other operating expenses” on the FirstEnergy Consolidated Statements of Income, associated with certain corporate support costs recorded to capital accounts from the FERC Audit that were determined, as a result of the settlement agreement, to be disallowed from future recovery.
JCP&L has implemented energy efficiency and peak demand reduction programs in accordance with the New Jersey Clean Energy Act as approved by the NJBPU in April 2021. The NJBPU approved plans include recovery of lost revenues resulting from the programs and a three-year plan (July 2021-June 2024) including total program costs of $203 million, of which $160 million of investment is recovered over a ten-year amortization period with a return as well as $43 million in operations and maintenance expenses and financing costs recovered on an annual basis. On December 12, 2016, effective as5, 2023, JCP&L filed a petition with the NJBPU for a six-month extension of EE&C Plan I, which was originally scheduled to end on June 30, 2024, but would end on December 31, 2024, with the extension. The proposed budget for the extension period would add approximately $69 million to the original program cost. Under the proposal, JCP&L would recover the costs of the extension period and the revenue impact of sales losses resulting therefrom through two separate tariff riders. On December 1, 2023, JCP&L filed a related petition with the NJBPU requesting approval of its EE&C Plan II, which covers the January 1, 2017. These rates provide an annual increase in operating revenues2025 through June 30, 2027 period and has a proposed budget of approximately $80$964 million. EE&C Plan II consists of a portfolio of ten energy efficiency programs, one peak demand reduction program and one building decarbonization program. Under the proposal, JCP&L would recover its EE&C Plan II revenue requirements and lost revenues from reduced electricity sales associated with EE&C Plan II. Evidentiary hearings are scheduled to begin August 19, 2024, with a final NJBPU decision and order required no later than October 15, 2024.
The settlement of the distribution rate case in 2020, provided among other things, that JCP&L would be subject to a management audit, which began in May 2021. On April 12, 2023, the NJBPU accepted the final management audit report for filing purposes and ordered that interested stakeholders file comments on the report by May 22, 2023, which deadline was extended until July 31, 2023. JCP&L filed its comments on July 31, 2023. The parties have filed responses.
On September 17, 2021, in connection with Mid-Atlantic Offshore Development, LLC, a transmission company jointly owned by Shell New Energies US and EDF Renewables North America, JCP&L submitted a proposal to the NJBPU and PJM to build transmission infrastructure connecting offshore wind-generated electricity to the New Jersey power grid. On October 26, 2022, the JCP&L proposal was accepted, in part, in an order issued by NJBPU. The proposal, as accepted, included approximately $723 million in investments for JCP&L to both build new and upgrade existing transmission infrastructure. JCP&L’s proposal projects an investment ROE of 10.2% and includes the option for JCP&L to acquire up to a 20% equity stake in Mid-Atlantic Offshore Development, LLC. The resulting rates associated with the project are expected to be shared among the ratepayers of all New Jersey electric utilities. On April 17, 2023, JCP&L applied for the FERC “abandonment” transmission rates incentive, which would provide for recovery of 100% of the cancelled prudent project costs that are incurred after the incentive is approved, and 50% of the costs incurred prior to that date, in the event that some or all of the project is cancelled for reasons beyond JCP&L’s control. FERC staff subsequently requested additional information on JCP&L’s application, which JCP&L provided. On August 21, 2023, FERC approved JCP&L’s application, effective August 22, 2023. On October 31, 2023, offshore wind developer, Orsted, announced plans to cease development of two offshore wind projects in New Jersey—Ocean Wind 1 and 2—having a combined planned capacity of 2,248 MWs. At this time, Orsted’s announcement does not affect JCP&L’s awarded projects and JCP&L is moving forward with preconstruction activities for the planned transmission infrastructure. Construction is expected to begin in 2025.
Consistent with the commitments made in its proposal to the NJBPU, JCP&L formally submitted in November 2023 the first part of its application to the United States Department of Energy to finance a portion of the project using low-interest rate loans available under the United States Department of Energy’s Energy Infrastructure Reinvestment Program of the IRA of 2022. JCP&L submitted the second part of its two-part application on March 13, 2024.
On April 3, 2024, Mid-Atlantic Offshore Development, LLC submitted a bid application for the NJBPU Prebuild Infrastructure Solicitation to the NJBPU which outlines its proposal to construct infrastructure connecting the identified landing point for offshore wind generation off the coast of New Jersey with the high-voltage electric grid at Larrabee Collector Station. JCP&L is described in the application as a joint developer with Mid-Atlantic Offshore Development, LLC, subject to the execution of a joint development agreement by the parties. Mid-Atlantic Offshore Development, LLC will be the party responsible for the project.
On November 9, 2023, JCP&L filed a petition for approval of its second EnergizeNJ with the NJBPU that would, among other things, support grid modernization, system resiliency and substation modernization in technologies designed to provide enhanced customer benefits. JCP&L proposes EnergizeNJ will be implemented over a five-year budget period with estimated costs of approximately $935 million over the deployment period, of which, $906 million is capital investments and $29 million is operating and maintenance expenses. Under the proposal, the costs of EnergizeNJ would be recovered through JCP&L’s base rates via annual and semi-annual base rate adjustment filings. Public hearings have been requested but are not yet scheduled. JCP&L has requested that the NJBPU issue a final decision and order no later than May 22, 2024, based on a June 1, 2024, commencement date for EnergizeNJ. JCP&L anticipates filing amendments to the EnergizeNJ program after receipt of approval from those previously in place and are intended to improve service and benefit customers by supporting equipment maintenance, tree trimming, and inspectionsthe NJBPU of lines, poles and substations, while also compensating for other business and operating expenses. In addition,the base rate case stipulation that was filed on January 25, 2017,February 2, 2024. On February 14, 2024, the NJBPU approved the accelerationstipulated settlement between JCP&L and various parties, resolving JCP&L’s request for a distribution base rate increase. On February 27, 2024, as part of the amortizationstipulated settlement, JCP&L amended its pending EnergizeNJ petition following receipt of JCP&L’s 2012 major storm expenses that are recovered throughNJBPU approval of 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 2012base rate case proceeding directingsettlement, to include the second phase of its reliability improvement plan 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
expected 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 companiesany remaining high-priority circuits not addressed in the savings calculation. On November 5, 2014,first phase. EnergizeNJ, as amended, if approved will result in the Divisioninvestment of Rate Counsel appealed the NJBPU Order regarding the generic CTA proceeding to the Superior Courtapproximately $930.5 million 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 October 20, 2017, the NJBPU directed its staff to begin a formal rulemaking process to modify its CTA methodology.total estimated costs over five years.
OHIO
The Ohio Companies operate under PUCO-approved base distribution rates that became effective in 2009. 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. The Rider DMR will be grossed up for federal income taxes, resulting in an approved amount of approximately $204 million annually. Revenues from the 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 continues2024, that provides for the supply of power to non-shopping customers at a market-based price set through an auction process.
ESP IV also continues the Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $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 ofIn addition, ESP IV include:includes: (1) the collectioncontinuation of losta base distribution revenues associated with energy efficiency and peak demand reduction programs;rate freeze through May 31, 2024; (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 CO2 emissions by 90% below 2005 levels by 2045; (4)and (3) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio; 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 onOhio.
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, 2017,5, 2023, the Ohio Companies filed an application with the PUCO for rehearingapproval of ESP V, for an eight-year term beginning June 1, 2024, and continuing through May 31, 2032. ESP V proposes to continue providing power to non-shopping customers at market-based prices set through an auction process, with process enhancements designed to reduce costs to customers. ESP V also proposes to continue riders supporting investment in the Ohio Companies’ distribution system, including Rider DCR with annual revenue cap increases of $15 million to $21 million per year, based on reliability performance, and Rider AMI for recovery of approved grid modernization investments. ESP V proposes new riders to support continued maintenance of the PUCO’s August 16, 2017 rulingdistribution system, including vegetation management and storm restoration operating expense. In addition, ESP V proposes four-year energy efficiency and peak demand reduction programs for residential and commercial customers, with cost recovery spread over eight years. ESP V further includes a commitment to spend $52 million in total over the eight-year term, without recovery from customers, on the issuesinitiatives to assist low-income customers, education and incentives to help ensure customers have good experiences with electric vehicles. Hearings commenced on November 7, 2023 and concluded on December 6, 2023. On December 6, 2023, certain intervenors filed a motion requesting a limited stay of the third-party monitor andOhio Companies’ proposal to continue Rider DCR. The Ohio Companies contested the ROE calculation for advanced metering infrastructure. motion, which is pending.
On October 11, 2017, the PUCO denied the Ohio Companies' application for rehearing on both issues. On OctoberMay 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. For additional information, see “FERC Matters - Ohio ESP IV PPA” below.
Under ORC 4928.66,2022, the Ohio Companies are required to implement energy efficiency programsfiled their application for determination of the existence of SEET under ESP IV for calendar year 2021, which demonstrated that achieve certain annual energy savings and total peak demand reductions. Starting in 2017, ORC 4928.66 requireseach of the energy savings benchmark to increase by 1% andindividual Ohio Companies did not have significantly excessive earnings. This matter remains pending before 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. PUCO.
On AprilJuly 15, 2016,2022, the Ohio Companies filed an application with the PUCO for approval of phase two of their three-year energy efficiency portfolio plansdistribution grid modernization plan that would, among other things, provide for the period from January 1, 2017 through December 31, 2019. The plans as proposed comply with benchmarks contemplated by ORC 4928.66installation of an additional 700 thousand smart meters, distribution automation equipment on approximately 240 distribution circuits, voltage regulating equipment on approximately 220 distribution circuits, and provisions of the ESP IV,other investments and include a portfolio of energy efficiencypilot programs targetedin related technologies designed to a variety ofprovide enhanced 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.benefits. The Ohio Companies anticipate the cost of the planspropose that phase two will be implemented over a four-year budget period with estimated capital investments of approximately $268$626 million and operations and maintenance expenses of approximately $144 million over the lifedeployment period. Under the proposal, costs of phase two of the portfolio plans and such costs are expected togrid modernization plan would be recovered through the Ohio Companies’ existing rate mechanisms.AMI rider, pursuant to the terms and conditions approved in ESP IV. On April 12, 2024, the Ohio Companies and certain of the parties filed a stipulation that modified the Ohio Companies’ application for phase two of its grid modernization plan. The hearingsstipulation, which is subject to PUCO approval, provides for the deployment of smart meters to the balance of the Ohio Companies’ customers or approximately 1.4 million meters. Phase two of the distribution grid modernization plan, as modified by the stipulation would be completed over a four-year budget period with estimated capital investments of approximately $421 million. On April 16, 2024, the PUCO scheduled the stipulation hearing for June 5, 2024.
On September 8, 2020, the OCC filed motions in the Ohio Companies’ corporate separation audit and DMR audit dockets, requesting the PUCO to open an investigation and management audit, hire an independent auditor, and require FirstEnergy to show it did not improperly use money collected from consumers or violate any utility regulatory laws, rules or orders in its activities regarding HB 6. On December 30, 2020, in response to the OCC's motion, the PUCO reopened the DMR audit docket, and directed PUCO staff to solicit a third-party auditor and conduct a full review of the DMR to ensure funds collected from customers through the DMR were heldonly used for the purposes established in ESP IV. On June 2, 2021, the PUCO selected an auditor, and the auditor filed the final audit report on January 2017.
14, 2022, which made certain findings and recommendations. The report found that spending of DMR revenues was not required to be tracked, and that DMR revenues, like all rider revenues, are placed into the regulated money pool as a matter of routine, where the funds lose their identity. Therefore, the report could not suggest that DMR funds were used definitively for direct or indirect support for grid modernization. The report also concluded that there was no documented evidence that ties revenues from the DMR to lobbying for the passage of HB 6, but also could not rule out with certainty uses of DMR funds to support the passage of HB 6. The report further recommended that the regulated companies' money pool be audited more frequently and the Ohio law requires electric utilitiesCompanies adopt formal dividend policies. Final comments and electric service companiesresponses were filed by parties during the second quarter of 2022. The proceeding was stayed 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 2015its entirety, including discovery and 2016motions, continuously at the 2014 level (2.5%), pushing back scheduled increases,request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner consolidated this proceeding with the expanded Rider DCR audit proceeding described below and set a procedural schedule, which resumed in 2017 (3.5%), and increases 1% each year through 2026 (to 12.5%) and shall remainwas vacated on March 15, 2024. A new procedural schedule will be set 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. Ina May 21, 2024 prehearing conference.
On September 2011,15, 2020, the PUCO opened a docketnew proceeding to review the Ohio Companies' alternative energy recovery rider through whichpolitical and charitable spending by the Ohio Companies recoverin support of HB 6 and the costs of acquiring these RECs. The PUCO issued an Opinionsubsequent referendum effort, 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 directeddirecting the Ohio Companies to credit non-shoppingshow cause, demonstrating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by customers. The Ohio Companies initially filed a response stating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by customers, but on August 6, 2021, filed a supplemental response explaining that, in light of the facts set forth in the amountDPA and the findings of $43.4 million, plus interest, on the basis thatRider DCR audit report further discussed below, political or charitable spending in support of HB 6, or the subsequent referendum effort, affected pole attachment rates paid by approximately $15 thousand. On October 26, 2021, the OCC filed a motion requesting the PUCO to order an independent external audit to investigate FE’s political and charitable spending related to HB 6, and to appoint an independent review panel to retain and oversee the auditor. In November and December 2021, parties filed comments and reply comments regarding the Ohio Companies’ original and supplemental responses to the PUCO’s September 15, 2020, show cause directive. On May 4, 2022, the PUCO selected a third-party auditor to determine whether the show cause demonstration submitted by the Ohio Companies didis sufficient to ensure that the cost of any political or charitable spending in support of HB 6 or the subsequent referendum effort was not prove such purchasesincluded, directly or indirectly, in any rates or charges paid by ratepayers. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner directed the third-party auditor to file its report by August 28, 2024.
In connection with an ongoing audit of the Ohio Companies’ policies and procedures relating to the code of conduct rules between affiliates, on November 4, 2020, the PUCO initiated an additional corporate separation audit as a result of the FirstEnergy leadership transition announcement made on October 29, 2020, as further discussed below. The additional audit is to ensure compliance by the Ohio Companies and their affiliates with corporate separation laws and the Ohio Companies’ corporate separation plan. The additional audit is for the period from November 2016 through October 2020. The final audit report was filed on September 13, 2021. The audit report makes no findings of major non-compliance with Ohio corporate separation requirements, minor non-compliance with eight requirements, and findings of compliance with 23 requirements. Parties filed comments and reply comments on the audit report. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner set a procedural schedule, which was vacated on March 15, 2024. A new procedural schedule will be set at an April 25, 2024 prehearing conference.
In connection with an ongoing annual audit of the Ohio Companies’ Rider DCR for 2020, and as a result of disclosures in FirstEnergy’s Form 10-K for the year ended December 31, 2020 (filed on February 18, 2021), the PUCO expanded the scope of the audit on March 10, 2021, to include a review of certain transactions that were prudent.either improperly classified, misallocated, or lacked supporting documentation, and to determine whether funds collected from customers were used to pay the vendors, and if so, whether or not the funds associated with those payments should be returned to customers through Rider DCR or through an alternative proceeding. On August 3, 2021, the auditor filed its final report on this phase of the audit, and the parties submitted comments and reply comments on this audit report in October 2021. Additionally, on September 29, 2021, the PUCO expanded the scope of the audit in this proceeding to determine if the costs of the naming rights for FirstEnergy Stadium have been recovered from the Ohio Companies’ customers. On November 19, 2021, the auditor filed its final report, in which the auditor concluded that the FirstEnergy Stadium naming rights expenses were not recovered from Ohio customers. On December 24, 2013, following15, 2021, the denialPUCO further expanded the scope of theirthe audit to include an investigation into an apparent nondisclosure of a side agreement in the Ohio Companies’ ESP IV settlement proceedings, but stayed its expansion of the audit until otherwise ordered by the PUCO. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner consolidated this proceeding with the Rider DMR audit proceeding described above, further lifted the stay of the portion of the investigation relating to an apparent nondisclosure of a side agreement, and set a procedural schedule, which was vacated on March 15, 2024. A new procedural schedule will be set at a May 21, 2024 prehearing conference.
On March 1, 2024, the Attorney Examiner issued an Entry in all four PUCO investigations that, among other things, precluded taking or offering the testimony of Charles E. Jones, Michael J. Dowling, or Samuel Randazzo through deposition or other means, or requiring these individuals to produce documents, in any PUCO proceeding, until otherwise ordered.
On September 22, 2023, OCC filed an application for rehearing challenging the PUCO’s August 23, 2023, order to stay the pending HB 6 related matters above, which the PUCO denied on October 18, 2023. On November 17, 2023, OCC filed an application for rehearing challenging the October 18, 2023 entry to the extent the PUCO decided not to stay pending proceedings regarding ESP V as well as phases one and two of the Ohio Companies’ distribution grid modernization plans. On November 27, 2023, the Ohio Companies filed a noticememorandum contra OCC’s application for rehearing.
In the fourth quarter of appeal and a motion for stay of the PUCO's order2020, motions were filed with the Supreme CourtPUCO requesting that the PUCO amend the Ohio Companies’ riders for collecting the OVEC-related charges required by HB 6 to provide for refunds in the event such provisions of HB 6 are repealed. Neither the Ohio which was granted. On February 18, 2014,Companies nor FE benefit from the OCC andOVEC-related charges the ELPC also filed appeals ofOhio Companies collect. Instead, the PUCO's order.Ohio Companies are further required by HB 6 to remit all the OVEC-related charges they collect to non-FE Ohio electric distribution utilities. The Ohio Companies timelycontested the motions, which are pending before the PUCO.
On May 15, 2023, the Ohio Companies filed their merit brief withapplication for determination of the Supreme Courtexistence of SEET under ESP IV for calendar year 2022, which demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings. This matter remains pending before the PUCO.
See below for additional details on the government investigations and subsequent litigation surrounding the briefing process has concluded. Oral argument on this matter was held on June 21, 2017.
On April 9, 2014, the PUCO initiated a generic investigation of marketing practices in the competitive retail electric service market, with a focus on the marketing of fixed-price or guaranteed percent-off SSO rate contracts where there is a provision that permits the pass-through of new or additional charges. On November 18, 2015, the PUCO ruled that on a going-forward basis, pass-through clauses may not be included in fixed-price contracts for all customer classes. On December 18, 2015, FES filed an Application for Rehearing seeking to change the ruling or have it only apply to residential and small commercial customers. On January 13, 2016, the PUCO granted reconsideration for further consideration of the matters specified in the applications for rehearing. On March 29, 2017, the PUCO issued a Second Entry on Rehearing that granted, in part, the applications for rehearing filed by FES and other parties, finding that the PUCO’s guidelines regarding fixed-price contracts should not apply to large mercantile customers. This finding changes the original order, which applied the guidelines to all customers, including mercantile customers. The PUCO also reaffirmed several provisions of the original order, including that the fixed-price guidelines only apply on a going-forward basis and not to existing contracts and that regulatory-out clauses in contracts are permissible.
HB 6.
PENNSYLVANIA
The Pennsylvania Companies operateoperated 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.
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 increasesOn January 1, 2024, each of the Pennsylvania Companies merged with and into FE PA. As a result of the PA Consolidation, FE PA will have five rate districts in operating revenues of approximately $96 million atPennsylvania – four that correspond to the territories previously serviced by ME, $100 million at PN, $29 million at Penn, and $66 million at WP and are intendedone rate district that corresponds to benefit customersWP’s service provided to The Pennsylvania State University. The rate districts created by modernizing the grid with smart technologies, increasing vegetation management activities, and continuing other customer service enhancements.PA Consolidation will not reach full rate unity until the earlier of 2033 or the conclusion of three base rate cases filed after January 1, 2025.
Pursuant to Pennsylvania's EE&C legislation inPennsylvania Act 129 of 2008 and PPUC orders, the Pennsylvania EDCs implementCompanies implemented energy efficiency and peak demand reduction programs. On June 19, 2015, the PPUC issued a Phase III Final Implementation Order setting:programs with demand reduction targets, relative to each Pennsylvania Companies' 2007-2008 peak demand (in MW),demands, at 1.8%2.9% MW for ME, 1.7%3.3% MW for PN, 2.0% MW for Penn, 1.8%and 2.5% MW for WP, and 0% for PN;WP; and energy consumption reduction targets, as a percentage of eachthe Pennsylvania Companies’ historic 2009 to 2010 forecasts (in MWH),reference load at 4.0%3.1% MWh for ME, 3.9%3.0% MWh for PN, 3.3%2.7% MWh for Penn, and 2.6%2.4% MWh for WP. The Pennsylvania Companies' Phase III EE&C plansfourth phase of FE PA’s energy efficiency and peak demand reduction program, which runs for the five-year period beginning June 20161, 2021 through May 2021 period, which were31, 2026, was approved in March 2016, with expected costs up toby the PPUC on June 18, 2020, providing through cost recovery of approximately $390 million are designed to achieve the targets established in the PPUC'sbe recovered through Energy Efficiency and Conservation Phase III Final Implementation Order with full recovery through the reconcilable EE&C riders.IV Riders for each FE PA rate district.
Pursuant to Act 11 of 2012, Pennsylvania EDCs may establish a DSICare permitted to recover costsseek PPUC approval of an LTIIP for 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 priorafter which a DSIC may be approved to approval of a DSIC.recover LTIIP costs. On February 11, 2016,January 16, 2020, the PPUC approved LTIIPs for each of the Pennsylvania Companies. On June 14, 2017, the PPUC approved modifiedCompanies’ 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 five-year period beginning January 1, 2020 and ending December 31, 2024 for a total capital investment of 2016approximately $572 million for certain infrastructure improvement initiatives. FE PA expects to 2020, as modified, are: WP $88.3 million; PN $60.0 million; Penn $58.9 million; and ME $51.6 million.
On February 16, 2016, the Pennsylvania Companies filed DSIC riders for PPUCseek approval for quarterly cost recovery, which were approvedthe next phase of its LTIIP program 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, inend of the PPUC’s order approvingthird quarter of 2024.
Following the Pennsylvania Companies’ general2016 base rate cases,proceedings, the PPUC added an additional issueruled in a separate proceeding related 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, which is pending PPUC approval. The ADIT issue is subject to further litigation and a hearing was held on May 12, 2017. On August 31, 2017, the ALJ issued a decision recommending that the complaint of the Pennsylvania Office of Consumer Advocate be granted by the PPUC suchmechanisms that the Pennsylvania Companies were not required to reflect all federal and state income tax deductions related to DSIC-eligible property in the currently effective DSIC rates. IfThe decision was appealed to the Pennsylvania Supreme Court and in July 2021 the court upheld the Pennsylvania Commonwealth Court’s reversal of the PPUC’s decision isand remanded the matter back to the PPUC for determination as to how DSIC calculations shall account for accumulated deferred income taxes and state taxes. The PPUC issued the order as directed.
On May 5, 2023, FirstEnergy and Brookfield submitted applications to FERC and to the PPUC to facilitate the FET Equity Interest Sale. On May 12, 2023, the parties also filed an application with the VSCC, which was approved on June 20, 2023. On August 14, 2023, FERC issued an order approving the FET Equity Interest Sale. On November 24, 2023, CFIUS notified FET, Brookfield and the Abu Dhabi Investment Authority, as an indirect investor in FET through Brookfield, that it had determined that there were no unresolved national security issues and its review of the transaction was concluded. On November 29, 2023, the parties filed a settlement agreement recommending that the PPUC approve the transaction subject to the terms of the settlement, which includes among other things, a number of ring-fencing provisions and a commitment to improve transmission reliability over the next five years. The settlement was approved by the PPUC on March 14, 2024. The transaction closed on March 25, 2024.
On April 2, 2024, FE PA filed a base rate case with the PPUC, based on a projected 2025 annual test year. The rate case requests a net increase in base distribution revenues of approximately $502 million with a return on equity of 11.3% and capital structure of 46.2% debt and 53.8% equity, and reflects a roll-in of several current riders such as DSIC, Tax Act and smart meter. The increase represents an overall net average rate increase in FE PA rates by approximately 7.7%, and a 10.5% average residential rate increase. Key components of the base rate case filing include a proposal to change pension and OPEB recovery to the delayed recognition method and to implement a mechanism to establish a regulatory asset (or liability) to recover (or refund) net differences between the amount of pension and OPEB expense requested in the proceeding and the actual annual amount each year using this method. Additionally, FE PA requests recovery of certain incurred costs, including the impact of major storms, COVID-19, a program to convert streetlights to LEDs, and others. The PPUC issued an order on April 25, 2024, deferring, by operation of law, the June 1, 2024 statutory effective date to January 1, 2025. A pre-hearing conference is notscheduled for May 2, 2024. A PPUC decision is expected to be material to FirstEnergy. The Pennsylvania Companies filed exceptions to the decision on September 20, 2017, and reply exceptions on October 2, 2017.in December 2024, with new rates becoming effective in January 2025.
WEST VIRGINIA
MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking.ratemaking and operate under WVPSC-approved rates. 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'sMP’s and PE'sPE’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 by the parties to the proceeding, 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 October 6, 2017, MP and PE proposed an annual decrease in their EE&C rates, effective January 1, 2018, which is not expected to be material to FirstEnergy.
On December 9, 2016, the WVPSC approved the annual ENEC case for MP and PE as reflected in a unanimous settlement by the parties to the proceeding, 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.
On December 30, 2015, MP and PE filed an IRP with the WVPSC identifying a capacity shortfall starting in 2016 and exceeding 700 MWs by 2020 and 850 MWs by 2027. On June 3, 2016, the WVPSC accepted the IRP. On December 16, 2016, MP issued an RFP to address its generation shortfall, along with issuing a second RFP to sell its interest in Bath County. Bids were received by an independent evaluator in February 2017 for both RFPs. AE Supply was the winning bidder of the 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 MW) for approximately $195 million, subject to customary and other closing conditions, including regulatory approvals. In addition, on March 7, 2017, MP and PE filed an application with the WVPSC and MP and AE Supply filed an application with FERC requesting authorization for such purchase. The WVPSC held an evidentiary hearing commencing on September 26, 2017, and public hearings were held on September 6, 11, and 12, 2017. An order is anticipated by early 2018. On June 27, 2017, FERC issued a deficiency letter requesting additional information to facilitate FERC’s review of the transaction. MP responded to the deficiency letter on July 18, 2017, and to related protests and comments on August 28, 2017. The applications remain pending before the WVPSC and FERC, respectively. With respect to the Bath County RFP, MP does not plan to move forward with that sale of its ownership interest. In the future, MP may re-evaluate its options with respect to its interest in Bath County.
On September 1, 2017,August 31, 2023, MP and PE filed with the WVPSC their annual ENEC case requesting an increase in ENEC rates of $167.5 million beginning January 1, 2024, which represents a 9.9% increase in overall rates. This increase, which was driven primarily by higher fuel expenses, includes the approximate $92 million carried over from the 2022 ENEC proceeding and a portion of the approximately $267 million under recovery balance at the end of the review period (July 1, 2022 to June 30, 2023). The remaining $75.6 million of the under recovery balance not recovered in 2024 will be deferred for collection during 2025, with an annual carrying charge of 4%. A hearing was held on November 30, 2023, at which time a joint stipulation for settlement that was agreed to by all but one party was presented to the WVPSC. The settlement provides for a reconciliationnet $55.4 million increase in ENEC rates beginning March 27, 2024 with the net deferred ENEC balance of their VMSapproximately $255 million to confirm that rate recovery matches VMP costs and for a regular review of that program.be recovered through 2026. There will be no 2024 ENEC case unless MP and PE proposedover or under recover more than $50 million than the 2024 ENEC balance and a $15 million annual decreaseparty elects to invoke a case filing. An order was issued on March 26, 2024 approving the settlement without modification and rates became effective on March 27, 2024.
On April 21, 2022, the WVPSC issued an order approving, effective May 1, 2022, a tariff to offer solar power to West Virginia customers and requiring MP and PE to subscribe at least 85% of the planned 50 MWs of solar generation before seeking final tariff approval. MP and PE must seek separate approval from the WVPSC to recover any solar generation costs in VMS rates effectiveexcess of the approved tariff. On April 24, 2023, MP and PE sought final tariff approval from the WVPSC for three of the five solar sites, representing 30 MWs of generation, and requested approval of a surcharge to recover any costs above the final approved tariff. The first solar generation site went into service in January 2024 and construction of the remaining four sites are expected to be completed no later than the end of 2025 at a total investment cost of approximately $110 million. On August 23, 2023, the WVPSC approved the customer surcharge and granted approval to construct three of the five solar sites. The surcharge went into effect January 1, 2018,2024.
On January 13, 2023, MP and an additional $15 million decrease inPE filed a request with the WVPSC seeking approval of new depreciation rates for 2019. This is an overall decreaseexisting and future capital assets. Specifically, MP and PE are seeking to increase depreciation expense by approximately $76 million per year, primarily for regulated generation-related assets. Any depreciation rates approved by the WVPSC would not become effective until new base rates were established. On August 22, 2023, a unanimous settlement of the case was filed recommending a $33 million per year increase in depreciation expense, effective April 1, 2024. An order from the WVPSC was issued on March 26, 2024 approving the settlement without modification and became effective on March 27, 2024.
On May 31, 2023, MP and PE filed a base rate case with the WVPSC requesting a total revenue increase of approximately $207 million utilizing a test year of 2022 with adjustments plus a request to establish a regulatory asset (or liability) to recover (or refund) in a subsequent base rate case the net differences between the amount of pension and OPEB expense requested in the proceeding (based on average expense from 2018 to 2022) and the actual annual amount each year using the delayed recognition method. Among other things, the increase includes the approximate $76 million requested in a depreciation case filed on January 13, 2023 and described above, and amounts to support a new low-income customer advocacy program, storm restoration work and service reliability investments. On January 23, 2024, MP, PE and various parties filed a joint settlement agreement with the WVPSC, which recommended a base rate increase of $105 million, inclusive of the $33 million increase in depreciation expense. Additionally, the settlement includes a new low-income customer advocacy program, a pilot program for service reliability investments and recovery of costs related to storm restoration, retired generation assets and COVID-19. The settlement did not include the request to establish a regulatory asset (or liability) for recover (or refund) associated with pension and OPEB expense, however, it did not preclude MP and PE from pursuing that in a future separate proceeding. On February 16, 2024, interested parties filed a settlement on the net energy metering credit for consideration by the WVPSC. An order was issued on March 26, 2024 approving the $105 million increase and accepting the settlement with slight non-material modifications with new rates going into effect on March 27, 2024. Additionally, due to the order including approval by the WVPSC to recover certain costs associated with retired generation assets, MP recognized a $60 million pre-tax benefit in the first quarter of 1%.2024 to establish a regulatory asset.
RELIABILITYFERC REGULATORY MATTERS
Federally-enforceableUnder the Federal Power Act, FERC regulates rates for interstate wholesale sales and transmission of electric power, regulatory accounting and reporting under the Uniform System of Accounts, and other matters, including construction and operation of hydroelectric projects. With respect to their wholesale services and rates, the Utilities, AE Supply and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE and the Transmission Companies are subject to functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff. On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo.
FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers to entry into markets. The Utilities and AE Supply each have the necessary authorization from FERC to sell their
wholesale power, if any, in interstate commerce at market-based rates, although in the case of the Utilities major wholesale purchases remain subject to review and regulation by the relevant state commissions.
Federally enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES and certain of its subsidiaries, AE Supply, FENOC, ATSI, MAIT and TrAIL.the Transmission Companies. NERC is the EROElectric Reliability Organization 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 eightsix regional entities, including RFC. All of FirstEnergy'sthe facilities that FirstEnergy operates 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 including FES, believes that it is in material compliance with all currently-effectivecurrently effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy including FES, occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy including FES, develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy's, including FES,FirstEnergy’s part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, andor obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations, and cash flows.
FERC MATTERSAudit
Ohio ESP IV PPA
FERC’s Division of Audits and Accounting initiated a nonpublic audit of FESC in February 2019. Among other matters, the audit is evaluating FirstEnergy’s compliance with certain accounting and reporting requirements under various FERC regulations. On AugustFebruary 4, 2014,2022, FERC filed the Ohio Companies filed an application withfinal audit report for the PUCO seeking approvalperiod of their ESP IV. ESP IVJanuary 1, 2015 through September 30, 2021, which included several findings and recommendations that FirstEnergy has accepted. The audit report included a proposed Rider RRS, which would flow throughfinding and related recommendation on FirstEnergy’s methodology for allocation of certain corporate support costs to customers either charges or credits representing the net result of the price paid to FES through an eight-year FERC-jurisdictional PPA, referred to as the ESP IV PPA, against the revenues received from selling such output into the PJM markets. The Ohio Companies entered into stipulations which modified ESP IV,regulatory capital accounts under certain FERC regulations and on March 31, 2016, the PUCO issued an Opinion and Order adopting and approving the Ohio Companies’ stipulated ESP IV with modifications. FES and the Ohio Companies entered into the ESP IV PPA on April 1, 2016, but subsequently agreed to suspend it and advised FERC of this course of action.
