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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2020
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________________ to ___________________

Commission |  | Registrant; State of Incorporation; |  | I.R.S. Employer
File Number |  | Address; and Telephone Number |  | Identification No.
333-21011 |  | FIRSTENERGY CORP |  | 34-1843785
|  | (An | Ohio | Corporation) |  |
|  | 76 South Main Street |  |
|  | Akron | OH | 44308 |  |
|  | Telephone | (800) | 736-3402 |  |

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

Title of Each Class |  | Trading Symbol |  | Name of Each Exchange on Which Registered
Common Stock, $0.10 par value |  | FE |  | New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes | ☑ | No | ☐ |

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes | ☑ | No | ☐ |

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer | ☑
Accelerated Filer | ☐
Non-accelerated Filer | ☐
Smaller Reporting Company | ☐
Emerging Growth Company | ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standard provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes | ☐ | No | ☑ |

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

|  | OUTSTANDING
CLASS |  | AS OF MARCH 31, 2020
Common Stock, $0.10 par value |  | 541,753,695 |

FirstEnergy Website and Other Social Media Sites and Applications
FirstEnergy’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, amendments to those reports and all other documents filed with or furnished to the SEC pursuant to Section 13(a) of the Securities Exchange Act of 1934 are made available free of charge on or through the “Investors” page of FirstEnergy’s website at www.firstenergycorp.com. These documents are also available to the public from commercial document retrieval services and the website maintained by the SEC at www.sec.gov.
These SEC filings are posted on the website as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. Additionally, FirstEnergy routinely posts additional important information, including press releases, investor presentations, investor factbook, and notices of upcoming events under the “Investors” section of FirstEnergy’s website and recognizes FirstEnergy’s website as a channel of distribution to reach public investors and as a means of disclosing material non-public information for complying with disclosure obligations under Regulation FD. Investors may be notified of postings to the website by signing up for email alerts and Rich Site Summary feeds on the “Investors” page of FirstEnergy’s website. FirstEnergy also uses Twitter® and Facebook® as additional channels of distribution to reach public investors and as a supplemental means of disclosing material non-public information for complying with its disclosure obligations under Regulation FD. Information contained on FirstEnergy’s website, Twitter® handle or Facebook® page, and any corresponding applications of those sites, shall not be deemed incorporated into, or to be part of, this report.

Forward-Looking Statements: This Form 10-Q includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 based on information currently available to management. Such statements are subject to certain risks and uncertainties and readers are cautioned not to place undue reliance on these forward-looking statements. These statements include declarations regarding management’s intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “forecast,” “target,” “will,” “intend,” “believe,” “project,” “estimate,” “plan” and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements, which may include the following (see Glossary of Terms for definitions of capitalized terms):

• | The extent and duration of the novel coronavirus (known as COVID-19) and the impacts to our business, operations and financial condition resulting from the outbreak of COVID-19 including, but not limited to, disruption of businesses in our territories, volatile capital and credit markets, legislative and regulatory actions, the effectiveness of our pandemic and business continuity plans, the precautionary measures we are taking on behalf of our customers and employees, our customers’ ability to make their utility payment and the potential for supply-chain disruptions.

• | Mitigating exposure for remedial activities associated with retired and formerly owned electric generation assets, including, but not limited to, risks associated with the decommissioning of TMI-2.

• | The ability to accomplish or realize anticipated benefits from strategic and financial goals, including, but not limited to, executing our transmission and distribution investment plans, controlling costs, improving our credit metrics, strengthening our balance sheet and growing earnings.

• | Legislative and regulatory developments, including, but not limited to, matters related to rates, compliance and enforcement activity.

• | Economic and weather conditions affecting future operating results, such as significant weather events and other natural disasters, and associated regulatory events or actions.

• | Changes in assumptions regarding economic conditions within our territories, the reliability of our transmission and distribution system, or the availability of capital or other resources supporting identified transmission and distribution investment opportunities.

• | Changes in customers’ demand for power, including, but not limited to, the impact of climate change or energy efficiency and peak demand reduction mandates.

• | Changes in national and regional economic conditions affecting us and/or our major industrial and commercial customers or others with which we do business.

• | The risks associated with cyber-attacks and other disruptions to our information technology system, which may compromise our operations, and data security breaches of sensitive data, intellectual property and proprietary or personally identifiable information.

• | The ability to comply with applicable reliability standards and energy efficiency and peak demand reduction mandates.

• | Changes to environmental laws and regulations, including, but not limited to, those related to climate change.

• | Changing market conditions affecting the measurement of certain liabilities and the value of assets held in our pension trusts and other trust funds, or causing us to make contributions sooner, or in amounts that are larger, than currently anticipated.

• | The risks and uncertainties associated with litigation, arbitration, mediation and like proceedings.

• | Labor disruptions by our unionized workforce.

• | Changes to significant accounting policies.

• | Any changes in tax laws or regulations, or adverse tax audit results or rulings.

• | The ability to access the public securities and other capital and credit markets in accordance with our financial plans, the cost of such capital and overall condition of the capital and credit markets affecting us, including the increasing number of financial institutions evaluating the impact of climate change on their investment decisions.

• | Actions that may be taken by credit rating agencies that could negatively affect either our access to or terms of financing or our financial condition and liquidity.

• | The risks and other factors discussed from time to time in our SEC filings.

Dividends declared from time to time on our common stock during any period may in the aggregate vary from prior periods due to circumstances considered by our Board of Directors at the time of the actual declarations. A security rating is not a recommendation to buy or hold securities and is subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.
These forward-looking statements are also qualified by, and should be read together with, the risk factors included in FirstEnergy’s filings with the SEC, including but not limited to the most recent Annual Report on Form 10-K and any subsequent Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. The foregoing review of factors also should not be construed as exhaustive. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor assess the impact of any such factor on FirstEnergy’s business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. FirstEnergy expressly disclaims any obligation to update or revise, except as required by law, any forward-looking statements contained herein or in the information incorporated by reference as a result of new information, future events or otherwise.

TABLE OF CONTENTS
| Page
Part I. Financial Information |
Glossary of Terms | ii
Item 1. Financial Statements |
FirstEnergy Corp. |
Consolidated Statements of Income | 1
Consolidated Statements of Comprehensive Income | 2
Consolidated Balance Sheets | 3
Consolidated Statements of Stockholders’ Equity | 4
Consolidated Statements of Cash Flows | 5
Notes To Consolidated Financial Statements | 6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations | 31
Item 3. Quantitative and Qualitative Disclosures About Market Risk | 62
Item 4. Controls and Procedures | 62
Part II. Other Information |
Item 1. Legal Proceedings | 62
Item 1A. Risk Factors | 62
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds | 62
Item 3. Defaults Upon Senior Securities | 63
Item 4. Mine Safety Disclosures | 63
Item 5. Other Information | 63
Item 6. Exhibits | 63

i

GLOSSARY OF TERMS
The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries:

AE Supply | Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary
AGC | Allegheny Generating Company, a generation subsidiary of MP
ATSI | American Transmission Systems, Incorporated, a subsidiary of FET, which owns and operates transmission facilities
BSPC | Bay Shore Power Company
CEI | The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
FE | FirstEnergy Corp., a public utility holding company
FENOC | Energy Harbor Nuclear Corp. (formerly known as FirstEnergy Nuclear Operating Company), a subsidiary of EH, which operates NG’s nuclear generating facilities
FES | Energy Harbor LLC. (formerly known as FirstEnergy Solutions Corp.), a subsidiary of EH, which provides energy-related products and services
FES Debtors | FES, FENOC, FG, NG, FE Aircraft Leasing Corp., Norton Energy Storage LLC, and FGMUC
FESC | FirstEnergy Service Company, which provides legal, financial and other corporate support services
FET | FirstEnergy Transmission, LLC, the parent company of ATSI, MAIT and TrAIL, and has a joint venture in PATH
FEV | FirstEnergy Ventures Corp., which invests in certain unregulated enterprises and business ventures
FG | Energy Harbor Generation LLC (formerly known as FirstEnergy Generation, LLC), a subsidiary of EH, which owns and operates fossil generating facilities
FGMUC | FirstEnergy Generation Mansfield Unit 1 Corp., a subsidiary of FG
FirstEnergy | FirstEnergy Corp., together with its consolidated subsidiaries
Global Holding | Global Mining Holding Company, LLC, a joint venture between FEV, WMB Marketing Ventures, LLC and Pinesdale LLC
Global Rail | Global Rail Group, LLC, a subsidiary of Global Holding that owns coal transportation operations near Roundup, Montana
GPUN | GPU Nuclear, Inc., a subsidiary of FE, which operates TMI-2
JCP&L | Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
MAIT | Mid-Atlantic Interstate Transmission, LLC, a subsidiary of FET, which owns and operates transmission facilities
ME | Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
MP | Monongahela Power Company, a West Virginia electric utility operating subsidiary
NG | Energy Harbor Nuclear Generation LLC (formerly known as FirstEnergy Nuclear Generation, LLC), a subsidiary of EH, which owns nuclear generating facilities
OE | Ohio Edison Company, an Ohio electric utility operating subsidiary
Ohio Companies | CEI, OE and TE
PATH | Potomac-Appalachian Transmission Highline, LLC, a joint venture between FE and a subsidiary of AEP
PATH-Allegheny | PATH Allegheny Transmission Company, LLC
PATH-WV | PATH West Virginia Transmission Company, LLC
PE | The Potomac Edison Company, a Maryland and West Virginia electric utility operating subsidiary
Penn | Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
Pennsylvania Companies | ME, PN, Penn and WP
PN | Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Signal Peak | Signal Peak Energy, LLC, an indirect subsidiary of Global Holding that owns mining operations near Roundup, Montana
TE | The Toledo Edison Company, an Ohio electric utility operating subsidiary
TrAIL | Trans-Allegheny Interstate Line Company, a subsidiary of FET, which owns and operates transmission facilities
Transmission Companies | ATSI, MAIT and TrAIL
Utilities | OE, CEI, TE, Penn, JCP&L, ME, PN, MP, PE and WP
WP | West Penn Power Company, a Pennsylvania electric utility operating subsidiary

ii

The following abbreviations and acronyms are used to identify frequently used terms in this report:
ACE | Affordable Clean Energy |  | Facebook® | Facebook is a registered trademark of Facebook, Inc.
ADIT | Accumulated Deferred Income Taxes |  | FASB | Financial Accounting Standards Board
AEP | American Electric Power Company, Inc. |  | FERC | Federal Energy Regulatory Commission
AFS | Available-for-sale |  | FES Bankruptcy | FES Debtors’ voluntary petitions for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code with the Bankruptcy Court
AFUDC | Allowance for Funds Used During Construction |  | Fitch | Fitch Ratings
ALJ | Administrative Law Judge |  | FPA | Federal Power Act
AMT | Alternative Minimum Tax |  | FTR | Financial Transmission Right
AOCI | Accumulated Other Comprehensive Income |  | GAAP | Accounting Principles Generally Accepted in the United States of America
ARO | Asset Retirement Obligation |  | GHG | Greenhouse Gases
ARP | Alternative Revenue Program |  | IIP | Infrastructure Investment Program
ASC | Accounting Standard Codification |  | kW | Kilowatt
ASU | Accounting Standards Update |  | LIBOR | London Inter-Bank Offered Rate
Bankruptcy Court | U.S. Bankruptcy Court in the Northern District of Ohio in Akron |  | LOC | Letter of Credit
Bath County | Bath County Pumped Storage Hydro-Power Station |  | LTIIPs | Long-Term Infrastructure Improvement Plans
BGS | Basic Generation Service |  | MDPSC | Maryland Public Service Commission
CAA | Clean Air Act |  | MGP | Manufactured Gas Plants
CARES Act | Coronavirus Aid, Relief and Economic Security Act of 2020 |  | MISO | Midcontinent Independent System Operator, Inc.
CCR | Coal Combustion Residuals |  | mmBTU | One Million British Thermal Units
CERCLA | Comprehensive Environmental Response, Compensation, and Liability Act of 1980 |  | Moody’s | Moody’s Investors Service, Inc.
CFR | Code of Federal Regulations |  | MW | Megawatt
CO 2 | Carbon Dioxide |  | MWH | Megawatt-hour
COVID-19 | Novel coronavirus |  | NAAQS | National Ambient Air Quality Standards
CPP | EPA’s Clean Power Plan |  | NDT | Nuclear Decommissioning Trust
CSAPR | Cross-State Air Pollution Rule |  | NERC | North American Electric Reliability Corporation
CTA | Consolidated Tax Adjustment |  | NJBPU | New Jersey Board of Public Utilities
CWA | Clean Water Act |  | NMB | Non-Market Based
D.C. Circuit | United States Court of Appeals for the District of Columbia Circuit |  | NOI | Notice of Inquiry
DCR | Delivery Capital Recovery |  | NOL | Net Operating Loss
DMR | Distribution Modernization Rider |  | NOx | Nitrogen Oxide
DPM | Distribution Platform Modernization |  | NRC | Nuclear Regulatory Commission
DSIC | Distribution System Improvement Charge |  | NUG | Non-Utility Generation
DSP | Default Service Plan |  | NYPSC | New York State Public Service Commission
EDC | Electric Distribution Company |  | OCA | Office of Consumer Advocate
EDCP | Executive Deferred Compensation Plan |  | OCC | Ohio Consumers’ Counsel
EDIS | Electric Distribution Investment Surcharge |  | OPEB | Other Post-Employment Benefits
EE&C | Energy Efficiency and Conservation |  | OPIC | Other Paid-in Capital
EGS | Electric Generation Supplier |  | OVEC | Ohio Valley Electric Corporation
EGU | Electric Generation Units |  | PA DEP | Pennsylvania Department of Environmental Protection
EH | Energy Harbor Corp. |  | PJM | PJM Interconnection, LLC
EmPOWER Maryland | EmPOWER Maryland Energy Efficiency Act |  | PJM Tariff | PJM Open Access Transmission Tariff
ENEC | Expanded Net Energy Cost |  | POLR | Provider of Last Resort
EPA | United States Environmental Protection Agency |  | POR | Purchase of Receivables
EPS | Earnings per Share |  | PPA | Purchase Power Agreement
ERO | Electric Reliability Organization |  | PPB | Parts per Billion
ESP IV | Electric Security Plan IV |  | PPUC | Pennsylvania Public Utility Commission

iii

PUCO | Public Utilities Commission of Ohio |  | SIP | State Implementation Plan(s) Under the Clean Air Act
PURPA | Public Utility Regulatory Policies Act of 1978 |  | SO 2 | Sulfur Dioxide
RCRA | Resource Conservation and Recovery Act |  | SOS | Standard Offer Service
Regulation FD | Regulation Fair Disclosure promulgated by the SEC |  | SREC | Solar Renewable Energy Credit
RFC | Reliability First Corporation |  | SSO | Standard Service Offer
RFP | Request for Proposal |  | Tax Act | Tax Cuts and Jobs Act adopted December 22, 2017
RGGI | Regional Greenhouse Gas Initiative |  | TMI-2 | Three Mile Island Unit 2
ROE | Return on Equity |  | Twitter® | Twitter is a registered trademark of Twitter, Inc.
RTEP | Regional Transmission Expansion Plan |  | UCC | Official committee of unsecured creditors appointed in connection with the FES Bankruptcy
RTO | Regional Transmission Organization |  | VIE | Variable Interest Entity
S&P | Standard & Poor’s Ratings Service |  | VMS | Vegetation Management Surcharge
SBC | Societal Benefits Charge |  | VSCC | Virginia State Corporation Commission
SCOH | Supreme Court of Ohio |  | WVPSC | Public Service Commission of West Virginia
SEC | United States Securities and Exchange Commission |  | ZEC | Zero Emissions Certificate

iv

PART I. FINANCIAL INFORMATION
ITEM I. Financial Statements
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

|  | For the Three Months Ended March 31,
(In millions, except per share amounts) |  | 2020 |  | 2019
REVENUES: |  |  |  |
Distribution services and retail generation |  | $ | 2,124 |  |  | $ | 2,309 |
Transmission |  | 397 |  |  | 352 |
Other |  | 188 |  |  | 222 |
Total revenues(1) |  | 2,709 |  |  | 2,883 |
OPERATING EXPENSES: |  |  |  |
Fuel |  | 98 |  |  | 131 |
Purchased power |  | 694 |  |  | 781 |
Other operating expenses |  | 749 |  |  | 779 |
Provision for depreciation |  | 317 |  |  | 297 |
Amortization of regulatory assets, net |  | 52 |  |  | 5 |
General taxes |  | 267 |  |  | 261 |
Total operating expenses |  | 2,177 |  |  | 2,254 |
OPERATING INCOME |  | 532 |  |  | 629 |
OTHER INCOME (EXPENSE): |  |  |  |
Miscellaneous income, net |  | 100 |  |  | 54 |
Pension and OPEB mark-to-market adjustment (Note 5) |  | (423 | ) |  | — |
Interest expense |  | (263 | ) |  | (253 | )
Capitalized financing costs |  | 18 |  |  | 18 |
Total other expense |  | (568 | ) |  | (181 | )
INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) |  | (36 | ) |  | 448 |
INCOME TAXES (BENEFITS) |  | (60 | ) |  | 93 |
INCOME FROM CONTINUING OPERATIONS |  | 24 |  |  | 355 |
Discontinued operations (Note 3)(2) |  | 50 |  |  | (35 | )
NET INCOME |  | $ | 74 |  |  | $ | 320 |
INCOME ALLOCATED TO PREFERRED STOCKHOLDERS (Note 4) |  | — |  |  | 5 |
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS |  | $ | 74 |  |  | $ | 315 |
EARNINGS PER SHARE OF COMMON STOCK (Note 4): |  |  |  |
Basic - Continuing Operations |  | $ | 0.05 |  |  | $ | 0.66 |
Basic - Discontinued Operations |  | 0.09 |  |  | (0.07 | )
Basic - Net Income Attributable to Common Stockholders |  | $ | 0.14 |  |  | $ | 0.59 |
Diluted - Continuing Operations |  | $ | 0.05 |  |  | $ | 0.66 |
Diluted - Discontinued Operations |  | 0.09 |  |  | (0.07 | )
Diluted - Net Income Attributable to Common Stockholders |  | $ | 0.14 |  |  | $ | 0.59 |
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING: |  |  |  |
Basic |  | 541 |  |  | 530 |
Diluted |  | 543 |  |  | 533 |

(1) Includes excise and gross receipts tax collections of $92 million and $102 million during the three months ended March 31, 2020 and 2019, respectively.
(2) Net of income tax expense (benefits) of $(36) million and $5 million for the three months ended March 31, 2020 and 2019, respectively.
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
1

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

|  | For the Three Months Ended March 31,
(In millions) |  | 2020 |  | 2019
NET INCOME |  | $ | 74 |  |  | $ | 320 |
OTHER COMPREHENSIVE INCOME (LOSS): |  |  |  |  |  |
Pension and OPEB prior service costs |  | (23 | ) |  | (7 | )
Amortized losses on derivative hedges |  | — |  |  | 1 |
Other comprehensive loss |  | (23 | ) |  | (6 | )
Income tax benefits on other comprehensive loss |  | (5 | ) |  | (1 | )
Other comprehensive loss, net of tax |  | (18 | ) |  | (5 | )
COMPREHENSIVE INCOME |  | $ | 56 |  |  | $ | 315 |

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
2

FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)

(In millions, except share amounts) |  | March 31, 2020 |  | December 31, 2019
ASSETS |  |  |  |  |  |
CURRENT ASSETS: |  |  |  |  |  |
Cash and cash equivalents |  | $ | 152 |  |  | $ | 627 |
Restricted cash |  | 33 |  |  | 52 |
Receivables- |  |  |  |  |
Customers |  | 1,053 |  |  | 1,137 |
Less — Allowance for uncollectible customer receivables |  | 44 |  |  | 46 |
|  | 1,009 |  |  | 1,091 |
Affiliated companies, net of allowance for uncollectible accounts of $1,063 in 2019 |  | — |  |  | — |
Other, net of allowance for uncollectible accounts of $26 in 2020 and $21 in 2019 |  | 245 |  |  | 203 |
Materials and supplies, at average cost |  | 285 |  |  | 281 |
Prepaid taxes and other |  | 279 |  |  | 157 |
Current assets - discontinued operations |  | — |  |  | 33 |
|  | 2,003 |  |  | 2,444 |
PROPERTY, PLANT AND EQUIPMENT: |  |  |  |  |  |
In service |  | 42,184 |  |  | 41,767 |
Less — Accumulated provision for depreciation |  | 11,635 |  |  | 11,427 |
|  | 30,549 |  |  | 30,340 |
Construction work in progress |  | 1,456 |  |  | 1,310 |
|  | 32,005 |  |  | 31,650 |
INVESTMENTS: |  |  |  |  |  |
Nuclear fuel disposal trust |  | 275 |  |  | 270 |
Other |  | 288 |  |  | 299 |
Investments - held for sale (Note 10) |  | 875 |  |  | 882 |
|  | 1,438 |  |  | 1,451 |
DEFERRED CHARGES AND OTHER ASSETS: |  |  |  |  |  |
Goodwill |  | 5,618 |  |  | 5,618 |
Regulatory assets |  | 91 |  |  | 99 |
Other |  | 935 |  |  | 1,039 |
|  | 6,644 |  |  | 6,756 |
|  | $ | 42,090 |  |  | $ | 42,301 |
LIABILITIES AND CAPITALIZATION |  |  |  |  |  |
CURRENT LIABILITIES: |  |  |  |  |  |
Currently payable long-term debt |  | $ | 381 |  |  | $ | 380 |
Short-term borrowings |  | 750 |  |  | 1,000 |
Accounts payable |  | 898 |  |  | 918 |
Accounts payable - affiliated companies |  | — |  |  | 87 |
Accrued interest |  | 278 |  |  | 249 |
Accrued taxes |  | 566 |  |  | 545 |
Accrued compensation and benefits |  | 252 |  |  | 258 |
Other |  | 572 |  |  | 1,425 |
|  | 3,697 |  |  | 4,862 |
CAPITALIZATION: |  |  |  |  |  |
Stockholders’ equity- |  |  |  |  |  |
Common stock, $0.10 par value, authorized 700,000,000 shares - 541,753,695 and 540,652,222 shares outstanding as of March 31, 2020 and December 31, 2019, respectively |  | 54 |  |  | 54 |
Other paid-in capital |  | 10,651 |  |  | 10,868 |
Accumulated other comprehensive income |  | 2 |  |  | 20 |
Accumulated deficit |  | (3,893 | ) |  | (3,967 | )
Total stockholders’ equity |  | 6,814 |  |  | 6,975 |
Long-term debt and other long-term obligations |  | 20,821 |  |  | 19,618 |
|  | 27,635 |  |  | 26,593 |
NONCURRENT LIABILITIES: |  |  |  |  |  |
Accumulated deferred income taxes |  | 2,774 |  |  | 2,849 |
Retirement benefits |  | 3,455 |  |  | 3,065 |
Regulatory liabilities |  | 2,266 |  |  | 2,360 |
Asset retirement obligations |  | 168 |  |  | 165 |
Adverse power contract liability |  | 38 |  |  | 49 |
Other |  | 1,357 |  |  | 1,667 |
Noncurrent liabilities - held for sale (Note 10) |  | 700 |  |  | 691 |
|  | 10,758 |  |  | 10,846 |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10) |  |  |  |  |  |
|  | $ | 42,090 |  |  | $ | 42,301 |

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
3

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Unaudited)

|  | Three Months Ended March 31, 2020
|  | Series A Convertible Preferred Stock |  | Common Stock |  | OPIC |  | AOCI |  | Accumulated Deficit |  | Total Stockholders’ Equity
(In millions) |  | Shares |  | Amount |  | Shares |  | Amount |  |  |
Balance, January 1, 2020 |  | — |  |  | $ | — |  |  | 541 |  |  | $ | 54 |  |  | $ | 10,868 |  |  | $ | 20 |  |  | $ | (3,967 | ) |  | $ | 6,975 |
Net income |  |  |  |  |  |  |  |  |  |  |  |  |  | 74 |  |  | 74 |
Other comprehensive loss, net of tax |  |  |  |  |  |  |  |  |  |  |  | (18 | ) |  |  |  | (18 | )
Stock-based compensation |  |  |  |  |  |  |  |  |  | 9 |  |  |  |  |  |  | 9 |
Stock Investment Plan and certain share-based benefit plans |  |  |  |  |  | 1 |  |  |  |  | (15 | ) |  |  |  |  |  | (15 | )
Cash dividends declared on common stock ($0.39/common share in March) |  |  |  |  |  |  |  |  |  | (211 | ) |  |  |  |  |  | (211 | )
Balance, March 31, 2020 |  | — |  |  | $ | — |  |  | 542 |  |  | $ | 54 |  |  | $ | 10,651 |  |  | $ | 2 |  |  | $ | (3,893 | ) |  | $ | 6,814 |

|  | Three Months Ended March 31, 2019
|  | Series A Convertible Preferred Stock |  | Common Stock |  | OPIC |  | AOCI |  | Accumulated Deficit |  | Total Stockholders’ Equity
(In millions) |  | Shares |  | Amount |  | Shares |  | Amount |  |  |
Balance, January 1, 2019 |  | 0.7 |  |  | $ | 71 |  |  | 512 |  |  | $ | 51 |  |  | $ | 11,530 |  |  | $ | 41 |  |  | $ | (4,879 | ) |  | $ | 6,814 |
Net income |  |  |  |  |  |  |  |  |  |  |  |  |  | 320 |  |  | 320 |
Other comprehensive loss, net of tax |  |  |  |  |  |  |  |  |  |  |  | (5 | ) |  |  |  | (5 | )
Stock-based compensation |  |  |  |  |  |  |  |  |  | 7 |  |  |  |  |  |  | 7 |
Stock Investment Plan and certain share-based benefit plans |  |  |  |  |  | 1 |  |  |  |  |  | 1 |  |  |  |  |  |  | 1 |
Cash dividends declared on common stock ($0.38/common share in March) |  |  |  |  |  |  |  |  |  | (202 | ) |  |  |  |  |  | (202 | )
Cash dividends declared on preferred stock ($0.38/as-converted share in March) |  |  |  |  |  |  |  |  |  | (3 | ) |  |  |  |  |  | (3 | )
Conversion of Series A Convertible Preferred Stock (1) |  | (0.5 | ) |  | (50 | ) |  | 18 |  |  | 2 |  |  | 48 |  |  |  |  |  |  | — |
Balance, March 31, 2019 |  | 0.2 |  |  | $ | 21 |  |  | 531 |  |  | $ | 53 |  |  | $ | 11,381 |  |  | $ | 36 |  |  | $ | (4,559 | ) |  | $ | 6,932 |

(1) As of March 31, 2019, there were 209,822 outstanding shares of Series A Convertible Preferred Stock.
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
4

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

|  | For the Three Months Ended March 31,
(In millions) |  | 2020 |  | 2019
CASH FLOWS FROM OPERATING ACTIVITIES: |  |  |  |
Net income |  | $ | 74 |  |  | $ | 320 |
Adjustments to reconcile net income to net cash from operating activities- |  |  |  |
Loss (gain) on disposal, net of tax (Note 3) |  | (50 | ) |  | 24 |
Depreciation and amortization, including regulatory assets, net, and deferred debt-related costs |  | 295 |  |  | 345 |
Deferred income taxes and investment tax credits, net |  | (78 | ) |  | 91 |
Retirement benefits, net of payments |  | (66 | ) |  | (39 | )
Pension trust contributions |  | — |  |  | (500 | )
Pension and OPEB mark-to-market adjustment |  | 423 |  |  | — |
Settlement agreement and tax sharing payments to the FES Debtors |  | (978 | ) |  | — |
Changes in current assets and liabilities- |  |  |  |
Receivables |  | 51 |  |  | 92 |
Prepaid taxes and other |  | (125 | ) |  | (148 | )
Accounts payable |  | (66 | ) |  | (143 | )
Accrued taxes |  | (37 | ) |  | (81 | )
Accrued interest |  | 29 |  |  | 13 |
Accrued compensation and benefits |  | (61 | ) |  | (123 | )
Other current liabilities |  | 1 |  |  | (13 | )
Other |  | 28 |  |  | (20 | )
Net cash used for operating activities |  | (560 | ) |  | (182 | )
CASH FLOWS FROM FINANCING ACTIVITIES: |  |  |  |
New financing- |  |  |  |
Long-term debt |  | 2,000 |  |  | 1,400 |
Short-term borrowings, net |  | — |  |  | 50 |
Redemptions and repayments- |  |  |  |
Long-term debt |  | (778 | ) |  | (628 | )
Short-term borrowings, net |  | (250 | ) |  | — |
Preferred stock dividend payments |  | — |  |  | (3 | )
Common stock dividend payments |  | (211 | ) |  | (201 | )
Other |  | (36 | ) |  | (25 | )
Net cash provided from financing activities |  | 725 |  |  | 593 |
CASH FLOWS FROM INVESTING ACTIVITIES: |  |  |  |
Property additions |  | (616 | ) |  | (554 | )
Sales of investment securities held in trusts |  | 13 |  |  | 153 |
Purchases of investment securities held in trusts |  | (18 | ) |  | (162 | )
Asset removal costs |  | (43 | ) |  | (65 | )
Other |  | 5 |  |  | (2 | )
Net cash used for investing activities |  | (659 | ) |  | (630 | )
Net change in cash, cash equivalents, and restricted cash |  | (494 | ) |  | (219 | )
Cash, cash equivalents, and restricted cash at beginning of period |  | 679 |  |  | 429 |
Cash, cash equivalents, and restricted cash at end of period |  | $ | 185 |  |  | $ | 210 |

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
5

FIRSTENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note Number |  | Page Number
1 | Organization and Basis of Presentation | 7
2 | Revenue | 9
3 | Discontinued Operations | 11
4 | Earnings Per Share of Common Stock | 13
5 | Pension and Other Post-Employment Benefits | 15
6 | Accumulated Other Comprehensive Income | 16
7 | Income Taxes | 17
8 | Fair Value Measurements | 18
9 | Regulatory Matters | 21
10 | Commitments, Guarantees and Contingencies | 26
11 | Segment Information | 29

6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
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.
FE was incorporated under Ohio law in 1996. FE’s principal business is the holding, directly or indirectly, of all of the outstanding equity of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), JCP&L, ME, PN, FESC, AE Supply, MP, AGC (a wholly owned subsidiary of MP), PE, WP, and FET and its principal subsidiaries (ATSI, MAIT and TrAIL). In addition, FE holds all of the outstanding equity of other direct subsidiaries including: AESC, FirstEnergy Properties, Inc., FEV, FELHC, Inc., GPUN, Allegheny Ventures, Inc., and Suvon, LLC doing business as both FirstEnergy Home and FirstEnergy Advisors.
FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity. FirstEnergy’s ten utility operating companies comprise one of the nation’s largest investor-owned electric systems, based on serving over six million customers in the Midwest and Mid-Atlantic regions. FirstEnergy’s transmission operations include approximately 24,500 miles of lines and two regional transmission operation centers. AGC, JCP&L and MP control 3,790 MWs of total capacity.
These interim financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and disclosures normally included in financial statements and notes prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. These interim financial statements should be read in conjunction with the financial statements and notes included in the Annual Report on Form 10-K for the year ended December 31, 2019.
FE and its subsidiaries follow GAAP and comply with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the NRC, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU. The accompanying interim financial statements are unaudited, but reflect all adjustments, consisting of normal recurring adjustments, that, in the opinion of management, are necessary for a fair statement of the financial statements. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not necessarily indicative of results of operations for any future period. FE and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued.
FE and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation as appropriate and permitted pursuant to GAAP. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary. Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but do not have a controlling financial interest, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage of FE’s ownership share of the entity’s earnings is reported in the Consolidated Statements of Income and Comprehensive Income.
Certain prior year amounts have been reclassified to conform to the current year presentation.
Capitalized Financing Costs
For each of the three months ended March 31, 2020 and 2019, capitalized financing costs on FirstEnergy’s Consolidated Statements of Income include $11 million and $13 million, respectively, of allowance for equity funds used during construction and $7 million and $5 million, respectively, of capitalized interest.
COVID-19
The outbreak of COVID-19 has become a global pandemic. FirstEnergy is continuously evaluating the global pandemic and taking steps to mitigate known risks. The full impact on FirstEnergy’s business from the pandemic, including the governmental and regulatory responses, is unknown at this time and difficult to predict. FirstEnergy provides a critical and essential service to its customers and the health and safety of its employees and customers is its first priority. FirstEnergy is continuously monitoring its supply chain and is working closely with essential vendors to understand the impact of COVID-19 to its business and does not currently expect service disruptions or any material impact on its capital spending plan.
Currently, FirstEnergy is effectively managing operations during the pandemic in order to continue to provide critical service to customers and believes it is well positioned to manage the resulting economic slowdown. FirstEnergy Distribution and Transmission revenues benefit from geographic and economic diversity across a five-state service territory, which also allows for flexibility with capital investments and measures to maintain sufficient liquidity over the next twelve months. However, the situation remains fluid and future impacts to FirstEnergy that are presently unknown or unanticipated may occur. Furthermore, the likelihood of an impact to FirstEnergy, and the severity of any impact that does occur, could increase the longer the global pandemic persists.
7

Customer Receivables
Receivables from customers include retail electric sales and distribution deliveries to residential, commercial and industrial customers for the Utilities. The allowance for uncollectible customer receivables is based on historical loss information comprised of a rolling 36-month average net write-off percentage of revenues, in conjunction with a qualitative assessment of elements that impact the collectability of receivables, such as changes in economic factors, regulatory matters, industry trends, customer credit factors, payment options and programs available to customers, and the methods that the Utilities are able to utilize to ensure payment. During the first quarter of 2020, FirstEnergy reviewed its allowance for uncollectible customer receivables based on this qualitative assessment, including consideration of the recent outbreak of COVID-19, along with past trends during times of economic instability, and determined the process and amounts recognized are appropriate, with no significant incremental expense adjustment recognized specifically due to the pandemic. However, due to significant uncertainty surrounding the pandemic, the full impact to FirstEnergy, including governmental and/or regulatory responses, is unknown at this time and difficult to predict. Furthermore, the Ohio Companies and JCP&L have existing regulatory mechanisms in place where incremental uncollectible expenses are able to be recovered through riders with no material impact to earnings. Additionally, in response to the COVID-19 outbreak, the MDPSC issued an order allowing PE to track and create a regulatory asset for future recovery incremental costs, including uncollectible expenses and waived late payment charges, incurred as a result of the pandemic.
Receivables from customers also include PJM receivables resulting from transmission and wholesale sales. FirstEnergy’s credit risk on PJM receivables is reduced due to the nature of PJM’s settlement process whereby members of PJM legally agree to share the cost of defaults and as a result there is no allowance for doubtful accounts.
Activity in the allowance for uncollectible accounts on customer receivables for the three months ended March 31, 2020 and for the year ended December 31, 2019 are as follows:

|  | (In millions)
Balance, January 1, 2019 |  | 50 |
Charged to income |  | 81 |
Charged to other accounts (1) |  | 47 |
Write-offs |  | (132 | )
Balance, December 31, 2019 |  | $ | 46 |
Charged to income |  | 19 |
Charged to other accounts (1) |  | 14 |
Write-offs |  | (35 | )
Balance, March 31, 2020 |  | $ | 44 |