On March 21, 2016, a number of generation owners filed with FERC a complaint against PJM requesting that FERC expand the MOPRreporting. Effective in the PJM Tariff to prevent the alleged artificial suppressionfirst quarter of prices2022 and in the PJM capacity markets by state-subsidized generation, in particular alleged price suppression that could result from the ESP IV PPA and other similar agreements. The complaint requested that FERC direct PJM to initiate a stakeholder process to develop a long-term MOPR reform for existing resources that receive out-of-market revenue. On January 9, 2017, the generation owners filed to amend their complaint to include challenges to certain legislation and regulatory programs in Illinois. On January 24, 2017, FESC, acting on behalf of its affected affiliates and along with other utility companies, filed a motion to dismiss the amended complaint for various reasons, including that the ESP IV PPA matter is now moot. In addition, on January 30, 2017, FESC along with other utility companies filed a substantive protestresponse to the amended complaint, demonstrating thatfinding, FirstEnergy had implemented a new methodology for the questionallocation of the proper rolethese corporate support costs to regulatory capital accounts for state participation in generation development should be addressed in the PJM stakeholder process. On August 30, 2017, the generation owners requested expedited action by FERC. This proceeding remains pending before FERC.
PJM Transmission Rates
PJMits regulated distribution and its stakeholders have been debating the proper method to allocate costs for certain transmission facilities. While FirstEnergy and other parties advocate for a traditional "beneficiary pays" (or usage based) approach, others advocate for “socializing” the costscompanies on a load-ratio share basis, where each customer inprospective basis. With the zone would pay based on its total usageassistance of energy within PJM. This question has beenan independent outside firm, FirstEnergy completed an analysis during the subjectthird quarter of extensive litigation before FERC and the appellate courts, including before the Seventh Circuit. On June
25, 2014, a divided three-judge panel of the Seventh Circuit ruled that FERC had not quantified the benefits that western PJM utilities would derive from certain new 500 kV or higher lines and thus had not adequately supported its decision to socialize the costs2022 of these lines. The majority found that eastern PJM utilities are the primary beneficiaries of the lines, while western PJM utilities are only incidental beneficiaries,costs and that, while incidental beneficiaries should pay some share of the costs of the lines, that share should be proportionate to the benefit they derive from the lines, and not on load-ratio share in PJM as a whole. The court remanded the case to FERC, which issued an order setting the issue of cost allocation for hearing and settlement proceedings. On June 15, 2016, various parties, including ATSI and the Utilities, filed a settlement agreement at FERC agreeing to apply a combined usage based/socialization approach to cost allocation for charges tohow it impacted certain FERC-jurisdictional wholesale transmission customers in the PJM Region for transmission projects operating at or above 500 kV. Certain other parties in the proceeding did not agree to the settlement and filed protests to the settlement seeking, among other issues, to strike certain of the evidence advanced by FirstEnergy and certain of the other settling parties in support of the settlement, as well as provided further comments in opposition to the settlement. FirstEnergy and certain of the other parties responded to such opposition. The settlement is pending before FERC.
RTO Realignment
On June 1, 2011, ATSI and the ATSI zone transferred from MISO to PJM. While many of the matters involved with the move have been resolved, FERC denied recovery under ATSI's transmission rate for certain charges that collectively can be described as "exit fees" and certain other transmission cost allocation charges totaling approximately $78.8 million until such time as ATSI submits a cost/benefit analysis demonstrating net benefits to customers from the transfer to PJM. Subsequently, FERC rejected a proposed settlement agreement to resolve the exit fee and transmission cost allocation issues, stating that its action is without prejudice to ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh the exit fee and transmission cost allocation charges. On March 17, 2016, FERC denied FirstEnergy's request for rehearing of FERC's earlier order rejecting the settlement agreement and affirmed its prior ruling that ATSI must submit the cost/benefit analysis.
Separately, ATSI resolved a dispute regarding responsibility for certain costscustomer rates for the “Michigan Thumb” transmission project. Potential responsibility arises under the MISO MVP tariff, which has been litigated in complex proceedings before FERC and certain U.S. appellate courts. On October 29,audit period of 2015 FERC issued an order finding that ATSI and the ATSI zone do not have to pay MISO MVP charges for the Michigan Thumb transmission project. MISO and the MISO TOs filed a request for rehearing, which FERC denied on May 19, 2016. The MISO TOs subsequently filed an appeal of FERC's orders with the Sixth Circuit. FirstEnergy intervened and participated in the proceedings on behalf of ATSI, the Ohio Companies and PP. On June 21, 2017, the Sixth Circuit issued its decision denying the MISO TOs' appeal request. September 19, 2017 was the deadline for MISO and the MISO TOs to seek review by the U.S. Supreme Court. They did not file for review, effectively resolving the dispute over the "Michigan Thumb" transmission project. On a related issue, FirstEnergy joined certain other PJM TOs in a protest of MISO's proposal to allocate MVP costs to energy transactions that cross MISO's borders into the PJM Region. On July 13, 2016, FERC issued its order finding it appropriate for MISO to assess an MVP usage charge for transmission exports from MISO to PJM. Various parties, including FirstEnergy and the PJM TOs, requested rehearing or clarification of FERC’s order. The requests for rehearing remain pending before FERC.
In addition, in a May 31, 2011 order, FERC ruled that the costs for certain "legacy RTEP" transmission projects in PJM approved before ATSI joined PJM could be charged to transmission customers in the ATSI zone. The amount to be paid, and the question of derived benefits, is pending before FERC as a result of the Seventh Circuit's June 25, 2014 order described above under "PJM Transmission Rates."
The outcome of the proceedings that address the remaining open issues related to MVP costs and "legacy RTEP" transmission projects cannot be predicted at this time.
MAIT Transmission Formula Rate
On October 28, 2016, MAIT submitted an application to FERC requesting authorization to implement a forward-looking formula transmission rate to recover and earn a return on transmission assets effective January 1, 2017. Various intervenors submitted protests of the proposed MAIT formula rate. Among other things, the protest asked FERC to suspend the proposed effective date for the formula rate until June 1, 2017. On March 10, 2017, FERC issued an order accepting the MAIT formula transmission rate for filing, suspending it for five months, and establishing hearing and settlement judge procedures. On April 10, 2017, MAIT requested rehearing of FERC’s decision to suspend the effective date of the formula rate. FERC's order on rehearing remains pending. MAIT’s rates went into effect on July 1, 2017, subject to refund pending the outcome of the hearing and settlement procedures. On October 13, 2017, MAIT and certain parties filed a settlement agreement with FERC. The settlement agreement provides for certain changes to MAIT's formula rate template and protocols, changes MAIT's ROE from 11% to 10.3%, sets the recovery amount for certain regulatory assets, and establishes that MAIT's capital structure will not exceed 60% equity over the period ending December 31,through 2021. The settlement agreement further provides that the ROE and the 60% cap on the equity component of MAIT's capital structure will remain in effect unless changed pursuant to section 205 or 206 of the FPA provided the effective date for any change shall be no earlier than January 1, 2022. The settlement agreement currently is pending at FERC. As a result of the settlement agreement, MAIT recognized a pre-tax impairment charge of $13 millionthis analysis, FirstEnergy recorded in the third quarter of 2017.2022 approximately $45 million ($34 million after-tax) in expected customer refunds, plus interest, due to its wholesale transmission customers and reclassified approximately $195 million of certain transmission capital assets to operating expenses for the audit period, of which $90 million ($67 million after-tax) are not expected to be recoverable and impacted FirstEnergy’s earnings since they relate to costs capitalized during stated transmission rate time periods. FirstEnergy is currently recovering approximately $105 million of costs reclassified to operating expenses in its transmission formula rate revenue requirements, of which $39 million of costs have been recovered as of March 31, 2024. On December 8, 2023, FERC audit staff issued a letter advising that two unresolved audit matters, primarily related to FirstEnergy’s plan to recover the reclassified operating expenses in formula transmission rates, were being referred to other offices within FERC for further review. These reclassifications also resulted in a reduction to the Regulated Transmission segment’s rate base by approximately $160 million, which is not expected to materially impact FirstEnergy or the segment’s future earnings. The expected wholesale transmission customer refunds were recognized as a reduction to revenue, and the amount of reclassified transmission capital assets that are not expected to be recoverable were recognized within “Other operating expenses” at the Regulated Transmission segment and on FirstEnergy’s Consolidated Statements of Income. Furthermore, FirstEnergy’s Utilities are in the process of addressing the outcomes of the FERC Audit with the applicable state commissions and proceedings, which includes seeking continued rate base treatment of approximately $200 million of certain corporate support costs allocated to distribution capital assets in Ohio and Pennsylvania. If FirstEnergy is unable to recover these transmission or distribution costs, it could result in future charges and/or adjustments and have an adverse impact on FirstEnergy’s financial condition.
ATSI ROE – Ohio Consumers Counsel v. ATSI, et al.
On February 24, 2022, the OCC filed a complaint with FERC against ATSI, AEP’s Ohio affiliates and American Electric Power Service Corporation, and Duke Energy Ohio, LLC asserting that FERC should reduce the ROE utilized in the utilities’ transmission formula rates by eliminating the 50 basis point adder associated with RTO membership, effective February 24, 2022. The OCC contends that this result is required because Ohio law mandates that transmission owning utilities join an RTO and that the 50 basis point adder is applicable only where RTO membership is voluntary. On December 15, 2022, FERC denied the complaint as to ATSI and Duke, but granted it as to AEP. AEP and OCC appealed FERC’s orders to the Sixth Circuit and the case remains pending. FirstEnergy is unable to predict the outcome of this proceeding, but it is not expected to have a material impact.
Transmission ROE Methodology
JCP&L Transmission Formula Rate
On October 28, 2016, after withdrawing its request to the NJBPU to transfer its transmission assets to MAIT, JCP&L submitted an application to FERC requesting authorization to implement a forward-looking formulaA proposed rulemaking proceeding concerning transmission rate to recover and earn a return on transmission assets effective January 1, 2017. A groupincentives provisions of intervenors, including the NJBPU and New Jersey Division of Rate Counsel, filed a protestSection 219 of the proposed JCP&L transmission rate.2005 Energy Policy Act was initiated in March of 2020 remains pending before FERC. Among other things, the protest asked FERC to suspendrulemaking explored whether utilities should collect an “RTO membership” ROE incentive adder for more than three years. FirstEnergy is a member of PJM and its transmission subsidiaries could be affected by the proposed effective date for the formula rate until June 1, 2017. On March 10, 2017, FERC issued an order accepting the JCP&L formula transmission rate for filing, suspending it for five months, and establishing hearing and settlement judge procedures. On April 10, 2017, JCP&L requested rehearing of FERC’s decision to suspend the effective date of the formula rate. FERC's order on rehearing remains pending. JCP&L’s rates went into effect on June 1, 2017, subject to refund pending the outcome of the hearing and settlement procedures. The settlement process is ongoing.
DOE NOPR: Grid Reliability and Resilience Pricing, FERC Docket No. RM18-1
On September 28, 2017, the Secretary of Energy released a NOPR requesting FERC to issue rules directing RTOs to incorporate pricing for defined “eligible grid reliability and resiliency resources” into wholesale energy markets. Specifically, as proposed, RTOs would develop and implement tariffs providing a just and reasonable rate for energy purchases from eligible grid reliability and resiliency resources and the recovery of fully allocated costs and a fair ROE. This NOPR follows the August 23, 2017 release of the DOE’s study regarding whether federally controlled wholesale energy markets properly recognize the importance of coal and nuclear plants for the reliability of the high-voltage grid, as well as whether federal policies supporting renewable energy sources have harmed the reliability of the energy grid. The DOE has requested for the final rules to be effectiverulemaking. FirstEnergy participated in January 2018.
FERC is not required to adopt the rules proposed by the DOE in the NOPR. FERC could take other actions as it deems fit pursuant to its statutory authority. On October 2, 2017, FERC established a docket and requested comments on the NOPR. supplemental rulemaking that were submitted by a group of PJM transmission owners and by various industry trade groups. If there were to be any changes to FirstEnergy's transmission incentive ROE, such changes will be applied on a prospective basis.
Transmission Planning Supplemental Projects: Ohio Consumers Counsel v ATSI, et al.
On October 23, 2017, FESCSeptember 27, 2023, the OCC filed a complaint against ATSI, PJM and certainother transmission utilities in Ohio alleging that the PJM Tariff and operating agreement are unjust, unreasonable, and unduly discriminatory because they include no provisions to ensure PJM’s review and approval for the planning, need, prudence and cost-effectiveness of its affiliates submitted comments. Reply commentsthe PJM Tariff Attachment M-3 “Supplemental Projects.” Supplemental Projects are due November 7, 2017. At this time, weprojects that are uncertain asplanned and constructed to address local needs on the potential impacttransmission system. The OCC demands that final rules adopted byFERC: (i) require PJM to review supplemental projects for need, prudence and cost-effectiveness; (ii) appoint an independent transmission monitor to assist PJM in such review; and (iii) require that Supplemental Projects go into rate base only through a “stated rate” procedure whereby prior FERC if any,approval would have on FES and our strategic options,be needed for projects with costs that exceed an established threshold. ATSI and the timing thereof, with respect toother transmission utilities in Ohio and PJM filed comments and the competitive business.complaint is pending before FERC.
PATH Transmission Project
In 2012, the PJM Board of Managers canceled the PATH project, a proposed transmission line from West Virginia through Virginia and into Maryland. As a result of PJM canceling the project, approximately $62 million and approximately $59 million in costs incurred by PATH-Allegheny and PATH-WV, respectively, were reclassified from net property, plant and equipment to a regulatory asset for future recovery. PATH-Allegheny and PATH-WV requested authorization from FERC to recover the costs with a proposed ROE of 10.9% (10.4% base plus 0.5% for RTO membership) from PJM customers over five years. FERC issued an order denying the 0.5% ROE adder for RTO membership and allowing the tariff changes enabling recovery of these costs to become effective on December 1, 2012, subject to hearing and settlement procedures. On January 19, 2017, FERC issued an order reducing the PATH formula rate ROE from 10.4% to 8.11% effective January 19, 2017 and allowing recovery of certain related costs. On February 21, 2017, PATH filed a request for rehearing with FERC seeking recovery of disallowed costs and requesting that the ROE be reset to 10.4%. The Edison Electric Institute submitted an amicus curiae request for reconsideration in support of PATH. On March 20, 2017, PATH also submitted a compliance filing implementing the January 19, 2017 order. Certain affected ratepayers commented on the compliance filing, alleging inaccuracies in and lack of transparency of data and information in the compliance filing, and requested that PATH be directed to recalculate the refund provided in the filing. PATH responded to these comments in a filing that was submitted on May 22, 2017. On July 27, 2017, FERC Staff issued a letter to PATH requesting additional information on, and edits to, the compliance filing, as directed by the January 19, 2017 order. PATH filed its response on September 27, 2017.FERC orders on PATH's requests for rehearing and compliance filing remain pending.
Market-Based Rate Authority, Triennial Update
The Utilities, AE Supply, FES and its subsidiaries, Buchanan Generation, LLC, and Green Valley Hydro, LLC each hold authority from FERC to sell electricity at market-based rates. One condition for retaining this authority is that every three years each entity must file an update with the FERC that demonstrates that each entity continues to meet FERC’s requirements for holding market-based rate authority. On December 23, 2016, FESC, on behalf of its affiliates with market-based rate authority, submitted to FERC the most recent triennial market power analysis filing for each market-based rate holder for the current cycle of this filing requirement. On July 27, 2017, FERC accepted the triennial filing as submitted.
ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. PursuantWhile FirstEnergy’s environmental policies and procedures are designed to a March 28, 2017 executive order,achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and potential revision by 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.implementing agencies. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof in particular with respect to existing environmental regulations, may materially 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 SO2 and NOx emission reduction requirements under the CAA and SIP(s)SIP by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls generating more electricity from lower or non-emitting plants and/or using emission allowances.
CSAPR requires reductions of NOx and SO2 emissions in two phases (2015 and 2017), ultimately capping SO2 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 SO2 emission allowances between power plants located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. The U.S. Court of Appeals forOn July 28, 2015, the D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO2 emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia. This followsfollowed 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 ruleUpdate 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 ruleUpdate to the D.C. Circuit in November and December 2016. On September 6, 2017,13, 2019, 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, EPA’s reconsideration ofremanded the CSAPR update rule and how EPA and the states ultimately implement CSAPR, the future cost of compliance may be material and changesUpdate to FirstEnergy's and FES' 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 countiesciting that failthe rule did not eliminate upwind states’ significant contributions to attain the new 2015 ozone NAAQS by October 1, 2017. The EPA missed the October 1, 2017 deadline and has not yet promulgated thedownwind states’ air quality attainment designations. States will then have roughly threeyears to develop implementation plans to attain 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 and FES’ operations may result. In August 2016,requirements within applicable attainment deadlines.
Also in March 2018, 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 Delaware's CAA Section 126 petition by six months to April 7, 2017 but has not taken any further action. In November 2016, the State of MarylandNew York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from 36 EGUs, including Harrison Units 1, 2 and 3, Mansfield Unit 1 and Pleasants Units 1 and 2,nine states (including West Virginia) significantly contribute to Maryland'sNew York’s inability to attain the ozone NAAQS.National Ambient Air Quality Standards. The petition seeks NOxsought suitable emission rate limits for large stationary sources that are allegedly affecting New York’s air quality within the 36 EGUsthree years allowed by May 1, 2017.CAA Section 126. On January 3, 2017,September 20, 2019, the EPA extended the time frame for acting on thedenied New York’s CAA Section 126 petition by six months to July 15, 2017 but has not taken any further action.petition. On September 27, 2017 and October 4, 2017,29, 2019, the State of Maryland and various environmental organizations filed complaints inNew York appealed the U.S. District Court for the Districtdenial of Maryland seeking an order that EPA either approve or deny the CAA Section 126its petition of November 16, 2016. 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 electric generating units 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 August 3, 2015, FG, a wholly owned subsidiary of FES, submitted to the AAA office inD.C. Circuit. On July 14, 2020, the D.C. Circuit reversed and remanded the New York N.Y., a demand for arbitration and statement of claim against BNSF and CSX seeking a declaration that MATS constituted a force majeure event that excuses FG’s performance under its coal transportation contract with these parties. Specifically, the dispute arose from a contract for the transportation by BNSF and CSX of a minimum of 3.5 million tons of coal annually through 2025 to certain coal-fired power plants owned by FG that are located in Ohio. As a result of and in compliance with MATS, all plants covered by this contract were deactivated by April 16, 2015. Separately, on August 4, 2015, BNSF and CSX submittedpetition to the AAA office in Washington, D.C.,EPA for further consideration. On March 15, 2021, the EPA issued a demand for arbitration and statement of claim against FG allegingrevised CSAPR Update that FG breached the contract and that FG’s declaration of a force majeure under the contract is not valid and seeking damages under the contract through 2025. On May 31, 2016, the parties agreed to a
stipulation that if FG’s force majeure defense is determined to be wholly or partially invalid, liquidated damages are the sole remedy available to BNSF and CSX. The arbitration panel consolidated the claims and held a hearing in November and December 2016. On April 12, 2017, the arbitration panel ruled on liability in favor of BNSF and CSX. In the liability award, the panel found,addressed, among other things, that FG’s demand for declaratory judgment that force majeure excused FG’s performancethe remands of the prior CSAPR Update and the New York Section 126 petition. In December 2021, MP purchased NOx emissions allowances to comply with 2021 ozone season requirements. On April 6, 2022, the EPA published proposed rules seeking to impose further significant reductions in EGU NOx emissions in 25 upwind states, including West Virginia, with the stated purpose of allowing downwind states to attain or maintain compliance with the 2015 ozone National Ambient Air Quality Standards. On February 13, 2023, the EPA disapproved 21 SIPs, which was denied, that FG breached and repudiated the coal transportation contract and that the panel retains jurisdiction of claims for liquidated damagesa prerequisite for the years 2015-2025.EPA to issue a final Good Neighbor Plan or FIP. On May 1, 2017, FEJune 5, 2023, the EPA issued the final Good Neighbor Plan with an effective date 60 days thereafter. Certain states, including West Virginia, have appealed the disapprovals of their respective SIPs, and FGsome of those states have obtained stays of those disapprovals precluding the Good Neighbor Plan from taking effect in those states. On August 10, 2023, the 4th Circuit granted West Virginia an interim stay of the disapproval of its SIP and CSXon January 10, 2024, after a hearing held on October 27, 2023, granted a full stay which precludes the Good Neighbor Plan from going into effect in West Virginia. In addition to West Virginia, certain other states, and BNSF entered into a definitive settlement agreement, which resolved all claims related to this consolidated proceeding oncertain trade
organizations, including the terms and conditions set forth below. Pursuant to the settlement agreement, FG will pay CSX and BNSF an aggregate amount equal to $109 million which is payable in three annual installments, the firstMidwest Ozone Group of which was made on May 1, 2017. FE agreedis a member, have separately appealed and filed motions to unconditionally and continually guaranteestay the settlement payments due by FG pursuantGood Neighbor Plan itself at the D.C. Circuit. On September 25, 2023, the D.C. Circuit denied the motions to stay the termsGood Neighbor Plan. On October 13, 2023, the aggrieved parties filed an Emergency Application for an Immediate Stay of the settlement agreement. The settlement agreement further providesGood Neighbor Plan with the U.S. Supreme Court, which remains pending. Oral argument was heard on February 21, 2024.
Climate Change
In March 2024, the SEC issued final rules to require public companies to disclose certain climate-related information in registration statements and annual reports filed with the SEC. As adopted, the final climate disclosure rules mandate the disclosure of climate-related risks and the material impacts 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. Further, FE and FG, and CSX and BNSF, agreed to release, waive and discharge each other from any further obligations under the claims covered by the settlement agreement upon payment in full of the settlement amount. Until such time, CSX and BNSF will retain the claims covered by the settlement agreement and in the event of a bankruptcy proceeding with respect to FG, to the extent the remaining settlement payments are not paid in full by FG or FE, CSX and BNSF shall be entitled to seek damages for such claims in an amount to be determined by the arbitration panel or otherwise agreed by the parties.
On December 22, 2016, FG, a wholly owned subsidiary of FES, received a demand for arbitration and statement of claim from BNSF and NS, which are the counterparties to the coal transportation contract covering the delivery of 2.5 million tons annually through 2025, for FG’s coal-fired Bay Shore Units 2-4, deactivated on September 1, 2012, as a result of the EPA’s MATS and for FG’s W.H. Sammis generating station. The demand for arbitration was submitted to the AAA office in Washington, D.C. against FG alleging, among other things, that FG breached the agreement in 2015 and 2016 and repudiated the agreement for 2017-2025. The counterparties are seeking, among other things, damages, including lost profits through 2025, and a declaratory judgment that FG's claim of force majeure is invalid. The arbitration hearing is scheduled for June 2018. The parties have exchanged settlement proposals to resolve all claims related to this proceeding and all remaining claims. FirstEnergy and FES recorded a pre-tax charge of$55 million in the first quarter of 2017 based on an estimated settlement. If the dispute with BNSF and NS is not settled, the amount of damages owed to BNSF and NS could be materially higher and may cause FES to seek protection under U.S. bankruptcy laws. Absent a settlement, FG intends to vigorously assert its position in this arbitration proceeding, and if it were ultimately determined that the force majeure provisions or other defenses do not excuse the delivery shortfalls, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted.
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. AE Supply filed an answer denying any liability related to the termination. On May 1, 2017, the complaint was amended to add FE, FES and FG, although not parties to the underlying contract, as defendants and to seek additional damages based on new claims of fraud, unjust enrichment, promissory estoppel and alter ego. On June 27, 2017, after oral argument, defendants' preliminary objections to the amended complaint were denied. FE, FES, FG and AE Supply believe the merits of this case are distinguishable from the rail arbitration proceedings above based on the contract termssevere weather events and other elements of the case. There were approximately 5.5 million tons remaining under the contract for delivery. This matter is in the discovery phase of litigation and no trial date has been established. FE, FES, FG and AE Supply dispute the allegations and intendnatural conditions have had, or are reasonably likely to vigorously defend the merits of the lawsuit. At this time, FE, FES, FG and AE Supply cannot estimate the loss or range of loss regarding the ongoing litigation with respect to this agreement. Damages, if any, are yet to be determined, but an adverse outcome could be material.
In September 2007, AE received an NOV from the EPA alleging NSR and PSD violations under the CAA,have, on FirstEnergy, as well as Pennsylvaniadisclosures related to management and West Virginia state laws atFE Board oversight of such risks. In April 2024, the coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania andSEC voluntarily stayed the coal-fired Fort Martin and Willow Island plants in West Virginia. The EPA's NOV alleges equipment replacements during maintenance outages triggeredfinal climate disclosure rules pending resolution of legal challenges. FirstEnergy currently is assessing the pre-construction permitting requirements underimpact of the NSR and PSD programs. On June 29, 2012, January 31, 2013, March 27, 2013 and October 18, 2016, EPA issued CAA section 114 requests for the Harrison coal-fired plant seeking information and documentation relevant tofinal climate disclosure rules on its operation and maintenance, including capital projects undertaken since 2007. On December 12, 2014, EPA issued a CAA section 114 request for the Fort Martin coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2009. FirstEnergy intends to comply with the CAA but, at this time, is unable to predict the outcome of this matter or estimate the loss or range of loss.
Climate Change
FirstEnergy has established a goal to reduce CO2 emissions by 90% below 2005 levels by 2045.business. There are a number ofseveral initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the RGGIRegional Greenhouse Gas Initiative 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.
TheFirstEnergy has pledged to achieve carbon neutrality by 2050 in GHGs within FirstEnergy’s direct operational control (Scope 1). With respect to our coal-fired plants in West Virginia, we have identified that the end of the useful life date is 2035 for Fort Martin and 2040 for Harrison. Determination of the useful life of the regulated coal-fired generation could result in changes in depreciation, and/or continued collection of net plant in rates after retirement, securitization, sale, impairment, or regulatory disallowances. If MP is unable to recover these costs, it could have a material adverse effect on FirstEnergy’s and/or MP’s financial condition, results of operations, and cash flow. Furthermore, FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations.
In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse GasesGHGs under the Clean Air Act” in December 2009,Act,” concluding that concentrations of several key GHGs constitutesconstitute an "endangerment"“endangerment” and may be regulated as "air pollutants"“air pollutants” under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. On June 23, 2014,Subsequently, the U.S. Supreme Court decided that CO2 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 CO2CO2 emissions from existing fossil fuel fired electric generating units that would require each state to develop SIPs by September 6, 2016, to meet the EPA’s state specific CO2 emission rate goals. The EPA’s CPP allows states to request a two-year extension to finalize SIPs by September 6, 2018. If states fail to develop SIPs, the EPA also proposed a federal implementation plan that can be implemented by the EPA that included model emissions trading rules which states can also adopt in their SIPs. The EPA alsofuel-fired EGUs and finalized separate regulations imposing CO2CO2 emission limits for new, modified, and reconstructed fossil fuel fired electric generating units.fuel-fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the U.S. Court of Appeals for 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.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,June 19, 2019, the EPA issuedrepealed the CPP and replaced it with the ACE rule that established guidelines for states to develop standards of performance to address GHG emissions from existing coal-fired generation. On January 19, 2021, the D.C. Circuit vacated and remanded the ACE rule declaring that the EPA was “arbitrary and capricious” in its rule making and, as such, the ACE rule is no longer in effect and all actions thus far taken by states to implement the federally mandated rule are now null and void. Vacating the ACE rule had the unintended effect of reinstating the CPP because the repeal of the CPP was a provision within the ACE rule. The D.C. Circuit decision was appealed by several states and interested parties, including West Virginia, arguing that the EPA did not have the authorization under Section 111(d) of the CAA to require “generation shifting” as a way to limit GHGs. On June 30, 2022, the U.S. Supreme Court in West Virginia v. Environmental Protection Agency held that the method the EPA used to regulate GHGs (generation shifting) under Section 111(d) of the CAA (the CPP) was not authorized by Congress and remanded the rule to the EPA for further reconsideration. In response, on May 23, 2023, the EPA published a proposed rule pursuant to repealCAA Section 111 (b) and (d) in line with the CPP.decision in West Virginia v. Environmental Protection Agency intended to reduce power sector GHG emissions (primarily CO2 emissions) from fossil fuel based EGUs. The rule, which proposed stringent emissions limitations based on fuel type and unit retirement date, was issued as final by the EPA on April 25, 2024. FirstEnergy is currently assessing the impact of the final rule. Depending on the outcomesoutcome of the review pursuant to the executive order, of furtherany 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 resultedwith these standards could require additional capital expenditures or changes 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 joined in adopting the agreement reached on December 12, 2015operation 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 2016Ft. Martin 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 CO2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.Harrison power stations.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal CWAClean Water Act and its amendments, apply to FirstEnergy's plants.FirstEnergy’s facilities. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy'sFirstEnergy’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. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore plant's cooling water intake channel to divert fish away from the plant's cooling water intake system. Depending on the results of such studies and any final action taken by the states based on those studies, 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 were to 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 basedHowever, 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. DependingOn August 31, 2020, the EPA issued a final rule revising the effluent limits for discharges from wet scrubber systems, retaining the zero-discharge standard for ash transport water, (with some limited
discharge allowances), and extending the deadline for compliance to December 31, 2025 for both. In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system, and unit retirement date. On March 29, 2023, the EPA published proposed revised ELGs applicable to coal-fired power plants that include more stringent effluent limitations for wet scrubber systems and ash transport water, and new limits on landfill leachate. The rule was issued as final by the EPA on April 25, 2024 and depending on the outcome of appeals and how any final revised rules are ultimately implemented, the future costs of compliance with these standards may be substantialcould require additional capital expenditures or changes in operation at closed and changesactive landfills, and at the Ft. Martin and Harrison power stations from what was approved by the WVPSC in September 2022 to FirstEnergy's and FES' 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. Concurrentcomply with the issuance2020 ELG rule. FirstEnergy is currently assessing the impact 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.rule.
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,Resource Conservation and Recovery Act, as amended, and the Toxic Substances Control Act. Certain coal combustion residuals,CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA'sEPA’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 regardingfor 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 onOn July 29, 2020, the EPA published a final rule again revising the date that certain CCR impoundments must cease accepting waste and initiate closure to April 11, 2021. The final rule allowed for an assessmentextension of the finalized regulations,closure deadline based on meeting identified site-specific criteria. On November 30, 2020, AE Supply submitted a closure deadline extension request to the future cost of compliance and expected timing of spend had no significant impact on FirstEnergy's or FES' existing AROs associated with CCRs. Although not currently expected, any changes in timing and closure plan requirements inEPA seeking to extend the future, including changes resulting from the strategic review at CES, could materially and adversely impact FirstEnergy's and FES' AROs.
Pursuant to a 2013 consent decree, PA DEP issued a 2014 permitcease accepting waste date for the Little BlueMcElroy's Run CCR impoundment requiringfacility to October 2024, which request is pending technical review by the Bruce Mansfield plantEPA. AE Supply continues to ceaseoperate McElroy’s Run as a disposal of CCRs by December 31, 2016facility for Pleasants Power Station and FGcontinues to provide bondingevaluate closure options. Also, on April 25, 2024, the EPA issued rules as final addressing, 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 dewateringthe first time, certain legacy CCR disposal sites. FirstEnergy is currently assessing the impact 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 should 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. On September 14, 2017, 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, which is subject to a thirty-day comment period with final approval expected in November 2017.rule.
FirstEnergyFE 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 theFirstEnergy’s Consolidated Balance Sheets as of September 30, 2017March 31, 2024, based on estimates of the total costs of cleanup, FE's and its subsidiaries'FirstEnergy’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $131$97 million have been accrued through September 30, 2017. Included in the totalMarch 31, 2024, of which approximately $70 million are accrued liabilities of approximately $84 million for environmental remediation of former manufactured gas plantsMGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. FirstEnergysocietal benefits charge. 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 MattersUnited States v. Larry Householder, et al.
On July 21, 2020, a complaint and supporting affidavit containing federal criminal allegations were unsealed against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. In March 2023, a jury found Mr. Householder and his co-defendant, Matthew Borges, guilty and in June 2023, the two were sentenced to prison for 20 and 5 years, respectively. Messrs. Householder and Borges have appealed their sentences. Also, on July 21, 2020, and in connection with the DOJ’s investigation, FirstEnergy received subpoenas for records from the U.S. Attorney’s Office for the Southern District Ohio. FirstEnergy was not aware of the criminal allegations, affidavit or subpoenas before July 21, 2020.