(1) Represents recoveries and reinstatements of accounts written off for uncollectible accounts.
Restricted Cash
Restricted cash primarily relates to cash collected from JCP&L, MP, PE and the Ohio Companies’ customers that is specifically used to service debt of their respective funding companies.
New Accounting Pronouncements
Recently Adopted Pronouncements
ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (Issued June 2016 and subsequently updated): ASU 2016-13 removes all recognition thresholds and will require companies to recognize an allowance for credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that the company expects to collect over the instrument’s contractual life. Prior to adoption, FirstEnergy analyzed its financial instruments within the scope of this guidance, primarily trade receivables and AFS debt securities. The adoption of this standard upon January 1, 2020 did not have a material impact to FirstEnergy’s financial statements and required additional disclosures in these Notes to the Consolidated Financial Statements.
ASU 2018-15, "Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract" (Issued August 2018): ASU 2018-15 allows implementation costs incurred by customers in cloud computing arrangements to be deferred and recognized over the term of the arrangement, if those costs would be capitalized by the customers in a software licensing arrangement. FirstEnergy adopted this standard as of January 1, 2020, with no material impact to its financial statements.
ASU 2020-04, "Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (Issued March 2020): ASU 2020-04 provides temporary optional expedients and exceptions to the current guidance on
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contract modifications to ease the financial reporting burdens related to the expected market transition from LIBOR and other interbank offered rates to alternative reference rates. FirstEnergy’s term loan maturing September 2020 with $750 million currently outstanding and $3.5 billion Revolving Credit Facility bear interest at fluctuating interest rates based on LIBOR. These agreements contain provisions (requiring an amendment) in the event that LIBOR can no longer be used. As of March 31, 2020, FirstEnergy has not utilized any of the expedients discussed within this ASU, however, it continues to assess other areas to determine if LIBOR is included and if the expedients would be utilized through the allowed period of December 2022.
Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB has not yet been adopted. Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable. FirstEnergy has assessed other FASB issuances of new standards not described below based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting.
ASU 2019-12, "Simplifying the Accounting for Income Taxes" (Issued in December 2019): ASU 2019-12 enhances and simplifies various aspects of the income tax accounting guidance including the elimination of certain exceptions related to the approach for intra-period tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. The new guidance also simplifies aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020, with early adoption permitted.
2. REVENUE
FirstEnergy accounts for revenues from contracts with customers under ASC 606, “Revenue from Contracts with Customers.” Revenue from leases, financial instruments, other contractual rights or obligations and other revenues that are not from contracts with customers are outside the scope of the new standard and accounted for under other existing GAAP.
FirstEnergy has elected to exclude sales taxes and other similar taxes collected on behalf of third parties from revenue as prescribed in the new standard. As a result, tax collections and remittances are excluded from recognition in the income statement and instead recorded through the balance sheet. Excise and gross receipts taxes that are assessed on FirstEnergy are not subject to the election and are included in revenue. FirstEnergy has elected the optional invoice practical expedient for most of its revenues and utilizes the optional short-term contract exemption for transmission revenues due to the annual establishment of revenue requirements, which eliminates the need to provide certain revenue disclosures regarding unsatisfied performance obligations.
FirstEnergy’s revenues are primarily derived from electric service provided by the Utilities and Transmission Companies.
The following tables represent a disaggregation of revenue from contracts with customers for the three months ended March 31, 2020 and 2019, by type of service from each reportable segment:

|  | For the Three Months Ended March 31, 2020
Revenues by Type of Service |  | Regulated Distribution |  | Regulated Transmission |  | Corporate/Other and Reconciling Adjustments (1) |  | Total
|  | (In millions)
Distribution services (2) |  | $ | 1,256 |  |  | $ | — |  |  | $ | (21 | ) |  | $ | 1,235 |
Retail generation |  | 904 |  |  | — |  |  | (15 | ) |  | 889 |
Wholesale sales |  | 71 |  |  | — |  |  | 1 |  |  | 72 |
Transmission (2) |  | — |  |  | 397 |  |  | — |  |  | 397 |
Other |  | 36 |  |  | — |  |  | — |  |  | 36 |
Total revenues from contracts with customers |  | $ | 2,267 |  |  | $ | 397 |  |  | $ | (35 | ) |  | $ | 2,629 |
ARP (3) |  | 68 |  |  | — |  |  | — |  |  | 68 |
Other non-customer revenue |  | 23 |  |  | 4 |  |  | (15 | ) |  | 12 |
Total revenues |  | $ | 2,358 |  |  | $ | 401 |  |  | $ | (50 | ) |  | $ | 2,709 |

(1) Includes eliminations and reconciling adjustments of inter-segment revenues.
(2) Includes $23 million reductions to revenue related to amounts subject to refund resulting from the Tax Act, primarily at Regulated Distribution.
(3) ARP revenue for the three months ended March 31, 2020, is related to the Ohio decoupling rates that became effective on February 1, 2020.
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|  | For the Three Months Ended March 31, 2019
Revenues by Type of Service |  | Regulated Distribution |  | Regulated Transmission |  | Corporate/Other and Reconciling Adjustments (1) |  | Total
|  | (In millions)
Distribution services (2) |  | $ | 1,286 |  |  | $ | — |  |  | $ | (21 | ) |  | $ | 1,265 |
Retail generation |  | 1,058 |  |  | — |  |  | (14 | ) |  | 1,044 |
Wholesale sales |  | 106 |  |  | — |  |  | 4 |  |  | 110 |
Transmission (2) |  | — |  |  | 352 |  |  | — |  |  | 352 |
Other |  | 34 |  |  | — |  |  | 1 |  |  | 35 |
Total revenues from contracts with customers |  | $ | 2,484 |  |  | $ | 352 |  |  | $ | (30 | ) |  | $ | 2,806 |
ARP (3) |  | 62 |  |  | — |  |  | — |  |  | 62 |
Other non-customer revenue |  | 27 |  |  | 4 |  |  | (16 | ) |  | 15 |
Total revenues |  | $ | 2,573 |  |  | $ | 356 |  |  | $ | (46 | ) |  | $ | 2,883 |

(1) Includes eliminations and reconciling adjustments of inter-segment revenues.
(2) Includes $32 million in net reductions to revenue related to amounts subject to refund resulting from the Tax Act ($27 million at Regulated Distribution and $5 million at Regulated Transmission).
(3) ARP revenue for the three months ended March 31, 2019, is related to the DMR and lost distribution and shared savings revenue in Ohio.
Other non-customer revenue includes revenue from late payment charges of $10 million and $11 million for the three months ended March 31, 2020 and 2019, respectively, that FirstEnergy expects are collectible. Starting in mid-March 2020, certain late payment charges began to be waived in response to the COVID-19 pandemic, and as a result, FirstEnergy stopped recognizing these revenues. See Note 1, “Organization and Basis of Presentation,” for further discussion on the COVID-19 pandemic. Other non-customer revenue also includes revenue from derivatives of $2 million for the three months ended March 31, 2019. There was no significant revenue from derivatives in the three months ended March 31, 2020.
Regulated Distribution
The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies and also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. Each of the Utilities earns revenue from state-regulated rate tariffs under which it provides distribution services to residential, commercial and industrial customers in its service territory. The Utilities are obligated under the regulated construct to deliver power to customers reliably, as it is needed, which creates an implied monthly contract with the end-use customer. See Note 9, “Regulatory Matters,” for additional information on rate recovery mechanisms. Distribution and electric revenues are recognized over time as electricity is distributed and delivered to the customer and the customers consume the electricity immediately as delivery occurs.
Retail generation sales relate to POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland, as well as generation sales in West Virginia that are regulated by the WVPSC. Certain of the Utilities have default service obligations to provide power to non-shopping customers who have elected to continue to receive service under regulated retail tariffs. The volume of these sales varies depending on the level of shopping that occurs. Supply plans vary by state and by service territory. Default service for the Ohio Companies, Pennsylvania Companies, JCP&L and PE’s Maryland jurisdiction are provided through a competitive procurement process approved by each state’s respective commission. Retail generation revenues are recognized over time as electricity is delivered and consumed immediately by the customer.
The following table represents a disaggregation of the Regulated Distribution segment revenue from contracts with distribution service and retail generation customers for the three months ended March 31, 2020 and 2019, by class:

|  | For the Three Months Ended March 31,
Revenues by Customer Class |  | 2020 |  | 2019
|  | (In millions)
Residential |  | $ | 1,319 |  |  | $ | 1,484 |
Commercial |  | 544 |  |  | 587 |
Industrial |  | 277 |  |  | 249 |
Other |  | 20 |  |  | 24 |
Total Revenues |  | $ | 2,160 |  |  | $ | 2,344 |

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Wholesale sales primarily consist of generation and capacity sales into the PJM market from FirstEnergy’s regulated electric generation capacity and NUGs. Certain of the Utilities may also purchase power in the PJM markets to supply power to their customers. Generally, these power sales from generation and purchases to serve load are netted hourly and reported as either revenues or purchased power on the Consolidated Statements of Income based on whether the entity was a net seller or buyer each hour. Capacity revenues are recognized ratably over the PJM planning year at prices cleared in the annual PJM Reliability Pricing Model Base Residual Auction and Incremental Auctions. Capacity purchases and sales through PJM capacity auctions are reported within revenues on the Consolidated Statements of Income. Certain capacity income (bonuses) and charges (penalties) related to the availability of units that have cleared in the auctions are unknown and not recorded in revenue until, and unless, they occur.
The Utilities’ distribution customers are metered on a cycle basis. An estimate of unbilled revenues is calculated to recognize electric service provided from the last meter reading through the end of the month. This estimate includes many factors, among which are historical customer usage, load profiles, estimated weather impacts, customer shopping activity and prices in effect for each class of customer. In each accounting period, the Utilities accrue the estimated unbilled amount as revenue and reverse the related prior period estimate. Customer payments vary by state but are generally due within 30 days.
ASC 606 excludes industry-specific accounting guidance for recognizing revenue from ARPs as these programs represent contracts between the utility and its regulators, as opposed to customers. Therefore, revenue from these programs are not within the scope of ASC 606 and regulated utilities are permitted to continue to recognize such revenues in accordance with existing practice but are presented separately from revenue arising from contracts with customers. FirstEnergy currently has ARPs in Ohio, primarily under Rider DMR in 2019 and decoupling revenue in 2020. Please see Note 9, “Regulatory Matters,” for further discussion on decoupling revenues in Ohio.
Regulated Transmission
The Regulated Transmission segment provides transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment's revenues are primarily derived from forward-looking formula rates at the Transmission Companies, as well as stated transmission rates at MP, PE and WP. JCP&L had stated rates in 2019, but moved to forward-looking formula rates, subject to a refund, effective January 1, 2020, as further discussed in Note 9, “Regulatory Matters.”
Both the forward-looking formula and stated rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. Revenue requirements under stated rates are calculated annually by multiplying the highest one-hour peak load in each respective transmission zone by the approved, stated rate in that zone. Revenues and cash receipts for the stand-ready obligation of providing transmission service are recognized ratably over time.
The following table represents a disaggregation of revenue from contracts with regulated transmission customers by transmission owner for the three months ended March 31, 2020 and 2019, by transmission owner:

|  | For the Three Months Ended March 31,
Transmission Owner |  | 2020 |  | 2019
|  | (In millions)
ATSI |  | $ | 204 |  |  | $ | 174 |
TrAIL |  | 63 |  |  | 58 |
MAIT |  | 57 |  |  | 49 |
Other |  | 73 |  |  | 71 |
Total Revenues |  | $ | 397 |  |  | $ | 352 |

3. DISCONTINUED OPERATIONS
FES and FENOC Chapter 11 Bankruptcy Filing
On March 31, 2018, the FES Debtors announced that, in order to facilitate an orderly financial restructuring, they filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code with the Bankruptcy Court (which is referred to throughout as the FES Bankruptcy). In September 2018, the Bankruptcy Court approved a FES Bankruptcy settlement agreement by and among FirstEnergy, two groups of key FES creditors (collectively, the FES Key Creditor Groups), the FES Debtors and the UCC. The FES Bankruptcy settlement agreement resolved certain claims by FirstEnergy against the FES Debtors, all claims by the FES Debtors and the FES Key Creditor Groups against FirstEnergy, as well as releases from third parties who voted in favor the FES Debtors' plan of reorganization, in return for among other things, a cash payment of $853 million upon emergence. The FES Bankruptcy settlement was conditioned on the FES Debtors confirming and effectuating a plan of reorganization acceptable to FirstEnergy.
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On February 18, 2020, the FES Debtors and FirstEnergy entered into an IT Access Agreement that provided IT support to enable the Debtors to emerge from bankruptcy prior to full IT separation by the FES Debtors. As part of the IT Access Agreement, the FES Debtors and FirstEnergy resolved, among other things, the on-going reconciliation of outstanding tax sharing payments for tax years 2018, 2019 and 2020 for a total of $125 million. On February 25, 2020, the Bankruptcy Court approved the IT Access Agreement. On February 27, 2020, the FES Debtors effectuated their plan, emerged from bankruptcy and FirstEnergy tendered the settlement payments totaling $853 million and the $125 million tax sharing payment to the FES Debtors, with no material impact to net income in the first quarter of 2020.
By eliminating a significant portion of its competitive generation fleet with the deconsolidation of the FES Debtors, FirstEnergy has concluded the FES Debtors meet the criteria for discontinued operations, as this represents a significant event in management’s strategic review to exit commodity-exposed generation and transition to a fully regulated company.
Services Agreements
Pursuant to the FES Bankruptcy settlement agreement, FirstEnergy entered into an amended and restated shared services agreement with the FES Debtors to extend the availability of shared services until no later than June 30, 2020, subject to reductions in services if requested by the FES Debtors, and extensions of time, subject to FirstEnergy’s approval, as provided by the IT Access Agreement. Under the amended shared services agreement, and consistent with the prior shared services agreements, costs are directly billed or assigned at no more than cost.
Currently, FirstEnergy continues to provide services post emergence to the FES Debtors under the terms of the amended and restated shared services agreement and the IT Access Agreement. The FES Debtors have paid approximately $34 million and $35 million for shared services for the three months ended March 31, 2020 and 2019, respectively.
FES Borrowings from FE and AE Supply
Due to the FES Debtors’ emergence from bankruptcy on February 27, 2020, FirstEnergy reversed the following amounts and related reserves in the first quarter of 2020, with no material impact to earnings:

• | $500 million in borrowings by FES from FE under the secured credit facility;

• | $92 million in borrowings by the FES Debtors from FE under the unregulated companies’ money pool; and

• | $102 million outstanding unsecured promissory note by FES from AE Supply.

Benefit Obligations
FirstEnergy retained certain obligations for the FES Debtors’ employees for services provided prior to emergence from bankruptcy. Prior to emergence, FirstEnergy billed the FES Debtors approximately $6 million and $10 million for their share of pension and OPEB service costs for the three months ended March 31, 2020 and 2019, respectively.
Purchase Power
At times, FES provides power through power sales agreements to meet a portion of the Utilities' POLR and default service requirements and also provides power to certain of the Utilities facilities. The terms and conditions of the power purchase agreements are generally consistent with industry practices and other similar third-party arrangements. These agreements were not impacted by the FES Debtors’ emergence and continue to operate under the original terms.
The Utilities purchased and recognized in continuing operations approximately $17 million and $83 million of power purchases from FES for the three months ended March 31, 2020 and 2019, respectively.
Income Taxes
For U.S. federal income taxes, the FES Debtors were included in FirstEnergy’s consolidated tax return until emergence from bankruptcy. Upon emergence on February 27, 2020, FirstEnergy deconsolidated the FES Debtors for federal income tax purposes and recognized a worthless stock deduction for the remaining tax basis in the FES Debtors of approximately $4.9 billion, net of unrecognized tax benefits of $316 million. Tax-effected, the worthless stock deduction is approximately $1 billion, net of valuation allowances recorded against the state tax benefit ($83 million) and the aforementioned unrecognized tax benefits ($72 million).
Additionally, the Tax Act amended Section 163(j) of the Internal Revenue Code, limiting interest expense deductions for corporations but with exemption for certain regulated utilities. Based on interpretation of subsequently issued proposed regulations, FirstEnergy has estimated the amount of deductible interest for its consolidated group in 2018 and 2019, with nondeductible portions being carried forward with an indefinite life and for which deferred tax assets have been recorded. However, full valuation allowances have been recorded against the deferred tax assets related to the carryforward of nondeductible interest as future utilization of the carryforwards requires profitability from sources other than regulated utility businesses. New or additional changes to proposed regulations or guidelines by the IRS on Section 163(j), including their impact resulting from the CARES Act, as further discussed below, could have a material impact on FirstEnergy’s results.
All tax expense related to nondeductible interest in 2018 and 2019 has been recorded in discontinued operations as it is entirely attributed to the inclusion of the FES Debtors in FirstEnergy's consolidated tax group. Upon emergence, FirstEnergy paid the FES Debtors $125 million to settle all reconciliations under the Intercompany Tax Allocation Agreement for 2018, 2019 and 2020 tax years, including all issues regarding nondeductible interest. Pursuant to certain safe harbor rules in existing proposed regulations
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under Section 163(j), and due to the FES Debtors’ emergence from bankruptcy on February 27, 2020, FirstEnergy expects interest expense for 2020 to be fully deductible. See Note 7, “Income Taxes” for further information.
Competitive Generation Asset Sales
As contemplated under the FES Bankruptcy settlement agreement, AE Supply entered into an agreement on December 31, 2018, to transfer the 1,300 MW Pleasants Power Station and related assets to FG, while retaining certain specified liabilities. Under the terms of the agreement, FG acquired the economic interests in Pleasants as of January 1, 2019, and AE Supply operated Pleasants until ownership was transferred on January 30, 2020. AE Supply will continue to provide access to the McElroy's Run CCR Impoundment Facility, which was not transferred, and FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility. During the first quarter of 2020, FG paid AE Supply approximately $65 million of cash for related materials and supplies (at book value) and the settlement of FG’s economic interest in Pleasants.
Summarized Results of Discontinued Operations
Summarized results of discontinued operations for the three months ended March 31, 2020 and 2019, were as follows:

|  | For the Three Months Ended March 31,
(In millions) |  | 2020 |  | 2019
Revenues |  | $ | 7 |  |  | $ | 54 |
Fuel |  | (6 | ) |  | (35 | )
Other operating expenses |  | (6 | ) |  | (10 | )
General taxes |  | — |  |  | (4 | )
Other income (expense) |  | 5 |  |  | (2 | )
Loss from discontinued operations, before tax |  | — |  |  | 3 |
Income tax expense |  | — |  |  | 14 |
Loss from discontinued operations, net of tax |  | — |  |  | (11 | )
Gain (loss) on disposal of FES and FENOC, net of tax (1) |  | 50 |  |  | (24 | )
Income (loss) from discontinued operations |  | $ | 50 |  |  | $ | (35 | )

(1) The gain on disposal of FES and FENOC recognized in the three months ended March 31, 2020, of $50 million primarily related to settlement expense of $4 million, accelerated net pension and OPEB prior service credits of $18 million and income tax benefits (including the estimated worthless stock deduction and adjustments from the tax sharing agreement with the FES Debtors) of $36 million. The loss on disposal of FES and FENOC recognized in the three months ended March 31, 2019, of $24 million consisted of settlement expense of $33 million and income tax benefits (including the estimated worthless stock deduction) of $9 million.
As of December 31, 2019, material and supplies of $33 million are included in FirstEnergy’s Consolidated Balance Sheets as Current assets - discontinued operations. As of March 31, 2020, there were no items on FirstEnergy’s Consolidated Balance Sheets classified as discontinued operations.
FirstEnergy’s Consolidated Statement of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. For the three months ended March 31, 2020 and 2019, cash flows from operating activities includes income (loss) from discontinued operations of $50 million and $(35) million, respectively.
4. EARNINGS PER SHARE OF COMMON STOCK
Basic EPS available to common stockholders is computed using the weighted average number of common shares outstanding during the relevant period as the denominator. The denominator for diluted EPS of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised.
During 2019, EPS was computed using the two-class method required for participating securities. The convertible preferred stock issued in January 2018 were considered participating securities since the shares participated in dividends on common stock on an “as-converted” basis. All convertible preferred stock was converted to common stock during 2019.
The two-class method uses an earnings allocation formula that treats participating securities as having rights to earnings that otherwise would have been available only to common stockholders. Under the two-class method, net income attributable to common stockholders is derived by subtracting the following from income from continuing operations:

• | preferred stock dividends,

• | deemed dividends for the amortization of the beneficial conversion feature recognized at issuance of the preferred stock (if any), and

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• | an allocation of undistributed earnings between the common stock and the participating securities (convertible preferred stock) based on their respective rights to receive dividends.

Net losses were not allocated to the convertible preferred stock as they did not have a contractual obligation to share in the losses of FirstEnergy. FirstEnergy allocated undistributed earnings based upon income from continuing operations.
Diluted EPS reflects the dilutive effect of potential common shares from share-based awards and convertible shares of preferred stock. The dilutive effect of outstanding share-based awards was computed using the treasury stock method, which assumes any proceeds that could be obtained upon the exercise of the award would be used to purchase common stock at the average market price for the period. The dilutive effect of the convertible preferred stock was computed using the if-converted method, which assumes conversion of the convertible preferred stock at the beginning of the period, giving income recognition for the add-back of the preferred stock dividends, amortization of beneficial conversion feature, and undistributed earnings allocated to preferred stockholders.
The following table reconciles basic and diluted EPS of common stock:

|  | For the Three Months Ended March 31,
Reconciliation of Basic and Diluted EPS of Common Stock |  | 2020 |  | 2019
(In millions, except per share amounts) |  |  |  |
EPS of Common Stock |  |  |  |
Income from continuing operations |  | $ | 24 |  |  | $ | 355 |
Less: Preferred dividends |  | — |  |  | (3 | )
Less: Undistributed earnings allocated to preferred stockholders |  | — |  |  | (2 | )
Income from continuing operations available to common stockholders |  | 24 |  |  | 350 |
Discontinued operations, net of tax |  | 50 |  |  | (35 | )
Less: Undistributed earnings allocated to preferred stockholders |  | — |  |  | — |
Income (loss) from discontinued operations available to common stockholders |  | 50 |  |  | (35 | )
Income available to common stockholders, basic |  | $ | 74 |  |  | $ | 315 |
Share Count information: |  |  |  |
Weighted average number of basic shares outstanding |  | 541 |  |  | 530 |
Assumed exercise of dilutive stock options and awards |  | 2 |  |  | 3 |
Weighted average number of diluted shares outstanding |  | 543 |  |  | 533 |
Income available to common stockholders, per common share: |  |  |  |
Income from continuing operations, basic |  | $ | 0.05 |  |  | $ | 0.66 |
Discontinued operations, basic |  | 0.09 |  |  | (0.07 | )
Income available to common stockholders, basic |  | $ | 0.14 |  |  | $ | 0.59 |
Income from continuing operations, diluted |  | $ | 0.05 |  |  | $ | 0.66 |
Discontinued operations, diluted |  | 0.09 |  |  | (0.07 | )
Income available to common stockholders, diluted |  | $ | 0.14 |  |  | $ | 0.59 |

For the three months ended March 31, 2020 and 2019, no shares from stock options and awards were excluded from the calculation of diluted shares outstanding. For the three months ended March 31, 2019, 8 million shares associated with the assumed conversion of preferred stock were excluded as their inclusion would be antidilutive to basic EPS from continuing operations.
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5. PENSION AND OTHER POST-EMPLOYMENT BENEFITS
The components of the consolidated net periodic costs (credits) for pension and OPEB were as follows:

Components of Net Periodic Benefit Costs (Credits) |  | Pension | OPEB
For the Three Months Ended March 31, |  | 2020 |  | 2019 |  | 2020 |  | 2019
|  | (In millions)
Service costs |  | $ | 52 |  |  | $ | 48 |  |  | $ | 1 |  |  | $ | 1 |
Interest costs |  | 75 |  |  | 93 |  |  | 4 |  |  | 5 |
Expected return on plan assets |  | (153 | ) |  | (135 | ) |  | (8 | ) |  | (7 | )
Amortization of prior service costs (credits) (1) |  | 10 |  |  | 2 |  |  | (33 | ) |  | (9 | )
Special termination costs (2) |  | — |  |  | 15 |  |  | — |  |  | — |
One-time termination benefit (3) |  | 8 |  |  | — |  |  | — |  |  | — |
Pension and OPEB mark-to-market adjustment |  | 386 |  |  | — |  |  | 37 |  |  | — |
Net periodic costs (credits), including amounts capitalized |  | $ | 378 |  |  | $ | 23 |  |  | $ | 1 |  |  | $ | (10 | )
Net periodic costs (credits), recognized in earnings |  | $ | 358 |  |  | $ | 6 |  |  | $ | 1 |  |  | $ | (10 | )

(1) 2020 includes the acceleration of $18 million in net credits as a result of the FES Debtors’ emergence and is a component of discontinued operations in FirstEnergy’s Consolidated Statements of Income.
(2) Subject to a cap, FirstEnergy agreed to fund a pension enhancement through its pension plan, for voluntary enhanced retirement packages offered to certain FES employees, as well as offer certain other employee benefits. The costs are a component of discontinued operations in FirstEnergy’s Consolidated Statements of Income.
(3) Costs represent additional benefits provided to FES and FENOC employees under the approved settlement agreement and are a component of discontinued operations in FirstEnergy’s Consolidated Statements of Income.
FirstEnergy recognizes a pension and OPEB mark-to-market adjustment for the change in fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for remeasurement. Under the approved bankruptcy settlement agreement discussed above, upon emergence, FES and FENOC employees ceased earning years of service under the FirstEnergy pension and OPEB plans. The emergence on February 27, 2020, triggered a remeasurement of the affected pension and OPEB plans and as a result, FirstEnergy recognized a non-cash, pre-tax pension and OPEB mark-to-market adjustment of approximately $423 million in the first quarter of 2020. The pension and OPEB mark-to-market adjustment primarily reflects a 38 bps decrease in the discount rate used to measure benefit obligations from December 31, 2019, partially offset by a slightly higher than expected return on assets.
Based on discount rates of 2.96% for pension and 2.80% for OPEB as well as an estimated return on assets of 7.50% for pension and OPEB, FirstEnergy expects its 2020 pre-tax net periodic benefit cost to be approximately $246 million, including the $423 million pension and OPEB mark-to-market adjustment in the first quarter of 2020.
Prior to emergence, FirstEnergy billed the FES Debtors approximately $6 million and $10 million for their share of pension and OPEB service costs for the three months ended March 31, 2020 and 2019, respectively.
On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. FirstEnergy expects no required contributions through 2021.
Service costs, net of capitalization, are reported within Other operating expenses on FirstEnergy’s Consolidated Statements of Income. Non-service costs, other than the pension and OPEB mark-to-market adjustment, which is separately shown, are reported within Miscellaneous income, net, within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income.
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6. ACCUMULATED OTHER COMPREHENSIVE INCOME
The following tables show the changes in AOCI for the three months ended March 31, 2020 and 2019:

|  | Gains & Losses on Cash Flow Hedges (1) |  | Defined Benefit Pension & OPEB Plans |  | Total
|  | (In millions)
AOCI Balance, January 1, 2020 |  | $ | (9 | ) |  | $ | 29 |  |  | $ | 20 |
Amounts reclassified from AOCI |  | — |  |  | (23 | ) |  | (23 | )
Other comprehensive loss |  | — |  |  | (23 | ) |  | (23 | )
Income tax benefits on other comprehensive loss |  | — |  |  | (5 | ) |  | (5 | )
Other comprehensive loss, net of tax |  | — |  |  | (18 | ) |  | (18 | )
AOCI Balance, March 31, 2020 |  | $ | (9 | ) |  | $ | 11 |  |  | $ | 2 |
AOCI Balance, January 1, 2019 |  | $ | (11 | ) |  | $ | 52 |  |  | $ | 41 |
Amounts reclassified from AOCI |  | 1 |  |  | (7 | ) |  | (6 | )
Other comprehensive income (loss) |  | 1 |  |  | (7 | ) |  | (6 | )
Income tax benefits on other comprehensive loss |  | — |  |  | (1 | ) |  | (1 | )
Other comprehensive income (loss), net of tax |  | 1 |  |  | (6 | ) |  | (5 | )
AOCI Balance, March 31, 2019 |  | $ | (10 | ) |  | $ | 46 |  |  | $ | 36 |

(1) Relates to previous cash flow hedges used to hedge fixed rate long-term debt securities prior to their issuance.
The following amounts were reclassified from AOCI in the three months ended March 31, 2020 and 2019:

|  | For the Three Months Ended March 31, |  | Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI(1) |  | 2020 |  | 2019 |
|  | (In millions) |  |
Gains & losses on cash flow hedges |  |  |  |  |  |
Long-term debt |  | $ | — |  |  | $ | 1 |  |  | Interest expense
|  | $ | — |  |  | $ | 1 |  |  | Net of tax
Defined benefit pension and OPEB plans |  |  |  |  |  |
Prior-service costs |  | $ | (23 | ) |  | $ | (7 | ) |  | (2)
|  | 5 |  |  | 1 |  |  | Income taxes
|  | $ | (18 | ) |  | $ | (6 | ) |  | Net of tax
(1) Amounts in parenthesis represent credits to the Consolidated Statements of Income from AOCI.
(2) Prior-service costs are reported within Miscellaneous income, net, within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income. Components are included in the computation of net periodic cost (credits), see Note 5, “Pension and Other Post-Employment Benefits.”

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7. INCOME TAXES
FirstEnergy’s interim effective tax rates reflect the estimated annual effective tax rates for 2020 and 2019. These tax rates are affected by estimated annual permanent items, such as AFUDC equity and other flow-through items, as well as discrete items that may occur in any given period but are not consistent from period to period.
FirstEnergy’s effective tax rate on continuing operations for the three months ended March 31, 2020 and 2019, was 166.7% and 20.8%, respectively. The change in effective tax rate was primarily due to a $52 million reduction in valuation allowances from the recognition of deferred gains on prior intercompany generation asset transfers that were triggered by the FES Debtors’ emergence from bankruptcy in the first quarter of 2020 and subsequent deconsolidation from FirstEnergy’s consolidated federal income tax group. See Note 3, “Discontinued Operations,” for other tax matters relating to the FES Bankruptcy that were recognized in discontinued operations.
During the three months ended March 31, 2020, FirstEnergy remeasured its reserve for uncertain tax positions for federal and state tax benefits related to the worthless stock deduction, resulting in a net decrease to the reserve of approximately $28 million, none of which had an impact on the effective tax rate. As of March 31, 2020, it is reasonably possible that FirstEnergy could record a net decrease to its reserve for uncertain tax positions by approximately $59 million within the next twelve months due to the statute of limitations expiring or resolution with taxing authorities, of which approximately $57 million would impact FirstEnergy’s effective tax rate.
On March 27, 2020, the President signed into law the CARES Act, an economic stimulus package in response to the COVID-19 global pandemic. The CARES Act contains several corporate income tax provisions, including making remaining AMT credits immediately refundable; providing a 5-year carryback of NOLs generated in tax years 2018, 2019, and 2020, and removing the 80% taxable income limitation on utilization of those NOLs if carried back to prior tax years or utilized in tax years beginning before 2021; and temporarily liberalizing the interest deductibility rules under Section 163(j) of the Tax Act, by raising the adjusted taxable income limitation from 30% to 50% for tax years 2019 and 2020 and giving taxpayers the election of using 2019 adjusted taxable income for purposes of computing 2020 interest deductibility. FirstEnergy has approximately $18 million of refundable AMT credits that will be fully refundable through the CARES Act, however, does not expect to generate additional income tax refunds from the NOL carryback provision and expects interest to be fully deductible starting in 2020. FirstEnergy does not currently expect the other provisions of the CARES Act to have a material effect on current income tax expense or the realizability of deferred income tax assets, however, new or additional changes to proposed regulations or guidelines by the IRS on Section 163(j), including their impact resulting from the CARES Act, could have a material impact.
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8. FAIR VALUE MEASUREMENTS
RECURRING FAIR VALUE MEASUREMENTS
Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy and a description of the valuation techniques are as follows:

Level 1 | - | Quoted prices for identical instruments in active market
Level 2 | - | Quoted prices for similar instruments in active market
| - | Quoted prices for identical or similar instruments in markets that are not active
| - | Model-derived valuations for which all significant inputs are observable market data

Models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.