On July 21, 2021, FE entered into a three-year DPA with the U.S. Attorney’s Office that, subject to court proceedings, resolves this matter. Under NRC regulations,the DPA, FE has agreed to the filing of a criminal information charging FE with one count of conspiracy to commit honest services wire fraud. The DPA requires that FirstEnergy, must ensure that adequate fundsamong other obligations: (i) continue to cooperate with the U.S. Attorney’s Office in all matters relating to the conduct described in the DPA and other conduct under investigation by the U.S. government; (ii) pay a criminal monetary penalty totaling $230 million within sixty days, which shall consist of (x) $115 million paid by FE to the United States Treasury and (y) $115 million paid by FE to the ODSA to fund certain assistance programs, as determined by the ODSA, for the benefit of low-income Ohio electric utility customers; (iii) publish a list of all payments made in 2021 to either 501(c)(4) entities or to entities known by FirstEnergy to be operating for the benefit of a public official, either directly or indirectly, and update the same on a quarterly basis during the term of the DPA; (iv) issue a public statement, as dictated in the DPA, regarding FE’s use of 501(c)(4) entities; and (v) continue to implement and review its compliance and ethics program, internal controls, policies and procedures designed, implemented and enforced to prevent and detect violations of the U.S. laws throughout its operations, and to take certain related remedial measures. The $230 million payment will neither be recovered in rates or charged to FirstEnergy customers, nor will FirstEnergy seek any tax deduction related to such payment. The entire amount of the monetary penalty was recognized as expense in the second quarter of 2021
and paid in the third quarter of 2021. Under the terms of the DPA, the criminal information will be availabledismissed after FirstEnergy fully complies with its obligations under the DPA.
Legal Proceedings Relating to decommissionUnited States v. Larry Householder, et al.
On August 10, 2020, the SEC, through its nuclear facilities. AsDivision of Enforcement, issued an order directing an investigation of possible securities laws violations by FE, and on September 30, 2017,1, 2020, issued subpoenas to FE and certain FE officers. On April 28, 2021, July 11, 2022, and May 25, 2023, the SEC issued additional subpoenas to FE, with which FE has complied. While no contingency has been reflected in its consolidated financial statements, FE believes that it is probable that it will incur a loss in connection with the resolution of the SEC investigation. Given the ongoing nature and complexity of the investigation, FE cannot yet reasonably estimate a loss or range of loss that may arise from the resolution of the SEC investigation.
On June 29, 2023, the OOCIC served FE a subpoena, seeking information relating to the conduct described in the DPA. FirstEnergy had approximately $2.6 billion(FES $1.8 billion) investedwas not aware of the OOCIC’s investigation prior to receiving the subpoena and understands that the OOCIC’s investigation is also focused on the conduct described in external truststhe DPA, other than with respect to the March 25, 2024, felony indictment of Mr. Householder brought in Cuyahoga County, Ohio. FirstEnergy is cooperating with the OOCIC in its investigation. On February 12, 2024, and in connection with the OOCIC’s ongoing investigation, an indictment by a grand jury of Summit County, Ohio was unsealed against the former chairman of the PUCO, Samuel Randazzo, and two former FirstEnergy senior officers, Charles E. Jones, and Michael J. Dowling, charging each of them with several felony counts, including bribery, telecommunications fraud, money laundering and aggravated theft, related to payments described in the DPA. FirstEnergy continues to both cooperate with the OOCIC in its investigation and discuss an appropriate resolution of the investigation with respect to FE. While no contingency has been reflected in FirstEnergy’s consolidated financial statements, FE believes that it is reasonably possible that it will incur a loss in connection with the resolution of the OOCIC investigation. Given the ongoing nature of the discussions, while FE cannot yet reasonably estimate a loss or range of loss that may arise from any resolution of the OOCIC investigation with respect to FE, any such payment by FE associated with an OOCIC resolution is not expected to be usedmaterial.
In addition to the subpoenas referenced above under “United States v. Larry Householder, et. al.” and the SEC investigation, certain FE stockholders and FirstEnergy customers filed several lawsuits against FirstEnergy and certain current and former directors, officers and other employees, and the complaints in each of these suits is related to allegations in the complaint and supporting affidavit relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. The plaintiffs in each of the below cases seek, among other things, to recover an unspecified amount of damages (unless otherwise noted). Unless otherwise indicated, no contingency has been reflected in FirstEnergy’s consolidated financial statements with respect to these lawsuits as a loss is neither probable, nor is a loss or range of a loss reasonably estimable.
•In re FirstEnergy Corp. Securities Litigation (S.D. Ohio); on July 28, 2020 and August 21, 2020, purported stockholders of FE filed putative class action lawsuits alleging violations of the federal securities laws. Those actions have been consolidated and a lead plaintiff, the Los Angeles County Employees Retirement Association, has been appointed by the court. A consolidated complaint was filed on February 26, 2021. The consolidated complaint alleges, on behalf of a proposed class of persons who purchased FE securities between February 21, 2017 and July 21, 2020, that FE and certain current or former FE officers violated Sections 10(b) and 20(a) of the Exchange Act by issuing misrepresentations or omissions concerning FE’s business and results of operations. The consolidated complaint also alleges that FE, certain current or former FE officers and directors, and a group of underwriters violated Sections 11, 12(a)(2) and 15 of the Securities Act of 1933 as a result of alleged misrepresentations or omissions in connection with offerings of senior notes by FE in February and June 2020. On March 30, 2023, the court granted plaintiffs’ motion for class certification. On April 14, 2023, FE filed a petition in the U.S. Court of Appeals for the decommissioning and environmental remediation of its nuclear generating facilities. The values of FirstEnergy's NDTs also fluctuate basedSixth Circuit seeking to appeal that order, which the Sixth Circuit granted on market conditions. IfNovember 16, 2023. On November 30, 2023, FE filed a motion with the valueS.D. Ohio to stay all proceedings pending the circuit court appeal. All discovery is stayed during the pendency of the trusts declinedistrict court motion. FE believes that it is probable that it will incur a loss in connection with the resolution of this lawsuit. Given the ongoing nature and complexity of such litigation, FE cannot yet reasonably estimate a loss or range of loss.
•MFS Series Trust I, et al. v. FirstEnergy Corp., et al. and Brighthouse Funds II – MFS Value Portfolio, et al. v. FirstEnergy Corp., et al. (S.D. Ohio) on December 17, 2021 and February 21, 2022, purported stockholders of FE filed complaints against FE, certain current and former officers, and certain current and former officers of EH. The complaints allege that the defendants violated Sections 10(b) and 20(a) of the Exchange Act by issuing alleged misrepresentations or omissions regarding FE’s business and its results of operations, and seek the same relief as the In re FirstEnergy Corp. Securities Litigation described above. All discovery is stayed during the pendency of the district court motion in In re FirstEnergy Corp. Securities Litigation described above. FE believes that it is probable that it will incur losses in connection with the resolution of these lawsuits. Given the ongoing nature and complexity of such litigation, FE cannot yet reasonably estimate a material amount, FirstEnergy's obligationloss or range of loss.
•State of Ohio ex rel. Dave Yost, Ohio Attorney General v. FirstEnergy Corp., et al. and City of Cincinnati and City of Columbus v. FirstEnergy Corp. (Common Pleas Court, Franklin County, OH, all actions have been consolidated); on September 23, 2020 and October 27, 2020, the OAG and the cities of Cincinnati and Columbus, respectively, filed complaints against several parties including FE, each alleging civil violations of the Ohio Corrupt Activity Act and related
claims in connection with the passage of HB 6. On January 13, 2021, the OAG filed a motion for a temporary restraining order and preliminary injunction against FirstEnergy seeking to fundenjoin FirstEnergy from collecting the trusts may increase. DisruptionsOhio Companies' decoupling rider. On January 31, 2021, FE reached a partial settlement with the OAG and the cities of Cincinnati and Columbus with respect to the temporary restraining order and preliminary injunction request and related issues. In connection with the partial settlement, the Ohio Companies filed an application on February 1, 2021, with the PUCO to set their respective decoupling riders (Conservation Support Rider) to zero. On February 2, 2021, the PUCO approved the application of the Ohio Companies setting the rider to zero, and no additional customer bills will include new decoupling rider charges after February 8, 2021. On August 13, 2021, new defendants were added to the complaint, including two former officers of FirstEnergy. On December 2, 2021, the cities and FE entered a stipulated dismissal with prejudice of the cities’ suit. This matter was stayed through a criminal trial in United States v. Larry Householder, et al. described above, but resumed pursuant to an order, dated March 15, 2023. On July 31, 2023, FE and other defendants filed motions to dismiss in part the OAG’s amended complaint, which the OAG opposed. On February 16, 2024, the OAG moved to stay discovery in the capital markets and their effectscase in light of the February 9, 2024, indictments against defendants in this action, which the court granted on particular businessesMarch 14, 2024. In connection with the ongoing OOCIC resolution discussions, FE is also discussing an appropriate settlement of this civil action with the OAG. As such, FE believes it is reasonably possible that it will incur a loss in connection with this civil action. Given the ongoing nature of these discussions, FE cannot yet reasonably estimate a loss or range of loss from any possible settlement of this civil action, however, any such settlement payment by FE is not expected to be material.
On February 9, 2022, FE, acting through the SLC, agreed to a settlement term sheet to resolve the following shareholder derivative lawsuits relating to HB 6 and the economy could also affectnow former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder that were filed in the valuesS.D. Ohio, the N.D. Ohio, and the Ohio Court of Common Pleas, Summit County:
•Gendrich v. Anderson, et al. and Sloan v. Anderson, et al. (Common Pleas Court, Summit County, Ohio, all actions have been consolidated); on July 26, 2020 and July 31, 2020, respectively, purported stockholders of FE filed shareholder derivative action lawsuits against certain current and former FE directors and officers, alleging, among other things, breaches of fiduciary duty.
•Miller v. Anderson, et al. (N.D. Ohio); Bloom, et al. v. Anderson, et al.; Employees Retirement System of the NDTs. City of St. Louis v. Jones, et al.; Electrical Workers Pension Fund, Local 103, I.B.E.W. v. Anderson et al.; Massachusetts Laborers Pension Fund v. Anderson et al.; The City of Philadelphia Board of Pensions and Retirement v. Anderson et al.; Atherton v. Dowling et al.; Behar v. Anderson, et al. (S.D. Ohio, all actions have been consolidated); beginning on August 7, 2020, purported stockholders of FE filed shareholder derivative actions alleging the FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act.
On March 11, 2022, the parties executed a stipulation and agreement of settlement, and filed a motion the same day requesting preliminary settlement approval in the S.D. Ohio, which the S.D. Ohio granted on May 9, 2022. Subsequently, following a hearing on August 4, 2022, the S.D. Ohio granted final approval of the settlement on August 23, 2022.
The settlement includes a series of corporate governance enhancements and a payment to FE of $180 million, to be paid by insurance after the judgment has become final, less approximately $36 million in court-ordered attorney’s fees awarded to plaintiffs. On September 20, 2022, a purported FE stockholder filed a motion for reconsideration of the S.D. Ohio’s final settlement approval. The parties filed oppositions to that motion on October 11, 2022, and the S.D. Ohio denied that motion on May 22, 2023. On June 15, 2023, the purported FE stockholder filed an appeal in the U.S. Court of Appeals for the Sixth Circuit. On February 16, 2024, the U.S. Court of Appeals for the Sixth Circuit affirmed the district court’s final settlement approval. Once all appeal options are exhausted the judgment will become final. The settlement agreement is expected to resolve fully these shareholder derivative lawsuits.
On June 2, 2022, the N.D. Ohio entered an order to show cause why the court should not appoint new plaintiffs’ counsel, and thereafter, on June 10, 2022, the parties filed a joint motion to dismiss the matter without prejudice, which the N.D. Ohio denied on July 5, 2022. On August 15, 2022, the N.D. Ohio issued an order stating its intention to appoint one group of applicants as new plaintiffs’ counsel, and on August 22, 2022, the N.D. Ohio ordered that any objections to the appointment be submitted by August 26, 2022. The parties filed their objections by that deadline, and on September 2, 2022, the applicants responded to those objections. In the meantime, on August 25, 2022, a purported FE stockholder represented by the applicants filed a motion to intervene, attaching a proposed complaint-in-intervention purporting to assert claims that the FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act as well as a claim against a third party for professional negligence and malpractice. The parties filed oppositions to that motion to intervene on September 8, 2022, and the proposed intervenor's reply in support of his motion to intervene was filed on September 22, 2022. On August 24, 2022, the parties filed a joint motion to dismiss the action pending in the N.D. Ohio based upon and in light of the approval of the settlement by the S.D. Ohio. On August 30, 2022, the parties filed a joint motion to dismiss the state court action, which the court granted on September 2, 2022. On September 29, 2023, the N.D. Ohio issued a stay of the case pending the appeal in the U.S. Court of Appeals for the Sixth Circuit. On April 12, 2024, the N.D. Ohio acknowledged the completion of the appeal and instructed the parties to file any further argument or information they wish to be considered by the N.D. Ohio no later than April 25, 2024.
As partIn letters dated January 26, and February 22, 2021, staff of routine inspectionsFERC's Division of the concrete shield building at Davis-Besse in 2013, FENOC identified changes to the subsurface laminar cracking condition originally discovered in 2011. These inspections revealedInvestigations notified FirstEnergy that the cracking condition had propagated a small amount in select areas. FENOC's analysis confirms that the building continuesDivision was conducting an investigation of FirstEnergy’s lobbying and governmental affairs activities concerning HB 6, and staff directed FirstEnergy to preserve and maintain its structural integrity,all documents and its ability to safely perform all of its functions. In a May 28, 2015, Inspection Report regarding the apparent cause evaluation on crack propagation, the NRC issued a non-cited violation for FENOC’s failure to request and obtain a license amendment for its method of evaluating the significance of the shield building cracking. The NRC also concluded that the shield building remained capable of performing its design safety functions despite the identified laminar cracking and that this issue was of very low safety significance. FENOC plans to submit a license amendment application to the NRCinformation related to the laminar cracking in the Shield Building.
On March 12, 2012, the NRC issued orders requiring safety enhancements at U.S. reactors based on recommendations from the lessons learned Task Force review of the accident at Japan's Fukushima Daiichi nuclear power plant. These orders require additional mitigation strategies for beyond-design-basis external events, and enhanced equipment for monitoring water levels in spent fuel pools. The NRC also requested that licensees including FENOC: re-analyze earthquake and flooding risks using the latest information available; conduct earthquake and flooding hazard walkdowns at their nuclear plants; assess the ability of current communications systems and equipment to perform under a prolonged loss of onsite and offsite electrical power; and assess plant staffing levels needed to fill emergency positions. Although a majority of the necessary modifications and evaluations at FirstEnergy’s nuclear facilitiessame as such have been completed, some still remain subjectdeveloped as part of an ongoing non-public audit being conducted by FERC's Division of Audits and Accounting. On December 30, 2022, FERC approved a Stipulation and Consent Agreement that resolves the investigation. The agreement includes a FirstEnergy admission of violating FERC’s “duty of candor” rule and related laws, and obligates FirstEnergy to regulatory reviewpay a civil penalty of $3.86 million, and to submit two annual compliance monitoring reports to FERC’s Office of Enforcement regarding improvements to FirstEnergy’s compliance programs. FE paid the civil penalty on January 4, 2023 and it will not be recovered from customers. The first annual compliance monitoring report was submitted in December 2023.
The outcome of any of these lawsuits, governmental investigations and audit is uncertain and could have a material adverse effect on FE’s or approval.its subsidiaries’ reputation, business, financial condition, results of operations, liquidity, and cash flows.
FES provides a parental support agreement to NG of up to $400 million. The NRC typically relies on such parental support agreements to provide additional assurance that U.S. merchant nuclear plants, including NG's nuclear units, have the necessary financial resources to maintain safe operations, particularly in the event of extraordinary circumstances. So long as FES remains in the unregulated companies’ money pool, the $500 million secured line of credit with FE discussed in Note 1, "Organization and Basis of Presentation - Going Concern at FES" above provides FES the needed liquidity in order for FES to satisfy its nuclear support obligations to NG.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy'sFirstEnergy’s normal business operations pending against FirstEnergy andFE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to FirstEnergyFE or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 10, "Regulatory Matters" of the Combined Notes to Consolidated Financial Statements.8, “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 FirstEnergyFE 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 FirstEnergy'sFE’s or its subsidiaries'subsidiaries’ financial condition, results of operations, and cash flows.
ASSET IMPAIRMENT
Competitive Generation Asset Sale
FirstEnergy announced in January 2017 that AE Supply and AGC had entered into an asset purchase agreement (which was subsequently amended and restated as described below) to sell four of AE Supply’s natural gas generating plants and approximately 59% of AGC’s interest in the Bath County pumped hydro facility (1,572 MWs of combined capacity) to a subsidiary of LS Power for an all-cash purchase price of $925 million, subject to customary and other closing conditions, including receipt of regulatory approvals from FERC and the VSCC, as applicable, and various third-party consents. On February 17, 2017, AE Supply and AGC submitted a filing with FERC and on June 13, 2017, FERC issued an order authorizing such transaction as described in the January 2017 asset purchase agreement. On September 29, 2017, the parties filed a request with FERC for authorization to transfer the related hydroelectric license for Bath County under Part I of the FPA. Additional filings have been submitted to FERC for the purpose of amending affected FERC-jurisdictional rates and implementing the transaction once all regulatory approvals are obtained. Additionally, the consent of VEPCO is needed for the sale of AGC’s interest in the Bath County pumped hydro facility, as well as agreement among AGC, LS Power and VEPCO with respect to certain amendments to the Bath County project agreements.
On August 30, 2017, the parties, along with AE Supply's subsidiary BU Energy, executed an amended and restated asset purchase agreement to (1) reduce the purchase price to $825 million, subject to adjustments, (2) add BU Energy’s 50% interest in a joint venture that owns the Buchanan Generating Facility (43 MWs) to the transaction and (3) provide that each component of the transaction (i.e., the AE Supply natural gas facilities, AGC’s interest in the Bath County hydroelectric power station and BU Energy’s interest in the Buchanan Generating Facility) may close independently. The sale of the AE Supply natural gas generating plants is expected to close in the fourth quarter of 2017 and the sale of approximately 59% of AGC’s interests in the Bath County hydroelectric power station and BU Energy’s 50% interest in the Buchanan Generating Facility are expected to close in the first quarter of 2018, subject in each case to various customary and other closing conditions including, without limitation, receipt of regulatory approvals and third-party consents, including the consent of VEPCO as discussed above. Under the amended and restated purchase agreement, AE Supply has agreed to satisfy and discharge all of its approximately $305 million of currently outstanding senior
notes, which is expected to require the payment of a “make-whole” premium currently estimated to be approximately $100 million based on current interest rates, upon both (i) the consummation of the sale of the natural gas generating plants and (ii) either (a) the consummation of the sale of approximately 59% of AGC's interest in the Bath County hydroelectric power station or (b) the consummation of the pending sale of the Pleasants Power Station by AE Supply to its affiliate, MP. As a further condition to closing, FE will provide the purchaser two limited three-year guarantees of certain obligations of AE Supply and AGC arising under the amended and restated purchase agreement. On September 29, 2017, the parties filed an application with FERC for authorization to complete the Buchanan Generating Facility sale. On October 20, 2017, the parties filed an application with the VSCC for approval of the sale of approximately 59% of AGC's interest in the Bath County hydroelectric power station. There can be no assurance that all regulatory approvals will be obtained and/or all closing conditions will be satisfied or that any of the transactions will be consummated.
As a result of the amended asset purchase agreement, CES recorded non-cash pre-tax impairment charges of $158 million in the nine-month period ended September 30, 2017.
NEW ACCOUNTING PRONOUNCEMENTSChanges in Cash Position
Recently Adopted Pronouncements
ASU 2016-09, "ImprovementsAs of March 31, 2024, FirstEnergy had $888 million of cash and cash equivalents and $27 million of restricted cash as compared to Employee Share-Based Payment Accounting" (Issued March 2016): ASU 2016-09 simplifies several aspects$137 million of the accounting for employee share-based payments. The new guidance requires all income tax effectscash and cash equivalents and $42 million of awards to be recognized in the income statement when the awards vest or are settled. It also does not require liability accounting when an employer repurchases more of an employee’s shares for tax withholding purposes. FirstEnergy adopted ASU 2016-09 on January 1, 2017. Upon adoption, FirstEnergy elected to account for forfeitures as they occur. The change was applied on a modified retrospective basis with a cumulative effect adjustment to retained earnings of approximately $6 millionrestricted cash as of January 1, 2017. Additionally, FirstEnergy retrospectively appliedDecember 31, 2023, on the Consolidated Balance Sheets.
The following table summarizes the major classes of cash flow presentation requirement to presentitems:
| | | | | | | | | | | | | | |
| | For the Three Months Ended March 31, |
| (In millions) | | 2024 | | 2023 |
| | | | |
| Net cash used for operating activities | | $ | (40) | | | $ | (112) | |
| Net cash used for investing activities | | (870) | | | (716) | |
| Net cash provided from financing activities | | 1,646 | | | 828 | |
| Net change in cash, cash equivalents, and restricted cash | | 736 | | | — | |
| | | | |
| Cash, cash equivalents, and restricted cash at beginning of period | | 179 | | | 206 | |
| Cash, cash equivalents, and restricted cash at end of period | | $ | 915 | | | $ | 206 | |
Cash Flows From Operating Activities
FirstEnergy’s most significant sources of cash paid to tax authorities when shares are withheld to satisfy statutory tax withholding obligations as financing activitiesderived from electric service provided by reclassifying $12 millionits operating subsidiaries. The most significant use of cash from operating activities is buying electricity to financingserve non-shopping customers, return of cash collateral associated with certain generation suppliers that serve shopping customers, pension contributions and paying fuel suppliers, employees, tax authorities, lenders and others for a wide range of materials and services.
Cash used for operating activities was $40 million and $112 million in the first three months of 2024 and 2023, respectively. Cash flows from operating activities were a net outflow in the first quarter of 2024, primarily due to working capital, including prepaid and accrued tax payments associated with Pennsylvania gross receipts tax payments and timing of property tax payments. Compared to the same period of 2023, the decrease in cash used for operating activities is primarily due to:
•Lower payments, primarily on generation energy purchases for certain customers, net of related customer receivable receipts;
•The decrease in return of cash collateral to certain generation suppliers that serve shopping customers that was previously received as a result of changes in power prices;
•Higher net transmission revenue collection based on the timing of formula rate collections; and
•Higher returns from distribution, integrated, and transmission capital investments;
The decrease in cash used for operating activities was partially offset by:
•Lower dividend distribution received by FEV from its equity investments in Global Holding; and
•Higher payments associated with Pennsylvania gross receipts taxes.
Cash Flows From Investing Activities
Cash used for investing activities in the 2016first three months of 2024 principally represented cash used for capital investments. The following table summarizes investing activities for the first three months of 2024 and 2023:
| | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended March 31, |
| Cash Used for Investing Activities | | 2024 | | 2023 | | Increase (Decrease) |
| | (In millions) |
| Capital investments: | | | | | | |
| Distribution Segment | | $ | 215 | | | $ | 193 | | | $ | 22 | |
| Integrated Segment | | 313 | | | 237 | | | 76 | |
| Stand-Alone Transmission Segment | | 258 | | | 212 | | | 46 | |
| Corporate / Other Segment | | 4 | | | 7 | | | (3) | |
| | | | | | |
| | | | | | |
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| Asset removal costs | | 78 | | | 60 | | | 18 | |
| Other | | 2 | | | 7 | | | (5) | |
| | $ | 870 | | | $ | 716 | | | $ | 154 | |
| | | | | | |
Cash used for investing activities for the first three months of 2024 increased $154 million, compared to the same period of 2023, primarily due to capital investments.
Cash Flows From Financing Activities
In the first three months of 2024 and 2023, cash provided from financing activities was $1,646 million and $828 million, respectively. The following table summarizes financing activities for the first three months of 2024 and 2023:
| | | | | | | | | | | | | | |
| | For the Three Months Ended March 31, |
| Financing Activities | | 2024 | | 2023 |
| | | (In millions) |
| | | | |
| New Issues: | | | | |
| Unsecured notes | | $ | 150 | | | $ | 900 | |
| | | | |
| | | | |
| FMBs | | — | | | 50 | |
| | | | |
| | $ | 150 | | | $ | 950 | |
| | | | |
| Redemptions / Repayments: | | | | |
| | | | |
| Unsecured notes | | $ | — | | | $ | (300) | |
| | | | |
| | | | |
| Senior secured notes | | (23) | | | (21) | |
| | | $ | (23) | | | $ | (321) | |
| | | | |
| Proceeds from FET Equity Interest Sale | | $ | 2,300 | | | $ | — | |
| Noncontrolling interest cash distributions | | (8) | | | (17) | |
| | | | |
| | | | |
| Short-term borrowings, net | | (525) | | | 450 | |
| | | | |
| | | | |
| Common stock dividend payments | | (235) | | | (223) | |
| Other | | (13) | | | (11) | |
| | $ | 1,646 | | | $ | 828 | |
FirstEnergy had the following issuances and redemptions during the three months ended March 31, 2024:
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| Company | Type | Issuance Date | Interest Rate | Maturity | Amount (In millions) | Description |
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| Issuance |
| ATSI | Senior Unsecured Note | March, 2024 | 5.63% | 2034 | $150 | Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes. |
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In March 2024, notice of redemption was provided for all remaining $463 million of FE’s 7.375% Notes, due 2031, which was completed on April 15, 2024, with a make-whole premium of approximately $80 million. Due to the redemption, the $463 million remaining notes are included within currently payable long-term debt on the Consolidated StatementBalance Sheets as of Cash Flow.March 31, 2024.
ASU 2016-15, "ClassificationOn April 1, 2024, JCP&L redeemed its $500 million 4.70% unsecured notes that became due.
On April 15, 2024, MP redeemed its $400 million 4.10% FMBs that became due.
On April 18, 2024, MAIT agreed to sell $250 million of Certain Cash Receiptsnew 5.94% Unsecured Notes due May 1, 2034. The sale is expected to settle on May 2, 2024. Proceeds are expected to be used to repay short-term borrowings, to finance capital expenditures and Cash Payments" (Issued August 2016): The standard is intendedfor other general corporate purposes.
FE or its affiliates may, from time to eliminate diversity in practice in how certain cash receiptstime, seek to retire or purchase outstanding debt through open-market purchases, privately negotiated transactions or otherwise. Such repurchases, if any, will be upon such terms and cash paymentsat such prices as FE or its affiliates may determine, and will depend on prevailing market conditions, liquidity requirements, contractual restrictions and other factors.
GUARANTEES AND OTHER ASSURANCES
FirstEnergy has various financial and performance guarantees and indemnifications, which are presented and classifiedissued in the normal course of business. These contracts include performance guarantees, stand-by LOCs, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. The maximum potential amount of future payments FE and its subsidiaries could be required to make under these guarantees as of March 31, 2024, was $820 million, as summarized below:
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| Guarantees and Other Assurances | | Maximum Exposure |
| | (In millions) |
| | |
| | |
| | |
| | |
| | |
| | |
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| | |
FE’s Guarantees on Behalf of its Consolidated Subsidiaries(1) | | |
| Deferred compensation arrangements | | $ | 430 | |
| Vehicle leases | | 75 | |
| | |
| Other | | 15 | |
| | 520 | |
| | |
| FE’s Guarantees on Other Assurances | | |
Surety Bonds(2) | | 182 | |
| | |
| Deferred compensation arrangements | | 114 | |
| LOCs | | 4 | |
| | 300 | |
| | |
| | |
| | |
| | |
| | |
| | |
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| Total Guarantees and Other Assurances | | $ | 820 | |
(1) During the third quarter of 2023, FE was required by PJM to issue a guarantee to cover non-performance until FE PA is able to provide audited financial statements to PJM, which is expected to occur in early 2025. The guarantee is expected to be immaterial to FE.
(2) During the second quarter of 2023, FE was released from its $169 million surety bond to the Pennsylvania Department of Environmental Protection related to the Little Blue Run Disposal Impoundment.
Collateral and Contingent-Related Features
In the normal course of business, FE and its subsidiaries may enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain agreements contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE’s or its subsidiaries’ credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.
As of March 31, 2024, $119 million of net cash collateral has been posted by FE or its subsidiaries and is included in “Prepaid taxes and other current assets” on FirstEnergy’s Consolidated Balance Sheets. FE or its subsidiaries are holding $33 million of net cash collateral as of March 31, 2024, from certain generation suppliers, and such amount is included in “Other current liabilities” on FirstEnergy’s Consolidated Balance Sheets.
These credit-risk-related contingent features stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of March 31, 2024:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Potential Collateral Obligations | | | | | | Utilities and Transmission Companies | | FE | | Total |
| | | (In millions) |
| Contractual obligations for additional collateral | | | | | | | | | | |
| | | | | | | | | | |
| Upon further downgrade | | | | | | $ | 63 | | | $ | — | | | $ | 63 | |
| | | | | | | | | | |
Surety bonds (collateralized amount)(1) | | | | | | 87 | | | 79 | | | 166 | |
| Total Exposure from Contractual Obligations | | | | | | $ | 150 | | | $ | 79 | | | $ | 229 | |
(1) Surety bonds are not tied to a credit rating. Surety bonds’ impact assumes maximum contractual obligations, which is ordinarily 100% of the face amount of the surety bond except with respect to $39 million of surety bond obligations for which the collateral obligation is capped at 60% of the face amount, and typical obligations require 30 days to cure.
MARKET RISK INFORMATION
FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Enterprise Risk Management Committee, comprised of members of senior management, provides general oversight for risk management activities throughout FirstEnergy.
Commodity Price Risk
FirstEnergy has limited exposure to financial risks resulting from fluctuating commodity prices, such as prices for electricity, coal and energy transmission. FirstEnergy’s Risk Management Department and Enterprise Risk Management Committee are responsible for promoting the effective design and implementation of sound risk management programs and overseeing compliance with corporate risk management policies and established risk management practice.
The valuation of derivative contracts is based on observable market information. As of March 31, 2024, FirstEnergy has a net liability of $1 million in non-hedge derivative contracts that are related to FTRs at certain of the Utilities. FTRs are subject to regulatory accounting and do not impact earnings. See Note 6, “Fair Value Measurements,” of the Notes to Consolidated Financial Statements for additional details on FirstEnergy’s FTRs.
Equity Price Risk
As of Cash Flows,March 31, 2024, the FirstEnergy pension plan assets were allocated approximately as follows: 30% in equity securities, 22% in fixed income securities, 7% in alternatives, 11% in real estate, 19% in private debt/equity, 5% in derivatives and 6% in cash and short-term securities. As discussed above, FirstEnergy made a $750 million voluntary cash contribution to the qualified pension plan on May 12, 2023. FirstEnergy does not currently expect to have a required contribution to the pension plan until 2028, which based on various assumptions, including an expected rate of return on assets of 8.0%, is expected to be approximately $260 million. However, FirstEnergy may elect to contribute to the presentationpension plan voluntarily.
As of debtMarch 31, 2024, FirstEnergy’s OPEB plan assets were allocated approximately as follows: 51% in equity securities, 43% in fixed income securities and 6% in cash and short-term securities. See Note 4, “Pension and Other Post-Employment Benefits,” of the Notes to Consolidated Financial Statements for additional details on FirstEnergy’s pension and OPEB plans.
In the three months ended March 31, 2024, FirstEnergy’s OPEB plan assets have gained approximately 4.9% as compared to an annualized expected return on plan assets of 7.0%. In the three months ended March 31, 2024, FirstEnergy’s pension plan assets have lost approximately 0.1% as compared to an annualized expected return on plan assets of 8.0%.
Interest Rate Risk
FirstEnergy recognizes net actuarial gains or losses for its pension and OPEB plans in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. A primary factor contributing to these actuarial gains and losses are changes in the discount rates used to value pension and OPEB obligations as of the measurement date and the difference between expected and actual returns on the plans’ assets.
The remaining components of pension and OPEB expense, primarily service costs, interest cost on obligations, expected return on plan assets and amortization of prior service costs, are set at the beginning of the calendar year (unless a remeasurement is triggered) and are recorded on a monthly basis. Changes in asset performance and discount rates will not impact these pension costs for 2024, unless an additional remeasurement were to be triggered during the year, however, future years could be impacted by changes in the market.
FirstEnergy utilizes a spot rate approach in the estimation of the components of benefit cost by applying specific spot rates along the full yield curve to the relevant projected cash flows. As of March 31, 2024, the spot rate was 5.28% and 5.22% for pension and OPEB obligations, respectively, as compared to 5.05% and 4.97% as of December 31, 2023, respectively.
The final discount rate and return or loss on plan assets as of the year-end remeasurement date is difficult to predict based on the currently volatile equity markets and interest rate environment. As a result, FirstEnergy is unable to determine or meaningfully project the mark-to-market adjustment, or estimate a reasonable range of adjustment, that will be recorded as of December 31, 2024.
FirstEnergy’s 2021 Credit Facilities and 2023 Credit Facilities bear interest at fluctuating interest rates, primarily based on SOFR, including term SOFR and daily simple SOFR. FirstEnergy has not hedged its interest rate exposure with respect to its floating rate debt. Accordingly, FirstEnergy’s interest expense for any particular period will fluctuate based on SOFR and other variable interest rates. The high interest rate environment has caused the rate and interest expense on borrowings under the various FirstEnergy credit facilities to be significantly higher.