Level 3 | - | Valuation inputs are unobservable and significant to the fair value measurement

FirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market conditions change. When underlying prices are not observable, prices from the long-term price forecast are used to measure fair value.
FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term PJM auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs’ carrying values are periodically adjusted to fair value using a mark-to-model methodology, which approximates market. The primary inputs into the model, which are generally less observable than objective sources, are the most recent PJM auction clearing prices and the FTRs’ remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. Significant increases or decreases in inputs in isolation may have resulted in a higher or lower fair value measurement.
NUG contracts represent PPAs with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. NUG contract carrying values are recorded at fair value and adjusted periodically using a mark-to-model methodology, which approximates market. The primary unobservable inputs into the model are regional power prices and generation MWH. Pricing for the NUG contracts is a combination of market prices for the current year and next two years based on observable data and internal models using historical trends and market data for the remaining years under contract. The internal models use forecasted energy purchase prices as an input when prices are not defined by the contract. Forecasted market prices are based on Intercontinental Exchange, Inc. quotes and management assumptions. Generation MWH reflects data provided by contractual arrangements and historical trends. The model calculates the fair value by multiplying the prices by the generation MWH. Significant increases or decreases in inputs in isolation may have resulted in a higher or lower fair value measurement.
FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were no changes in valuation methodologies used as of March 31, 2020, from those used as of December 31, 2019. 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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The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy:

| March 31, 2020 |  | December 31, 2019
| Level 1 |  | Level 2 |  | Level 3 |  | Total |  | Level 1 |  | Level 2 |  | Level 3 |  | Total
Assets | (In millions)
Corporate debt securities | $ | — |  |  | $ | 124 |  |  | $ | — |  |  | $ | 124 |  |  | $ | — |  |  | $ | 135 |  |  | $ | — |  |  | $ | 135 |
Derivative assets FTRs(1) | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 4 |  |  | 4 |
Equity securities(2) | 2 |  |  | — |  |  | — |  |  | 2 |  |  | 2 |  |  | — |  |  | — |  |  | 2 |
U.S. state debt securities | — |  |  | 274 |  |  | — |  |  | 274 |  |  | — |  |  | 271 |  |  | — |  |  | 271 |
Other(3) | 166 |  |  | 802 |  |  | — |  |  | 968 |  |  | 627 |  |  | 789 |  |  | — |  |  | 1,416 |
Total assets | $ | 168 |  |  | $ | 1,200 |  |  | $ | — |  |  | $ | 1,368 |  |  | $ | 629 |  |  | $ | 1,195 |  |  | $ | 4 |  |  | $ | 1,828 |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Derivative liabilities FTRs(1) | $ | — |  |  | $ | — |  |  | $ | (1 | ) |  | $ | (1 | ) |  | $ | — |  |  | $ | — |  |  | $ | (1 | ) |  | $ | (1 | )
Derivative liabilities NUG contracts(1) | — |  |  | — |  |  | (6 | ) |  | (6 | ) |  | — |  |  | — |  |  | (16 | ) |  | (16 | )
Total liabilities | $ | — |  |  | $ | — |  |  | $ | (7 | ) |  | $ | (7 | ) |  | $ | — |  |  | $ | — |  |  | $ | (17 | ) |  | $ | (17 | )
Net assets (liabilities)(4) | $ | 168 |  |  | $ | 1,200 |  |  | $ | (7 | ) |  | $ | 1,361 |  |  | $ | 629 |  |  | $ | 1,195 |  |  | $ | (13 | ) |  | $ | 1,811 |

(1) | Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings.

(2) | NDT funds hold equity portfolios whose performance is benchmarked against the S&P 500 Low Volatility High Dividend Index, S&P 500 Index and MSCI AC World IMI Index.

(3) | Primarily consists of short-term cash investments.

(4) | Excludes $(18) million and $(16) million as of March 31, 2020 and December 31, 2019, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended March 31, 2020, and December 31, 2019:

| NUG Contracts(1) |  | FTRs(1)
| Derivative Assets |  | Derivative Liabilities |  | Net |  | Derivative Assets |  | Derivative Liabilities |  | Net
| (In millions)
January 1, 2019 Balance | $ | — |  |  | $ | (44 | ) |  | $ | (44 | ) |  | $ | 10 |  |  | $ | (1 | ) |  | $ | 9 |
Unrealized gain | — |  |  | (11 | ) |  | (11 | ) |  | (1 | ) |  | — |  |  | (1 | )
Purchases | — |  |  | — |  |  | — |  |  | 6 |  |  | (4 | ) |  | 2 |
Settlements | — |  |  | 39 |  |  | 39 |  |  | (11 | ) |  | 4 |  |  | (7 | )
December 31, 2019 Balance | $ | — |  |  | $ | (16 | ) |  | $ | (16 | ) |  | $ | 4 |  |  | $ | (1 | ) |  | $ | 3 |
Unrealized loss | — |  |  | (3 | ) |  | (3 | ) |  | — |  |  | — |  |  | — |
Purchases | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Settlements | — |  |  | 13 |  |  | 13 |  |  | (4 | ) |  | — |  |  | (4 | )
March 31, 2020 Balance | $ | — |  |  | $ | (6 | ) |  | $ | (6 | ) |  | $ | — |  |  | $ | (1 | ) |  | $ | (1 | )

(1) | Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings.

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Level 3 Quantitative Information
The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2020:

|  | Fair Value, Net (In millions) |  | Valuation Technique |  | Significant Input |  | Range |  | Weighted Average |  | Units
FTRs |  | $ | (1 | ) |  | Model |  | RTO auction clearing prices |  | $(0.10) to $2.10 |  | $0.50 |  | Dollars/MWH
NUG Contracts |  | $ | (6 | ) |  | Model |  | Generation |  | 400 to 109,000 |  | 27,000 |  |  | MWH
|  |  | Regional electricity prices |  | $20.50 to $34.70 |  | $21.60 |  | Dollars/MWH

INVESTMENTS
All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include equity securities, AFS debt securities and other investments. FirstEnergy has no debt securities held for trading purposes.
Generally, unrealized gains and losses on equity securities are recognized in income whereas unrealized gains and losses on AFS debt securities are recognized in AOCI. However, the NDTs and nuclear fuel disposal trusts of JCP&L, ME and PN are subject to regulatory accounting with all gains and losses on equity and AFS debt securities offset against regulatory assets.
The investment policy for the NDT funds restricts or limits the trusts’ ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, securities convertible into common stock and securities of the trust funds’ custodian or managers and their parents or subsidiaries.
Nuclear Decommissioning and Nuclear Fuel Disposal Trusts
JCP&L, ME and PN hold debt and equity securities within their respective NDT and nuclear fuel disposal trusts. The debt securities are classified as AFS securities, recognized at fair market value. As further discussed in Note 10, "Commitments, Guarantees and Contingencies", assets and liabilities held for sale on the FirstEnergy Consolidated Balance Sheets associated with the TMI-2 transaction consist of an ARO of $700 million, NDTs of $875 million, as well as property, plant and equipment with a net book value of zero, which are included in the regulated distribution segment.
The following table summarizes the amortized cost basis, unrealized gains, unrealized losses and fair values of investments held in NDT and nuclear fuel disposal trusts as of March 31, 2020, and December 31, 2019:

|  | March 31, 2020(1) |  | December 31, 2019(2)
|  | Cost Basis |  | Unrealized Gains |  | Unrealized Losses |  | Fair Value (3) |  | Cost Basis |  | Unrealized Gains |  | Unrealized Losses |  | Fair Value (3)
|  | (In millions)
Debt securities |  | $ | 405 |  |  | $ | 8 |  |  | $ | (16 | ) |  | $ | 397 |  |  | $ | 403 |  |  | $ | 9 |  |  | $ | (11 | ) |  | $ | 401 |

(1) Excludes short-term cash investments of $753 million, of which $751 million is classified as held for sale.
(2) Excludes short-term cash investments of $751 million, of which $747 million is classified as held for sale.
(3) Includes $124 million and $135 million classified as held for sale as of March 31, 2020 and December 31, 2019, respectively.
Proceeds from the sale of investments in equity and AFS debt securities, realized gains and losses on those sales and interest and dividend income for the three months ended March 31, 2020 and 2019, were as follows:

|  | For the Three Months Ended March 31, |
|  | 2020 |  | 2019 |
|  | (In millions) |
Sale proceeds |  | $ | 13 |  |  | $ | 153 |  |
Realized gains |  | 4 |  |  | 7 |  |
Realized losses |  | (5 | ) |  | (6 | ) |
Interest and dividend income |  | 5 |  |  | 9 |  |

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Other Investments
Other investments include employee benefit trusts, which are primarily invested in corporate-owned life insurance policies and equity method investments. Other investments were $288 million and $299 million as of March 31, 2020, and December 31, 2019, respectively, and are excluded from the amounts reported above.
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS
All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported as Short-term borrowings on the Consolidated Balance Sheets at cost. Since these borrowings are short-term in nature, FirstEnergy believes that their costs approximate their fair market value. The following table provides the approximate fair value and related carrying amounts of long-term debt, which excludes finance lease obligations and net unamortized debt issuance costs, premiums and discounts as of March 31, 2020 and December 31, 2019:

| March 31, 2020 |  | December 31, 2019
| (In millions)
Carrying value (1) | $ | 21,297 |  |  | $ | 20,074 |
Fair value | $ | 23,576 |  |  | $ | 22,928 |