Economic Conditions
Post-pandemic economic conditions have increased supply chain lead times across numerous material categories, with some as much as tripling from pre-pandemic lead times. Several key suppliers have struggled with labor shortages and raw material availability, which along with inflationary pressure that appears to be moderating, have increased costs and decreased the availability of certain materials, equipment and contractors. FirstEnergy has taken steps to mitigate these risks and does not currently expect service disruptions or any material impact on its capital spending plan. However, the situation remains fluid and a prolonged continuation or further increase in supply chain disruptions could have an adverse effect on FirstEnergy’s results of operations, cash flow and financial condition.
CREDIT RISK
Credit risk is the risk that FirstEnergy would incur a loss as a result of nonperformance by counterparties of their contractual obligations. FirstEnergy maintains credit policies and procedures with respect to counterparty credit (including a requirement that counterparties maintain specified credit ratings) and requires other assurances in the form of credit support or collateral in certain circumstance in order to limit counterparty credit risk. FirstEnergy has concentrations of suppliers and customers among electric utilities, financial institutions and energy marketing and trading companies. These concentrations may impact FirstEnergy’s overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions. In the event an energy supplier of the Ohio Companies, FE PA, JCP&L or PE defaults on its obligation, the affected company would be required to seek replacement power in the market. In general, subject to regulatory review or other processes, it is expected that appropriate incremental costs incurred by these entities would be recoverable from customers through applicable rate mechanisms, thereby mitigating the financial risk for these entities. FirstEnergy’s credit policies to manage credit risk include the use of an established credit approval process, daily credit mitigation provisions, such as margin, prepayment or debt extinguishment costs, allcollateral requirements. FirstEnergy and its subsidiaries may request additional credit assurance, in certain circumstances, in the event that the counterparties’ credit ratings fall below investment grade, their tangible net worth falls below specified percentages or their exposures exceed an established credit limit.
OUTLOOK
INCOME TAXES
On August 16, 2022, President Biden signed into law the IRA of 2022, which, will be classified as financing activities. ASU 2016-15among other things, imposes a new 15% corporate AMT based on AFSI applicable to corporations with a three-year average AFSI over $1 billion. The AMT is effective for fiscal years,the 2023 tax year and, forif applicable, corporations must pay the greater of the regular corporate income tax or the AMT. Although NOL carryforwards created through the regular corporate income tax system cannot be used to reduce the AMT, financial statement net operating losses can be used to reduce AFSI and the amount of AMT owed. The IRA of 2022 as enacted requires the U.S. Treasury to provide regulations and other guidance necessary to administer the AMT, including further defining allowable adjustments to determine AFSI, which directly impacts the amount of AMT to be paid. Based on interim periods within those fiscal years, beginning after December 15, 2017. FirstEnergy early adopted this ASU as of January 1, 2017. There was no impact to prior periods.
Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASBU.S. Treasury during 2022 and 2023, FirstEnergy continues to believe that it is more likely than not it will be subject to the AMT beginning with 2023. Accordingly, FirstEnergy made a first quarter estimated payment of AMT of approximately $49 million in April 2023, however, made no additional payments in 2023 based on various factors, including additional guidance from the U.S. Treasury that eliminated the requirement of corporations to include AMT in quarterly estimated tax payments. Until final U.S. Treasury regulations are issued, the amount of AMT FirstEnergy pays could be significantly different than current estimates or it may not be a payer at all. The regulatory treatment of the impacts of this legislation may also be subject to regulation by FERC and/or applicable state regulatory authorities. Any adverse development in this legislation, including guidance from the U.S. Treasury and/or the IRS or unfavorable regulatory treatment, could negatively impact FirstEnergy’s cash flows, results of operations and financial condition.
As discussed above, on March 25, 2024, FirstEnergy closed on the sale of an additional 30% interest in FET, realizing an approximate $7.3 billion tax gain from the combined sale of 49.9% of the membership interests in FET for the consideration received and recapture of negative tax basis in FET. In the first quarter of 2024, FirstEnergy recognized a net tax charge of approximately $46 million, comprised of updates to estimated deferred tax liability for the deferred gain from the 19.9% sale of FET in May 2022, deferred tax liability related to its ongoing investment in FET, and valuation allowance associated with the expected utilization of certain state NOL carryforwards impacted by the sale and the PA Consolidation. During the first quarter of 2024, FirstEnergy also recognized a reduction to OPIC of approximately $797 million for federal and state income tax associated with the tax gain from closing on the 30% interest sale. As of December 31, 2023, FirstEnergy had approximately $8.1 billion of gross federal NOL carryforwards which will be used to offset a majority of the tax gain from the FET Equity Interest Sale and expected taxable income in 2024, however due to certain limitations on utilization enacted in the Tax Act, a portion of the NOL will carry into 2025 and possibly beyond. As a result of the additional 30% sale, FET and its subsidiaries deconsolidated from FirstEnergy’s consolidated federal income tax group and now constitute their own consolidated federal income tax group subject to their own income tax allocation agreement.
STATE REGULATION
Each of the Utilities' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE and TrAIL in Virginia, ATSI in Ohio, the Transmission Companies in Pennsylvania, PE and MP in West Virginia, and PE in Maryland are subject to certain regulations of the VSCC, PUCO, PPUC, WVPSC, and MDPSC, respectively. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission facility.
MARYLAND
PE operates under MDPSC approved base rates that were effective as of October 19, 2023, and that were subsequently modified by an MDPSC order dated January 3, 2024, which became effective as of March 1, 2024. PE also provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third-party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS.
The EmPOWER Maryland program requires each electric utility to file a plan to reduce electric consumption and demand 0.2% per year, up to the ultimate goal of 2% annual savings. PE recovers program investments with a return through an annually reconciled surcharge, with most costs subject to recovery over a five-year period with a return on the unamortized balance. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding. On August 1, 2023, PE filed its proposed plan for the 2024-2026 cycle as required by the MDPSC. Consistent with a December 29, 2022, order by the MDPSC phasing out the ability of Maryland utilities to earn a return on EmPOWER investments, PE will be required to expense 33% of its EmPOWER program costs in 2024, 67% in 2025 and 100% in 2026. Notwithstanding the order to phase out PE’s ability to earn a return on its EmPOWER investments, all previously unamortized costs for prior cycles will continue to earn a return and be collected by the end of 2029, consistent with the plan PE submitted on January 11, 2023. In the 2024-2026 order issued on December 29, 2023, the period to pay down the amortized balances was extended through the end of 2031. Additionally at the direction of the MDPSC, PE together with other Maryland utilities are required to address GHG reductions in addition to energy efficiency. In compliance with the MDPSC directive, PE submitted three scenarios with projected costs over a three-year cycle of $310 million, $354 million, and $510 million, respectively. The MDPSC conducted hearings on the proposed plans for all Maryland utilities on November 6-8, 2023. On December 29, 2023, the MDPSC issued an order approving the $310 million scenario for most programs, with some modifications. On February 21, 2024, the MDPSC approved PE’s tariff to recover costs in 2024 but directed PE to analyze alternative amortization methods for possible use in later years.
NEW JERSEY
JCP&L operates under NJBPU approved rates that took effect as of February 15, 2024, and will become effective for customers as of June 1, 2024. JCP&L provides BGS for retail customers who do not choose a third-party EGS and for customers of third- party EGSs that fail to provide the contracted service. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates.
The base rate increase, which was approved by the NJBPU on February 14, 2024, took effect on February 15, 2024, and is effective for customers on June 1, 2024. Until those new rates became effective for customers, JCP&L is amortizing an existing regulatory liability totaling approximately $18 million to offset the base rate increase that otherwise would have occurred in this period. Under the base rate case settlement agreement, JCP&L also agreed to a two-phase reliability improvement plan to enhance the reliability related to 18 high-priority circuits, the first phase of which began on February 14, 2024, and represents an approximate investment of $95 million. Additionally, JCP&L recognized a $53 million pre-tax charge in the first quarter 2024 at
the Integrated segment within “Other operating expenses” on the FirstEnergy Consolidated Statements of Income, associated with certain corporate support costs recorded to capital accounts from the FERC Audit that were determined, as a result of the settlement agreement, to be disallowed from future recovery.
JCP&L has implemented energy efficiency and peak demand reduction programs in accordance with the New Jersey Clean Energy Act as approved by the NJBPU in April 2021. The NJBPU approved plans include recovery of lost revenues resulting from the programs and a three-year plan (July 2021-June 2024) including total program costs of $203 million, of which $160 million of investment is recovered over a ten-year amortization period with a return as well as $43 million in operations and maintenance expenses and financing costs recovered on an annual basis. On December 5, 2023, JCP&L filed a petition with the NJBPU for a six-month extension of EE&C Plan I, which was originally scheduled to end on June 30, 2024, but would end on December 31, 2024, with the extension. The proposed budget for the extension period would add approximately $69 million to the original program cost. Under the proposal, JCP&L would recover the costs of the extension period and the revenue impact of sales losses resulting therefrom through two separate tariff riders. On December 1, 2023, JCP&L filed a related petition with the NJBPU requesting approval of its EE&C Plan II, which covers the January 1, 2025 through June 30, 2027 period and has a proposed budget of approximately $964 million. EE&C Plan II consists of a portfolio of ten energy efficiency programs, one peak demand reduction program and one building decarbonization program. Under the proposal, JCP&L would recover its EE&C Plan II revenue requirements and lost revenues from reduced electricity sales associated with EE&C Plan II. Evidentiary hearings are scheduled to begin August 19, 2024, with a final NJBPU decision and order required no later than October 15, 2024.
The settlement of the distribution rate case in 2020, provided among other things, that JCP&L would be subject to a management audit, which began in May 2021. On April 12, 2023, the NJBPU accepted the final management audit report for filing purposes and ordered that interested stakeholders file comments on the report by May 22, 2023, which deadline was extended until July 31, 2023. JCP&L filed its comments on July 31, 2023. The parties have filed responses.
On September 17, 2021, in connection with Mid-Atlantic Offshore Development, LLC, a transmission company jointly owned by Shell New Energies US and EDF Renewables North America, JCP&L submitted a proposal to the NJBPU and PJM to build transmission infrastructure connecting offshore wind-generated electricity to the New Jersey power grid. On October 26, 2022, the JCP&L proposal was accepted, in part, in an order issued by NJBPU. The proposal, as accepted, included approximately $723 million in investments for JCP&L to both build new and upgrade existing transmission infrastructure. JCP&L’s proposal projects an investment ROE of 10.2% and includes the option for JCP&L to acquire up to a 20% equity stake in Mid-Atlantic Offshore Development, LLC. The resulting rates associated with the project are expected to be shared among the ratepayers of all New Jersey electric utilities. On April 17, 2023, JCP&L applied for the FERC “abandonment” transmission rates incentive, which would provide for recovery of 100% of the cancelled prudent project costs that are incurred after the incentive is approved, and 50% of the costs incurred prior to that date, in the event that some or all of the project is cancelled for reasons beyond JCP&L’s control. FERC staff subsequently requested additional information on JCP&L’s application, which JCP&L provided. On August 21, 2023, FERC approved JCP&L’s application, effective August 22, 2023. On October 31, 2023, offshore wind developer, Orsted, announced plans to cease development of two offshore wind projects in New Jersey—Ocean Wind 1 and 2—having a combined planned capacity of 2,248 MWs. At this time, Orsted’s announcement does not affect JCP&L’s awarded projects and JCP&L is moving forward with preconstruction activities for the planned transmission infrastructure. Construction is expected to begin in 2025.
Consistent with the commitments made in its proposal to the NJBPU, JCP&L formally submitted in November 2023 the first part of its application to the United States Department of Energy to finance a portion of the project using low-interest rate loans available under the United States Department of Energy’s Energy Infrastructure Reinvestment Program of the IRA of 2022. JCP&L submitted the second part of its two-part application on March 13, 2024.
On April 3, 2024, Mid-Atlantic Offshore Development, LLC submitted a bid application for the NJBPU Prebuild Infrastructure Solicitation to the NJBPU which outlines its proposal to construct infrastructure connecting the identified landing point for offshore wind generation off the coast of New Jersey with the high-voltage electric grid at Larrabee Collector Station. JCP&L is described in the application as a joint developer with Mid-Atlantic Offshore Development, LLC, subject to the execution of a joint development agreement by the parties. Mid-Atlantic Offshore Development, LLC will be the party responsible for the project.
On November 9, 2023, JCP&L filed a petition for approval of its second EnergizeNJ with the NJBPU that would, among other things, support grid modernization, system resiliency and substation modernization in technologies designed to provide enhanced customer benefits. JCP&L proposes EnergizeNJ will be implemented over a five-year budget period with estimated costs of approximately $935 million over the deployment period, of which, $906 million is capital investments and $29 million is operating and maintenance expenses. Under the proposal, the costs of EnergizeNJ would be recovered through JCP&L’s base rates via annual and semi-annual base rate adjustment filings. Public hearings have been requested but are not yet scheduled. JCP&L has requested that the NJBPU issue a final decision and order no later than May 22, 2024, based on a June 1, 2024, commencement date for EnergizeNJ. JCP&L anticipates filing amendments to the EnergizeNJ program after receipt of approval from the NJBPU of the base rate case stipulation that was filed on February 2, 2024. On February 14, 2024, the NJBPU approved the stipulated settlement between JCP&L and various parties, resolving JCP&L’s request for a distribution base rate increase. On February 27, 2024, as part of the stipulated settlement, JCP&L amended its pending EnergizeNJ petition following receipt of NJBPU approval of the base rate case settlement, to include the second phase of its reliability improvement plan that is
expected to address any remaining high-priority circuits not addressed in the first phase. EnergizeNJ, as amended, if approved will result in the investment of approximately $930.5 million of total estimated costs over five years.
OHIO
The Ohio Companies operate under PUCO-approved base distribution rates that became effective in 2009. The Ohio Companies currently operate under ESP IV, which continues through May 31, 2024, that provides for the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continues the Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with revenue caps of $15 million per year through May 31, 2024. In addition, ESP IV includes: (1) continuation of a base distribution rate freeze through May 31, 2024; (2) a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045; and (3) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio.
On April 5, 2023, the Ohio Companies filed an application with the PUCO for approval of ESP V, for an eight-year term beginning June 1, 2024, and continuing through May 31, 2032. ESP V proposes to continue providing power to non-shopping customers at market-based prices set through an auction process, with process enhancements designed to reduce costs to customers. ESP V also proposes to continue riders supporting investment in the Ohio Companies’ distribution system, including Rider DCR with annual revenue cap increases of $15 million to $21 million per year, based on reliability performance, and Rider AMI for recovery of approved grid modernization investments. ESP V proposes new riders to support continued maintenance of the distribution system, including vegetation management and storm restoration operating expense. In addition, ESP V proposes four-year energy efficiency and peak demand reduction programs for residential and commercial customers, with cost recovery spread over eight years. ESP V further includes a commitment to spend $52 million in total over the eight-year term, without recovery from customers, on initiatives to assist low-income customers, education and incentives to help ensure customers have good experiences with electric vehicles. Hearings commenced on November 7, 2023 and concluded on December 6, 2023. On December 6, 2023, certain intervenors filed a motion requesting a limited stay of the Ohio Companies’ proposal to continue Rider DCR. The Ohio Companies contested the motion, which is pending.
On May 16, 2022, the Ohio Companies filed their application for determination of the existence of SEET under ESP IV for calendar year 2021, which demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings. This matter remains pending before the PUCO.
On July 15, 2022, the Ohio Companies filed an application with the PUCO for approval of phase two of their distribution grid modernization plan that would, among other things, provide for the installation of an additional 700 thousand smart meters, distribution automation equipment on approximately 240 distribution circuits, voltage regulating equipment on approximately 220 distribution circuits, and other investments and pilot programs in related technologies designed to provide enhanced customer benefits. The Ohio Companies propose that phase two will be implemented over a four-year budget period with estimated capital investments of approximately $626 million and operations and maintenance expenses of approximately $144 million over the deployment period. Under the proposal, costs of phase two of the grid modernization plan would be recovered through the Ohio Companies’ AMI rider, pursuant to the terms and conditions approved in ESP IV. On April 12, 2024, the Ohio Companies and certain of the parties filed a stipulation that modified the Ohio Companies’ application for phase two of its grid modernization plan. The stipulation, which is subject to PUCO approval, provides for the deployment of smart meters to the balance of the Ohio Companies’ customers or approximately 1.4 million meters. Phase two of the distribution grid modernization plan, as modified by the stipulation would be completed over a four-year budget period with estimated capital investments of approximately $421 million. On April 16, 2024, the PUCO scheduled the stipulation hearing for June 5, 2024.
On September 8, 2020, the OCC filed motions in the Ohio Companies’ corporate separation audit and DMR audit dockets, requesting the PUCO to open an investigation and management audit, hire an independent auditor, and require FirstEnergy to show it did not improperly use money collected from consumers or violate any utility regulatory laws, rules or orders in its activities regarding HB 6. On December 30, 2020, in response to the OCC's motion, the PUCO reopened the DMR audit docket, and directed PUCO staff to solicit a third-party auditor and conduct a full review of the DMR to ensure funds collected from customers through the DMR were only used for the purposes established in ESP IV. On June 2, 2021, the PUCO selected an auditor, and the auditor filed the final audit report on January 14, 2022, which made certain findings and recommendations. The report found that spending of DMR revenues was not required to be tracked, and that DMR revenues, like all rider revenues, are placed into the regulated money pool as a matter of routine, where the funds lose their identity. Therefore, the report could not suggest that DMR funds were used definitively for direct or indirect support for grid modernization. The report also concluded that there was no documented evidence that ties revenues from the DMR to lobbying for the passage of HB 6, but also could not rule out with certainty uses of DMR funds to support the passage of HB 6. The report further recommended that the regulated companies' money pool be audited more frequently and the Ohio Companies adopt formal dividend policies. Final comments and responses were filed by parties during the second quarter of 2022. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner consolidated this proceeding with the expanded Rider DCR audit proceeding described below and set a procedural schedule, which was vacated on March 15, 2024. A new procedural schedule will be set at a May 21, 2024 prehearing conference.
On September 15, 2020, the PUCO opened a new proceeding to review the political and charitable spending by the Ohio Companies in support of HB 6 and the subsequent referendum effort, and directing the Ohio Companies to show cause, demonstrating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by customers. The Ohio Companies initially filed a response stating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by customers, but on August 6, 2021, filed a supplemental response explaining that, in light of the facts set forth in the DPA and the findings of the Rider DCR audit report further discussed below, political or charitable spending in support of HB 6, or the subsequent referendum effort, affected pole attachment rates paid by approximately $15 thousand. On October 26, 2021, the OCC filed a motion requesting the PUCO to order an independent external audit to investigate FE’s political and charitable spending related to HB 6, and to appoint an independent review panel to retain and oversee the auditor. In November and December 2021, parties filed comments and reply comments regarding the Ohio Companies’ original and supplemental responses to the PUCO’s September 15, 2020, show cause directive. On May 4, 2022, the PUCO selected a third-party auditor to determine whether the show cause demonstration submitted by the Ohio Companies is sufficient to ensure that the cost of any political or charitable spending in support of HB 6 or the subsequent referendum effort was not included, directly or indirectly, in any rates or charges paid by ratepayers. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner directed the third-party auditor to file its report by August 28, 2024.
In connection with an ongoing audit of the Ohio Companies’ policies and procedures relating to the code of conduct rules between affiliates, on November 4, 2020, the PUCO initiated an additional corporate separation audit as a result of the FirstEnergy leadership transition announcement made on October 29, 2020, as further discussed below. The additional audit is to ensure compliance by the Ohio Companies and their affiliates with corporate separation laws and the Ohio Companies’ corporate separation plan. The additional audit is for the period from November 2016 through October 2020. The final audit report was filed on September 13, 2021. The audit report makes no findings of major non-compliance with Ohio corporate separation requirements, minor non-compliance with eight requirements, and findings of compliance with 23 requirements. Parties filed comments and reply comments on the audit report. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner set a procedural schedule, which was vacated on March 15, 2024. A new procedural schedule will be set at an April 25, 2024 prehearing conference.
In connection with an ongoing annual audit of the Ohio Companies’ Rider DCR for 2020, and as a result of disclosures in FirstEnergy’s Form 10-K for the year ended December 31, 2020 (filed on February 18, 2021), the PUCO expanded the scope of the audit on March 10, 2021, to include a review of certain transactions that were either improperly classified, misallocated, or lacked supporting documentation, and to determine whether funds collected from customers were used to pay the vendors, and if so, whether or not the funds associated with those payments should be returned to customers through Rider DCR or through an alternative proceeding. On August 3, 2021, the auditor filed its final report on this phase of the audit, and the parties submitted comments and reply comments on this audit report in October 2021. Additionally, on September 29, 2021, the PUCO expanded the scope of the audit in this proceeding to determine if the costs of the naming rights for FirstEnergy Stadium have been adopted. Unlessrecovered from the Ohio Companies’ customers. On November 19, 2021, the auditor filed its final report, in which the auditor concluded that the FirstEnergy Stadium naming rights expenses were not recovered from Ohio customers. On December 15, 2021, the PUCO further expanded the scope of the audit to include an investigation into an apparent nondisclosure of a side agreement in the Ohio Companies’ ESP IV settlement proceedings, but stayed its expansion of the audit until otherwise indicated,ordered by the PUCO. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner consolidated this proceeding with the Rider DMR audit proceeding described above, further lifted the stay of the portion of the investigation relating to an apparent nondisclosure of a side agreement, and set a procedural schedule, which was vacated on March 15, 2024. A new procedural schedule will be set at a May 21, 2024 prehearing conference.
On March 1, 2024, the Attorney Examiner issued an Entry in all four PUCO investigations that, among other things, precluded taking or offering the testimony of Charles E. Jones, Michael J. Dowling, or Samuel Randazzo through deposition or other means, or requiring these individuals to produce documents, in any PUCO proceeding, until otherwise ordered.
On September 22, 2023, OCC filed an application for rehearing challenging the PUCO’s August 23, 2023, order to stay the pending HB 6 related matters above, which the PUCO denied on October 18, 2023. On November 17, 2023, OCC filed an application for rehearing challenging the October 18, 2023 entry to the extent the PUCO decided not to stay pending proceedings regarding ESP V as well as phases one and two of the Ohio Companies’ distribution grid modernization plans. On November 27, 2023, the Ohio Companies filed a memorandum contra OCC’s application for rehearing.
In the fourth quarter of 2020, motions were filed with the PUCO requesting that the PUCO amend the Ohio Companies’ riders for collecting the OVEC-related charges required by HB 6 to provide for refunds in the event such provisions of HB 6 are repealed. Neither the Ohio Companies nor FE benefit from the OVEC-related charges the Ohio Companies collect. Instead, the Ohio Companies are further required by HB 6 to remit all the OVEC-related charges they collect to non-FE Ohio electric distribution utilities. The Ohio Companies contested the motions, which are pending before the PUCO.
On May 15, 2023, the Ohio Companies filed their application for determination of the existence of SEET under ESP IV for calendar year 2022, which demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings. This matter remains pending before the PUCO.
See below for additional details on the government investigations and subsequent litigation surrounding the investigation of HB 6.
PENNSYLVANIA
The Pennsylvania Companies operated under rates approved by the PPUC, effective as of January 27, 2017. On January 1, 2024, each of the Pennsylvania Companies merged with and into FE PA. As a result of the PA Consolidation, FE PA will have five rate districts in Pennsylvania – four that correspond to the territories previously serviced by ME, PN, Penn, and WP and one rate district that corresponds to WP’s service provided to The Pennsylvania State University. The rate districts created by the PA Consolidation will not reach full rate unity until the earlier of 2033 or the conclusion of three base rate cases filed after January 1, 2025.
Pursuant to Pennsylvania Act 129 of 2008 and PPUC orders, the Pennsylvania Companies implemented energy efficiency and peak demand reduction programs with demand reduction targets, relative to 2007-2008 peak demands, at 2.9% MW for ME, 3.3% MW for PN, 2.0% MW for Penn, and 2.5% MW for WP; and energy consumption reduction targets, as a percentage of the Pennsylvania Companies’ historic 2009 to 2010 reference load at 3.1% MWh for ME, 3.0% MWh for PN, 2.7% MWh for Penn, and 2.4% MWh for WP. The fourth phase of FE PA’s energy efficiency and peak demand reduction program, which runs for the five-year period beginning June 1, 2021 through May 31, 2026, was approved by the PPUC on June 18, 2020, providing through cost recovery of approximately $390 million to be recovered through Energy Efficiency and Conservation Phase IV Riders for each FE PA rate district.
Pennsylvania EDCs are permitted to seek PPUC approval of an LTIIP for infrastructure improvements and costs related to highway relocation projects, after which a DSIC may be approved to recover LTIIP costs. On January 16, 2020, the PPUC approved the Pennsylvania Companies’ LTIIPs for the five-year period beginning January 1, 2020 and ending December 31, 2024 for a total capital investment of approximately $572 million for certain infrastructure improvement initiatives. FE PA expects to seek approval for the next phase of its LTIIP program by the end of the third quarter of 2024.
Following the Pennsylvania Companies’ 2016 base rate proceedings, the PPUC ruled in a separate proceeding related to the DSIC mechanisms that the Pennsylvania Companies were not required to reflect federal and state income tax deductions related to DSIC-eligible property in DSIC rates. The decision was appealed to the Pennsylvania Supreme Court and in July 2021 the court upheld the Pennsylvania Commonwealth Court’s reversal of the PPUC’s decision and remanded the matter back to the PPUC for determination as to how DSIC calculations shall account for accumulated deferred income taxes and state taxes. The PPUC issued the order as directed.
On May 5, 2023, FirstEnergy and Brookfield submitted applications to FERC and to the PPUC to facilitate the FET Equity Interest Sale. On May 12, 2023, the parties also filed an application with the VSCC, which was approved on June 20, 2023. On August 14, 2023, FERC issued an order approving the FET Equity Interest Sale. On November 24, 2023, CFIUS notified FET, Brookfield and the Abu Dhabi Investment Authority, as an indirect investor in FET through Brookfield, that it had determined that there were no unresolved national security issues and its review of the transaction was concluded. On November 29, 2023, the parties filed a settlement agreement recommending that the PPUC approve the transaction subject to the terms of the settlement, which includes among other things, a number of ring-fencing provisions and a commitment to improve transmission reliability over the next five years. The settlement was approved by the PPUC on March 14, 2024. The transaction closed on March 25, 2024.
On April 2, 2024, FE PA filed a base rate case with the PPUC, based on a projected 2025 annual test year. The rate case requests a net increase in base distribution revenues of approximately $502 million with a return on equity of 11.3% and capital structure of 46.2% debt and 53.8% equity, and reflects a roll-in of several current riders such as DSIC, Tax Act and smart meter. The increase represents an overall net average rate increase in FE PA rates by approximately 7.7%, and a 10.5% average residential rate increase. Key components of the base rate case filing include a proposal to change pension and OPEB recovery to the delayed recognition method and to implement a mechanism to establish a regulatory asset (or liability) to recover (or refund) net differences between the amount of pension and OPEB expense requested in the proceeding and the actual annual amount each year using this method. Additionally, FE PA requests recovery of certain incurred costs, including the impact of major storms, COVID-19, a program to convert streetlights to LEDs, and others. The PPUC issued an order on April 25, 2024, deferring, by operation of law, the June 1, 2024 statutory effective date to January 1, 2025. A pre-hearing conference is scheduled for May 2, 2024. A PPUC decision is expected in December 2024, with new rates becoming effective in January 2025.
WEST VIRGINIA
MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operate under WVPSC-approved rates. 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 August 31, 2023, MP and PE filed with the WVPSC their annual ENEC case requesting an increase in ENEC rates of $167.5 million beginning January 1, 2024, which represents a 9.9% increase in overall rates. This increase, which was driven primarily by higher fuel expenses, includes the approximate $92 million carried over from the 2022 ENEC proceeding and a portion of the approximately $267 million under recovery balance at the end of the review period (July 1, 2022 to June 30, 2023). The remaining $75.6 million of the under recovery balance not recovered in 2024 will be deferred for collection during 2025, with an annual carrying charge of 4%. A hearing was held on November 30, 2023, at which time a joint stipulation for settlement that was agreed to by all but one party was presented to the WVPSC. The settlement provides for a net $55.4 million increase in ENEC rates beginning March 27, 2024 with the net deferred ENEC balance of approximately $255 million to be recovered through 2026. There will be no 2024 ENEC case unless MP and PE over or under recover more than $50 million than the 2024 ENEC balance and a party elects to invoke a case filing. An order was issued on March 26, 2024 approving the settlement without modification and rates became effective on March 27, 2024.
On April 21, 2022, the WVPSC issued an order approving, effective May 1, 2022, a tariff to offer solar power to West Virginia customers and requiring MP and PE to subscribe at least 85% of the planned 50 MWs of solar generation before seeking final tariff approval. MP and PE must seek separate approval from the WVPSC to recover any solar generation costs in excess of the approved tariff. On April 24, 2023, MP and PE sought final tariff approval from the WVPSC for three of the five solar sites, representing 30 MWs of generation, and requested approval of a surcharge to recover any costs above the final approved tariff. The first solar generation site went into service in January 2024 and construction of the remaining four sites are expected to be completed no later than the end of 2025 at a total investment cost of approximately $110 million. On August 23, 2023, the WVPSC approved the customer surcharge and granted approval to construct three of the five solar sites. The surcharge went into effect January 1, 2024.
On January 13, 2023, MP and PE filed a request with the WVPSC seeking approval of new depreciation rates for existing and future capital assets. Specifically, MP and PE are seeking to increase depreciation expense by approximately $76 million per year, primarily for regulated generation-related assets. Any depreciation rates approved by the WVPSC would not become effective until new base rates were established. On August 22, 2023, a unanimous settlement of the case was filed recommending a $33 million per year increase in depreciation expense, effective April 1, 2024. An order from the WVPSC was issued on March 26, 2024 approving the settlement without modification and became effective on March 27, 2024.
On May 31, 2023, MP and PE filed a base rate case with the WVPSC requesting a total revenue increase of approximately $207 million utilizing a test year of 2022 with adjustments plus a request to establish a regulatory asset (or liability) to recover (or refund) in a subsequent base rate case the net differences between the amount of pension and OPEB expense requested in the proceeding (based on average expense from 2018 to 2022) and the actual annual amount each year using the delayed recognition method. Among other things, the increase includes the approximate $76 million requested in a depreciation case filed on January 13, 2023 and described above, and amounts to support a new low-income customer advocacy program, storm restoration work and service reliability investments. On January 23, 2024, MP, PE and various parties filed a joint settlement agreement with the WVPSC, which recommended a base rate increase of $105 million, inclusive of the $33 million increase in depreciation expense. Additionally, the settlement includes a new low-income customer advocacy program, a pilot program for service reliability investments and recovery of costs related to storm restoration, retired generation assets and COVID-19. The settlement did not include the request to establish a regulatory asset (or liability) for recover (or refund) associated with pension and OPEB expense, however, it did not preclude MP and PE from pursuing that in a future separate proceeding. On February 16, 2024, interested parties filed a settlement on the net energy metering credit for consideration by the WVPSC. An order was issued on March 26, 2024 approving the $105 million increase and accepting the settlement with slight non-material modifications with new rates going into effect on March 27, 2024. Additionally, due to the order including approval by the WVPSC to recover certain costs associated with retired generation assets, MP recognized a $60 million pre-tax benefit in the first quarter of 2024 to establish a regulatory asset.
FERC REGULATORY MATTERS
Under the Federal Power Act, FERC regulates rates for interstate wholesale sales and transmission of electric power, regulatory accounting and reporting under the Uniform System of Accounts, and other matters, including construction and operation of hydroelectric projects. With respect to their wholesale services and rates, the Utilities, AE Supply and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE and the Transmission Companies are subject to functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff. On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo.
FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers to entry into markets. The Utilities and AE Supply each have the necessary authorization from FERC to sell their
wholesale power, if any, in interstate commerce at market-based rates, although in the case of the Utilities major wholesale purchases remain subject to review and regulation by the relevant state commissions.
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, and the Transmission Companies. NERC is the Electric Reliability Organization 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 six regional entities, including RFC. All of the facilities that FirstEnergy operates 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 material compliance with all currently effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy’s part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, or obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations, and cash flows.