(1) The carrying value as of March 31, 2020, includes $2 billion of debt issuances and $778 million of redemptions that occurred in 2020.
The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy. FirstEnergy classified short-term borrowings, long-term debt and other long-term obligations as Level 2 in the fair value hierarchy as of March 31, 2020, and December 31, 2019.
9. REGULATORY MATTERS
STATE REGULATION
Each of the Utilities’ retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia are subject to certain regulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. 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 March 23, 2019. PE also provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third-party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS.
The EmPOWER Maryland program requires each electric utility to file a plan to reduce electric consumption and demand 0.2% per year, up to the ultimate goal of 2% annual savings, for the duration of the 2018-2020 and 2021-2023 EmPOWER Maryland program cycles, to the extent the MDPSC determines that cost-effective programs and services are available. PE’s approved 2018-2020 EmPOWER Maryland plan continues and expands upon prior years’ programs, and adds new programs, for a projected total cost of $116 million over the three-year period. PE recovers program costs subject to a five-year amortization. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding, and to date, such recovery has not been sought or obtained by PE.
On January 19, 2018, PE filed a joint petition along with other utility companies, work group stakeholders and the MDPSC electric vehicle work group leader to implement a statewide electric vehicle portfolio in connection with a 2016 MDPSC 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. PE proposed an electric vehicle charging infrastructure program at a projected total cost of $12 million, to be recovered over a five-year amortization. On January 14, 2019, the MDPSC approved the petition subject to certain reductions in the scope of the program. The MDPSC approved PE’s compliance filing, which implements the pilot program, with minor modifications, on July 3, 2019.
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On August 24, 2018, PE filed a base rate case with the MDPSC, which it supplemented on October 22, 2018, to update the partially forecasted test year with a full twelve months of actual data. The rate case requested an annual increase in base distribution rates of $19.7 million, plus creation of an EDIS to fund four enhanced service reliability programs. In responding to discovery, PE revised its request for an annual increase in base rates to $17.6 million. The proposed rate increase reflected $7.3 million in annual savings for customers resulting from the recent federal tax law changes. On March 22, 2019, the MDPSC issued a final order that approved a rate increase of $6.2 million, approved three of the four EDIS programs for four years, directed PE to file a new depreciation study within 18 months, and ordered the filing of a new base rate case in four years to correspond to the ending of the approved EDIS programs.
Maryland’s Governor issued an order on March 16, 2020, forbidding utilities from terminating residential service or charging late fees for non-payment for the duration of the COVID-19 emergency. On April 9, 2020, the MDPSC issued an order allowing utilities to track and create a regulatory asset for future recovery of all prudently-incurred incremental costs arising from the COVID-19 emergency.
NEW JERSEY
JCP&L operates under NJBPU approved rates that were effective as of January 1, 2017. 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.
On April 18, 2019, pursuant to the May 2018 New Jersey enacted legislation establishing a ZEC program to provide ratepayer funded subsidies of New Jersey nuclear energy supply, the NJBPU approved the implementation of a non-bypassable, irrevocable ZEC charge for all New Jersey electric utility customers, including JCP&L’s customers. Once collected from customers by JCP&L, these funds will be remitted to eligible nuclear energy generators.
In December 2017, the NJBPU issued proposed rules to modify its current CTA policy in base rate cases to: (i) calculate savings using a five-year look back from the beginning of the test year; (ii) allocate savings with 75% retained by the company and 25% allocated to ratepayers; and (iii) exclude transmission assets of electric distribution companies in the savings calculation, which were published in the NJ Register in the first quarter of 2018. JCP&L filed comments supporting the proposed rulemaking. On January 17, 2019, the NJBPU approved the proposed CTA rules with no changes. On May 17, 2019, the Rate Counsel filed an appeal with the Appellate Division of the Superior Court of New Jersey. JCP&L is contesting this appeal but is unable to predict the outcome of this matter.
Also in December 2017, the NJBPU approved its IIP rulemaking. The IIP creates a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing components that enhance reliability, resiliency, and/or safety. On May 8, 2019, the NJBPU approved a Stipulation of Settlement submitted by JCP&L, Rate Counsel, NJBPU Staff and New Jersey Large Energy Users Coalition to implement JCP&L’s infrastructure plan, JCP&L Reliability Plus. The plan provides that JCP&L will invest up to approximately $97 million in capital investments beginning on June 1, 2019 through December 31, 2020, to enhance the reliability and resiliency of JCP&L’s distribution system and reduce the frequency and duration of power outages. JCP&L shall seek recovery of the capital investment through an accelerated cost recovery mechanism, provided for in the rules, that includes a revenue adjustment calculation and a process for two rate adjustments. The NJBPU approved adjusted rates that took effect on March 1, 2020.
On February 18, 2020, JCP&L submitted a filing with the NJBPU requesting a distribution base rate increase of $186.9 million on an annual basis, which represents an overall average increase in JCP&L rates of 7.8%. The filing seeks to recover certain costs associated with providing safe and reliable electric service to JCP&L customers, along with recovery of previously incurred storm costs. JCP&L proposed a rate effective date of March 19, 2020. On March 9, 2020, the Board issued an order suspending JCP&L’s proposed rates for four months. Based on the historical procedures of the NJBPU Board a second suspension order is expected with revised base rates becoming effective in late November 2020.
On April 6, 2020, JCP&L signed an asset purchase agreement with Yard’s Creek Energy, LLC, a subsidiary of LS Power to sell its 50% interest in the Yards Creek pumped-storage hydro generation facility in NJ (210 MWs). Subject to terms and conditions of the agreement, the base purchase price is $155 million. Completion of the transaction is subject to several closing conditions, including approval by the NJBPU and FERC. There can be no assurance that all regulatory approvals will be obtained and/or all closing conditions will be satisfied or that the transaction will be consummated. JCP&L currently anticipates closing of the transaction to occur in the first half of 2021. As of March 31, 2020, Yards Creek’s net book value is approximately $44 million, which is included in the regulated distribution segment. Treatment of the gain is subject to NJBPU approval.
OHIO
The Ohio Companies operate under base distribution rates approved by the PUCO effective in 2009. The Ohio Companies’ residential and commercial base distribution revenues are decoupled, through a mechanism that took effect on February 1, 2020, to the base distribution revenue and lost distribution revenue associated with energy efficiency and peak demand reduction programs recovered as of the twelve-month period ending on December 31, 2018. The Ohio Companies currently operate under ESP IV effective June
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1, 2016, and continuing through May 31, 2024, that continues the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continues Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024. In addition, ESP IV includes: (1) continuation of a base distribution rate freeze through May 31, 2024; (2) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (3) a goal across FirstEnergy to reduce CO 2 emissions by 90% below 2005 levels by 2045; and (4) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio. ESP IV further provided for the Ohio Companies to collect through Rider DMR $132.5 million annually for three years beginning in 2017, grossed up for federal income taxes, resulting in an approved amount of approximately $168 million annually in 2018 and 2019. On appeal, the SCOH, on June 19, 2019, reversed the PUCO’s determination that Rider DMR is lawful, and remanded the matter to the PUCO with instructions to remove Rider DMR from ESP IV. On August 20, 2019, the SCOH denied the Ohio Companies’ motion for reconsideration. The PUCO entered an Order directing the Ohio Companies to cease further collection through Rider DMR, credit back to customers a refund of Rider DMR funds collected since July 2, 2019, and remove Rider DMR from ESP IV. On July 15, 2019, OCC filed a Notice of Appeal with the SCOH, challenging the PUCO’s exclusion of Rider DMR revenues from the determination of the existence of significantly excessive earnings under ESP IV for calendar year 2017 and claiming a $42 million refund is due to OE customers. The Ohio Companies are contesting this appeal but are unable to predict the outcome of this matter. The SCOH is scheduled to hear argument on this matter on May 12, 2020.
On July 23, 2019, Ohio enacted legislation establishing support for nuclear energy supply in Ohio. In addition to the provisions supporting nuclear energy, the legislation included a provision implementing a decoupling mechanism for Ohio electric utilities and ending current energy efficiency program mandates on December 31, 2020, provided that statewide energy efficiency mandates are achieved as determined by the PUCO. On February 26, 2020, the PUCO ordered (i) that a wind-down of statutorily required energy efficiency programs shall commence on September 30, 2020, and the programs shall terminate on December 31, 2020, and (ii) that the Ohio Companies’ existing portfolio plans are extended through 2020 without changes.
On November 21, 2019, the Ohio Companies applied to the PUCO for approval of a decoupling mechanism, which would set residential and commercial base distribution related revenues at the levels collected in 2018. As such, those base distribution revenues would no longer be based on electric consumption, which allows continued support of energy efficiency initiatives while also providing revenue certainty to the Ohio Companies. On January 15, 2020, the PUCO approved the Ohio Companies’ decoupling application, and the decoupling mechanism took effect on February 1, 2020.
On July 17, 2019, the PUCO approved, with no material modifications, a settlement agreement that provides for the implementation of the Ohio Companies’ first phase of grid modernization plans, including the investment of $516 million over three years to modernize the Ohio Companies’ electric distribution system, and for all tax savings associated with the Tax Act to flow back to customers. The settlement had broad support, including PUCO Staff, the OCC, representatives of industrial and commercial customers, a low-income advocate, environmental advocates, hospitals, competitive generation suppliers and other parties.
PENNSYLVANIA
The Pennsylvania Companies operate under rates approved by the PPUC, effective as of January 27, 2017. These rates were adjusted for the net impact of the Tax Act, effective March 15, 2018. The net impact of the Tax Act for the period January 1, 2018 through March 14, 2018 was separately tracked and its treatment will be addressed in a future rate proceeding. The Pennsylvania Companies operate under DSPs for the June 1, 2019 through May 31, 2023 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 2019-2023 DSPs, supply will be provided by wholesale suppliers through a mix of 3, 12 and 24-month energy contracts, as well as two RFPs for 2-year SREC contracts for ME, PN and Penn.
Pursuant to Pennsylvania Act 129 of 2008 and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs. The Pennsylvania Companies’ Phase III EE&C plans for the June 2016 through May 2021 period, which were approved in March 2016, with expected costs up to $390 million, are designed to achieve the targets established in the PPUC’s Phase III Final Implementation Order with full recovery through the reconcilable EE&C riders. On March 12, 2020, the PPUC entered a Tentative Implementation Order for a Phase IV EE&C Plan, operating from June 2021 through May 2026.
Pennsylvania EDCs may file with the PPUC for 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 August 30, 2019, the Pennsylvania Companies filed Petitions for approval of new LTIIPs for the five-year period beginning January 1, 2020 and ending December 31, 2024 for a total capital investment of approximately $572 million for certain infrastructure improvement initiatives. On January 16, 2020, the PPUC approved the LTIIPs without modification. The Pennsylvania Companies’ approved DSIC riders for quarterly cost recovery went into effect July 1, 2016. On August 30, 2019, Penn filed a Petition seeking approval of a waiver of the statutory DSIC cap of 5% of distribution rate revenue and approval to increase the maximum allowable DSIC to 11.81% of distribution rate revenue for the five-year period of its proposed LTIIP. On March 12, 2020, an order was entered approving a settlement by all parties to that case which provides for a temporary increase in the recoverability cap from 5% to 7.5%, to expire on the earlier of the effective date of new base rates following Penn’s next base rate case or the expiration of its LTIIP II program.
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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, which decision was appealed by the Pennsylvania OCA to the Pennsylvania Commonwealth Court. The Commonwealth Court reversed the PPUC’s decision and remanded the matter to require the Pennsylvania Companies to revise their tariffs and DSIC calculations to include ADIT and state income taxes. On April 7, 2020, the Pennsylvania Supreme Court issued an Order granting Petitions for Allowance of Appeal by both the PPUC and the Pennsylvania Companies of the Commonwealth Court’s Opinion and Order. A briefing schedule is pending. An adverse ruling by the Pennsylvania Supreme Court is not expected to result in a material impact to FirstEnergy.
WEST VIRGINIA
MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operates under rates approved by the WVPSC effective February 2015. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP’s and PE’s ENEC rate is updated annually.
On August 21, 2019, MP and PE filed with the WVPSC their annual ENEC case requesting a decrease in ENEC rates of $6.1 million beginning January 1, 2020, representing a 0.4% decrease in rates versus those in effect on August 21, 2019. On October 11, 2019, MP and PE filed a supplement requesting approval of the termination of the 50 MW PPA with Morgantown Energy Associates, a NUG entity. A settlement between MP, PE, and the majority of the intervenors fully resolving the ENEC case, which maintains 2019 ENEC rates into 2020, and supports the termination of the Morgantown Energy Associates PPA was filed with the WVPSC on October 18, 2019. An order was issued on December 20, 2019, approving the ENEC settlement and termination of the PPA with Morgantown Energy Associates.
On August 21, 2019, MP and PE filed with the WVPSC for a reconciliation of their VMS and a periodic review of its vegetation management program requesting an increase in VMS rates of $7.6 million beginning January 1, 2020. The increase is due to moving from a 5-year maintenance cycle to a 4-year cycle and performing more operation and maintenance work and less capital work on the rights of way. The increase is a 0.5% increase in rates versus those in effect on August 21, 2019. All the parties reached a settlement in the case, and the WVPSC issued its order approving the settlement without change on December 20, 2019.
FERC REGULATORY MATTERS
Under the FPA, FERC regulates rates for interstate wholesale sales, transmission of electric power, accounting 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, WP and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE, WP 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.
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 been authorized by FERC to sell wholesale power in interstate commerce at market-based rates and have a market-based rate tariff on file with FERC, although major wholesale purchases remain subject to 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 ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to 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.
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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 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 exceed the costs. In a subsequent order, FERC affirmed its prior ruling that ATSI must submit the cost/benefit analysis. ATSI is evaluating the cost/benefit approach.
FERC Actions on Tax Act
On March 15, 2018, FERC initiated proceedings on the question of how to address possible changes to ADIT and bonus depreciation as a result of the Tax Act. Such possible changes could impact FERC-jurisdictional rates, including transmission rates. On November 21, 2019, FERC issued a final rule (Order No. 864). Order No. 864 requires utilities with transmission formula rates to update their formula rate templates to include mechanisms to (i) deduct any excess ADIT from or add any deficient ADIT to their rate base; (ii) raise or lower their income tax allowances by any amortized excess or deficient ADIT; and (iii) incorporate a new permanent worksheet into their rates that will annually track information related to excess or deficient ADIT. Alternatively, formula rate utilities can demonstrate to FERC that their formula rate template already achieves these outcomes. Utilities with transmission stated rates are required to address these new requirements as part of their next transmission rate case. FERC also issued on November 15, 2018, a policy statement providing accounting and ratemaking guidance for treatment of ADIT for all FERC-jurisdictional public utilities. The policy statement also addresses the accounting and ratemaking treatment of ADIT following the sale or retirement of an asset after December 31, 2017. FirstEnergy’s formula rate transmission utilities will make the required filings on or before the deadlines established in FERC’s order. FirstEnergy’s stated rate transmission utilities will address the requirements as part of their next transmission rate case. JCP&L is addressing the requirements in the course of its pending transmission rate case.
Transmission ROE Methodology
FERC’s methodology for calculating electric transmission utility ROE has been in transition as a result of an April 14, 2017 ruling by the D.C. Circuit that vacated FERC’s then-effective methodology. On October 16, 2018, FERC issued an order in which it proposed a revised ROE methodology. FERC proposed that, for complaint proceedings alleging that an existing ROE is not just and reasonable, FERC will rely on three financial models - discounted cash flow, capital-asset pricing, and expected earnings - to establish a composite zone of reasonableness to identify a range of just and reasonable ROEs. FERC then will utilize the transmission utility’s risk relative to other utilities within that zone of reasonableness to assign the transmission utility to one of three quartiles within the zone. FERC would take no further action (i.e., dismiss the complaint) if the existing ROE falls within the identified quartile. However, if the replacement ROE falls outside the quartile, FERC would deem the existing ROE presumptively unjust and unreasonable and would determine the replacement ROE. FERC would add a fourth financial model risk premium to the analysis to calculate a ROE based on the average point of central tendency for each of the four financial models. On March 21, 2019, FERC established NOIs to collect industry and stakeholder comments on the revised ROE methodology that is described in the October 16, 2018 decision, and also whether to make changes to FERC’s existing policies and practices for awarding transmission rates incentives. On November 21, 2019, FERC announced in a complaint proceeding involving MISO utilities that FERC would rely on the discounted cash flow and capital-asset pricing models as the basis for establishing ROE. It is not clear at this time whether FERC’s November ruling will be applied more broadly. Any changes to FERC’s transmission rate ROE and incentive policies would be applied on a prospective basis. FirstEnergy currently is participating through various trade groups in the FERC dockets where the ROE methodology is being reviewed, and on December 23, 2019, JCP&L filed a request for rehearing of FERC’s November decision in the MISO utilities docket.
FERC’s ROE policy may also impact PATH’s regulatory proceedings regarding recovery of investments and costs associated with a proposed transmission line from West Virginia through Virginia and into Maryland that PJM canceled in 2012. Specifically, on January 24, 2020, FERC issued an order in the PATH transmission abandonment rate case that noted FERC’s recent actions on transmission utility ROE methodologies and directed parties to brief the applicability of the October 2018 methodology to the PATH ROE. Initial briefs are due May 1, 2020 and reply briefs are due June 1, 2020.
On March 20, 2020, FERC initiated a rulemaking proceeding on the transmission rate incentives provisions of Section 219 of the 2005 Energy Policy Act. Initial comments are due July 1, 2020. FirstEnergy currently is participating through EEI and other industry groups.
JCP&L Transmission Formula Rate
On October 30, 2019, JCP&L filed tariff amendments with FERC to convert JCP&L’s existing stated transmission rate to a forward-looking formula transmission rate. JCP&L requested that the tariff amendments become effective January 1, 2020. On December 19, 2019, FERC issued its initial order in the case, allowing JCP&L to transition to a forward-looking formula rate as of January 1, 2020 as requested, subject to refund, pending further hearing and settlement proceedings. JCP&L and the parties to the FERC
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proceeding are engaged in settlement negotiations.
10. COMMITMENTS, GUARANTEES AND CONTINGENCIES
GUARANTEES AND OTHER ASSURANCES
FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party.
As of March 31, 2020, outstanding guarantees and other assurances aggregated approximately $1.7 billion, consisting of parental guarantees on behalf of its consolidated subsidiaries ($1.1 billion), other guarantees ($114 million) and other assurances ($502 million).
COLLATERAL AND CONTINGENT-RELATED FEATURES
In the normal course of business, FE and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain bilateral agreements and derivative instruments contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE’s or its subsidiaries’ credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements.
Bilateral agreements and derivative instruments entered into by FE and its subsidiaries have margining provisions that require posting of collateral. As of March 31, 2020, no collateral has been posted by FE or its subsidiaries.
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, 2020:

Potential Collateral Obligations |  |  | Utilities and FET |  | FE |  | Total
|  | (In millions)
Contractual Obligations for Additional Collateral |  |  |  |  |  |  |
Upon Further Downgrade |  |  | $ | 33 |  |  | $ | — |  |  | $ | 33 |
Surety Bonds (Collateralized Amount) (1) |  |  | 63 |  |  | 257 |  |  | 320 |
Total Exposure from Contractual Obligations |  |  | $ | 96 |  |  | $ | 257 |  |  | $ | 353 |

(1) | Surety Bonds are not tied to a credit rating. Surety Bonds’ impact assumes maximum contractual obligations (typical obligations require 30 days to cure).

OTHER COMMITMENTS AND CONTINGENCIES
FE is a guarantor under a $120 million syndicated senior secured term loan facility due November 12, 2024, under which Global Holding’s outstanding principal balance is $114 million as of March 31, 2020. 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. 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.
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Clean Air Act
FirstEnergy complies with SO 2 and NOx emission reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls and/or using emission allowances.
CSAPR requires reductions of NOx and SO 2 emissions in two phases (2015 and 2017), ultimately capping SO 2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO 2 emission allowances between power plants located in the same state and interstate trading of NOx and SO 2 emission allowances with some restrictions. The D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO 2 emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia. This follows the 2014 U.S. Supreme Court ruling generally upholding the EPA’s regulatory approach under CSAPR, but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR update rule on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR update rule to the D.C. Circuit in November and December 2016. On September 6, 2017, the D.C. Circuit rejected the industry’s bid for a lengthy pause in the litigation and set a briefing schedule. On September 13, 2019, the D.C. Circuit remanded the CSAPR update rule 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. Depending on the outcome of the appeals, the EPA’s reconsideration of the CSAPR update rule and how the EPA and the states ultimately implement CSAPR, the future cost of compliance may materially impact FirstEnergy’s operations, cash flows and financial condition.
In February 2019, the EPA announced its final decision to retain without changes the NAAQS for SO 2, specifically retaining the 2010 primary (health-based) 1-hour standard of 75 PPB. As of March 31, 2020, FirstEnergy has no power plants operating in areas designated as non-attainment by the EPA.
In August 2016, the State of Delaware filed a CAA Section 126 petition with the EPA alleging that the Harrison generating facility’s NOx emissions significantly contribute to Delaware’s inability to attain the ozone NAAQS. The petition sought a short-term NOx emission rate limit of 0.125 lb./mmBTU over an averaging period of no more than 24 hours. In November 2016, the State of Maryland filed a CAA Section 126 petition with the EPA alleging that NOx emissions from 36 EGUs, including Harrison Units 1, 2 and 3, significantly contribute to Maryland’s inability to attain the ozone NAAQS. The petition sought NOx emission rate limits for the 36 EGUs by May 1, 2017. On September 14, 2018, the EPA denied both the States of Delaware and Maryland’s petitions under CAA Section 126. In October 2018, Delaware and Maryland appealed the denials of their petitions to the D.C. Circuit. In March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from nine states (including West Virginia) significantly contribute to New York’s inability to attain the ozone NAAQS. The petition seeks suitable emission rate limits for large stationary sources that are affecting New York’s air quality within the three years allowed by CAA Section 126. On May 3, 2018, the EPA extended the time frame for acting on the CAA Section 126 petition by six months to November 9, 2018. 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. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss.
Climate Change
There are a number of initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.
At the international level, the United Nations Framework Convention on Climate Change resulted in the Kyoto Protocol requiring participating countries, which does not include the U.S., to reduce GHGs commencing in 2008 and has been extended through 2020. The Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide GHG emissions by 26 to 28 percent below 2005 levels by 2025. In 2015, FirstEnergy set a goal of reducing company-wide CO 2 emissions by at least 90 percent below 2005 levels by 2045. As of December 31, 2018, FirstEnergy has reduced its CO 2 emissions by approximately 62 percent. In September 2016, the U.S. joined in adopting the agreement reached on December 12, 2015, at the United Nations Framework Convention on Climate Change meetings in Paris. The Paris Agreement’s non-binding obligations to limit global warming to below two degrees Celsius became effective on November 4, 2016. On June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the Paris Agreement. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO 2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations.
In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for GHG under the Clean Air Act” concluding that concentrations of several key GHGs constitutes an “endangerment” and may be regulated as “air pollutants” under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. The EPA released its final CPP regulations in August 2015 to reduce CO 2 emissions from existing fossil fuel-fired EGUs and finalized separate regulations imposing CO 2 emission limits for new, modified, and reconstructed fossil fuel fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. On February 9, 2016, the U.S.
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Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court. On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On October 16, 2017, the EPA issued a proposed rule to repeal the CPP. To replace the CPP, the EPA proposed the ACE rule on August 21, 2018, which would establish emission guidelines for states to develop plans to address GHG emissions from existing coal-fired power plants. On June 19, 2019, the EPA repealed the CPP and replaced it with the ACE rule that establishes guidelines for states to develop standards of performance to address GHG emissions from existing coal-fired power plants. Depending on the outcomes of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy’s facilities. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy’s operations.
The EPA finalized CWA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts of a cooling water intake system to a 12% annual average and requiring cooling water intake structures exceeding 125 million gallons per day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a facility’s cooling water system. Depending on any final action taken by the states with respect to impingement and entrainment, the future capital costs of compliance with these standards may be material.
On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations phase-in as permits are renewed on a five-year cycle from 2018 to 2023. 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 November 4, 2019, the EPA issued a proposed rule revising the effluent limits for discharges from wet scrubber systems and extending the deadline for compliance to December 31, 2025. The EPA’s proposed rule retains the zero discharge standard and 2023 compliance date for ash transport water, but adds some allowances for discharge under certain circumstances. 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. Depending on the outcome of appeals and how any final rules are ultimately implemented, the future costs of compliance with these standards may be substantial and changes to FirstEnergy’s operations may result.
On September 29, 2016, FirstEnergy received a request from the EPA for information pursuant to CWA Section 308(a) for information concerning boron exceedances of effluent limitations established in the NPDES Permit for the former Mitchell Power Station’s Mingo landfill, owned by WP. On November 1, 2016, WP provided an initial response that contained information related to a similar boron issue at the former Springdale Power Station’s landfill. The EPA requested additional information regarding the Springdale landfill and on November 15, 2016, WP provided a response and intends to fully comply with the Section 308(a) information request. On March 3, 2017, WP proposed to the PA DEP a re-route of its wastewater discharge to eliminate potential boron exceedances at the Springdale landfill. On January 29, 2018, WP submitted an NPDES permit renewal application to PA DEP proposing to re-route its wastewater discharge to eliminate potential boron exceedances at the Mingo landfill. On February 20, 2018, the DOJ issued a letter and tolling agreement on behalf of EPA alleging violations of the CWA at the Mingo landfill while seeking to enter settlement negotiations in lieu of filing a complaint. The EPA has proposed a penalty of $900,000 to settle alleged past boron exceedances at the Mingo and Springdale landfills. Negotiations are continuing and WP is unable to predict the outcome of this matter.
Regulation of Waste Disposal
Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act. Certain CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation.
In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 17, 2018, the EPA Administrator signed a final rule extending the deadline for certain CCR facilities to cease disposal and commence closure activities, as well as, establishing less stringent groundwater monitoring and protection requirements. On August 21, 2018, the D.C. Circuit remanded sections of the CCR Rule to the EPA to provide additional safeguards for unlined CCR impoundments that are more protective of human health and the environment. On December 2, 2019, the EPA published a proposed rule accelerating the date that certain CCR impoundments must cease accepting waste and initiate closure to August 31, 2020. The proposed rule, which includes a 60-day comment period, provides exceptions, which could allow extensions to closure dates.
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
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joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of March 31, 2020, 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 $109 million have been accrued through March 31, 2020. Included in the total are accrued liabilities of approximately $70 million for environmental remediation of former MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. FE or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time.
OTHER LEGAL PROCEEDINGS
Nuclear Plant Matters
Under NRC regulations, JCP&L, ME and PN must ensure that adequate funds will be available to decommission their retired nuclear facility, TMI-2. As of March 31, 2020, JCP&L, ME and PN had in total approximately $875 million invested in external trusts to be used for the decommissioning and environmental remediation of their retired TMI-2 nuclear generating facility. The values of these NDTs also fluctuate based on market conditions. If the values of the trusts decline by a material amount, the obligation to JCP&L, ME and PN to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDTs.
On October 15, 2019, JCP&L, ME, PN and GPUN executed an asset purchase and sale agreement with TMI-2 Solutions, LLC, a subsidiary of Energy Solutions, LLC, concerning the transfer and dismantlement of TMI-2. This transfer of TMI-2 to TMI-2 Solutions, LLC will include the transfer of: (i) the ownership and operating NRC licenses for TMI-2; (ii) the external trusts for the decommissioning and environmental remediation of TMI-2; and (iii) related liabilities of approximately $900 million as of December 31, 2019. There can be no assurance that the transfer will receive the required regulatory approvals and, even if approved, whether the conditions to the closing of the transfer will be satisfied. On November 12, 2019, JCP&L filed a Petition with the NJBPU seeking approval of the transfer and sale of JCP&L’s entire 25% interest in TMI-2 to TMI-2 Solutions, LLC. Also on November 12, 2019, JCP&L, ME, PN, GPUN and TMI-2 Solutions, LLC filed an application with the NRC seeking approval to transfer the NRC license for TMI-2 to TMI-2 Solutions, LLC. Both proceedings are ongoing. Assets and liabilities held for sale on the FirstEnergy Consolidated Balance Sheet associated with the transaction consist of asset retirement obligations of $700 million, NDTs of $875 million as well as property, plant and equipment with a net book value of zero, which are included in the regulated distribution segment.
FES Bankruptcy
On March 31, 2018, FES, including its consolidated subsidiaries, FG, NG, FE Aircraft Leasing Corp., Norton Energy Storage L.L.C. and FGMUC, and FENOC filed voluntary petitions for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court and emerged on February 27, 2020. See Note 3, “Discontinued Operations,” for additional discussion.
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 9, “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.
11. SEGMENT INFORMATION
FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity through its reportable segments, Regulated Distribution and Regulated Transmission.
The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. The segment’s results reflect the costs of securing and delivering electric generation from transmission facilities to customers, including the deferral and amortization of certain related costs. Included within the segment are $875 million and $882 million of assets classified as held for sale as of March 31, 2020 and December 31, 2019, respectively, associated with the asset purchase and sale agreement with TMI-2 Solutions to transfer TMI-2 to TMI-2 Solutions, LLC. See Note 10, "Commitments, Guarantees and Contingencies" for additional information.
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The Regulated Transmission segment provides transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy’s utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment’s revenues are primarily derived from forward-looking formula rates at the Transmission Companies as well as stated transmission rates at JCP&L, MP, PE and WP. Effective January 1, 2020, JPC&L's transmission rates became forward-looking formula rates, subject to refund, pending further hearing and settlement proceedings. Both the forward-looking formula and stated rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. The segment’s results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy’s transmission facilities.
Corporate/Other reflects corporate support costs not charged to FE’s subsidiaries, including FE’s retained Pension and OPEB assets and liabilities of the FES Debtors, interest expense on FE’s holding company debt and other businesses that do not constitute an operating segment. Reconciling adjustments for the elimination of inter-segment transactions and discontinued operations are shown separately in the following table of Segment Financial Information. As of March 31, 2020, 67 MWs of electric generating capacity, representing AE Supply’s OVEC capacity entitlement, was included in continuing operations of Corporate/Other. As of March 31, 2020, Corporate/Other had approximately $7.9 billion FE holding company debt.
Financial information for each of FirstEnergy’s reportable segments is presented in the tables below:
Segment Financial Information