FERC Audit
FERC’s Division of Audits and Accounting initiated a nonpublic audit of FESC in February 2019. Among other matters, the audit is evaluating FirstEnergy’s compliance with certain accounting and reporting requirements under various FERC regulations. On February 4, 2022, FERC filed the final audit report for the period of January 1, 2015 through September 30, 2021, which included several findings and recommendations that FirstEnergy has accepted. The audit report included a finding and related recommendation on FirstEnergy’s methodology for allocation of certain corporate support costs to regulatory capital accounts under certain FERC regulations and reporting. Effective in the first quarter of 2022 and in response to the finding, FirstEnergy had implemented a new methodology for the allocation of these corporate support costs to regulatory capital accounts for its regulated distribution and transmission companies on a prospective basis. With the assistance of an independent outside firm, FirstEnergy completed an analysis during the third quarter of 2022 of these costs and how it impacted certain FERC-jurisdictional wholesale transmission customer rates for the audit period of 2015 through 2021. As a result of this analysis, FirstEnergy recorded in the third quarter of 2022 approximately $45 million ($34 million after-tax) in expected customer refunds, plus interest, due to its wholesale transmission customers and reclassified approximately $195 million of certain transmission capital assets to operating expenses for the audit period, of which $90 million ($67 million after-tax) are not expected to be recoverable and impacted FirstEnergy’s earnings since they relate to costs capitalized during stated transmission rate time periods. FirstEnergy is currently recovering approximately $105 million of costs reclassified to operating expenses in its transmission formula rate revenue requirements, of which $39 million of costs have been recovered as of March 31, 2024. On December 8, 2023, FERC audit staff issued a letter advising that two unresolved audit matters, primarily related to FirstEnergy’s plan to recover the reclassified operating expenses in formula transmission rates, were being referred to other offices within FERC for further review. These reclassifications also resulted in a reduction to the Regulated Transmission segment’s rate base by approximately $160 million, which is not expected to materially impact FirstEnergy or the segment’s future earnings. The expected wholesale transmission customer refunds were recognized as a reduction to revenue, and the amount of reclassified transmission capital assets that are not expected to be recoverable were recognized within “Other operating expenses” at the Regulated Transmission segment and on FirstEnergy’s Consolidated Statements of Income. Furthermore, FirstEnergy’s Utilities are in the process of addressing the outcomes of the FERC Audit with the applicable state commissions and proceedings, which includes seeking continued rate base treatment of approximately $200 million of certain corporate support costs allocated to distribution capital assets in Ohio and Pennsylvania. If FirstEnergy is unable to recover these transmission or distribution costs, it could result in future charges and/or adjustments and have an adverse impact on FirstEnergy’s financial condition.
ATSI ROE – Ohio Consumers Counsel v. ATSI, et al.
On February 24, 2022, the OCC filed a complaint with FERC against ATSI, AEP’s Ohio affiliates and American Electric Power Service Corporation, and Duke Energy Ohio, LLC asserting that FERC should reduce the ROE utilized in the utilities’ transmission formula rates by eliminating the 50 basis point adder associated with RTO membership, effective February 24, 2022. The OCC contends that this result is required because Ohio law mandates that transmission owning utilities join an RTO and that the 50 basis point adder is applicable only where RTO membership is voluntary. On December 15, 2022, FERC denied the complaint as to ATSI and Duke, but granted it as to AEP. AEP and OCC appealed FERC’s orders to the Sixth Circuit and the case remains pending. FirstEnergy is unable to predict the outcome of this proceeding, but it is not expected to have a material impact.
Transmission ROE Methodology
A proposed rulemaking proceeding concerning transmission rate incentives provisions of Section 219 of the 2005 Energy Policy Act was initiated in March of 2020 remains pending before FERC. Among other things, the rulemaking explored whether utilities should collect an “RTO membership” ROE incentive adder for more than three years. FirstEnergy is a member of PJM and its transmission subsidiaries could be affected by the proposed rulemaking. FirstEnergy participated in comments on the supplemental rulemaking that were submitted by a group of PJM transmission owners and by various industry trade groups. If there were to be any changes to FirstEnergy's transmission incentive ROE, such changes will be applied on a prospective basis.
Transmission Planning Supplemental Projects: Ohio Consumers Counsel v ATSI, et al.
On September 27, 2023, the OCC filed a complaint against ATSI, PJM and other transmission utilities in Ohio alleging that the PJM Tariff and operating agreement are unjust, unreasonable, and unduly discriminatory because they include no provisions to ensure PJM’s review and approval for the planning, need, prudence and cost-effectiveness of the PJM Tariff Attachment M-3 “Supplemental Projects.” Supplemental Projects are projects that are planned and constructed to address local needs on the transmission system. The OCC demands that FERC: (i) require PJM to review supplemental projects for need, prudence and cost-effectiveness; (ii) appoint an independent transmission monitor to assist PJM in such review; and (iii) require that Supplemental Projects go into rate base only through a “stated rate” procedure whereby prior FERC approval would be needed for projects with costs that exceed an established threshold. ATSI and the other transmission utilities in Ohio and PJM filed comments and the complaint is pending before FERC.
ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. While FirstEnergy’s environmental policies and procedures are designed to achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and potential revision by the implementing agencies. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof may materially impact its business, results of operations, cash flows and financial condition.
Clean Air Act
FirstEnergy complies with SO2 and NOx emission reduction requirements under the CAA and SIP by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls and/or using emission allowances.
CSAPR requires reductions of NOx and SO2 emissions in two phases (2015 and 2017), ultimately capping SO2 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 SO2 emission allowances between power plants located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. On July 28, 2015, the D.C. Circuit ordered the EPA to reconsider the CSAPR caps on NOx and SO2 emissions from power plants in 13 states, including West Virginia. This followed the 2014 U.S. Supreme Court ruling generally upholding the EPA’s regulatory approach under CSAPR but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR Update on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR Update to the D.C. Circuit in November and December 2016. On September 13, 2019, the D.C. Circuit remanded the CSAPR Update to the EPA citing that the rule did not eliminate upwind states’ significant contributions to downwind states’ air quality attainment requirements within applicable attainment deadlines.
Also in March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from nine states (including West Virginia) significantly contribute to New York’s inability to attain the ozone National Ambient Air Quality Standards. The petition sought suitable emission rate limits for large stationary sources that are allegedly affecting New York’s air quality within the three years allowed by CAA Section 126. On September 20, 2019, the EPA denied New York’s CAA Section 126 petition. On October 29, 2019, the State of New York appealed the denial of its petition to the D.C. Circuit. On July 14, 2020, the D.C. Circuit reversed and remanded the New York petition to the EPA for further consideration. On March 15, 2021, the EPA issued a revised CSAPR Update that addressed, among other things, the remands of the prior CSAPR Update and the New York Section 126 petition. In December 2021, MP purchased NOx emissions allowances to comply with 2021 ozone season requirements. On April 6, 2022, the EPA published proposed rules seeking to impose further significant reductions in EGU NOx emissions in 25 upwind states, including West Virginia, with the stated purpose of allowing downwind states to attain or maintain compliance with the 2015 ozone National Ambient Air Quality Standards. On February 13, 2023, the EPA disapproved 21 SIPs, which was a prerequisite for the EPA to issue a final Good Neighbor Plan or FIP. On June 5, 2023, the EPA issued the final Good Neighbor Plan with an effective date 60 days thereafter. Certain states, including West Virginia, have appealed the disapprovals of their respective SIPs, and some of those states have obtained stays of those disapprovals precluding the Good Neighbor Plan from taking effect in those states. On August 10, 2023, the 4th Circuit granted West Virginia an interim stay of the disapproval of its SIP and on January 10, 2024, after a hearing held on October 27, 2023, granted a full stay which precludes the Good Neighbor Plan from going into effect in West Virginia. In addition to West Virginia, certain other states, and certain trade
organizations, including the Midwest Ozone Group of which FE is a member, have separately appealed and filed motions to stay the Good Neighbor Plan itself at the D.C. Circuit. On September 25, 2023, the D.C. Circuit denied the motions to stay the Good Neighbor Plan. On October 13, 2023, the aggrieved parties filed an Emergency Application for an Immediate Stay of the Good Neighbor Plan with the U.S. Supreme Court, which remains pending. Oral argument was heard on February 21, 2024.
Climate Change
In March 2024, the SEC issued final rules to require public companies to disclose certain climate-related information in registration statements and annual reports filed with the SEC. As adopted, the final climate disclosure rules mandate the disclosure of climate-related risks and the material impacts that severe weather events and other natural conditions have had, or are reasonably likely to have, on FirstEnergy, as well as disclosures related to management and FE Board oversight of such risks. In April 2024, the SEC voluntarily stayed the final climate disclosure rules pending resolution of legal challenges. FirstEnergy currently is assessing the impact of the final climate disclosure rules on its business. There are several initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the Regional Greenhouse Gas Initiative 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.
FirstEnergy has pledged to achieve carbon neutrality by 2050 in GHGs within FirstEnergy’s direct operational control (Scope 1). With respect to our coal-fired plants in West Virginia, we have identified that the end of the useful life date is 2035 for Fort Martin and 2040 for Harrison. Determination of the useful life of the regulated coal-fired generation could result in changes in depreciation, and/or continued collection of net plant in rates after retirement, securitization, sale, impairment, or regulatory disallowances. If MP is unable to recover these costs, it could have a material adverse effect on FirstEnergy’s and/or MP’s financial condition, results of operations, and cash flow. Furthermore, FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations.
In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for GHGs under the Clean Air Act,” concluding that concentrations of several key GHGs constitute an “endangerment” and may be regulated as “air pollutants” under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. Subsequently, the EPA released its final CPP regulations in August 2015 to reduce CO2 emissions from existing fossil fuel-fired EGUs and finalized separate regulations imposing CO2 emission limits for new, modified, and reconstructed fossil fuel-fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court. On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On June 19, 2019, the EPA repealed the CPP and replaced it with the ACE rule that established guidelines for states to develop standards of performance to address GHG emissions from existing coal-fired generation. On January 19, 2021, the D.C. Circuit vacated and remanded the ACE rule declaring that the EPA was “arbitrary and capricious” in its rule making and, as such, the ACE rule is no longer in effect and all actions thus far taken by states to implement the federally mandated rule are now null and void. Vacating the ACE rule had the unintended effect of reinstating the CPP because the repeal of the CPP was a provision within the ACE rule. The D.C. Circuit decision was appealed by several states and interested parties, including West Virginia, arguing that the EPA did not have the authorization under Section 111(d) of the CAA to require “generation shifting” as a way to limit GHGs. On June 30, 2022, the U.S. Supreme Court in West Virginia v. Environmental Protection Agency held that the method the EPA used to regulate GHGs (generation shifting) under Section 111(d) of the CAA (the CPP) was not authorized by Congress and remanded the rule to the EPA for further reconsideration. In response, on May 23, 2023, the EPA published a proposed rule pursuant to CAA Section 111 (b) and (d) in line with the decision in West Virginia v. Environmental Protection Agency intended to reduce power sector GHG emissions (primarily CO2 emissions) from fossil fuel based EGUs. The rule, which proposed stringent emissions limitations based on fuel type and unit retirement date, was issued as final by the EPA on April 25, 2024. FirstEnergy is currently assessing the impact such guidance mayof the final rule. Depending on the outcome of any appeals, compliance with these standards could require additional capital expenditures or changes in operation at the Ft. Martin and Harrison power stations.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy’s facilities. In addition, the states in which FirstEnergy operates have on its financial statementswater quality standards applicable to FirstEnergy’s operations.
On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and disclosures,nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations were to phase-in 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 2016 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 2016 Annual Report on Form 10-K.
ASU 2014-09, "Revenue from Contracts with Customers" (Issued May 2014 and subsequently updated to address implementation questions): For public business entities, the new revenue recognition guidance will be effective for annual and interim reporting periods beginning after December 15, 2017. FirstEnergy will not early adopt the standard. FirstEnergy has evaluated its revenues and expects limited impacts to current revenue recognition practices. FirstEnergy expects to apply the new guidancepermits are renewed on a modified retrospective basisfive-year cycle from 2018 to 2023. However, on April 13, 2017, the EPA granted a Petition for Reconsideration and continueson September 18, 2017, the EPA postponed certain compliance deadlines for two years. On August 31, 2020, the EPA issued a final rule revising the effluent limits for discharges from wet scrubber systems, retaining the zero-discharge standard for ash transport water, (with some limited
discharge allowances), and extending the deadline for compliance to assessDecember 31, 2025 for both. In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system, and unit retirement date. On March 29, 2023, the EPA published proposed revised ELGs applicable to coal-fired power plants that include more stringent effluent limitations for wet scrubber systems and ash transport water, and new limits on landfill leachate. The rule was issued as final by the EPA on April 25, 2024 and depending on the outcome of appeals and how final revised rules are ultimately implemented, compliance with these standards could require additional capital expenditures or changes in operation at closed and active landfills, and at the Ft. Martin and Harrison power stations from what was approved by the WVPSC in September 2022 to comply with the 2020 ELG rule. FirstEnergy is currently assessing the impact on its financial statements and disclosures.
ASU 2016-02,"Leases (Topic 842)" (Issued February 2016): 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,final rule.
Regulation of Waste Disposal
Federal 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. 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.
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. ASU 2017-01 is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. The ASU will be applied prospectively to any transactions occurring within the period of adoption. Early adoption is permitted, including for interim or annual periods in which the financial statementsstate hazardous waste regulations have not been issued or made available for issuance.
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. Because the non-service cost components of net benefit cost will no longer be eligible for capitalization after December 31, 2017, FirstEnergy will recognize these components in incomepromulgated as a result of adopting the standard.Resource Conservation and Recovery Act, as amended, and the Toxic Substances Control Act. Certain CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation.
In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 29, 2020, the EPA published a final rule again revising the date that certain CCR impoundments must cease accepting waste and initiate closure to April 11, 2021. The final rule allowed for an extension of the closure deadline based on meeting identified site-specific criteria. On November 30, 2020, AE Supply submitted a closure deadline extension request to the EPA seeking to extend the cease accepting waste date for the McElroy's Run CCR impoundment facility to October 2024, which request is pending technical review by the EPA. AE Supply continues to operate McElroy’s Run as a disposal facility for Pleasants Power Station and continues to evaluate closure options. Also, on April 25, 2024, the EPA issued rules as final addressing, for the first time, certain legacy CCR disposal sites. FirstEnergy is currently evaluating presentationassessing the impact of the Statementfinal rule.
FE or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of Incomedisposal of hazardous substances at historical sites and the impactliability 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 disclosuresa joint and several basis. Environmental liabilities that are considered probable have been recognized on FirstEnergy’s Consolidated Balance Sheets as of March 31, 2024, based on estimates of the total costs of cleanup, FirstEnergy’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $97 million have been accrued through March 31, 2024, of which approximately $70 million are for environmental remediation of former MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable societal benefits charge. FE or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time.
OTHER LEGAL PROCEEDINGS
United States v. Larry Householder, et al.
On July 21, 2020, a complaint and supporting affidavit containing federal criminal allegations were unsealed against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. In March 2023, a jury found Mr. Householder and his co-defendant, Matthew Borges, guilty and in June 2023, the two were sentenced to prison for 20 and 5 years, respectively. Messrs. Householder and Borges have appealed their sentences. Also, on July 21, 2020, and in connection with the DOJ’s investigation, FirstEnergy received subpoenas for records from the U.S. Attorney’s Office for the Southern District Ohio. FirstEnergy was not aware of the criminal allegations, affidavit or subpoenas before July 21, 2020.
On July 21, 2021, FE entered into a three-year DPA with the U.S. Attorney’s Office that, subject to court proceedings, resolves this matter. Under the DPA, FE has agreed to the filing of a criminal information charging FE with one count of conspiracy to commit honest services wire fraud. The DPA requires that FirstEnergy, among other obligations: (i) continue to cooperate with the U.S. Attorney’s Office in all matters relating to the conduct described in the DPA and other conduct under investigation by the U.S. government; (ii) pay a criminal monetary penalty totaling $230 million within sixty days, which shall consist of (x) $115 million paid by FE to the United States Treasury and (y) $115 million paid by FE to the ODSA to fund certain assistance programs, as determined by the ODSA, for the benefit of low-income Ohio electric utility customers; (iii) publish a list of all payments made in 2021 to either 501(c)(4) entities or to entities known by FirstEnergy to be operating for the benefit of a public official, either directly or indirectly, and update the same on a quarterly basis during the term of the DPA; (iv) issue a public statement, as dictated in the DPA, regarding FE’s use of 501(c)(4) entities; and (v) continue to implement and review its compliance and ethics program, internal controls, policies and procedures designed, implemented and enforced to prevent and detect violations of the U.S. laws throughout its operations, and to take certain related remedial measures. The $230 million payment will neither be recovered in rates or charged to FirstEnergy customers, nor will FirstEnergy seek any tax deduction related to such payment. The entire amount of the monetary penalty was recognized as expense in the second quarter of 2021
and paid in the third quarter of 2021. Under the terms of the DPA, the criminal information will be dismissed after FirstEnergy fully complies with its obligations under the DPA.
Legal Proceedings Relating to United States v. Larry Householder, et al.
On August 10, 2020, the SEC, through its Division of Enforcement, issued an order directing an investigation of possible securities laws violations by FE, and on September 1, 2020, issued subpoenas to FE and certain FE officers. On April 28, 2021, July 11, 2022, and May 25, 2023, the SEC issued additional subpoenas to FE, with which FE has complied. While no contingency has been reflected in its consolidated financial statements, FE believes that it is probable that it will incur a loss in connection with the resolution of the SEC investigation. Given the ongoing nature and complexity of the investigation, FE cannot yet reasonably estimate a loss or range of loss that may arise from the resolution of the SEC investigation.
On June 29, 2023, the OOCIC served FE a subpoena, seeking information relating to the conduct described in the DPA. FirstEnergy was not aware of the OOCIC’s investigation prior to receiving the subpoena and understands that the OOCIC’s investigation is also focused on the conduct described in the DPA, other than with respect to the March 25, 2024, felony indictment of Mr. Householder brought in Cuyahoga County, Ohio. FirstEnergy is cooperating with the OOCIC in its investigation. On February 12, 2024, and in connection with the OOCIC’s ongoing investigation, an indictment by a grand jury of Summit County, Ohio was unsealed against the former chairman of the PUCO, Samuel Randazzo, and two former FirstEnergy senior officers, Charles E. Jones, and Michael J. Dowling, charging each of them with several felony counts, including bribery, telecommunications fraud, money laundering and aggravated theft, related to payments described in the DPA. FirstEnergy continues to both cooperate with the OOCIC in its investigation and discuss an appropriate resolution of the investigation with respect to FE. While no contingency has been reflected in FirstEnergy’s consolidated financial statements, FE believes that it is reasonably possible that it will incur a loss in connection with the resolution of the OOCIC investigation. Given the ongoing nature of the discussions, while FE cannot yet reasonably estimate a loss or range of loss that may arise from any resolution of the OOCIC investigation with respect to FE, any such payment by FE associated with an OOCIC resolution is not expected to be material.
In addition to the subpoenas referenced above under “United States v. Larry Householder, et. al.” and the SEC investigation, certain FE stockholders and FirstEnergy customers filed several lawsuits against FirstEnergy and certain current and former directors, officers and other employees, and the complaints in each of these suits is related to allegations in the complaint and supporting affidavit relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. The plaintiffs in each of the below cases seek, among other things, to recover an unspecified amount of damages (unless otherwise noted). Unless otherwise indicated, no contingency has been reflected in FirstEnergy’s consolidated financial statements with respect to these lawsuits as a loss is neither probable, nor is a loss or range of a loss reasonably estimable.
•In re FirstEnergy Corp. Securities Litigation (S.D. Ohio); on July 28, 2020 and August 21, 2020, purported stockholders of FE filed putative class action lawsuits alleging violations of the federal securities laws. Those actions have been consolidated and a lead plaintiff, the Los Angeles County Employees Retirement Association, has been appointed by the court. A consolidated complaint was filed on February 26, 2021. The consolidated complaint alleges, on behalf of a proposed class of persons who purchased FE securities between February 21, 2017 and July 21, 2020, that FE and certain current or former FE officers violated Sections 10(b) and 20(a) of the Exchange Act by issuing misrepresentations or omissions concerning FE’s business and results of operations. The consolidated complaint also alleges that FE, certain current or former FE officers and directors, and a group of underwriters violated Sections 11, 12(a)(2) and 15 of the Securities Act of 1933 as a result of adopting ASU 2017-07. The ASUalleged misrepresentations or omissions in connection with offerings of senior notes by FE in February and June 2020. On March 30, 2023, the court granted plaintiffs’ motion for class certification. On April 14, 2023, FE filed a petition in the U.S. Court of Appeals for the Sixth Circuit seeking to appeal that order, which the Sixth Circuit granted on November 16, 2023. On November 30, 2023, FE filed a motion with the S.D. Ohio to stay all proceedings pending the circuit court appeal. All discovery is stayed during the pendency of the district court motion. FE believes that it is probable that it will be effectiveincur a loss in fiscal years beginning afterconnection with the resolution of this lawsuit. Given the ongoing nature and complexity of such litigation, FE cannot yet reasonably estimate a loss or range of loss.
•MFS Series Trust I, et al. v. FirstEnergy Corp., et al. and Brighthouse Funds II – MFS Value Portfolio, et al. v. FirstEnergy Corp., et al. (S.D. Ohio) on December 15, 2017, including interim periods within those fiscal years.
FIRSTENERGY SOLUTIONS CORP.
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
FES, a subsidiary17, 2021 and February 21, 2022, purported stockholders of FE was organized underfiled complaints against FE, certain current and former officers, and certain current and former officers of EH. The complaints allege that the lawsdefendants violated Sections 10(b) and 20(a) of the Exchange Act by issuing alleged misrepresentations or omissions regarding FE’s business and its results of operations, and seek the same relief as the In re FirstEnergy Corp. Securities Litigation described above. All discovery is stayed during the pendency of the district court motion in In re FirstEnergy Corp. Securities Litigation described above. FE believes that it is probable that it will incur losses in connection with the resolution of these lawsuits. Given the ongoing nature and complexity of such litigation, FE cannot yet reasonably estimate a loss or range of loss.
•State of Ohio in 1997. FES provides energy-related productsex rel. Dave Yost, Ohio Attorney General v. FirstEnergy Corp., et al. and services to retailCity of Cincinnati and wholesale customers. FES also ownsCity of Columbus v. FirstEnergy Corp. (Common Pleas Court, Franklin County, OH, all actions have been consolidated); on September 23, 2020 and operates, through its FG subsidiary, fossil generating facilitiesOctober 27, 2020, the OAG and owns, through its NG subsidiary, nuclear generating facilities, which are operated by FENOC. FES purchases the entire outputcities of Cincinnati and Columbus, respectively, filed complaints against several parties including FE, each alleging civil violations of the generation facilities owned by FGOhio Corrupt Activity Act and NG. Priorrelated
claims in connection with the passage of HB 6. On January 13, 2021, the OAG filed a motion for a temporary restraining order and preliminary injunction against FirstEnergy seeking to Aprilenjoin FirstEnergy from collecting the Ohio Companies' decoupling rider. On January 31, 2021, FE reached a partial settlement with the OAG and the cities of Cincinnati and Columbus with respect to the temporary restraining order and preliminary injunction request and related issues. In connection with the partial settlement, the Ohio Companies filed an application on February 1, 2016, FES financially purchased2021, with the uncommitted outputPUCO to set their respective decoupling riders (Conservation Support Rider) to zero. On February 2, 2021, the PUCO approved the application of AE Supply's generation facilities under a PSA.the Ohio Companies setting the rider to zero, and no additional customer bills will include new decoupling rider charges after February 8, 2021. On August 13, 2021, new defendants were added to the complaint, including two former officers of FirstEnergy. On December 21, 2015, FES agreed, under2, 2021, the cities and FE entered a PSA,stipulated dismissal with prejudice of the cities’ suit. This matter was stayed through a criminal trial in United States v. Larry Householder, et al. described above, but resumed pursuant to physically purchase allan order, dated March 15, 2023. On July 31, 2023, FE and other defendants filed motions to dismiss in part the output of AE Supply's generation facilities effective April 1, 2016. FES and AE Supply terminatedOAG’s amended complaint, which the PSA effective April 1, 2017.
FES' revenues are derived primarily from salesOAG opposed. On February 16, 2024, the OAG moved to individual retail customers, sales to customersstay discovery in the formcase in light of governmental aggregation programs, and participationthe February 9, 2024, indictments against defendants in affiliated and non-affiliated POLR auctions. FES' sales are primarily concentrated in Ohio, Pennsylvania, Illinois, Michigan, New Jersey, and Maryland. The demand for electricity produced and sold by FES, alongthis action, which the court granted on March 14, 2024. In connection with the priceongoing OOCIC resolution discussions, FE is also discussing an appropriate settlement of this civil action with the OAG. As such, FE believes it is reasonably possible that electricity,it will incur a loss in connection with this civil action. Given the ongoing nature of these discussions, FE cannot yet reasonably estimate a loss or range of loss from any possible settlement of this civil action, however, any such settlement payment by FE is principally impactednot expected to be material.
On February 9, 2022, FE, acting through the SLC, agreed to a settlement term sheet to resolve the following shareholder derivative lawsuits relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder that were filed in the S.D. Ohio, the N.D. Ohio, and the Ohio Court of Common Pleas, Summit County:
•Gendrich v. Anderson, et al. and Sloan v. Anderson, et al. (Common Pleas Court, Summit County, Ohio, all actions have been consolidated); on July 26, 2020 and July 31, 2020, respectively, purported stockholders of FE filed shareholder derivative action lawsuits against certain current and former FE directors and officers, alleging, among other things, breaches of fiduciary duty.
•Miller v. Anderson, et al. (N.D. Ohio); Bloom, et al. v. Anderson, et al.; Employees Retirement System of the City of St. Louis v. Jones, et al.; Electrical Workers Pension Fund, Local 103, I.B.E.W. v. Anderson et al.; Massachusetts Laborers Pension Fund v. Anderson et al.; The City of Philadelphia Board of Pensions and Retirement v. Anderson et al.; Atherton v. Dowling et al.; Behar v. Anderson, et al. (S.D. Ohio, all actions have been consolidated); beginning on August 7, 2020, purported stockholders of FE filed shareholder derivative actions alleging the FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act.
On March 11, 2022, the parties executed a stipulation and agreement of settlement, and filed a motion the same day requesting preliminary settlement approval in the S.D. Ohio, which the S.D. Ohio granted on May 9, 2022. Subsequently, following a hearing on August 4, 2022, the S.D. Ohio granted final approval of the settlement on August 23, 2022.
The settlement includes a series of corporate governance enhancements and a payment to FE of $180 million, to be paid by conditionsinsurance after the judgment has become final, less approximately $36 million in competitive power markets, global economic activitycourt-ordered attorney’s fees awarded to plaintiffs. On September 20, 2022, a purported FE stockholder filed a motion for reconsideration of the S.D. Ohio’s final settlement approval. The parties filed oppositions to that motion on October 11, 2022, and the S.D. Ohio denied that motion on May 22, 2023. On June 15, 2023, the purported FE stockholder filed an appeal in the U.S. Court of Appeals for the Sixth Circuit. On February 16, 2024, the U.S. Court of Appeals for the Sixth Circuit affirmed the district court’s final settlement approval. Once all appeal options are exhausted the judgment will become final. The settlement agreement is expected to resolve fully these shareholder derivative lawsuits.
On June 2, 2022, the N.D. Ohio entered an order to show cause why the court should not appoint new plaintiffs’ counsel, and thereafter, on June 10, 2022, the parties filed a joint motion to dismiss the matter without prejudice, which the N.D. Ohio denied on July 5, 2022. On August 15, 2022, the N.D. Ohio issued an order stating its intention to appoint one group of applicants as new plaintiffs’ counsel, and on August 22, 2022, the N.D. Ohio ordered that any objections to the appointment be submitted by August 26, 2022. The parties filed their objections by that deadline, and on September 2, 2022, the applicants responded to those objections. In the meantime, on August 25, 2022, a purported FE stockholder represented by the applicants filed a motion to intervene, attaching a proposed complaint-in-intervention purporting to assert claims that the FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act as well as economic activitya claim against a third party for professional negligence and weather conditionsmalpractice. The parties filed oppositions to that motion to intervene on September 8, 2022, and the proposed intervenor's reply in support of his motion to intervene was filed on September 22, 2022. On August 24, 2022, the parties filed a joint motion to dismiss the action pending in the MidwestN.D. Ohio based upon and Mid-Atlantic regionsin light of the United States.
FES is exposedapproval of the settlement by the S.D. Ohio. On August 30, 2022, the parties filed a joint motion to various market and financial risks, includingdismiss the riskstate court action, which the court granted on September 2, 2022. On September 29, 2023, the N.D. Ohio issued a stay of price fluctuationsthe case pending the appeal in the wholesale power markets. Wholesale power prices mayU.S. Court of Appeals for the Sixth Circuit. On April 12, 2024, the N.D. Ohio acknowledged the completion of the appeal and instructed the parties to file any further argument or information they wish to be impactedconsidered by the pricesN.D. Ohio no later than April 25, 2024.
In letters dated January 26, and February 22, 2021, staff of other commodities, including coalFERC's Division of Investigations notified FirstEnergy that the Division was conducting an investigation of FirstEnergy’s lobbying and natural gas,governmental affairs activities concerning HB 6, and energy efficiencystaff directed FirstEnergy to preserve and DR programs, as well as regulatorymaintain all documents and legislative actions, such as MATS among other factors. FES attempts to mitigate the market risk inherent in its energy position by economically hedging its exposure and continuously monitoring various risk measurement metrics to ensure compliance with its risk management policies.
Today, FES' competitive generation portfolio is comprised of more than 10,000 MWs of generation, primarily from coal, nuclear and natural gas and oil fuel sources. The assets generate approximately 60-65 million MWHs annually, with up to an additional five million MWHs available from purchased power agreements for wind, solar, and FES' entitlement in OVEC.
Over the past several years, FES has been impacted by a decrease in demand and excess generation supply in the PJM Region, which has resulted in low power and capacity prices, as well as significant environmental compliance costs. To address this, FES sold or deactivated approximately 2,700 MWs of competitive generation from 2012 to 2015 and announced in 2016 plans to exit and/or deactivate an additional 856 MWs by 2020information related to the Bay Shore Unit 1 generating station and Units 1-4 of the W.H. Sammis generating station. Additionally, FES has continued to focus on cost reductions, including those identifiedsame as such have been developed as part of an ongoing non-public audit being conducted by FERC's Division of Audits and Accounting. On December 30, 2022, FERC approved a Stipulation and Consent Agreement that resolves the investigation. The agreement includes a FirstEnergy admission of violating FERC’s “duty of candor” rule and related laws, and obligates FirstEnergy to pay a civil penalty of $3.86 million, and to submit two annual compliance monitoring reports to FERC’s Office of Enforcement regarding improvements to FirstEnergy’s previously disclosed cash flow improvement plan.compliance programs. FE paid the civil penalty on January 4, 2023 and it will not be recovered from customers. The first annual compliance monitoring report was submitted in December 2023.
However, the energy and capacity markets remain weak with significantly low capacity clearing prices and current forward pricing as well as the long-term fundamental view on energy and capacity prices. In order to focus on stable and predictable cash flow from its regulated business units, in November of 2016, FirstEnergy announced a strategic review of its competitive operations with a target to implement its exit from competitive operations by mid-2018.
The strategic options to exit the competitive operations are still uncertain, but could include one or more of the following:
legislative or regulatory solutions for generation assets that recognize their environmental or energy security benefits;
restructuring FES debt with its creditors;
seeking protection under U.S. bankruptcy laws for FES and likely FENOC; and/or
additional asset sales and/or plant deactivations.
Furthermore, the implementation of various strategic options, and the timing thereof, could be impacted by various events, including, but not limited to the following:
The outcome of effortsany of these lawsuits, governmental investigations and audit is uncertain and could have a material adverse effect on FE’s or its subsidiaries’ reputation, business, financial condition, results of operations, liquidity, and cash flows.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to the NOPR released by the SecretaryFirstEnergy’s normal business operations pending against FE or its subsidiaries. The loss or range of Energy and action by FERC to address critical issues central to protecting the long-term reliability and resiliency of the electric grid provided by traditional baseload resources, such as coal and nuclear generation;
The resolution of legislation before the Ohio General Assembly that would create a zero-emission nuclear (ZEN) program that would provide compensation to nuclear power plants for their fuel diversity, environmental and other benefits and the potential for similar legislative actionloss in Pennsylvania; and/or
The inability to finalize and consummate a settlement agreement with BNSF and NS regarding a previously disclosed long-term coal transportation contract dispute as discussed in "Outlook - Environmental Matters" above, whereby FG could be subject to materially higher damages.
FES continues to be managed conservatively due to the stress of weak energy prices, insufficient results from recent capacity auctions and anemic demand forecasts. Furthermore, the credit quality of FES, specifically the unsecured debt rating of Caa1 at Moody’s, CCC- at S&P and C at Fitch and a negative outlook from Moody's and S&P, has challenged its ability to hedge generation with retail and forward wholesale sales due to significant collateral requirements. As a result, FES' contract sales are expected to decline from 52 million MWHs in 2016 to 40-45 million MWHs in 2017 and to 30-35 million MWHs in 2018. While the reduced contract sales will decrease potential collateral requirements, market price volatility may significantly impact FES' financial results due to the increased exposure to the wholesale spot market.
Although FES has access to a $500 million secured line of credit with FE, all of which was available as of September 30, 2017, its current credit rating and the current forward wholesale pricing environment present significant challenges to FES. Furthermore, an inability to develop and execute upon viable alternative strategies for its competitive portfolio would continue to further stress the liquidity and financial condition of FES.
Cash flow from operations at FESthese matters is not expected to be sufficientmaterial to fund capital expenditures, nuclear fuel purchases,FE or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 8, “Regulatory Matters.”
FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and repay money pool borrowings through March 2018. However, as previously disclosed, FEScan reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has $515 million of maturing debt in 2018, beginning in the second quarter. Additionally, FES has $48 million of interest and lease payments in December 2017 and $38 million of interest payments in the first quarter of 2018. Based on FES' current senior unsecured debt rating, capital structurea material obligation, it discloses such obligations and the forecasted decline in wholesale forward market prices over the next few years, the debt maturitiespossible 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 likelyotherwise made subject to be difficult to refinance. Furthermore, lack of clarity regarding the timing and viability of alternative strategies, including additional asset sales or deactivations and/or converting generation from competitive operations to a regulated or regulated-like construct in a way that provides FES with the means to satisfy its obligations over the long-term, may also require FES to restructure debt and other financial obligations with its creditors and/or seek protection under U.S. bankruptcy laws. In the event FES seeks protection under U.S. bankruptcy laws, FENOC will likely seek such protection. Although management is exploring capital and other cost reductions, asset sales, and other options to improve cash flow as well as continuing with efforts to explore legislative or regulatory solutions, these obligations and their impact to liquidity raise substantial doubt about FES’ ability to meet its obligations as they come due over the next twelve months and, as such, its ability to continue as a going concern.
For additional information with respect to FES, please see the information contained under "Risk Factors" in Part II, Item 1A of this Form 10-Q and in "FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations" under the following subheadings, which information is incorporated by reference herein: "FirstEnergy's Business," "Executive Summary," "Capital Resources and Liquidity," "Guarantees and Other Assurances," "Off-Balance Sheet Arrangements," "Market Risk Information," "Credit Risk," "New Accounting Pronouncements," and "Outlook."
Results of Operations
Operating results increased $282 million in the first nine months of 2017, compared to the same period of 2016, primarily due to the absence of asset impairment and plant exit costs recognized in 2016, as discussed below, and lower depreciation expense, partially offset by a pre-tax charge of $164 million associated with estimated lossesliability based on long-term coal transportation contract disputes, as discussed in "Outlook - Environmental Matters" above, higher non-cash mark-to-market losses on commodity contract positions and lower capacity revenue.
Revenues -
Total revenues decreased $1,003 million in the first nine months of 2017, compared to the same period of 2016, primarily due to lower contract sales volumes at lower rates, lower capacity revenues from lower capacity auction prices, and lower net gains on financially settled contracts, partially offset by an increase in short-term (net hourly position) transactions, as further described below.
The change in total revenues resulted from the following sources:
|
| | | | | | | | | | | | |
| | | For the Nine Months Ended September 30 | | |
| Revenues by Type of Service | | 2017 | | 2016 | | Decrease |
| | | (In millions) |
| Contract Sales: | | | | | | |
| Direct | | $ | 560 |
| | $ | 610 |
| | $ | (50 | ) |
| Governmental Aggregation | | 303 |
| | 666 |
| | (363 | ) |
| Mass Market | | 97 |
| | 133 |
| | (36 | ) |
| POLR | | 389 |
| | 447 |
| | (58 | ) |
| Structured | | 246 |
| | 353 |
| | (107 | ) |
| Total Contract Sales | | 1,595 |
| | 2,209 |
| | (614 | ) |
| Wholesale | | 710 |
| | 1,015 |
| | (305 | ) |
| Transmission | | 30 |
| | 53 |
| | (23 | ) |
| Other | | 63 |
| | 124 |
| | (61 | ) |
| Total Revenues | | $ | 2,398 |
| | $ | 3,401 |
| | $ | (1,003 | ) |
|
| | | | | | | | | |
| | | For the Nine Months Ended September 30 | | Increase |
| MWH Sales by Channel | | 2017 | | 2016 | | (Decrease) |
| | | (In thousands) | | |
| Contract Sales: | | | | | | |
| Direct | | 11,504 |
| | 11,391 |
| | 1.0 | % |
| Governmental Aggregation | | 5,686 |
| | 10,798 |
| | (47.3 | )% |
| Mass Market | | 1,425 |
| | 1,912 |
| | (25.5 | )% |
| POLR | | 6,983 |
| | 7,526 |
| | (7.2 | )% |
| Structured | | 6,398 |
| | 8,863 |
| | (27.8 | )% |
| Total Contract Sales | | 31,996 |
| | 40,490 |
| | (21.0 | )% |
| Wholesale | | 11,134 |
| | 8,461 |
| | 31.6 | % |
| Total MWH Sales | | 43,130 |
| | 48,951 |
| | (11.9 | )% |
The following table summarizes the price and volume factors contributing to changes in revenues in the first nine months of 2017, compared with the same period of 2016:
|
| | | | | | | | | | | | | | | | | | | | |
| | | Source of Change in Revenues |
| | | Increase (Decrease) |
| MWH Sales Channel: | | Sales Volumes | | Prices | | Gain on Settled Contracts | | Capacity Revenue | | Total |
| | | (In millions) |
| Direct | | $ | 6 |
| | $ | (56 | ) | | $ | — |
| | $ | — |
| | $ | (50 | ) |
| Governmental Aggregation | | (315 | ) | | (48 | ) | | — |
| | — |
| | (363 | ) |
| Mass Market | | (34 | ) | | (2 | ) | | — |
| | — |
| | (36 | ) |
| POLR | | (32 | ) | | (26 | ) | | — |
| | — |
| | (58 | ) |
| Structured | | (100 | ) | | (7 | ) | | — |
| | — |
| | (107 | ) |
| Wholesale | | 73 |
| | (4 | ) | | (114 | ) | | (260 | ) | | (305 | ) |
| | | | | | | | | | | |
Lower sales volumes in the Governmental Aggregation channel primarily reflects the termination of an FES customer contract in 2016. The Direct, Governmental Aggregation and Mass Market customer base was approximately 842,000 as of September 30, 2017, compared to 1.4 million as of September 30, 2016. Although unit pricing in Direct, Governmental Aggregation and Mass
Market was lower year-over-year, the decrease was primarily attributable to lower capacity expense as discussed below, which is a componentany of the retail price.matters referenced above, it could have a material adverse effect on FE’s or its subsidiaries’ financial condition, results of operations, and cash flows.
The decrease in POLR revenue of $58 million was primarily due to lower volumes and lower unit prices. Structured revenue decreased $107 million, primarily due to the impact of lower transaction volumes.
Wholesale revenues decreased $305 million, primarily due to a decrease in capacity revenue from lower capacity auction prices and lower net gains on financially settled contracts, partially offset by an increase in short-term (net hourly position) transactions at slightly lower market prices.
Transmission revenue decreased $23 million, primarily due to lower congestion revenues.
Other revenues decreased $61 million, primarily due to lower lease revenues from the expiration of a nuclear sale-leaseback agreement. FES earned lease revenue associated with the lessor equity interests it has purchased in sale-leaseback transactions, one of which expired in June 2017 and another in May 2016.
Operating Expenses -
Total operating expenses decreased $1,293 million in the first nine months of 2017, compared to the same period of 2016.
The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first nine months of 2017, compared with the same period of 2016:
|
| | | | | | | | | | | | | | | | | | | | |
| | | Source of Change |
| | | Increase (Decrease) |
| Operating Expenses | | Volumes | | Unit Costs | | Loss on Settled Contracts | | Capacity Expense | | Total |
| | | (In millions) |
| Fossil Fuel | | $ | (88 | ) | | $ | 9 |
| | $ | (58 | ) | | $ | — |
| | $ | (137 | ) |
| Nuclear Fuel | | 3 |
| | 2 |
| | — |
| | — |
| | 5 |
|
| Affiliated Purchased Power | | (92 | ) | | 23 |
| | (169 | ) | | — |
| | (238 | ) |
| Non-affiliated Purchased Power | | (34 | ) | | 17 |
| | (91 | ) | | (253 | ) | | (361 | ) |
Fossil and nuclear fuel costs decreased $132 million, primarily due to the absence of $58 million in settlement and termination costs on coal contracts recognized in 2016, as well as lower generation associated with outages and economic dispatch of fossil units resulting from low wholesale spot market energy prices, as described above, partially offset by higher unit costs.
Affiliated purchased power costs decreased $238 million, primarily resulting from the termination of the AE Supply PSA, effective April 1, 2017, and the expiration of a nuclear sale-leaseback agreement.
Non-affiliated purchased power costs decreased $361 million due to lower capacity expenses ($253 million), reduced net losses on financially settled contracts ($91 million), and lower volumes ($34 million), partially offset by higher unit costs ($17 million). The decrease in capacity expense, which is a component of FES' retail price, was primarily the result of lower contract sales and lower capacity rates associated with FES' retail sales obligation. Lower volumes primarily resulted from lower contract sales as discussed above, partially offset by economic purchases resulting from the low wholesale spot market price environment.
Other operating expenses increased $170 million in the first nine months of 2017, compared to the same period of 2016, due to the following:
A $164 million charge associated with estimated losses on long-term coal transportation contract disputes was recognized in the first quarter of 2017, as discussed in "Outlook - Environmental Matters" above.
Fossil operating and maintenance expenses decreased $33 million, primarily due to lower outage costs and the absence of plant demolition costs recognized in 2016.
Nuclear operating and maintenance expenses increased $18 million, primarily as a result of higher refueling outage costs, partially offset by lower non-outage maintenance costs. There were two refueling outages during the first nine months of 2017, as compared to one refueling outage during the same period of 2016.
Transmission expenses decreased $49million, primarily due to lower contract sales volumes.
Other operating expenses increased $70 million, primarily due to higher non-cash mark-to-market losses on commodity contract positions, partially offset by the absence of a termination charge associated with an FES Governmental Aggregation customer contract.
Depreciation expense decreased $170 million, primarily due to a lower asset base resulting from asset impairments recognized in 2016.
General taxes decreased $22 million, primarily due to lower property taxes and reduced gross receipts taxes associated with lower retail sales volumes.
Impairment of assets decreased $540 million, primarily due to the absence of an impairment of goodwill and a $517 million impairment of Units 1-4 of the W.H. Sammis generating station and the Bay Shore Unit 1 generating station recognized in 2016.
Other Expense —
Total other expense decreased $11 million in the first nine months of 2017, as compared to the same period of 2016, primarily due to higher investment income on NDT investments.
Income Tax Benefits —
FES' effective tax rate for the nine months ended September 30, 2017 and 2016 was 48.3% on pre-tax income and 1.8% on pre-tax losses, respectively. The change in the effective tax rate was primarily due to a $65 million of valuation allowance recognized in 2016 against state and local NOL carryforwards and the impairment of goodwill also recognized in 2016, of which $23 million was non-deductible for tax purposes.
Changes in Cash Position
FES expects to rely on its current access to the unregulated companies' money pool and a two-year secured line of credit from FE of up to $500 million, as further described above. Additionally, FES subsidiaries have debt maturities of $515 million in 2018, beginning in the second quarter. The inability to refinance the debt maturities could cause FES to take one or more of the following actions: (i) restructuring of debt and other financial obligations, (ii) additional borrowings under its credit facility with FE, (iii) further asset sales or plant deactivations, and/or (iv) seeking protection under U.S. bankruptcy laws. In the event FES seeks such protection, FENOC will likely seek protection under U.S. bankruptcy laws.
FES continues to be managed conservatively due to the stress of weak power prices, insufficient proceeds from recent capacity auctions and anemic demand forecasts that have lowered the value of the business. Furthermore, the credit quality of FES, specifically its unsecured debt rating of Caa1 at Moody’s, CCC- at S&P and C at Fitch and a negative outlook from Moody's and S&P, has challenged its ability to hedge generation with retail and forward wholesale sales without collateral obligations, which reduce the business units available liquidity. A lack of viable alternative strategies for its competitive portfolio would continue to further stress the liquidity and financial condition of FES.
As discussed above, FES currently maintains access to the unregulated companies' money pool in lieu of borrowing under its $500 million secured line of credit. FE expects to provide ongoing access to FES to the unregulated companies' money pool to allow time to evaluate its strategic alternatives including, among other things, the results of legislative and regulatory solutions, including the NOPR released by the Secretary of Energy and action by FERC. As of September 30, 2017, FES, and its subsidiaries, and FENOCMarch 31, 2024, FirstEnergy had $67$888 million of net borrowings incash and cash equivalents and $27 million of restricted cash as compared to $137 million of cash and cash equivalents and $42 million of restricted cash as of December 31, 2023, on the aggregate underConsolidated Balance Sheets.
The following table summarizes the unregulated companies' money pool. Cashmajor classes of cash flow from operations at FES is expected to be sufficient to fund capital expenditures, nuclear fuel purchases, and repay money pool borrowings through March 2018.items:
| | | | | | | | | | | | | | |
| | For the Three Months Ended March 31, |
| (In millions) | | 2024 | | 2023 |
| | | | |
| Net cash used for operating activities | | $ | (40) | | | $ | (112) | |
| Net cash used for investing activities | | (870) | | | (716) | |
| Net cash provided from financing activities | | 1,646 | | | 828 | |
| Net change in cash, cash equivalents, and restricted cash | | 736 | | | — | |
| | | | |
| Cash, cash equivalents, and restricted cash at beginning of period | | 179 | | | 206 | |
| Cash, cash equivalents, and restricted cash at end of period | | $ | 915 | | | $ | 206 | |
Cash Flows From Operating Activities
FES'FirstEnergy’s most significant sources of cash are derived from electric service provided by the sales of energy and related products and services.its operating subsidiaries. The most significant use of cash from operating activities is buying electricity to buy electricity in the wholesale marketserve non-shopping customers, return of cash collateral associated with certain generation suppliers that serve shopping customers, pension contributions and paypaying fuel suppliers, employees, tax authorities, lenders and others for a wide range of materialmaterials and services.
Net cash provided fromCash used for operating activities was $458$40 million during the first nine months of 2017 compared with $605 million provided from operating activities during the first nine months of 2016. Cash flows from operations decreased $147and $112 million in the first ninethree months of 2017, compared2024 and 2023, respectively. Cash flows from operating activities were a net outflow in the first quarter of 2024, primarily due to working capital, including prepaid and accrued tax payments associated with Pennsylvania gross receipts tax payments and timing of property tax payments. Compared to the same period of 2016 primarily due to lower receipts from a2023, the decrease in capacity revenues and retail sales, as discussed above in "Results of Operations" and timing of working capital.
Cash Flows From Financing Activities
For the first nine months of 2017, cash used for financingoperating activities is primarily due to:
•Lower payments, primarily on generation energy purchases for certain customers, net of related customer receivable receipts;
•The decrease in return of cash collateral to certain generation suppliers that serve shopping customers that was previously received as a result of changes in power prices;
•Higher net transmission revenue collection based on the timing of formula rate collections; and
•Higher returns from distribution, integrated, and transmission capital investments;
The decrease in cash used for operating activities was $83 million, compared to cash providedpartially offset by:
•Lower dividend distribution received by FEV from financing activities of $61 millionits equity investments in same period of 2016. The following table summarizes new debt financing, redemptions, repaymentsGlobal Holding; and short-term borrowings:
•Higher payments associated with Pennsylvania gross receipts taxes.
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| | | For the Nine Months Ended September 30 |
| Securities Issued or Redeemed / Repaid | | 2017 | | 2016 |
| | | (In millions) |
| New Issues | | | | |
| PCRBs | | $ | — |
| | $ | 471 |
|
| | | | | |
| Redemptions / Repayments | | |
| | |
|
| Senior secured notes | | $ | (5 | ) | | $ | (20 | ) |
| PCRBs | | (158 | ) | | (483 | ) |
| | | $ | (163 | ) | | $ | (503 | ) |
| | | | | |
| Short-term borrowings, net | | $ | 85 |
| | $ | 101 |
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Cash Flows From Investing Activities
Cash used for investing activities in the first three months of 2024 principally represented cash used for capital investments. The following table summarizes investing activities for the first three months of 2024 and 2023:
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| | For the Three Months Ended March 31, |
| Cash Used for Investing Activities | | 2024 | | 2023 | | Increase (Decrease) |
| | (In millions) |
| Capital investments: | | | | | | |
| Distribution Segment | | $ | 215 | | | $ | 193 | | | $ | 22 | |
| Integrated Segment | | 313 | | | 237 | | | 76 | |
| Stand-Alone Transmission Segment | | 258 | | | 212 | | | 46 | |
| Corporate / Other Segment | | 4 | | | 7 | | | (3) | |
| | | | | | |
| | | | | | |
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| Asset removal costs | | 78 | | | 60 | | | 18 | |
| Other | | 2 | | | 7 | | | (5) | |
| | $ | 870 | | | $ | 716 | | | $ | 154 | |
| | | | | | |
Cash used for investing activities for the first ninethree months of 2017 principally represented cash used for property additions and nuclear fuel. The following table summarizes investing activities for the first nine months of 2017 and comparable period of 2016.
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| | | | | | | | |
| | | For the Nine Months Ended September 30 |
| Cash Used for Investing Activities | | 2017 | | 2016 |
| | | (In millions) |
| Property Additions | | $ | 201 |
| | $ | 432 |
|
| Nuclear fuel | | 156 |
| | 195 |
|
| Loans to affiliated companies, net | | (29 | ) | | 15 |
|
| Investments | | 44 |
| | 43 |
|
| Other | | 3 |
| | (19 | ) |
| | | $ | 375 |
| | $ | 666 |
|
Cash used for investing activity for the first nine months of 2017 decreased $2912024 increased $154 million, compared to the same period of 2016,2023, primarily due to lower property additions. Property additions decreasedcapital investments.
Cash Flows From Financing Activities
In the first three months of 2024 and 2023, cash provided from financing activities was $1,646 million and $828 million, respectively. The following table summarizes financing activities for the first three months of 2024 and 2023:
| | | | | | | | | | | | | | |
| | For the Three Months Ended March 31, |
| Financing Activities | | 2024 | | 2023 |
| | | (In millions) |
| | | | |
| New Issues: | | | | |
| Unsecured notes | | $ | 150 | | | $ | 900 | |
| | | | |
| | | | |
| FMBs | | — | | | 50 | |
| | | | |
| | $ | 150 | | | $ | 950 | |
| | | | |
| Redemptions / Repayments: | | | | |
| | | | |
| Unsecured notes | | $ | — | | | $ | (300) | |
| | | | |
| | | | |
| Senior secured notes | | (23) | | | (21) | |
| | | $ | (23) | | | $ | (321) | |
| | | | |
| Proceeds from FET Equity Interest Sale | | $ | 2,300 | | | $ | — | |
| Noncontrolling interest cash distributions | | (8) | | | (17) | |
| | | | |
| | | | |
| Short-term borrowings, net | | (525) | | | 450 | |
| | | | |
| | | | |
| Common stock dividend payments | | (235) | | | (223) | |
| Other | | (13) | | | (11) | |
| | $ | 1,646 | | | $ | 828 | |
FirstEnergy had the following issuances and redemptions during the three months ended March 31, 2024:
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| Company | Type | Issuance Date | Interest Rate | Maturity | Amount (In millions) | Description |
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| Issuance |
| ATSI | Senior Unsecured Note | March, 2024 | 5.63% | 2034 | $150 | Proceeds were used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes. |
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In March 2024, notice of redemption was provided for all remaining $463 million of FE’s 7.375% Notes, due 2031, which was completed on April 15, 2024, with a make-whole premium of approximately $80 million. Due to lowerthe redemption, the $463 million remaining notes are included within currently payable long-term debt on the Consolidated Balance Sheets as of March 31, 2024.
On April 1, 2024, JCP&L redeemed its $500 million 4.70% unsecured notes that became due.
On April 15, 2024, MP redeemed its $400 million 4.10% FMBs that became due.
On April 18, 2024, MAIT agreed to sell $250 million of new 5.94% Unsecured Notes due May 1, 2034. The sale is expected to settle on May 2, 2024. Proceeds are expected to be used to repay short-term borrowings, to finance capital expenditures and for other general corporate purposes.
FE or its affiliates may, from time to time, seek to retire or purchase outstanding debt through open-market purchases, privately negotiated transactions or otherwise. Such repurchases, if any, will be upon such terms and at such prices as FE or its affiliates may determine, and will depend on prevailing market conditions, liquidity requirements, contractual restrictions and other factors.
GUARANTEES AND OTHER ASSURANCES
FirstEnergy has various financial and performance guarantees and indemnifications, which are issued in the normal course of business. These contracts include performance guarantees, stand-by LOCs, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. The maximum potential amount of future payments FE and its subsidiaries could be required to make under these guarantees as of March 31, 2024, was $820 million, as summarized below:
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| Guarantees and Other Assurances | | Maximum Exposure |
| | (In millions) |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
FE’s Guarantees on Behalf of its Consolidated Subsidiaries(1) | | |
| Deferred compensation arrangements | | $ | 430 | |
| Vehicle leases | | 75 | |
| | |
| Other | | 15 | |
| | 520 | |
| | |
| FE’s Guarantees on Other Assurances | | |
Surety Bonds(2) | | 182 | |
| | |
| Deferred compensation arrangements | | 114 | |
| LOCs | | 4 | |
| | 300 | |
| | |
| | |
| | |
| | |
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| | |
| | |
| Total Guarantees and Other Assurances | | $ | 820 | |
(1) During the third quarter of 2023, FE was required by PJM to issue a guarantee to cover non-performance until FE PA is able to provide audited financial statements to PJM, which is expected to occur in early 2025. The guarantee is expected to be immaterial to FE.
(2) During the second quarter of 2023, FE was released from its $169 million surety bond to the Pennsylvania Department of Environmental Protection related to outagesthe Little Blue Run Disposal Impoundment.
Collateral and Contingent-Related Features
In the Mansfield dewatering facility,normal course of business, FE and its subsidiaries may enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain agreements contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE’s or its subsidiaries’ credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.
As of March 31, 2024, $119 million of net cash collateral has been posted by FE or its subsidiaries and is included in “Prepaid taxes and other current assets” on FirstEnergy’s Consolidated Balance Sheets. FE or its subsidiaries are holding $33 million of net cash collateral as of March 31, 2024, from certain generation suppliers, and such amount is included in “Other current liabilities” on FirstEnergy’s Consolidated Balance Sheets.
These credit-risk-related contingent features stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of March 31, 2024:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Potential Collateral Obligations | | | | | | Utilities and Transmission Companies | | FE | | Total |
| | | (In millions) |
| Contractual obligations for additional collateral | | | | | | | | | | |
| | | | | | | | | | |
| Upon further downgrade | | | | | | $ | 63 | | | $ | — | | | $ | 63 | |
| | | | | | | | | | |
Surety bonds (collateralized amount)(1) | | | | | | 87 | | | 79 | | | 166 | |
| Total Exposure from Contractual Obligations | | | | | | $ | 150 | | | $ | 79 | | | $ | 229 | |
(1) Surety bonds are not tied to a credit rating. Surety bonds’ impact assumes maximum contractual obligations, which was substantially completed in 2016.is ordinarily 100% of the face amount of the surety bond except with respect to $39 million of surety bond obligations for which the collateral obligation is capped at 60% of the face amount, and typical obligations require 30 days to cure.
Market Risk Information
FESFirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Enterprise Risk PolicyManagement Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.FirstEnergy.
Commodity Price Risk
FES is exposedFirstEnergy has limited exposure to financial risks resulting from fluctuating commodity prices, includingsuch as prices for electricity, natural gas, coal and energy transmission. FirstEnergy'sFirstEnergy’s Risk Management Department and Enterprise Risk Management Committee isare responsible for promoting the effective design and implementation of sound risk management programs and overseesoverseeing compliance with corporate risk management policies and established risk management practice. FES uses a variety
The valuation of derivative instrumentscontracts is based on observable market information. As of March 31, 2024, FirstEnergy has a net liability of $1 million in non-hedge derivative contracts that are related to FTRs at certain of the Utilities. FTRs are subject to regulatory accounting and do not impact earnings. See Note 6, “Fair Value Measurements,” of the Notes to Consolidated Financial Statements for risk management purposes including forward contracts, options, futures contractsadditional details on FirstEnergy’s FTRs.
Equity Price Risk
As of March 31, 2024, the FirstEnergy pension plan assets were allocated approximately as follows: 30% in equity securities, 22% in fixed income securities, 7% in alternatives, 11% in real estate, 19% in private debt/equity, 5% in derivatives and swaps.
Sources of information for the valuation of commodity derivative assets6% in cash and liabilities as of September 30, 2017 are summarized by year in the following table:
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Source of Information- Fair Value by Contract Year | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | Thereafter | | Total |
| | | (In millions) |
Other external sources(1) | | $ | 10 |
| | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 25 |
|
| Prices based on models | | (2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (2 | ) |
| Total | | $ | 8 |
| | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 23 |
|
| |
(1)
| Primarily represents contracts based on broker and ICE quotes. |
FES performs sensitivity analyses to estimate its exposureshort-term securities. As discussed above, FirstEnergy made a $750 million voluntary cash contribution to the market riskqualified pension plan on May 12, 2023. FirstEnergy does not currently expect to have a required contribution to the pension plan until 2028, which based on various assumptions, including an expected rate of its commodity positions. Basedreturn on derivative contracts heldassets of 8.0%, is expected to be approximately $260 million. However, FirstEnergy may elect to contribute to the pension plan voluntarily.
As of March 31, 2024, FirstEnergy’s OPEB plan assets were allocated approximately as follows: 51% in equity securities, 43% in fixed income securities and 6% in cash and short-term securities. See Note 4, “Pension and Other Post-Employment Benefits,” of September 30, 2017,the Notes to Consolidated Financial Statements for additional details on FirstEnergy’s pension and OPEB plans.
In the three months ended March 31, 2024, FirstEnergy’s OPEB plan assets have gained approximately 4.9% as compared to an increase in commodity pricesannualized expected return on plan assets of 10% would decrease net income by7.0%. In the three months ended March 31, 2024, FirstEnergy’s pension plan assets have lost approximately $6 million during the next twelve months.0.1% as compared to an annualized expected return on plan assets of 8.0%.
Interest Rate Risk
FES’ exposure
FirstEnergy recognizes net actuarial gains or losses for its pension and OPEB plans in the fourth quarter of each fiscal year and whenever a plan is determined to fluctuationsqualify for a remeasurement. A primary factor contributing to these actuarial gains and losses are changes in marketthe discount rates used to value pension and OPEB obligations as of the measurement date and the difference between expected and actual returns on the plans’ assets.
The remaining components of pension and OPEB expense, primarily service costs, interest cost on obligations, expected return on plan assets and amortization of prior service costs, are set at the beginning of the calendar year (unless a remeasurement is triggered) and are recorded on a monthly basis. Changes in asset performance and discount rates will not impact these pension costs for 2024, unless an additional remeasurement were to be triggered during the year, however, future years could be impacted by changes in the market.
FirstEnergy utilizes a spot rate approach in the estimation of the components of benefit cost by applying specific spot rates along the full yield curve to the relevant projected cash flows. As of March 31, 2024, the spot rate was 5.28% and 5.22% for pension and OPEB obligations, respectively, as compared to 5.05% and 4.97% as of December 31, 2023, respectively.
The final discount rate and return or loss on plan assets as of the year-end remeasurement date is difficult to predict based on the currently volatile equity markets and interest rate environment. As a result, FirstEnergy is unable to determine or meaningfully project the mark-to-market adjustment, or estimate a reasonable range of adjustment, that will be recorded as of December 31, 2024.
FirstEnergy’s 2021 Credit Facilities and 2023 Credit Facilities bear interest at fluctuating interest rates, is reduced sinceprimarily based on SOFR, including term SOFR and daily simple SOFR. FirstEnergy has not hedged its interest rate exposure with respect to its floating rate debt. Accordingly, FirstEnergy’s interest expense for any particular period will fluctuate based on SOFR and other variable interest rates. The high interest rate environment has caused the rate and interest expense on borrowings under the various FirstEnergy credit facilities to be significantly higher.
Economic Conditions
Post-pandemic economic conditions have increased supply chain lead times across numerous material categories, with some as much as tripling from pre-pandemic lead times. Several key suppliers have struggled with labor shortages and raw material availability, which along with inflationary pressure that appears to be moderating, have increased costs and decreased the availability of certain materials, equipment and contractors. FirstEnergy has taken steps to mitigate these risks and does not currently expect service disruptions or any material impact on its capital spending plan. However, the situation remains fluid and a significant portionprolonged continuation or further increase in supply chain disruptions could have an adverse effect on FirstEnergy’s results of its debt has fixed interest rates.operations, cash flow and financial condition.
Equity Price RiskCREDIT RISK
NDT funds have been established to satisfy NG’s nuclear decommissioning obligations. Included in NG's NDT are fixed income, equities and short-term investments carried at market values of approximately $969 million, $765 million and $96 million, respectively, as of September 30, 2017, excluding $(7) million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $76 million reduction in fair value as of September 30, 2017. NG recognizes in earnings the unrealized losses on AFS securities held in its NDT as OTTI. A decline in the value of NG's NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements by NG.
Credit Risk
Credit risk is defined as the risk that FirstEnergy would incur a counterparty toloss as a transaction will be unable to fulfill itsresult of nonperformance by counterparties of their contractual obligations. FES evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. FES may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. FES monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.
Wholesale Credit Risk
FES measures wholesale credit risk as the replacement cost for derivatives in power, natural gas, coal and emission allowances, adjusted for amounts owed to, or due from, counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, where FES has a legally enforceable right of offset. FES monitors and manages the credit risk of wholesale marketing, risk management and energy transacting operations throughFirstEnergy maintains credit policies and procedures whichwith respect to counterparty credit (including a requirement that counterparties maintain specified credit ratings) and requires other assurances in the form of credit support or collateral in certain circumstance in order to limit counterparty credit risk. FirstEnergy has concentrations of suppliers and customers among electric utilities, financial institutions and energy marketing and trading companies. These concentrations may impact FirstEnergy’s overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions. In the event an energy supplier of the Ohio Companies, FE PA, JCP&L or PE defaults on its obligation, the affected company would be required to seek replacement power in the market. In general, subject to regulatory review or other processes, it is expected that appropriate incremental costs incurred by these entities would be recoverable from customers through applicable rate mechanisms, thereby mitigating the financial risk for these entities. FirstEnergy’s credit policies to manage credit risk include the use of an established credit approval process, daily monitoring of counterparty credit limits, the use of credit mitigation measuresprovisions, such as margin, prepayment or collateral requirements. FirstEnergy and its subsidiaries may request additional credit assurance, in certain circumstances, in the event that the counterparties’ credit ratings fall below investment grade, their tangible net worth falls below specified percentages or their exposures exceed an established credit limit.
OUTLOOK
INCOME TAXES
On August 16, 2022, President Biden signed into law the IRA of 2022, which, among other things, imposes a new 15% corporate AMT based on AFSI applicable to corporations with a three-year average AFSI over $1 billion. The AMT is effective for the 2023 tax year and, if applicable, corporations must pay the greater of the regular corporate income tax or the AMT. Although NOL carryforwards created through the regular corporate income tax system cannot be used to reduce the AMT, financial statement net operating losses can be used to reduce AFSI and the useamount of master netting agreements.AMT owed. The IRA of 2022 as enacted requires the U.S. Treasury to provide regulations and other guidance necessary to administer the AMT, including further defining allowable adjustments to determine AFSI, which directly impacts the amount of AMT to be paid. Based on interim guidance issued by the U.S. Treasury during 2022 and 2023, FirstEnergy continues to believe that it is more likely than not it will be subject to the AMT beginning with 2023. Accordingly, FirstEnergy made a first quarter estimated payment of AMT of approximately $49 million in April 2023, however, made no additional payments in 2023 based on various factors, including additional guidance from the U.S. Treasury that eliminated the requirement of corporations to include AMT in quarterly estimated tax payments. Until final U.S. Treasury regulations are issued, the amount of AMT FirstEnergy pays could be significantly different than current estimates or it may not be a payer at all. The regulatory treatment of the impacts of this legislation may also be subject to regulation by FERC and/or applicable state regulatory authorities. Any adverse development in this legislation, including guidance from the U.S. Treasury and/or the IRS or unfavorable regulatory treatment, could negatively impact FirstEnergy’s cash flows, results of operations and financial condition.
As discussed above, on March 25, 2024, FirstEnergy closed on the sale of an additional 30% interest in FET, realizing an approximate $7.3 billion tax gain from the combined sale of 49.9% of the membership interests in FET for the consideration received and recapture of negative tax basis in FET. In the first quarter of 2024, FirstEnergy recognized a net tax charge of approximately $46 million, comprised of updates to estimated deferred tax liability for the deferred gain from the 19.9% sale of FET in May 2022, deferred tax liability related to its ongoing investment in FET, and valuation allowance associated with the expected utilization of certain state NOL carryforwards impacted by the sale and the PA Consolidation. During the first quarter of 2024, FirstEnergy also recognized a reduction to OPIC of approximately $797 million for federal and state income tax associated with the tax gain from closing on the 30% interest sale. As of December 31, 2023, FirstEnergy had approximately $8.1 billion of gross federal NOL carryforwards which will be used to offset a majority of FES' energy contract counterparties maintain investment-grade credit ratings.the tax gain from the FET Equity Interest Sale and expected taxable income in 2024, however due to certain limitations on utilization enacted in the Tax Act, a portion of the NOL will carry into 2025 and possibly beyond. As a result of the additional 30% sale, FET and its subsidiaries deconsolidated from FirstEnergy’s consolidated federal income tax group and now constitute their own consolidated federal income tax group subject to their own income tax allocation agreement.