For the Three Months Ended |  | Regulated Distribution |  | Regulated Transmission |  | Corporate/ Other |  | Reconciling Adjustments |  | FirstEnergy Consolidated
|  | (In millions)
March 31, 2020 |  |  |  |  |  |  |  |  |  |
External revenues |  | $ | 2,311 |  |  | $ | 397 |  |  | $ | 1 |  |  | $ | — |  |  | $ | 2,709 |
Internal revenues |  | 47 |  |  | 4 |  |  | — |  |  | (51 | ) |  | — |
Total revenues |  | $ | 2,358 |  |  | $ | 401 |  |  | $ | 1 |  |  | $ | (51 | ) |  | $ | 2,709 |
Depreciation |  | 223 |  |  | 76 |  |  | 2 |  |  | 16 |  |  | 317 |
Amortization of regulatory assets, net |  | 49 |  |  | 3 |  |  | — |  |  | — |  |  | 52 |
Miscellaneous income (expense), net |  | 75 |  |  | 6 |  |  | 25 |  |  | (6 | ) |  | 100 |
Interest expense |  | 127 |  |  | 52 |  |  | 90 |  |  | (6 | ) |  | 263 |
Income taxes (benefits) |  | (32 | ) |  | 34 |  |  | (62 | ) |  | — |  |  | (60 | )
Income (loss) from continuing operations |  | 136 |  |  | 117 |  |  | (229 | ) |  | — |  |  | 24 |
Property additions |  | $ | 338 |  |  | $ | 269 |  |  | $ | 9 |  |  | $ | — |  |  | $ | 616 |
March 31, 2019 |  |  |  |  |  |  |  |  |  |
External revenues |  | $ | 2,526 |  |  | $ | 352 |  |  | $ | 5 |  |  | $ | — |  |  | $ | 2,883 |
Internal revenues |  | 47 |  |  | 4 |  |  | — |  |  | (51 | ) |  | — |
Total revenues |  | $ | 2,573 |  |  | $ | 356 |  |  | $ | 5 |  |  | $ | (51 | ) |  | $ | 2,883 |
Depreciation |  | 209 |  |  | 69 |  |  | 2 |  |  | 17 |  |  | 297 |
Amortization of regulatory assets, net |  | 3 |  |  | 2 |  |  | — |  |  | — |  |  | 5 |
Miscellaneous income (expense), net |  | 46 |  |  | 4 |  |  | 11 |  |  | (7 | ) |  | 54 |
Interest expense |  | 122 |  |  | 45 |  |  | 93 |  |  | (7 | ) |  | 253 |
Income taxes (benefits) |  | 89 |  |  | 31 |  |  | (27 | ) |  | — |  |  | 93 |
Income (loss) from continuing operations |  | 329 |  |  | 104 |  |  | (78 | ) |  | — |  |  | 355 |
Property additions |  | $ | 318 |  |  | $ | 231 |  |  | $ | 5 |  |  | $ | — |  |  | $ | 554 |
As of March 31, 2020 |  |  |  |  |  |  |  |  |  |
Total assets |  | $ | 29,642 |  |  | $ | 11,753 |  |  | $ | 695 |  |  | $ | — |  |  | $ | 42,090 |
Total goodwill |  | $ | 5,004 |  |  | $ | 614 |  |  | $ | — |  |  | $ | — |  |  | $ | 5,618 |
As of December 31, 2019 |  |  |  |  |  |  |  |  |  |
Total assets |  | $ | 29,642 |  |  | $ | 11,611 |  |  | $ | 1,015 |  |  | $ | 33 |  |  | $ | 42,301 |
Total goodwill |  | $ | 5,004 |  |  | $ | 614 |  |  | $ | — |  |  | $ | — |  |  | $ | 5,618 |

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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FIRSTENERGY’S BUSINESS
FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity through its reportable segments, Regulated Distribution and Regulated Transmission.
The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. The segment’s results reflect the costs of securing and delivering electric generation from transmission facilities to customers, including the deferral and amortization of certain related costs.
The Regulated Transmission segment provides transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy’s utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment’s revenues are primarily derived from forward-looking formula rates at the Transmission Companies as well as stated transmission rates at JCP&L, MP, PE and WP. Effective January 1, 2020, JPC&L's transmission rates became forward-looking formula rates, subject to refund, pending further hearing and settlement proceedings. Both the forward-looking formula and stated rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. The segment’s results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy’s transmission facilities.
Corporate/Other reflects corporate support costs not charged to FE’s subsidiaries, including FE’s retained Pension and OPEB assets and liabilities of the FES Debtors, interest expense on FE’s holding company debt and other businesses that do not constitute an operating segment. Additionally, reconciling adjustments for the elimination of inter-segment transactions and discontinued operations are included in Corporate/Other. As of March 31, 2020, 67 MWs of electric generating capacity, representing AE Supply’s OVEC capacity entitlement, was included in continuing operations of Corporate/Other. As of March 31, 2020, Corporate/Other had approximately $7.9 billion of FE holding company debt.
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EXECUTIVE SUMMARY
FirstEnergy is a forward-thinking fully regulated electric utility focused on stable and predictable earnings and cash flow from its regulated business units - Regulated Distribution and Regulated Transmission - through delivering enhanced customer service and reliability that supports FE's dividend.
The outbreak of COVID-19 has become a global pandemic. FirstEnergy is taking steps to mitigate known risks and is continuously evaluating the rapidly evolving situation based on guidance from governmental officials and public health experts. The full impact on FirstEnergy’s business from the pandemic, including the governmental and regulatory responses, is unknown at this time and difficult to predict. FirstEnergy provides a critical and essential service to its customers and the health and safety of FirstEnergy’s employees and customers is its first priority. FirstEnergy is effectively managing its operations, while still providing flexibility for approximately 7,000 of its 12,000 employees to work from home.
Beginning March 13, 2020, FirstEnergy discontinued power shutoff’s to customers, and has the ability to recover incremental uncollectible expenses through riders in OH and NJ. FirstEnergy is continuously monitoring its supply chain and is working closely with essential vendors to understand the impact of COVID-19 to its business and does not currently expect service disruptions or any material impact to its capital spending plan. FirstEnergy’s Distribution and Transmission revenues benefit from geographic and economic diversity across a five-state service territory. Two-thirds of base distribution revenues come from the residential customer class, along with a decoupled rate structure in Ohio, which accounts for approximately 20% of total retail load. FirstEnergy’s commercial and industrial revenues are primarily fixed and demand-based, rather than volume-based. As a result of this, FirstEnergy’s Distribution and Transmission investments provide stable and predictable earnings. However, due to the actions taken by state governments in our service territories limiting certain commercial and industrial activities, current expectations are that retail load may increase in the near term, while commercial and industrial loads may decline, however, the magnitude of these changes are currently unknown and difficult to predict. Related to FirstEnergy’s pension investments, the asset allocation is conservative, with no required contributions until 2022 and the funded status at March 31, 2020, is essentially unchanged from the end of 2019 at 79%. FirstEnergy believes it is well positioned to manage the economic slowdown resulting from the pandemic. However, the situation remains fluid and future impacts to FirstEnergy, that are presently unknown or unanticipated, may occur.
In 2020, FirstEnergy continues to execute its regulated growth plans, through the following achievements and plans:

• | Implemented forward-looking rates, subject to refund, at JCP&L effective January 1, 2020,

• | OH Decoupling rider went into effect on February 1, 2020,

• | JCP&L submitted a filing with the NJBPU on February 18, 2020, requesting a distribution base rate increase of $186.9 million on an annual basis,

• | PAPUC-approved Penn DSIC waiver on March 12, 2020,

• | Completed final step of FirstEnergy’s strategy to exit the competitive generation business with FES Debtors’ emergence on February 27, 2020, and

• | IRP filing in West Virginia to be made by December 30, 2020.

With an operating territory of 65,000 square miles, the scale and diversity of the ten Utilities that comprise the Regulated Distribution business uniquely position this business for growth through opportunities for additional investment. Over the past several years, Regulated Distribution has experienced rate base growth through investments that have improved reliability and added operating flexibility to the distribution infrastructure, which provide benefits to the customers and communities those Utilities serve. Based on its current capital plan, which includes over $10 billion in forecasted capital investments from 2018 through 2023, Regulated Distribution’s rate base compounded annual growth rate is expected to be approximately 4% from 2018 through 2023. Additionally, this business is exploring other opportunities for growth, including investments in electric system improvement and modernization projects to increase reliability and improve service to customers, as well as exploring opportunities in customer engagement that focus on the electrification of customers’ homes and businesses by providing a full range of products and services.
With approximately 24,500 miles of transmission lines in operation, the Regulated Transmission business is the centerpiece of FirstEnergy’s regulated investment strategy with nearly 90% of its capital investments recovered under forward-looking formula rates at the Transmission Companies, and beginning in 2020, JCP&L. Regulated Transmission has also experienced significant growth as part of its Energizing the Future transmission plan with plans to invest over $7 billion in capital from 2018 to 2023, which is expected to result in Regulated Transmission rate base compounded annual growth rate of approximately 10% from 2018 through 2023.
FirstEnergy believes there are incremental investment opportunities for its existing transmission infrastructure of over $20 billion beyond those identified through 2023, 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.
In November 2018, the Board of Directors approved a dividend policy that includes a targeted payout ratio. As a first step, the Board declared a $0.02 increase to the common dividend payable March 1, 2019, to $0.38 per share, which represents an increase of 6% compared to the quarterly dividend of $0.36 per share that had been paid since 2014. In November 2019, the Board declared a $0.01 increase to the common dividend payable March 1, 2020, to $0.39 per share, which represents a 3% increase. Modest dividend growth enables enhanced shareholder returns, while still allowing for continued substantial regulated investments. Dividend
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payments are subject to declaration by the Board and future dividend decisions determined by the Board may be impacted by earnings growth, cash flows, credit metrics and other business conditions.
FirstEnergy is progressing in its sustainability efforts. In 2019, FirstEnergy's Sustainability group focused on the continued realization of sustainability accomplishments. In November 2019, FirstEnergy's Corporate Responsibility Report was published. The report addresses FirstEnergy's work to reduce the environmental impact of our operations, including progress on our CO 2 reduction goal, as we continue to build, strengthen and modernize our transmission and distribution system. The report also describes FirstEnergy's high standards for corporate governance and our work to improve lives in our communities, while providing safe, reliable electric service to our customers. In 2020, FirstEnergy is focusing on additional initiatives that aim to inform, engage and achieve its sustainability goals, and demonstrate its commitment to stakeholders.
The $2.5 billion equity issuance in 2018 strengthened FirstEnergy’s balance sheet, supported the company’s transition to a fully regulated utility company and positions FirstEnergy for sustained investment-grade credit metrics. The shares of preferred stock participated in the dividend paid on common stock on an as-converted basis and were non-voting except in certain limited circumstances. Because of this investment, FirstEnergy does not currently anticipate the need to issue additional equity through 2021 and expects to issue, subject to, among other things, market conditions, pricing terms and business operations, up to $600 million of equity annually in 2022 and 2023, including approximately $100 million in equity for its regular stock investment and employee benefit plans.
On March 31, 2018, the FES Debtors announced that, in order to facilitate an orderly financial restructuring, they filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code with the Bankruptcy Court (which is referred to throughout as the FES Bankruptcy). In September 2018, the Bankruptcy Court approved a FES Bankruptcy settlement agreement by and among FirstEnergy, two groups of key FES creditors (collectively, the FES Key Creditor Groups), the FES Debtors and the UCC. The FES Bankruptcy settlement agreement resolved certain claims by FirstEnergy against the FES Debtors, all claims by the FES Debtors and the FES Key Creditor Groups against FirstEnergy, as well as releases from third parties who voted in favor the FES Debtors' plan of reorganization, in return for among other things, a cash payment of $853 million upon emergence. The FES Bankruptcy settlement was conditioned on the FES Debtors confirming and effectuating a plan of reorganization acceptable to FirstEnergy.
On February 18, 2020, the FES Debtors and FirstEnergy entered into an IT Access Agreement that provided IT support to enable the Debtors to emerge from bankruptcy prior to full IT separation by the FES Debtors. As part of the IT Access Agreement, the FES Debtors and FirstEnergy resolved, among other things, the on-going reconciliation of outstanding tax sharing payments for tax years 2018, 2019 and 2020 for a total of $125 million. On February 25, 2020, the Bankruptcy Court approved the IT Access Agreement. On February 27, 2020, the FES Debtors effectuated their plan, emerged from bankruptcy and FirstEnergy tendered the settlement payments totaling $853 million and the $125 million tax sharing payment to the FES Debtors, with no material impact to net income in the first quarter of 2020.
As contemplated under the FES Bankruptcy settlement agreement, AE Supply entered into an agreement on December 31, 2018, to transfer the 1,300 MW Pleasants Power Station and related assets to FG, while retaining certain specified liabilities. Under the terms of the agreement, FG acquired the economic interests in Pleasants as of January 1, 2019, and AE Supply operated Pleasants until ownership was transferred on January 30, 2020. AE Supply will continue to provide access to the McElroy's Run CCR Impoundment Facility, which was not transferred, and FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility.
The emergence of the FES Debtors from bankruptcy represents the final step in FirstEnergy’s previously announced strategy to exit the competitive generation business and become a fully regulated utility company with a stronger balance sheet, solid cash flows and more predictable earnings.
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FINANCIAL OVERVIEW AND RESULTS OF OPERATIONS