Retail Credit RiskSTATE REGULATION
FES' principalEach of the Utilities' retail credit risk exposure relatesrates, conditions of service, issuance of securities and other matters are subject to its competitive electricity activities,regulation in the states in which serve residential, commercialit operates - in Maryland by the MDPSC, in New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and industrial companies. Retail credit risk results when customers defaultin New York by the NYPSC. The transmission operations of PE and TrAIL in Virginia, ATSI in Ohio, the Transmission Companies in Pennsylvania, PE and MP in West Virginia, and PE in Maryland are subject to certain regulations of the VSCC, PUCO, PPUC, WVPSC, and MDPSC, respectively. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission facilities, depending on contractual obligations or fail to pay for service rendered. This risk represents the loss thatstate, they may be incurred duerequired to obtain state regulatory authorization to site, construct and operate the nonpaymentnew transmission facility.
MARYLAND
PE operates under MDPSC approved base rates that were effective as of customer accounts receivable balances,October 19, 2023, and that were subsequently modified by an MDPSC order dated January 3, 2024, which became effective as well as the loss from the resale of energy previously committedMarch 1, 2024. PE also provides SOS pursuant to serve customers.
Retail credit riska combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is managed through established credit approval policies, monitoring customer exposures and the use of credit mitigation measures such as depositscompetitively procured in the form of LOCs,rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third-party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS.
The EmPOWER Maryland program requires each electric utility to file a plan to reduce electric consumption and demand 0.2% per year, up to the ultimate goal of 2% annual savings. PE recovers program investments with a return through an annually reconciled surcharge, with most costs subject to recovery over a five-year period with a return on the unamortized balance. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding. On August 1, 2023, PE filed its proposed plan for the 2024-2026 cycle as required by the MDPSC. Consistent with a December 29, 2022, order by the MDPSC phasing out the ability of Maryland utilities to earn a return on EmPOWER investments, PE will be required to expense 33% of its EmPOWER program costs in 2024, 67% in 2025 and 100% in 2026. Notwithstanding the order to phase out PE’s ability to earn a return on its EmPOWER investments, all previously unamortized costs for prior cycles will continue to earn a return and be collected by the end of 2029, consistent with the plan PE submitted on January 11, 2023. In the 2024-2026 order issued on December 29, 2023, the period to pay down the amortized balances was extended through the end of 2031. Additionally at the direction of the MDPSC, PE together with other Maryland utilities are required to address GHG reductions in addition to energy efficiency. In compliance with the MDPSC directive, PE submitted three scenarios with projected costs over a three-year cycle of $310 million, $354 million, and $510 million, respectively. The MDPSC conducted hearings on the proposed plans for all Maryland utilities on November 6-8, 2023. On December 29, 2023, the MDPSC issued an order approving the $310 million scenario for most programs, with some modifications. On February 21, 2024, the MDPSC approved PE’s tariff to recover costs in 2024 but directed PE to analyze alternative amortization methods for possible use in later years.
NEW JERSEY
JCP&L operates under NJBPU approved rates that took effect as of February 15, 2024, and will become effective for customers as of June 1, 2024. JCP&L provides BGS for retail customers who do not choose a third-party EGS and for customers of third- party EGSs that fail to provide the contracted service. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates.
The base rate increase, which was approved by the NJBPU on February 14, 2024, took effect on February 15, 2024, and is effective for customers on June 1, 2024. Until those new rates became effective for customers, JCP&L is amortizing an existing regulatory liability totaling approximately $18 million to offset the base rate increase that otherwise would have occurred in this period. Under the base rate case settlement agreement, JCP&L also agreed to a two-phase reliability improvement plan to enhance the reliability related to 18 high-priority circuits, the first phase of which began on February 14, 2024, and represents an approximate investment of $95 million. Additionally, JCP&L recognized a $53 million pre-tax charge in the first quarter 2024 at
the Integrated segment within “Other operating expenses” on the FirstEnergy Consolidated Statements of Income, associated with certain corporate support costs recorded to capital accounts from the FERC Audit that were determined, as a result of the settlement agreement, to be disallowed from future recovery.
JCP&L has implemented energy efficiency and peak demand reduction programs in accordance with the New Jersey Clean Energy Act as approved by the NJBPU in April 2021. The NJBPU approved plans include recovery of lost revenues resulting from the programs and a three-year plan (July 2021-June 2024) including total program costs of $203 million, of which $160 million of investment is recovered over a ten-year amortization period with a return as well as $43 million in operations and maintenance expenses and financing costs recovered on an annual basis. On December 5, 2023, JCP&L filed a petition with the NJBPU for a six-month extension of EE&C Plan I, which was originally scheduled to end on June 30, 2024, but would end on December 31, 2024, with the extension. The proposed budget for the extension period would add approximately $69 million to the original program cost. Under the proposal, JCP&L would recover the costs of the extension period and the revenue impact of sales losses resulting therefrom through two separate tariff riders. On December 1, 2023, JCP&L filed a related petition with the NJBPU requesting approval of its EE&C Plan II, which covers the January 1, 2025 through June 30, 2027 period and has a proposed budget of approximately $964 million. EE&C Plan II consists of a portfolio of ten energy efficiency programs, one peak demand reduction program and one building decarbonization program. Under the proposal, JCP&L would recover its EE&C Plan II revenue requirements and lost revenues from reduced electricity sales associated with EE&C Plan II. Evidentiary hearings are scheduled to begin August 19, 2024, with a final NJBPU decision and order required no later than October 15, 2024.
The settlement of the distribution rate case in 2020, provided among other things, that JCP&L would be subject to a management audit, which began in May 2021. On April 12, 2023, the NJBPU accepted the final management audit report for filing purposes and ordered that interested stakeholders file comments on the report by May 22, 2023, which deadline was extended until July 31, 2023. JCP&L filed its comments on July 31, 2023. The parties have filed responses.
On September 17, 2021, in connection with Mid-Atlantic Offshore Development, LLC, a transmission company jointly owned by Shell New Energies US and EDF Renewables North America, JCP&L submitted a proposal to the NJBPU and PJM to build transmission infrastructure connecting offshore wind-generated electricity to the New Jersey power grid. On October 26, 2022, the JCP&L proposal was accepted, in part, in an order issued by NJBPU. The proposal, as accepted, included approximately $723 million in investments for JCP&L to both build new and upgrade existing transmission infrastructure. JCP&L’s proposal projects an investment ROE of 10.2% and includes the option for JCP&L to acquire up to a 20% equity stake in Mid-Atlantic Offshore Development, LLC. The resulting rates associated with the project are expected to be shared among the ratepayers of all New Jersey electric utilities. On April 17, 2023, JCP&L applied for the FERC “abandonment” transmission rates incentive, which would provide for recovery of 100% of the cancelled prudent project costs that are incurred after the incentive is approved, and 50% of the costs incurred prior to that date, in the event that some or all of the project is cancelled for reasons beyond JCP&L’s control. FERC staff subsequently requested additional information on JCP&L’s application, which JCP&L provided. On August 21, 2023, FERC approved JCP&L’s application, effective August 22, 2023. On October 31, 2023, offshore wind developer, Orsted, announced plans to cease development of two offshore wind projects in New Jersey—Ocean Wind 1 and 2—having a combined planned capacity of 2,248 MWs. At this time, Orsted’s announcement does not affect JCP&L’s awarded projects and JCP&L is moving forward with preconstruction activities for the planned transmission infrastructure. Construction is expected to begin in 2025.
Consistent with the commitments made in its proposal to the NJBPU, JCP&L formally submitted in November 2023 the first part of its application to the United States Department of Energy to finance a portion of the project using low-interest rate loans available under the United States Department of Energy’s Energy Infrastructure Reinvestment Program of the IRA of 2022. JCP&L submitted the second part of its two-part application on March 13, 2024.
On April 3, 2024, Mid-Atlantic Offshore Development, LLC submitted a bid application for the NJBPU Prebuild Infrastructure Solicitation to the NJBPU which outlines its proposal to construct infrastructure connecting the identified landing point for offshore wind generation off the coast of New Jersey with the high-voltage electric grid at Larrabee Collector Station. JCP&L is described in the application as a joint developer with Mid-Atlantic Offshore Development, LLC, subject to the execution of a joint development agreement by the parties. Mid-Atlantic Offshore Development, LLC will be the party responsible for the project.
On November 9, 2023, JCP&L filed a petition for approval of its second EnergizeNJ with the NJBPU that would, among other things, support grid modernization, system resiliency and substation modernization in technologies designed to provide enhanced customer benefits. JCP&L proposes EnergizeNJ will be implemented over a five-year budget period with estimated costs of approximately $935 million over the deployment period, of which, $906 million is capital investments and $29 million is operating and maintenance expenses. Under the proposal, the costs of EnergizeNJ would be recovered through JCP&L’s base rates via annual and semi-annual base rate adjustment filings. Public hearings have been requested but are not yet scheduled. JCP&L has requested that the NJBPU issue a final decision and order no later than May 22, 2024, based on a June 1, 2024, commencement date for EnergizeNJ. JCP&L anticipates filing amendments to the EnergizeNJ program after receipt of approval from the NJBPU of the base rate case stipulation that was filed on February 2, 2024. On February 14, 2024, the NJBPU approved the stipulated settlement between JCP&L and various parties, resolving JCP&L’s request for a distribution base rate increase. On February 27, 2024, as part of the stipulated settlement, JCP&L amended its pending EnergizeNJ petition following receipt of NJBPU approval of the base rate case settlement, to include the second phase of its reliability improvement plan that is
expected to address any remaining high-priority circuits not addressed in the first phase. EnergizeNJ, as amended, if approved will result in the investment of approximately $930.5 million of total estimated costs over five years.
OHIO
The Ohio Companies operate under PUCO-approved base distribution rates that became effective in 2009. The Ohio Companies currently operate under ESP IV, which continues through May 31, 2024, that provides for the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continues the Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with revenue caps of $15 million per year through May 31, 2024. In addition, ESP IV includes: (1) continuation of a base distribution rate freeze through May 31, 2024; (2) a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045; and (3) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio.
On April 5, 2023, the Ohio Companies filed an application with the PUCO for approval of ESP V, for an eight-year term beginning June 1, 2024, and continuing through May 31, 2032. ESP V proposes to continue providing power to non-shopping customers at market-based prices set through an auction process, with process enhancements designed to reduce costs to customers. ESP V also proposes to continue riders supporting investment in the Ohio Companies’ distribution system, including Rider DCR with annual revenue cap increases of $15 million to $21 million per year, based on reliability performance, and Rider AMI for recovery of approved grid modernization investments. ESP V proposes new riders to support continued maintenance of the distribution system, including vegetation management and storm restoration operating expense. In addition, ESP V proposes four-year energy efficiency and peak demand reduction programs for residential and commercial customers, with cost recovery spread over eight years. ESP V further includes a commitment to spend $52 million in total over the eight-year term, without recovery from customers, on initiatives to assist low-income customers, education and incentives to help ensure customers have good experiences with electric vehicles. Hearings commenced on November 7, 2023 and concluded on December 6, 2023. On December 6, 2023, certain intervenors filed a motion requesting a limited stay of the Ohio Companies’ proposal to continue Rider DCR. The Ohio Companies contested the motion, which is pending.
On May 16, 2022, the Ohio Companies filed their application for determination of the existence of SEET under ESP IV for calendar year 2021, which demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings. This matter remains pending before the PUCO.
On July 15, 2022, the Ohio Companies filed an application with the PUCO for approval of phase two of their distribution grid modernization plan that would, among other things, provide for the installation of an additional 700 thousand smart meters, distribution automation equipment on approximately 240 distribution circuits, voltage regulating equipment on approximately 220 distribution circuits, and other investments and pilot programs in related technologies designed to provide enhanced customer benefits. The Ohio Companies propose that phase two will be implemented over a four-year budget period with estimated capital investments of approximately $626 million and operations and maintenance expenses of approximately $144 million over the deployment period. Under the proposal, costs of phase two of the grid modernization plan would be recovered through the Ohio Companies’ AMI rider, pursuant to the terms and conditions approved in ESP IV. On April 12, 2024, the Ohio Companies and certain of the parties filed a stipulation that modified the Ohio Companies’ application for phase two of its grid modernization plan. The stipulation, which is subject to PUCO approval, provides for the deployment of smart meters to the balance of the Ohio Companies’ customers or approximately 1.4 million meters. Phase two of the distribution grid modernization plan, as modified by the stipulation would be completed over a four-year budget period with estimated capital investments of approximately $421 million. On April 16, 2024, the PUCO scheduled the stipulation hearing for June 5, 2024.
On September 8, 2020, the OCC filed motions in the Ohio Companies’ corporate separation audit and DMR audit dockets, requesting the PUCO to open an investigation and management audit, hire an independent auditor, and require FirstEnergy to show it did not improperly use money collected from consumers or violate any utility regulatory laws, rules or orders in its activities regarding HB 6. On December 30, 2020, in response to the OCC's motion, the PUCO reopened the DMR audit docket, and directed PUCO staff to solicit a third-party auditor and conduct a full review of the DMR to ensure funds collected from customers through the DMR were only used for the purposes established in ESP IV. On June 2, 2021, the PUCO selected an auditor, and the auditor filed the final audit report on January 14, 2022, which made certain findings and recommendations. The report found that spending of DMR revenues was not required to be tracked, and that DMR revenues, like all rider revenues, are placed into the regulated money pool as a matter of routine, where the funds lose their identity. Therefore, the report could not suggest that DMR funds were used definitively for direct or indirect support for grid modernization. The report also concluded that there was no documented evidence that ties revenues from the DMR to lobbying for the passage of HB 6, but also could not rule out with certainty uses of DMR funds to support the passage of HB 6. The report further recommended that the regulated companies' money pool be audited more frequently and the Ohio Companies adopt formal dividend policies. Final comments and responses were filed by parties during the second quarter of 2022. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner consolidated this proceeding with the expanded Rider DCR audit proceeding described below and set a procedural schedule, which was vacated on March 15, 2024. A new procedural schedule will be set at a May 21, 2024 prehearing conference.
On September 15, 2020, the PUCO opened a new proceeding to review the political and charitable spending by the Ohio Companies in support of HB 6 and the subsequent referendum effort, and directing the Ohio Companies to show cause, demonstrating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by customers. The Ohio Companies initially filed a response stating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by customers, but on August 6, 2021, filed a supplemental response explaining that, in light of the facts set forth in the DPA and the findings of the Rider DCR audit report further discussed below, political or charitable spending in support of HB 6, or the subsequent referendum effort, affected pole attachment rates paid by approximately $15 thousand. On October 26, 2021, the OCC filed a motion requesting the PUCO to order an independent external audit to investigate FE’s political and charitable spending related to HB 6, and to appoint an independent review panel to retain and oversee the auditor. In November and December 2021, parties filed comments and reply comments regarding the Ohio Companies’ original and supplemental responses to the PUCO’s September 15, 2020, show cause directive. On May 4, 2022, the PUCO selected a third-party auditor to determine whether the show cause demonstration submitted by the Ohio Companies is sufficient to ensure that the cost of any political or charitable spending in support of HB 6 or the subsequent referendum effort was not included, directly or indirectly, in any rates or charges paid by ratepayers. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner directed the third-party auditor to file its report by August 28, 2024.
In connection with an ongoing audit of the Ohio Companies’ policies and procedures relating to the code of conduct rules between affiliates, on November 4, 2020, the PUCO initiated an additional corporate separation audit as a result of the FirstEnergy leadership transition announcement made on October 29, 2020, as further discussed below. The additional audit is to ensure compliance by the Ohio Companies and their affiliates with corporate separation laws and the Ohio Companies’ corporate separation plan. The additional audit is for the period from November 2016 through October 2020. The final audit report was filed on September 13, 2021. The audit report makes no findings of major non-compliance with Ohio corporate separation requirements, minor non-compliance with eight requirements, and findings of compliance with 23 requirements. Parties filed comments and reply comments on the audit report. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner set a procedural schedule, which was vacated on March 15, 2024. A new procedural schedule will be set at an April 25, 2024 prehearing conference.
In connection with an ongoing annual audit of the Ohio Companies’ Rider DCR for 2020, and as a result of disclosures in FirstEnergy’s Form 10-K for the year ended December 31, 2020 (filed on February 18, 2021), the PUCO expanded the scope of the audit on March 10, 2021, to include a review of certain transactions that were either improperly classified, misallocated, or lacked supporting documentation, and to determine whether funds collected from customers were used to pay the vendors, and if so, whether or not the funds associated with those payments should be returned to customers through Rider DCR or through an alternative proceeding. On August 3, 2021, the auditor filed its final report on this phase of the audit, and the parties submitted comments and reply comments on this audit report in October 2021. Additionally, on September 29, 2021, the PUCO expanded the scope of the audit in this proceeding to determine if the costs of the naming rights for FirstEnergy Stadium have been recovered from the Ohio Companies’ customers. On November 19, 2021, the auditor filed its final report, in which the auditor concluded that the FirstEnergy Stadium naming rights expenses were not recovered from Ohio customers. On December 15, 2021, the PUCO further expanded the scope of the audit to include an investigation into an apparent nondisclosure of a side agreement in the Ohio Companies’ ESP IV settlement proceedings, but stayed its expansion of the audit until otherwise ordered by the PUCO. The proceeding was stayed in its entirety, including discovery and motions, continuously at the request of the U.S. Attorney for the Southern District of Ohio beginning in August 2022 and was lifted on February 26, 2024. On February 26, 2024, the Attorney Examiner consolidated this proceeding with the Rider DMR audit proceeding described above, further lifted the stay of the portion of the investigation relating to an apparent nondisclosure of a side agreement, and set a procedural schedule, which was vacated on March 15, 2024. A new procedural schedule will be set at a May 21, 2024 prehearing conference.
On March 1, 2024, the Attorney Examiner issued an Entry in all four PUCO investigations that, among other things, precluded taking or offering the testimony of Charles E. Jones, Michael J. Dowling, or Samuel Randazzo through deposition or other means, or requiring these individuals to produce documents, in any PUCO proceeding, until otherwise ordered.
On September 22, 2023, OCC filed an application for rehearing challenging the PUCO’s August 23, 2023, order to stay the pending HB 6 related matters above, which the PUCO denied on October 18, 2023. On November 17, 2023, OCC filed an application for rehearing challenging the October 18, 2023 entry to the extent the PUCO decided not to stay pending proceedings regarding ESP V as well as phases one and two of the Ohio Companies’ distribution grid modernization plans. On November 27, 2023, the Ohio Companies filed a memorandum contra OCC’s application for rehearing.
In the fourth quarter of 2020, motions were filed with the PUCO requesting that the PUCO amend the Ohio Companies’ riders for collecting the OVEC-related charges required by HB 6 to provide for refunds in the event such provisions of HB 6 are repealed. Neither the Ohio Companies nor FE benefit from the OVEC-related charges the Ohio Companies collect. Instead, the Ohio Companies are further required by HB 6 to remit all the OVEC-related charges they collect to non-FE Ohio electric distribution utilities. The Ohio Companies contested the motions, which are pending before the PUCO.
On May 15, 2023, the Ohio Companies filed their application for determination of the existence of SEET under ESP IV for calendar year 2022, which demonstrated that each of the individual Ohio Companies did not have significantly excessive earnings. This matter remains pending before the PUCO.
See below for additional details on the government investigations and subsequent litigation surrounding the investigation of HB 6.
PENNSYLVANIA
The Pennsylvania Companies operated under rates approved by the PPUC, effective as of January 27, 2017. On January 1, 2024, each of the Pennsylvania Companies merged with and into FE PA. As a result of the PA Consolidation, FE PA will have five rate districts in Pennsylvania – four that correspond to the territories previously serviced by ME, PN, Penn, and WP and one rate district that corresponds to WP’s service provided to The Pennsylvania State University. The rate districts created by the PA Consolidation will not reach full rate unity until the earlier of 2033 or the conclusion of three base rate cases filed after January 1, 2025.
Pursuant to Pennsylvania Act 129 of 2008 and PPUC orders, the Pennsylvania Companies implemented energy efficiency and peak demand reduction programs with demand reduction targets, relative to 2007-2008 peak demands, at 2.9% MW for ME, 3.3% MW for PN, 2.0% MW for Penn, and 2.5% MW for WP; and energy consumption reduction targets, as a percentage of the Pennsylvania Companies’ historic 2009 to 2010 reference load at 3.1% MWh for ME, 3.0% MWh for PN, 2.7% MWh for Penn, and 2.4% MWh for WP. The fourth phase of FE PA’s energy efficiency and peak demand reduction program, which runs for the five-year period beginning June 1, 2021 through May 31, 2026, was approved by the PPUC on June 18, 2020, providing through cost recovery of approximately $390 million to be recovered through Energy Efficiency and Conservation Phase IV Riders for each FE PA rate district.
Pennsylvania EDCs are permitted to seek PPUC approval of an LTIIP for infrastructure improvements and costs related to highway relocation projects, after which a DSIC may be approved to recover LTIIP costs. On January 16, 2020, the PPUC approved the Pennsylvania Companies’ LTIIPs for the five-year period beginning January 1, 2020 and ending December 31, 2024 for a total capital investment of approximately $572 million for certain infrastructure improvement initiatives. FE PA expects to seek approval for the next phase of its LTIIP program by the end of the third quarter of 2024.
Following the Pennsylvania Companies’ 2016 base rate proceedings, the PPUC ruled in a separate proceeding related to the DSIC mechanisms that the Pennsylvania Companies were not required to reflect federal and state income tax deductions related to DSIC-eligible property in DSIC rates. The decision was appealed to the Pennsylvania Supreme Court and in July 2021 the court upheld the Pennsylvania Commonwealth Court’s reversal of the PPUC’s decision and remanded the matter back to the PPUC for determination as to how DSIC calculations shall account for accumulated deferred income taxes and state taxes. The PPUC issued the order as directed.
On May 5, 2023, FirstEnergy and Brookfield submitted applications to FERC and to the PPUC to facilitate the FET Equity Interest Sale. On May 12, 2023, the parties also filed an application with the VSCC, which was approved on June 20, 2023. On August 14, 2023, FERC issued an order approving the FET Equity Interest Sale. On November 24, 2023, CFIUS notified FET, Brookfield and the Abu Dhabi Investment Authority, as an indirect investor in FET through Brookfield, that it had determined that there were no unresolved national security issues and its review of the transaction was concluded. On November 29, 2023, the parties filed a settlement agreement recommending that the PPUC approve the transaction subject to the terms of the settlement, which includes among other things, a number of ring-fencing provisions and a commitment to improve transmission reliability over the next five years. The settlement was approved by the PPUC on March 14, 2024. The transaction closed on March 25, 2024.
On April 2, 2024, FE PA filed a base rate case with the PPUC, based on a projected 2025 annual test year. The rate case requests a net increase in base distribution revenues of approximately $502 million with a return on equity of 11.3% and capital structure of 46.2% debt and 53.8% equity, and reflects a roll-in of several current riders such as DSIC, Tax Act and smart meter. The increase represents an overall net average rate increase in FE PA rates by approximately 7.7%, and a 10.5% average residential rate increase. Key components of the base rate case filing include a proposal to change pension and OPEB recovery to the delayed recognition method and to implement a mechanism to establish a regulatory asset (or liability) to recover (or refund) net differences between the amount of pension and OPEB expense requested in the proceeding and the actual annual amount each year using this method. Additionally, FE PA requests recovery of certain incurred costs, including the impact of major storms, COVID-19, a program to convert streetlights to LEDs, and others. The PPUC issued an order on April 25, 2024, deferring, by operation of law, the June 1, 2024 statutory effective date to January 1, 2025. A pre-hearing conference is scheduled for May 2, 2024. A PPUC decision is expected in December 2024, with new rates becoming effective in January 2025.
WEST VIRGINIA
MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operate under WVPSC-approved rates. 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 August 31, 2023, MP and PE filed with the WVPSC their annual ENEC case requesting an increase in ENEC rates of $167.5 million beginning January 1, 2024, which represents a 9.9% increase in overall rates. This increase, which was driven primarily by higher fuel expenses, includes the approximate $92 million carried over from the 2022 ENEC proceeding and a portion of the approximately $267 million under recovery balance at the end of the review period (July 1, 2022 to June 30, 2023). The remaining $75.6 million of the under recovery balance not recovered in 2024 will be deferred for collection during 2025, with an annual carrying charge of 4%. A hearing was held on November 30, 2023, at which time a joint stipulation for settlement that was agreed to by all but one party was presented to the WVPSC. The settlement provides for a net $55.4 million increase in ENEC rates beginning March 27, 2024 with the net deferred ENEC balance of approximately $255 million to be recovered through 2026. There will be no 2024 ENEC case unless MP and PE over or under recover more than $50 million than the 2024 ENEC balance and a party elects to invoke a case filing. An order was issued on March 26, 2024 approving the settlement without modification and rates became effective on March 27, 2024.
On April 21, 2022, the WVPSC issued an order approving, effective May 1, 2022, a tariff to offer solar power to West Virginia customers and requiring MP and PE to subscribe at least 85% of the planned 50 MWs of solar generation before seeking final tariff approval. MP and PE must seek separate approval from the WVPSC to recover any solar generation costs in excess of the approved tariff. On April 24, 2023, MP and PE sought final tariff approval from the WVPSC for three of the five solar sites, representing 30 MWs of generation, and requested approval of a surcharge to recover any costs above the final approved tariff. The first solar generation site went into service in January 2024 and construction of the remaining four sites are expected to be completed no later than the end of 2025 at a total investment cost of approximately $110 million. On August 23, 2023, the WVPSC approved the customer surcharge and granted approval to construct three of the five solar sites. The surcharge went into effect January 1, 2024.
On January 13, 2023, MP and PE filed a request with the WVPSC seeking approval of new depreciation rates for existing and future capital assets. Specifically, MP and PE are seeking to increase depreciation expense by approximately $76 million per year, primarily for regulated generation-related assets. Any depreciation rates approved by the WVPSC would not become effective until new base rates were established. On August 22, 2023, a unanimous settlement of the case was filed recommending a $33 million per year increase in depreciation expense, effective April 1, 2024. An order from the WVPSC was issued on March 26, 2024 approving the settlement without modification and became effective on March 27, 2024.
On May 31, 2023, MP and PE filed a base rate case with the WVPSC requesting a total revenue increase of approximately $207 million utilizing a test year of 2022 with adjustments plus a request to establish a regulatory asset (or liability) to recover (or refund) in a subsequent base rate case the net differences between the amount of pension and OPEB expense requested in the proceeding (based on average expense from 2018 to 2022) and the actual annual amount each year using the delayed recognition method. Among other things, the increase includes the approximate $76 million requested in a depreciation case filed on January 13, 2023 and described above, and amounts to support a new low-income customer advocacy program, storm restoration work and service reliability investments. On January 23, 2024, MP, PE and various parties filed a joint settlement agreement with the WVPSC, which recommended a base rate increase of $105 million, inclusive of the $33 million increase in depreciation expense. Additionally, the settlement includes a new low-income customer advocacy program, a pilot program for service reliability investments and recovery of costs related to storm restoration, retired generation assets and COVID-19. The settlement did not include the request to establish a regulatory asset (or liability) for recover (or refund) associated with pension and OPEB expense, however, it did not preclude MP and PE from pursuing that in a future separate proceeding. On February 16, 2024, interested parties filed a settlement on the net energy metering credit for consideration by the WVPSC. An order was issued on March 26, 2024 approving the $105 million increase and accepting the settlement with slight non-material modifications with new rates going into effect on March 27, 2024. Additionally, due to the order including approval by the WVPSC to recover certain costs associated with retired generation assets, MP recognized a $60 million pre-tax benefit in the first quarter of 2024 to establish a regulatory asset.
FERC REGULATORY MATTERS
Under the Federal Power Act, FERC regulates rates for interstate wholesale sales and transmission of electric power, regulatory accounting and reporting under the Uniform System of Accounts, and other matters, including construction and operation of hydroelectric projects. With respect to their wholesale services and rates, the Utilities, AE Supply and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE and the Transmission Companies are subject to functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff. On January 1, 2024, WP transferred certain of its Pennsylvania-based transmission assets to KATCo.
FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers to entry into markets. The Utilities and AE Supply each have the necessary authorization from FERC to sell their
wholesale power, if any, in interstate commerce at market-based rates, although in the case of the Utilities major wholesale purchases remain subject to review and regulation by the relevant state commissions.
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, and the Transmission Companies. NERC is the Electric Reliability Organization 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 six regional entities, including RFC. All of the facilities that FirstEnergy operates 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 material compliance with all currently effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy’s part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, or obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations, and cash flows.
FERC Audit
FERC’s Division of Audits and Accounting initiated a nonpublic audit of FESC in February 2019. Among other matters, the audit is evaluating FirstEnergy’s compliance with certain accounting and reporting requirements under various FERC regulations. On February 4, 2022, FERC filed the final audit report for the period of January 1, 2015 through September 30, 2021, which included several findings and recommendations that FirstEnergy has accepted. The audit report included a finding and related recommendation on FirstEnergy’s methodology for allocation of certain corporate support costs to regulatory capital accounts under certain FERC regulations and reporting. Effective in the first quarter of 2022 and in response to the finding, FirstEnergy had implemented a new methodology for the allocation of these corporate support costs to regulatory capital accounts for its regulated distribution and transmission companies on a prospective basis. With the assistance of an independent outside firm, FirstEnergy completed an analysis during the third quarter of 2022 of these costs and how it impacted certain FERC-jurisdictional wholesale transmission customer rates for the audit period of 2015 through 2021. As a result of this analysis, FirstEnergy recorded in the third quarter of 2022 approximately $45 million ($34 million after-tax) in expected customer refunds, plus interest, due to its wholesale transmission customers and reclassified approximately $195 million of certain transmission capital assets to operating expenses for the audit period, of which $90 million ($67 million after-tax) are not expected to be recoverable and impacted FirstEnergy’s earnings since they relate to costs capitalized during stated transmission rate time periods. FirstEnergy is currently recovering approximately $105 million of costs reclassified to operating expenses in its transmission formula rate revenue requirements, of which $39 million of costs have been recovered as of March 31, 2024. On December 8, 2023, FERC audit staff issued a letter advising that two unresolved audit matters, primarily related to FirstEnergy’s plan to recover the reclassified operating expenses in formula transmission rates, were being referred to other offices within FERC for further review. These reclassifications also resulted in a reduction to the Regulated Transmission segment’s rate base by approximately $160 million, which is not expected to materially impact FirstEnergy or prepayment arrangements.the segment’s future earnings. The expected wholesale transmission customer refunds were recognized as a reduction to revenue, and the amount of reclassified transmission capital assets that are not expected to be recoverable were recognized within “Other operating expenses” at the Regulated Transmission segment and on FirstEnergy’s Consolidated Statements of Income. Furthermore, FirstEnergy’s Utilities are in the process of addressing the outcomes of the FERC Audit with the applicable state commissions and proceedings, which includes seeking continued rate base treatment of approximately $200 million of certain corporate support costs allocated to distribution capital assets in Ohio and Pennsylvania. If FirstEnergy is unable to recover these transmission or distribution costs, it could result in future charges and/or adjustments and have an adverse impact on FirstEnergy’s financial condition.
Retail credit qualityATSI ROE – Ohio Consumers Counsel v. ATSI, et al.
On February 24, 2022, the OCC filed a complaint with FERC against ATSI, AEP’s Ohio affiliates and American Electric Power Service Corporation, and Duke Energy Ohio, LLC asserting that FERC should reduce the ROE utilized in the utilities’ transmission formula rates by eliminating the 50 basis point adder associated with RTO membership, effective February 24, 2022. The OCC contends that this result is required because Ohio law mandates that transmission owning utilities join an RTO and that the 50 basis point adder is applicable only where RTO membership is voluntary. On December 15, 2022, FERC denied the complaint as to ATSI and Duke, but granted it as to AEP. AEP and OCC appealed FERC’s orders to the Sixth Circuit and the case remains pending. FirstEnergy is unable to predict the outcome of this proceeding, but it is not expected to have a material impact.
Transmission ROE Methodology
A proposed rulemaking proceeding concerning transmission rate incentives provisions of Section 219 of the 2005 Energy Policy Act was initiated in March of 2020 remains pending before FERC. Among other things, the rulemaking explored whether utilities should collect an “RTO membership” ROE incentive adder for more than three years. FirstEnergy is a member of PJM and its transmission subsidiaries could be affected by the economyproposed rulemaking. FirstEnergy participated in comments on the supplemental rulemaking that were submitted by a group of PJM transmission owners and the ability of customers to manage through unfavorable economic cycles and other market changes.by various industry trade groups. If the business environmentthere were to be negativelyany changes to FirstEnergy's transmission incentive ROE, such changes will be applied on a prospective basis.
Transmission Planning Supplemental Projects: Ohio Consumers Counsel v ATSI, et al.
On September 27, 2023, the OCC filed a complaint against ATSI, PJM and other transmission utilities in Ohio alleging that the PJM Tariff and operating agreement are unjust, unreasonable, and unduly discriminatory because they include no provisions to ensure PJM’s review and approval for the planning, need, prudence and cost-effectiveness of the PJM Tariff Attachment M-3 “Supplemental Projects.” Supplemental Projects are projects that are planned and constructed to address local needs on the transmission system. The OCC demands that FERC: (i) require PJM to review supplemental projects for need, prudence and cost-effectiveness; (ii) appoint an independent transmission monitor to assist PJM in such review; and (iii) require that Supplemental Projects go into rate base only through a “stated rate” procedure whereby prior FERC approval would be needed for projects with costs that exceed an established threshold. ATSI and the other transmission utilities in Ohio and PJM filed comments and the complaint is pending before FERC.
ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. While FirstEnergy’s environmental policies and procedures are designed to achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and potential revision by the implementing agencies. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof may materially impact its business, results of operations, cash flows and financial condition.
Clean Air Act
FirstEnergy complies with SO2 and NOx emission reduction requirements under the CAA and SIP by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls and/or using emission allowances.
CSAPR requires reductions of NOx and SO2 emissions in two phases (2015 and 2017), ultimately capping SO2 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 SO2 emission allowances between power plants located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. On July 28, 2015, the D.C. Circuit ordered the EPA to reconsider the CSAPR caps on NOx and SO2 emissions from power plants in 13 states, including West Virginia. This followed the 2014 U.S. Supreme Court ruling generally upholding the EPA’s regulatory approach under CSAPR but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR Update on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR Update to the D.C. Circuit in November and December 2016. On September 13, 2019, the D.C. Circuit remanded the CSAPR Update to the EPA citing that the rule did not eliminate upwind states’ significant contributions to downwind states’ air quality attainment requirements within applicable attainment deadlines.
Also in March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from nine states (including West Virginia) significantly contribute to New York’s inability to attain the ozone National Ambient Air Quality Standards. The petition sought suitable emission rate limits for large stationary sources that are allegedly affecting New York’s air quality within the three years allowed by CAA Section 126. On September 20, 2019, the EPA denied New York’s CAA Section 126 petition. On October 29, 2019, the State of New York appealed the denial of its petition to the D.C. Circuit. On July 14, 2020, the D.C. Circuit reversed and remanded the New York petition to the EPA for further consideration. On March 15, 2021, the EPA issued a revised CSAPR Update that addressed, among other things, the remands of the prior CSAPR Update and the New York Section 126 petition. In December 2021, MP purchased NOx emissions allowances to comply with 2021 ozone season requirements. On April 6, 2022, the EPA published proposed rules seeking to impose further significant reductions in EGU NOx emissions in 25 upwind states, including West Virginia, with the stated purpose of allowing downwind states to attain or maintain compliance with the 2015 ozone National Ambient Air Quality Standards. On February 13, 2023, the EPA disapproved 21 SIPs, which was a prerequisite for the EPA to issue a final Good Neighbor Plan or FIP. On June 5, 2023, the EPA issued the final Good Neighbor Plan with an effective date 60 days thereafter. Certain states, including West Virginia, have appealed the disapprovals of their respective SIPs, and some of those states have obtained stays of those disapprovals precluding the Good Neighbor Plan from taking effect in those states. On August 10, 2023, the 4th Circuit granted West Virginia an interim stay of the disapproval of its SIP and on January 10, 2024, after a hearing held on October 27, 2023, granted a full stay which precludes the Good Neighbor Plan from going into effect in West Virginia. In addition to West Virginia, certain other states, and certain trade
organizations, including the Midwest Ozone Group of which FE is a member, have separately appealed and filed motions to stay the Good Neighbor Plan itself at the D.C. Circuit. On September 25, 2023, the D.C. Circuit denied the motions to stay the Good Neighbor Plan. On October 13, 2023, the aggrieved parties filed an Emergency Application for an Immediate Stay of the Good Neighbor Plan with the U.S. Supreme Court, which remains pending. Oral argument was heard on February 21, 2024.
Climate Change
In March 2024, the SEC issued final rules to require public companies to disclose certain climate-related information in registration statements and annual reports filed with the SEC. As adopted, the final climate disclosure rules mandate the disclosure of climate-related risks and the material impacts that severe weather events and other natural conditions have had, or are reasonably likely to have, on FirstEnergy, as well as disclosures related to management and FE Board oversight of such risks. In April 2024, the SEC voluntarily stayed the final climate disclosure rules pending resolution of legal challenges. FirstEnergy currently is assessing the impact of the final climate disclosure rules on its business. There are several initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the Regional Greenhouse Gas Initiative 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.
FirstEnergy has pledged to achieve carbon neutrality by 2050 in GHGs within FirstEnergy’s direct operational control (Scope 1). With respect to our coal-fired plants in West Virginia, we have identified that the end of the useful life date is 2035 for Fort Martin and 2040 for Harrison. Determination of the useful life of the regulated coal-fired generation could result in changes in economic depreciation, and/or continued collection of net plant in rates after retirement, securitization, sale, impairment, or regulatory disallowances. If MP is unable to recover these costs, it could have a material adverse effect on FirstEnergy’s and/or MP’s financial condition, results of operations, and cash flow. Furthermore, FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other market conditions, FES' retail credit riskexpenditures or result in changes to its operations.
In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for GHGs under the Clean Air Act,” concluding that concentrations of several key GHGs constitute an “endangerment” and may be adversely impacted.regulated as “air pollutants” under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. Subsequently, the EPA released its final CPP regulations in August 2015 to reduce CO2 emissions from existing fossil fuel-fired EGUs and finalized separate regulations imposing CO2 emission limits for new, modified, and reconstructed fossil fuel-fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court. On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On June 19, 2019, the EPA repealed the CPP and replaced it with the ACE rule that established guidelines for states to develop standards of performance to address GHG emissions from existing coal-fired generation. On January 19, 2021, the D.C. Circuit vacated and remanded the ACE rule declaring that the EPA was “arbitrary and capricious” in its rule making and, as such, the ACE rule is no longer in effect and all actions thus far taken by states to implement the federally mandated rule are now null and void. Vacating the ACE rule had the unintended effect of reinstating the CPP because the repeal of the CPP was a provision within the ACE rule. The D.C. Circuit decision was appealed by several states and interested parties, including West Virginia, arguing that the EPA did not have the authorization under Section 111(d) of the CAA to require “generation shifting” as a way to limit GHGs. On June 30, 2022, the U.S. Supreme Court in West Virginia v. Environmental Protection Agency held that the method the EPA used to regulate GHGs (generation shifting) under Section 111(d) of the CAA (the CPP) was not authorized by Congress and remanded the rule to the EPA for further reconsideration. In response, on May 23, 2023, the EPA published a proposed rule pursuant to CAA Section 111 (b) and (d) in line with the decision in West Virginia v. Environmental Protection Agency intended to reduce power sector GHG emissions (primarily CO2 emissions) from fossil fuel based EGUs. The rule, which proposed stringent emissions limitations based on fuel type and unit retirement date, was issued as final by the EPA on April 25, 2024. FirstEnergy is currently assessing the impact of the final rule. Depending on the outcome of any appeals, compliance with these standards could require additional capital expenditures or changes in operation at the Ft. Martin and Harrison power stations.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy’s facilities. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy’s operations.
On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations were to phase-in as permits are renewed on a five-year cycle from 2018 to 2023. However, on April 13, 2017, the EPA granted a Petition for Reconsideration and on September 18, 2017, the EPA postponed certain compliance deadlines for two years. On August 31, 2020, the EPA issued a final rule revising the effluent limits for discharges from wet scrubber systems, retaining the zero-discharge standard for ash transport water, (with some limited
discharge allowances), and extending the deadline for compliance to December 31, 2025 for both. In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system, and unit retirement date. On March 29, 2023, the EPA published proposed revised ELGs applicable to coal-fired power plants that include more stringent effluent limitations for wet scrubber systems and ash transport water, and new limits on landfill leachate. The rule was issued as final by the EPA on April 25, 2024 and depending on the outcome of appeals and how final revised rules are ultimately implemented, compliance with these standards could require additional capital expenditures or changes in operation at closed and active landfills, and at the Ft. Martin and Harrison power stations from what was approved by the WVPSC in September 2022 to comply with the 2020 ELG rule. FirstEnergy is currently assessing the impact of the final rule.
Regulation of Waste Disposal
Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act, as amended, and the Toxic Substances Control Act. Certain CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation.
In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 29, 2020, the EPA published a final rule again revising the date that certain CCR impoundments must cease accepting waste and initiate closure to April 11, 2021. The final rule allowed for an extension of the closure deadline based on meeting identified site-specific criteria. On November 30, 2020, AE Supply submitted a closure deadline extension request to the EPA seeking to extend the cease accepting waste date for the McElroy's Run CCR impoundment facility to October 2024, which request is pending technical review by the EPA. AE Supply continues to operate McElroy’s Run as a disposal facility for Pleasants Power Station and continues to evaluate closure options. Also, on April 25, 2024, the EPA issued rules as final addressing, for the first time, certain legacy CCR disposal sites. FirstEnergy is currently assessing the impact of the final rule.
FE or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on FirstEnergy’s Consolidated Balance Sheets as of March 31, 2024, based on estimates of the total costs of cleanup, FirstEnergy’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $97 million have been accrued through March 31, 2024, of which approximately $70 million are for environmental remediation of former MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable societal benefits charge. FE or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time.
OTHER LEGAL PROCEEDINGS
United States v. Larry Householder, et al.
On July 21, 2020, a complaint and supporting affidavit containing federal criminal allegations were unsealed against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. In March 2023, a jury found Mr. Householder and his co-defendant, Matthew Borges, guilty and in June 2023, the two were sentenced to prison for 20 and 5 years, respectively. Messrs. Householder and Borges have appealed their sentences. Also, on July 21, 2020, and in connection with the DOJ’s investigation, FirstEnergy received subpoenas for records from the U.S. Attorney’s Office for the Southern District Ohio. FirstEnergy was not aware of the criminal allegations, affidavit or subpoenas before July 21, 2020.
On July 21, 2021, FE entered into a three-year DPA with the U.S. Attorney’s Office that, subject to court proceedings, resolves this matter. Under the DPA, FE has agreed to the filing of a criminal information charging FE with one count of conspiracy to commit honest services wire fraud. The DPA requires that FirstEnergy, among other obligations: (i) continue to cooperate with the U.S. Attorney’s Office in all matters relating to the conduct described in the DPA and other conduct under investigation by the U.S. government; (ii) pay a criminal monetary penalty totaling $230 million within sixty days, which shall consist of (x) $115 million paid by FE to the United States Treasury and (y) $115 million paid by FE to the ODSA to fund certain assistance programs, as determined by the ODSA, for the benefit of low-income Ohio electric utility customers; (iii) publish a list of all payments made in 2021 to either 501(c)(4) entities or to entities known by FirstEnergy to be operating for the benefit of a public official, either directly or indirectly, and update the same on a quarterly basis during the term of the DPA; (iv) issue a public statement, as dictated in the DPA, regarding FE’s use of 501(c)(4) entities; and (v) continue to implement and review its compliance and ethics program, internal controls, policies and procedures designed, implemented and enforced to prevent and detect violations of the U.S. laws throughout its operations, and to take certain related remedial measures. The $230 million payment will neither be recovered in rates or charged to FirstEnergy customers, nor will FirstEnergy seek any tax deduction related to such payment. The entire amount of the monetary penalty was recognized as expense in the second quarter of 2021
and paid in the third quarter of 2021. Under the terms of the DPA, the criminal information will be dismissed after FirstEnergy fully complies with its obligations under the DPA.
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ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Legal Proceedings Relating to United States v. Larry Householder, et al.
On August 10, 2020, the SEC, through its Division of Enforcement, issued an order directing an investigation of possible securities laws violations by FE, and on September 1, 2020, issued subpoenas to FE and certain FE officers. On April 28, 2021, July 11, 2022, and May 25, 2023, the SEC issued additional subpoenas to FE, with which FE has complied. While no contingency has been reflected in its consolidated financial statements, FE believes that it is probable that it will incur a loss in connection with the resolution of the SEC investigation. Given the ongoing nature and complexity of the investigation, FE cannot yet reasonably estimate a loss or range of loss that may arise from the resolution of the SEC investigation.
On June 29, 2023, the OOCIC served FE a subpoena, seeking information relating to the conduct described in the DPA. FirstEnergy was not aware of the OOCIC’s investigation prior to receiving the subpoena and understands that the OOCIC’s investigation is also focused on the conduct described in the DPA, other than with respect to the March 25, 2024, felony indictment of Mr. Householder brought in Cuyahoga County, Ohio. FirstEnergy is cooperating with the OOCIC in its investigation. On February 12, 2024, and in connection with the OOCIC’s ongoing investigation, an indictment by a grand jury of Summit County, Ohio was unsealed against the former chairman of the PUCO, Samuel Randazzo, and two former FirstEnergy senior officers, Charles E. Jones, and Michael J. Dowling, charging each of them with several felony counts, including bribery, telecommunications fraud, money laundering and aggravated theft, related to payments described in the DPA. FirstEnergy continues to both cooperate with the OOCIC in its investigation and discuss an appropriate resolution of the investigation with respect to FE. While no contingency has been reflected in FirstEnergy’s consolidated financial statements, FE believes that it is reasonably possible that it will incur a loss in connection with the resolution of the OOCIC investigation. Given the ongoing nature of the discussions, while FE cannot yet reasonably estimate a loss or range of loss that may arise from any resolution of the OOCIC investigation with respect to FE, any such payment by FE associated with an OOCIC resolution is not expected to be material.
In addition to the subpoenas referenced above under “United States v. Larry Householder, et. al.” and the SEC investigation, certain FE stockholders and FirstEnergy customers filed several lawsuits against FirstEnergy and certain current and former directors, officers and other employees, and the complaints in each of these suits is related to allegations in the complaint and supporting affidavit relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. The plaintiffs in each of the below cases seek, among other things, to recover an unspecified amount of damages (unless otherwise noted). Unless otherwise indicated, no contingency has been reflected in FirstEnergy’s consolidated financial statements with respect to these lawsuits as a loss is neither probable, nor is a loss or range of a loss reasonably estimable.
•In re FirstEnergy Corp. Securities Litigation (S.D. Ohio); on July 28, 2020 and August 21, 2020, purported stockholders of FE filed putative class action lawsuits alleging violations of the federal securities laws. Those actions have been consolidated and a lead plaintiff, the Los Angeles County Employees Retirement Association, has been appointed by the court. A consolidated complaint was filed on February 26, 2021. The consolidated complaint alleges, on behalf of a proposed class of persons who purchased FE securities between February 21, 2017 and July 21, 2020, that FE and certain current or former FE officers violated Sections 10(b) and 20(a) of the Exchange Act by issuing misrepresentations or omissions concerning FE’s business and results of operations. The consolidated complaint also alleges that FE, certain current or former FE officers and directors, and a group of underwriters violated Sections 11, 12(a)(2) and 15 of the Securities Act of 1933 as a result of alleged misrepresentations or omissions in connection with offerings of senior notes by FE in February and June 2020. On March 30, 2023, the court granted plaintiffs’ motion for class certification. On April 14, 2023, FE filed a petition in the U.S. Court of Appeals for the Sixth Circuit seeking to appeal that order, which the Sixth Circuit granted on November 16, 2023. On November 30, 2023, FE filed a motion with the S.D. Ohio to stay all proceedings pending the circuit court appeal. All discovery is stayed during the pendency of the district court motion. FE believes that it is probable that it will incur a loss in connection with the resolution of this lawsuit. Given the ongoing nature and complexity of such litigation, FE cannot yet reasonably estimate a loss or range of loss.
•MFS Series Trust I, et al. v. FirstEnergy Corp., et al. and Brighthouse Funds II – MFS Value Portfolio, et al. v. FirstEnergy Corp., et al. (S.D. Ohio) on December 17, 2021 and February 21, 2022, purported stockholders of FE filed complaints against FE, certain current and former officers, and certain current and former officers of EH. The complaints allege that the defendants violated Sections 10(b) and 20(a) of the Exchange Act by issuing alleged misrepresentations or omissions regarding FE’s business and its results of operations, and seek the same relief as the In re FirstEnergy Corp. Securities Litigation described above. All discovery is stayed during the pendency of the district court motion in In re FirstEnergy Corp. Securities Litigation described above. FE believes that it is probable that it will incur losses in connection with the resolution of these lawsuits. Given the ongoing nature and complexity of such litigation, FE cannot yet reasonably estimate a loss or range of loss.
•State of Ohio ex rel. Dave Yost, Ohio Attorney General v. FirstEnergy Corp., et al. and City of Cincinnati and City of Columbus v. FirstEnergy Corp. (Common Pleas Court, Franklin County, OH, all actions have been consolidated); on September 23, 2020 and October 27, 2020, the OAG and the cities of Cincinnati and Columbus, respectively, filed complaints against several parties including FE, each alleging civil violations of the Ohio Corrupt Activity Act and related
claims in connection with the passage of HB 6. On January 13, 2021, the OAG filed a motion for a temporary restraining order and preliminary injunction against FirstEnergy seeking to enjoin FirstEnergy from collecting the Ohio Companies' decoupling rider. On January 31, 2021, FE reached a partial settlement with the OAG and the cities of Cincinnati and Columbus with respect to the temporary restraining order and preliminary injunction request and related issues. In connection with the partial settlement, the Ohio Companies filed an application on February 1, 2021, with the PUCO to set their respective decoupling riders (Conservation Support Rider) to zero. On February 2, 2021, the PUCO approved the application of the Ohio Companies setting the rider to zero, and no additional customer bills will include new decoupling rider charges after February 8, 2021. On August 13, 2021, new defendants were added to the complaint, including two former officers of FirstEnergy. On December 2, 2021, the cities and FE entered a stipulated dismissal with prejudice of the cities’ suit. This matter was stayed through a criminal trial in United States v. Larry Householder, et al. described above, but resumed pursuant to an order, dated March 15, 2023. On July 31, 2023, FE and other defendants filed motions to dismiss in part the OAG’s amended complaint, which the OAG opposed. On February 16, 2024, the OAG moved to stay discovery in the case in light of the February 9, 2024, indictments against defendants in this action, which the court granted on March 14, 2024. In connection with the ongoing OOCIC resolution discussions, FE is also discussing an appropriate settlement of this civil action with the OAG. As such, FE believes it is reasonably possible that it will incur a loss in connection with this civil action. Given the ongoing nature of these discussions, FE cannot yet reasonably estimate a loss or range of loss from any possible settlement of this civil action, however, any such settlement payment by FE is not expected to be material.
On February 9, 2022, FE, acting through the SLC, agreed to a settlement term sheet to resolve the following shareholder derivative lawsuits relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder that were filed in the S.D. Ohio, the N.D. Ohio, and the Ohio Court of Common Pleas, Summit County:
•Gendrich v. Anderson, et al. and Sloan v. Anderson, et al. (Common Pleas Court, Summit County, Ohio, all actions have been consolidated); on July 26, 2020 and July 31, 2020, respectively, purported stockholders of FE filed shareholder derivative action lawsuits against certain current and former FE directors and officers, alleging, among other things, breaches of fiduciary duty.
•Miller v. Anderson, et al. (N.D. Ohio); Bloom, et al. v. Anderson, et al.; Employees Retirement System of the City of St. Louis v. Jones, et al.; Electrical Workers Pension Fund, Local 103, I.B.E.W. v. Anderson et al.; Massachusetts Laborers Pension Fund v. Anderson et al.; The City of Philadelphia Board of Pensions and Retirement v. Anderson et al.; Atherton v. Dowling et al.; Behar v. Anderson, et al. (S.D. Ohio, all actions have been consolidated); beginning on August 7, 2020, purported stockholders of FE filed shareholder derivative actions alleging the FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act.
On March 11, 2022, the parties executed a stipulation and agreement of settlement, and filed a motion the same day requesting preliminary settlement approval in the S.D. Ohio, which the S.D. Ohio granted on May 9, 2022. Subsequently, following a hearing on August 4, 2022, the S.D. Ohio granted final approval of the settlement on August 23, 2022.
The settlement includes a series of corporate governance enhancements and a payment to FE of $180 million, to be paid by insurance after the judgment has become final, less approximately $36 million in court-ordered attorney’s fees awarded to plaintiffs. On September 20, 2022, a purported FE stockholder filed a motion for reconsideration of the S.D. Ohio’s final settlement approval. The parties filed oppositions to that motion on October 11, 2022, and the S.D. Ohio denied that motion on May 22, 2023. On June 15, 2023, the purported FE stockholder filed an appeal in the U.S. Court of Appeals for the Sixth Circuit. On February 16, 2024, the U.S. Court of Appeals for the Sixth Circuit affirmed the district court’s final settlement approval. Once all appeal options are exhausted the judgment will become final. The settlement agreement is expected to resolve fully these shareholder derivative lawsuits.
On June 2, 2022, the N.D. Ohio entered an order to show cause why the court should not appoint new plaintiffs’ counsel, and thereafter, on June 10, 2022, the parties filed a joint motion to dismiss the matter without prejudice, which the N.D. Ohio denied on July 5, 2022. On August 15, 2022, the N.D. Ohio issued an order stating its intention to appoint one group of applicants as new plaintiffs’ counsel, and on August 22, 2022, the N.D. Ohio ordered that any objections to the appointment be submitted by August 26, 2022. The parties filed their objections by that deadline, and on September 2, 2022, the applicants responded to those objections. In the meantime, on August 25, 2022, a purported FE stockholder represented by the applicants filed a motion to intervene, attaching a proposed complaint-in-intervention purporting to assert claims that the FE Board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Exchange Act as well as a claim against a third party for professional negligence and malpractice. The parties filed oppositions to that motion to intervene on September 8, 2022, and the proposed intervenor's reply in support of his motion to intervene was filed on September 22, 2022. On August 24, 2022, the parties filed a joint motion to dismiss the action pending in the N.D. Ohio based upon and in light of the approval of the settlement by the S.D. Ohio. On August 30, 2022, the parties filed a joint motion to dismiss the state court action, which the court granted on September 2, 2022. On September 29, 2023, the N.D. Ohio issued a stay of the case pending the appeal in the U.S. Court of Appeals for the Sixth Circuit. On April 12, 2024, the N.D. Ohio acknowledged the completion of the appeal and instructed the parties to file any further argument or information they wish to be considered by the N.D. Ohio no later than April 25, 2024.
In letters dated January 26, and February 22, 2021, staff of FERC's Division of Investigations notified FirstEnergy that the Division was conducting an investigation of FirstEnergy’s lobbying and governmental affairs activities concerning HB 6, and staff directed FirstEnergy to preserve and maintain all documents and information related to the same as such have been developed as part of an ongoing non-public audit being conducted by FERC's Division of Audits and Accounting. On December 30, 2022, FERC approved a Stipulation and Consent Agreement that resolves the investigation. The agreement includes a FirstEnergy admission of violating FERC’s “duty of candor” rule and related laws, and obligates FirstEnergy to pay a civil penalty of $3.86 million, and to submit two annual compliance monitoring reports to FERC’s Office of Enforcement regarding improvements to FirstEnergy’s compliance programs. FE paid the civil penalty on January 4, 2023 and it will not be recovered from customers. The first annual compliance monitoring report was submitted in December 2023.
The outcome of any of these lawsuits, governmental investigations and audit is uncertain and could have a material adverse effect on FE’s or its subsidiaries’ reputation, business, financial condition, results of operations, liquidity, and cash flows.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to FE or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 8, “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.
NEW ACCOUNTING PRONOUNCEMENTS
See “First EnergyNote 1, "Organization and Basis of Presentation," for a discussion of new accounting pronouncements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See “FirstEnergy Corp. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Information” and "FirstEnergy Solutions Corp. Management's Narrative Analysis of Results of Operations - Market Risk Information" in Item 2 above.
| |
ITEM 4. | CONTROLS AND PROCEDURES |
ITEM 4. CONTROLS AND PROCEDURES
(a) Evaluation of Disclosure Controls and Procedures
The management of FirstEnergy, and FES, with the participation of each registrant's principal executive officerthe Chief Executive Officer and principal financial officer,Chief Financial Officer, have reviewed and evaluated the effectiveness of their registrant'sits disclosure controls and procedures as(as defined in the Securities Exchange Act of 1934, as amended, Rules 13a-15(e) and 15d-15(e), under the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, the principal executive officerChief Executive Officer and principal financial officerChief Financial Officer of FirstEnergy and FES have concluded that their respective registrant'sits disclosure controls and procedures were effective as of the end of the period covered by this report.
(b) Changes in Internal Control over Financial Reporting
During the quarter ended September 30, 2017,March 31, 2024, there were no changes in internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, FirstEnergy's and FES'FirstEnergy’s internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Information required for Part II, Item 1 is incorporated by reference to the discussions in Note 10, "Regulatory8, “Regulatory Matters,"” and Note 11, "Commitments,9, “Commitments, Guarantees and Contingencies,"” of the Combined Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
ITEM 1A. RISK FACTORS
You should carefully consider the risk factors discussed in Part I, “Item"Item 1A. Risk Factors”Factors" in the Registrants’FirstEnergy’s Annual Report on Form 10-K for the year ended December 31, 2016, and Part II, "Item 1A. Risk Factors" in the Registrants' Quarterly Report on Form 10-Q for the quarter ended June 30, 2017,2023, which could materially affect the Registrants’FirstEnergy’s business, financial condition or future results. In addition, you should carefully consider theThe information set forth in this report, including without limitation, the updated disclosures throughout and the risk factor presented below, which update,updates and should be read in conjunction with, the above-referenced risk factors and information disclosed in FirstEnergy’s Annual Report on Form 10-K for the Registrants’ documents previously filedyear ended December 31, 2023.
The Physical Risks Associated with Climate Change May Have an Adverse Impact on Our Business Operations, Financial Condition and Cash Flows.
Physical risks of climate change such as flooding, wildfires, rising sea levels, and other related phenomena, resulting from more frequent or more extreme weather events and changes in temperature and precipitation patterns associated with climate change, could affect some, or all, of our operations.Frequent or extreme weather events could disrupt our operations and/or be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within the SEC.Utilities’ and Transmission Companies’ service areas could also directly affect their capital assets, such as downed wires, poles, or damage to other operating equipment, resulting in service disruptions to customers and possibly creating hazardous conditions. Further, as extreme weather conditions increase system stress, we may incur costs relating to additional system backup or service interruptions, and in some instances, we may be unable to recover such costs. For all of these reasons, these physical risks could have an adverse financial impact on our business operations, financial condition and cash flows.
InClimate change poses other financial risks as well. To the event of a foreclosure, liquidation, bankruptcyextent weather conditions are affected by climate change, customers’ energy use could increase or similar proceeding involving FES, FG or NG,decrease depending on the valueduration and magnitude of the collateral securing the secured indebtedness of FG and NG may not be sufficient to ensure repayment of such indebtedness and, in the case of a bankruptcy proceeding, the ability of holders of such indebtedness, including FE, to realize any such value may be delayed or otherwise limited
FG and NG have secured pollution control notes outstanding of $612.2 million (FG - $327.6 million of FMBs; NG - $284.6 million of FMBs) and secured obligations supporting FES’ $500 million revolving line of credit and $200 million additional credit support with FE (FG - $250 million of FMBs; NG - $450 million of FMBs). In the event of a foreclosure, liquidation, bankruptcy or similar proceeding affecting FES, FG or NG or any of their respective properties or assets, the value of the collateral securing such indebtedness or the net proceeds from any sale or liquidation of such collateral, as applicable, may not be sufficient to pay the obligations under such secured indebtedness. If the value of the collateral or the net proceeds of any sale of such collateral, as applicable, are not sufficient to repay all amounts due with respect to such secured indebtedness, the holders of the secured indebtedness would have an unsecured claim for the deficiency in value or proceeds against the applicable obligors alongside all other unsecured creditors of such obligor. None of FG, NG or FES can assure holders of their respective secured debt that, if a sale process were to be pursued, the collateral will be saleable or, if saleable, that there will not be substantial delays in its liquidationchanges. Increased energy use due to among other things, the need for regulatory authorization from the FERC, NRCweather changes may require us to invest in additional system assets and purchase additional power. Additionally, decreased energy use due to weather changes may affect our financial condition through decreased revenues, margins or other governmental authorities, as applicable.earnings.
Additionally, in the context of a bankruptcy case by or against FES, FG or NG, the holders of the secured indebtedness may not be able or entitled to receive payment of interest, fees, (including attorney’s fees) costs or charges related to such secured obligations, and may be required to repay any such amounts received by such holders during such bankruptcy case.
The value of the collateral securing FG’s and NG’s secured obligations is subject to fluctuation and will depend on market and other economic conditions, including the availability of any suitable buyers for the collateral, which could be impacted by the risks and costs associated with operating nuclear generation facilities in the case of NG’s properties and the risks and costs of operating coal and other fossil-fueled generation facilities in the case of FG’s properties, including, in each case, complying with federal, state and local statutes and regulations associated with public health and safety and the environment.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
(c) FirstEnergyNone.
The table below sets forth information on a monthly basis regarding FirstEnergy's purchases of its common stock during the third quarter of 2017:
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| | | | | | | | | | | | | |
| Period | | Total Number of Shares Purchased(1) | | Average Price Paid per Share | | Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs(2) | | Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs(2) |
| | | | | | | | | |
| July 1-31, 2017 | | — |
| | — |
| | — |
| | — |
|
| August 1-31, 2017 | | 2,318 |
| | $ | 32.62 |
| | — |
| | — |
|
| September 1-30, 2017 | | — |
| | — |
| | — |
| | — |
|
| | | | | | | | | |
| Third Quarter | | 2,318 |
| | $ | 32.62 |
| | — |
| | — |
|
| |
(1)
| Share amounts reflect shares that were surrendered to FirstEnergy by a participant under our 2007 Incentive Plan to satisfy tax withholding obligations relating to the vesting of a restricted stock award and the subsequent dividend reinvestments on such equity award. The total number of shares repurchased represents the net shares surrendered to FirstEnergy to satisfy tax withholding. All such repurchased shares are now held as treasury shares. |
| |
(2)
| FirstEnergy does not currently have any publicly announced plan or program for share purchases. |
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. OTHER INFORMATION
None.Trading Arrangements
During the quarter ended March 31, 2024, no director or officer (as defined in Rule 16a-1(f) promulgated under the Exchange Act) of FE adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement” (as each term is defined in Item 408 of Regulation S-K).
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ITEM 6. EXHIBITS
| | | | | | | | | | | |
| Exhibit Number | Description |
| | | | |
| 10.1 | | | |
FirstEnergy | | |
(A) | 12 | | |
| (A) (B) | 31.110.2 | | |
| (A) (B) | 10.3 | | |
| (A) | 31.1 | | |
| (A) | 31.2 | | |
| (A) | 32 | | |
| 101 | | 101 | The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended September 30, 2017,March 31, 2024, formatted in XBRL (ExtensibleiXBRL (Inline Extensible Business Reporting Language): (i) Consolidated Statements of Income, (Loss) and(ii) Consolidated Statements of Comprehensive Income, (Loss), (ii)(iii) Consolidated Balance Sheets, (iii)(iv) Consolidated Statements of Cash Flows, (iv)(v) related notes to these financial statements and (v)(vi) document and entity information.information |
| FES104 | | Cover Page Interactive Data File (the cover page XBRL tags are embedded within the Inline XBRL document contained in Exhibit 101) |
| (A) | 31.1 | |
(A) | 31.2 | | |
(A) | 32 | | |
| 101 | | The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Solutions Corp. for the period ended September 30, 2017, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Statements of Income (Loss) and Comprehensive Income (Loss), (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements and (v) document and entity information. |
(A) Provided herein in electronic format as an exhibit.
(B) Management contract or compensatory plan contract or arrangement filed pursuant to Item 601 of Regulation S-K.
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, except as set forth above, neither FirstEnergy nor FES havehas not filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but each hereby agrees to furnish to the SEC on request any such documents.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, eachthe Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
October 26, 2017
| | | | | |
| FIRSTENERGY CORP. |
| Registrant |
| | FIRSTENERGY CORP.
| /s/ Jason J. Lisowski |
| RegistrantJason J. Lisowski |
| |
| /s/ K. Jon Taylor |
| K. Jon Taylor |
| Vice President, Controller and Chief Accounting Officer |
| |
| FIRSTENERGY SOLUTIONS CORP. |
| Registrant |
| |
| /s/ Jason J. Lisowski |
| Jason J. Lisowski |
| Controller and Treasurer |
| (Principal Financial Officer) |