(In millions) |  | For the Three Months Ended March 31,
|  | 2020 |  | 2019 |  | Change
Revenues |  | $ | 2,709 |  |  | $ | 2,883 |  |  | $ | (174 | ) |  | (6 | )%
Operating expenses |  | 2,177 |  |  | 2,254 |  |  | (77 | ) |  | (3 | )%
Operating income |  | 532 |  |  | 629 |  |  | (97 | ) |  | (15 | )%
Other expenses, net |  | (568 | ) |  | (181 | ) |  | (387 | ) |  | (214 | )%
Income before income taxes |  | (36 | ) |  | 448 |  |  | (484 | ) |  | (108 | )%
Income taxes |  | (60 | ) |  | 93 |  |  | (153 | ) |  | (165 | )%
Income from continuing operations |  | 24 |  |  | 355 |  |  | (331 | ) |  | (93 | )%
Discontinued operations, net of tax |  | 50 |  |  | (35 | ) |  | 85 |  |  | NM |
Net income |  | $ | 74 |  |  | $ | 320 |  |  | $ | (246 | ) |  | (77 | )%

* NM = not meaningful
The financial results discussed below include revenues and expenses from transactions among FirstEnergy’s business segments. A reconciliation of segment financial results is provided in Note 11, “Segment Information,” of the Notes to Consolidated Financial Statements.
Certain prior year amounts have been reclassified to conform to the current year presentation.
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Summary of Results of Operations — First Quarter 2020 Compared with First Quarter 2019
Financial results for FirstEnergy’s business segments in the first quarter of 2020 and 2019 were as follows:

First Quarter 2020 Financial Results |  | Regulated Distribution |  | Regulated Transmission |  | Corporate/Other and Reconciling Adjustments |  | FirstEnergy Consolidated
|  | (In millions)
Revenues: |  |  |  |  |  |  |  |  |  |  |
Electric |  | $ | 2,299 |  |  | $ | 397 |  |  | $ | (35 | ) |  | $ | 2,661 |
Other |  | 59 |  |  | 4 |  |  | (15 | ) |  | 48 |
Total Revenues |  | 2,358 |  |  | 401 |  |  | (50 | ) |  | 2,709 |
Operating Expenses: |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  | 98 |  |  | — |  |  | — |  |  | 98 |
Purchased power |  | 690 |  |  | — |  |  | 4 |  |  | 694 |
Other operating expenses |  | 699 |  |  | 53 |  |  | (3 | ) |  | 749 |
Provision for depreciation |  | 223 |  |  | 76 |  |  | 18 |  |  | 317 |
Amortization of regulatory assets, net |  | 49 |  |  | 3 |  |  | — |  |  | 52 |
General taxes |  | 195 |  |  | 62 |  |  | 10 |  |  | 267 |
Total Operating Expenses |  | 1,954 |  |  | 194 |  |  | 29 |  |  | 2,177 |
Operating Income (Loss) |  | 404 |  |  | 207 |  |  | (79 | ) |  | 532 |
Other Income (Expense): |  |  |  |  |  |  |  |  |  |  |  |
Miscellaneous income, net |  | 75 |  |  | 6 |  |  | 19 |  |  | 100 |
Pension and OPEB mark-to-market adjustment |  | (257 | ) |  | (19 | ) |  | (147 | ) |  | (423 | )
Interest expense |  | (127 | ) |  | (52 | ) |  | (84 | ) |  | (263 | )
Capitalized financing costs |  | 9 |  |  | 9 |  |  | — |  |  | 18 |
Total Other Expense |  | (300 | ) |  | (56 | ) |  | (212 | ) |  | (568 | )
Income (Loss) Before Income Taxes (Benefits) |  | 104 |  |  | 151 |  |  | (291 | ) |  | (36 | )
Income taxes (benefits) |  | (32 | ) |  | 34 |  |  | (62 | ) |  | (60 | )
Income (Loss) From Continuing Operations |  | 136 |  |  | 117 |  |  | (229 | ) |  | 24 |
Discontinued operations, net of tax |  | — |  |  | — |  |  | 50 |  |  | 50 |
Net Income (Loss) |  | $ | 136 |  |  | $ | 117 |  |  | $ | (179 | ) |  | $ | 74 |

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First Quarter 2019 Financial Results |  | Regulated Distribution |  | Regulated Transmission |  | Corporate/Other and Reconciling Adjustments |  | FirstEnergy Consolidated
|  | (In millions)
Revenues: |  |  |  |  |  |  |  |  |  |  |
Electric |  | $ | 2,512 |  |  | $ | 352 |  |  | $ | (31 | ) |  | $ | 2,833 |
Other |  | 61 |  |  | 4 |  |  | (15 | ) |  | 50 |
Total Revenues |  | 2,573 |  |  | 356 |  |  | (46 | ) |  | 2,883 |
Operating Expenses: |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  | 131 |  |  | — |  |  | — |  |  | 131 |
Purchased power |  | 777 |  |  | — |  |  | 4 |  |  | 781 |
Other operating expenses |  | 771 |  |  | 66 |  |  | (58 | ) |  | 779 |
Provision for depreciation |  | 209 |  |  | 69 |  |  | 19 |  |  | 297 |
Amortization of regulatory assets, net |  | 3 |  |  | 2 |  |  | — |  |  | 5 |
General taxes |  | 198 |  |  | 51 |  |  | 12 |  |  | 261 |
Total Operating Expenses |  | 2,089 |  |  | 188 |  |  | (23 | ) |  | 2,254 |
Operating Income (Loss) |  | 484 |  |  | 168 |  |  | (23 | ) |  | 629 |
Other Income (Expense): |  |  |  |  |  |  |  |  |  |  |  |
Miscellaneous income, net |  | 46 |  |  | 4 |  |  | 4 |  |  | 54 |
Pension and OPEB mark-to-market adjustment |  | — |  |  | — |  |  | — |  |  | — |
Interest expense |  | (122 | ) |  | (45 | ) |  | (86 | ) |  | (253 | )
Capitalized financing costs |  | 10 |  |  | 8 |  |  | — |  |  | 18 |
Total Other Expense |  | (66 | ) |  | (33 | ) |  | (82 | ) |  | (181 | )
Income (Loss) Before Income Taxes (Benefits) |  | 418 |  |  | 135 |  |  | (105 | ) |  | 448 |
Income taxes (benefits) |  | 89 |  |  | 31 |  |  | (27 | ) |  | 93 |
Income (Loss) From Continuing Operations |  | 329 |  |  | 104 |  |  | (78 | ) |  | 355 |
Discontinued operations, net of tax |  | — |  |  | — |  |  | (35 | ) |  | (35 | )
Net Income (Loss) |  | $ | 329 |  |  | $ | 104 |  |  | $ | (113 | ) |  | $ | 320 |

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Changes Between First Quarter 2020 and First Quarter 2019 Financial Results |  | Regulated Distribution |  | Regulated Transmission |  | Corporate/Other and Reconciling Adjustments |  | FirstEnergy Consolidated
|  | (In millions)
Revenues: |  |  |  |  |  |  |  |  |  |  |
Electric |  | $ | (213 | ) |  | $ | 45 |  |  | $ | (4 | ) |  | $ | (172 | )
Other |  | (2 | ) |  | — |  |  | — |  |  | (2 | )
Total Revenues |  | (215 | ) |  | 45 |  |  | (4 | ) |  | (174 | )
Operating Expenses: |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  | (33 | ) |  | — |  |  | — |  |  | (33 | )
Purchased power |  | (87 | ) |  | — |  |  | — |  |  | (87 | )
Other operating expenses |  | (72 | ) |  | (13 | ) |  | 55 |  |  | (30 | )
Provision for depreciation |  | 14 |  |  | 7 |  |  | (1 | ) |  | 20 |
Amortization of regulatory assets, net |  | 46 |  |  | 1 |  |  | — |  |  | 47 |
General taxes |  | (3 | ) |  | 11 |  |  | (2 | ) |  | 6 |
Total Operating Expenses |  | (135 | ) |  | 6 |  |  | 52 |  |  | (77 | )
Operating Income (Loss) |  | (80 | ) |  | 39 |  |  | (56 | ) |  | (97 | )
Other Income (Expense): |  |  |  |  |  |  |  |  |  |  |  |
Miscellaneous income, net |  | 29 |  |  | 2 |  |  | 15 |  |  | 46 |
Pension and OPEB mark-to-market adjustment |  | (257 | ) |  | (19 | ) |  | (147 | ) |  | (423 | )
Interest expense |  | (5 | ) |  | (7 | ) |  | 2 |  |  | (10 | )
Capitalized financing costs |  | (1 | ) |  | 1 |  |  | — |  |  | — |
Total Other Expense |  | (234 | ) |  | (23 | ) |  | (130 | ) |  | (387 | )
Income (Loss) Before Income Taxes (Benefits) |  | (314 | ) |  | 16 |  |  | (186 | ) |  | (484 | )
Income taxes (benefits) |  | (121 | ) |  | 3 |  |  | (35 | ) |  | (153 | )
Income (Loss) From Continuing Operations |  | (193 | ) |  | 13 |  |  | (151 | ) |  | (331 | )
Discontinued operations, net of tax |  | — |  |  | — |  |  | 85 |  |  | 85 |
Net Income (Loss) |  | $ | (193 | ) |  | $ | 13 |  |  | $ | (66 | ) |  | $ | (246 | )

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Regulated Distribution — First Quarter 2020 Compared with First Quarter 2019
Regulated Distribution’s net income decreased $193 million in the first quarter of 2020, as compared to the same period of 2019, primarily resulting from the pension and OPEB mark-to-market adjustment in 2020, lower weather-related customer usage, and the absence of Rider DMR revenues that ended in July 2019, partially offset by lower pension and OPEB non-service expenses and the implementation of decoupling rates in Ohio.
Revenues —
The $215 million decrease in total revenues resulted from the following sources:

|  | For the Three Months Ended March 31, |  |
Revenues by Type of Service |  | 2020 |  | 2019 |  | (Decrease)
|  | (In millions)
Distribution(1) |  | $ | 1,324 |  |  | $ | 1,348 |  |  | $ | (24 | )
Generation sales: |  |  |  |  |  |
Retail |  | 904 |  |  | 1,058 |  |  | (154 | )
Wholesale |  | 71 |  |  | 106 |  |  | (35 | )
Total generation sales |  | 975 |  |  | 1,164 |  |  | (189 | )
Other |  | 59 |  |  | 61 |  |  | (2 | )
Total Revenues |  | $ | 2,358 |  |  | $ | 2,573 |  |  | $ | (215 | )

(1) Includes $68 million and $62 million of ARP revenues for the three months ended March 31, 2020 and 2019, respectively.
Distribution revenues decreased $24 million in the first quarter of 2020, as compared to the same period of 2019, primarily resulting from lower weather-related customer usage and the absence of Rider DMR revenues that ended in July 2019, partially offset by the implementation of Ohio decoupling rates in 2020 and New Jersey Zero Emission Program in June 2019, and higher rates associated with recovery of distribution capital investment programs. Distribution deliveries by customer class are summarized in the following table:

|  | For the Three Months Ended March 31,
(In thousands) |  | Including Ohio Decoupled MWH |  | Excluding Ohio Decoupled MWH
Electric Distribution MWH |  | 2020 |  | 2019 |  | (Decrease) |  | 2020 |  | 2019 |  | (Decrease)
Residential |  | 13,204 |  |  | 15,103 |  |  | (12.6 | )% |  | 8,996 |  |  | 10,404 |  |  | (13.5 | )%
Commercial |  | 8,766 |  |  | 9,478 |  |  | (7.5 | )% |  | 5,396 |  |  | 5,886 |  |  | (8.3 | )%
Industrial |  | 13,548 |  |  | 13,960 |  |  | (3.0 | )% |  | 13,548 |  |  | 13,960 |  |  | (3.0 | )%
Other |  | 135 |  |  | 140 |  |  | (3.6 | )% |  | 135 |  |  | 140 |  |  | (3.6 | )%
Total Electric Distribution MWH |  | 35,653 |  |  | 38,681 |  |  | (7.8 | )% |  | 28,075 |  |  | 30,390 |  |  | (7.6 | )%

Lower distribution deliveries to residential and commercial customers primarily reflect lower weather-related usage resulting from heating degree days that were 18% below 2019 and 18% below normal. Deliveries to industrial customers reflect lower steel, mining, and automotive customer usage, partially offset by higher shale customer usage.
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The following table summarizes the price and volume factors contributing to the $189 million decrease in generation revenues for the first quarter of 2020, as compared to the same period of 2019:

Source of Change in Generation Revenues |  | (Decrease)
|  | (In millions)
Retail: |  |  |
Change in sales volumes |  | $ | (133 | )
Change in prices |  | (21 | )
|  | (154 | )
Wholesale: |  |
Change in sales volumes |  | (6 | )
Change in prices |  | (8 | )
Capacity revenue |  | (21 | )
|  | (35 | )
Decrease in Generation Revenues |  | $ | (189 | )

The decrease in retail generation sales volumes was primarily due to lower weather-related usage and increased customer shopping in New Jersey and Pennsylvania. Total generation provided by alternative suppliers as a percentage of total MWH deliveries increased to 51% from 47% in New Jersey and to 66% from 63% in Pennsylvania. The decrease in retail generation prices primarily resulted from lower non-shopping generation auction rates in New Jersey and Pennsylvania.
Wholesale generation revenues decreased $35 million in the first quarter of 2020, as compared to the same period in 2019, primarily due to lower spot market prices and capacity revenues. 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 $135 million in the first quarter of 2020, as compared to the same period of 2019, primarily due to the following:

• | Fuel expense decreased $33 million in the first quarter of 2020, as compared to the same period of 2019, primarily due to lower unit costs and lower generation output.

• | Purchased power costs were $87 million lower in the first quarter of 2020, as compared to the same period in 2019, primarily due to decreased volumes as described above and lower capacity expense, partially offset by the implementation of the NJ Zero Emission Program in June 2019.

| Source of Change in Purchased Power |  | Increase (Decrease)
|  |  | (In millions)
| Purchases |  |
| Change due to unit costs |  | 9 |
| Change due to volumes |  | (70 | )
|  |  | (61 | )
| Capacity expense |  | (26 | )
| Decrease in Purchased Power Costs |  | $ | (87 | )

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• | Other operating expenses decreased $72 million in the first quarter of 2020, as compared to the same period of 2019, primarily due to the following:

• | Decreased storm restoration costs of $100 million, which were mostly deferred for future recovery, resulting in no material impact on current period earnings.

• | Higher network transmission expenses of $10 million. These costs are deferred for future recovery, resulting in no material impact on current period earnings.

• | Higher operating and maintenance expense of $13 million, primarily associated with higher labor, employee benefit costs and contractor and maintenance spend, partially offset by lower corporate support costs.

• | Higher pension and OPEB service costs of $5 million.

• | Depreciation expense increased $14 million in the first quarter of 2020, as compared to the same period of 2019, primarily due to a higher asset base.

• | Amortization expense increased $46 million in the first quarter of 2020, as compared to the same period of 2019, primarily due to lower storm restoration cost deferrals, partially offset by higher generation and transmission deferrals.

Other Expenses —
Other Expense increased $234 million in the first quarter of 2020, as compared to the same period of 2019, primarily due to the $257 million pension and OPEB mark-to-market adjustment in 2020, higher interest expense from debt issuances primarily at WP and MP, partially offset by higher net miscellaneous income primarily resulting from lower pension and OPEB non-service costs.
Income Taxes —
Regulated Distribution’s effective tax rate was (30.8)% and 21.3% for the three months ended March 31, 2020 and 2019, respectively. The change in the effective tax rate was primarily due to the recognition of $52 million in deferred gains relating to prior intercompany transfers of generation assets that were triggered by the deconsolidation of the FES Debtors from FirstEnergy’s consolidated federal income tax group as a result of their emergence from bankruptcy in the first quarter or 2020.
Regulated Transmission — First Quarter 2020 Compared with First Quarter 2019
Regulated Transmission’s net income increased $13 million in the first quarter of 2020, as compared to the same period of 2019, primarily due to the impact of a higher rate base at ATSI and MAIT.
Revenues —
Total revenues increased $45 million in the first quarter of 2020, as compared to the same period of 2019, primarily due to recovery of incremental operating expenses and a higher rate base at ATSI and MAIT.
The following table shows revenues by transmission asset owner:

|  | For the Three Months Ended March 31, |  |
Revenues by Transmission Asset Owner |  | 2020 |  | 2019 |  | Increase
|  | (In millions)
ATSI |  | $ | 205 |  |  | $ | 175 |  |  | $ | 30 |
TrAIL |  | 65 |  |  | 60 |  |  | 5 |
MAIT |  | 58 |  |  | 50 |  |  | 8 |
Other |  | 73 |  |  | 71 |  |  | 2 |
Total Revenues |  | $ | 401 |  |  | $ | 356 |  |  | $ | 45 |

Operating Expenses —
Total operating expenses increased $6 million in the first quarter of 2020, as compared to the same period of 2019, primarily due to higher property taxes and depreciation due to a higher asset base, partially offset by lower operating and maintenance expenses. The majority of operating expenses are recovered through formula rates, resulting in no material impact on current period earnings.
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Other Expense —
Total other expense increased $23 million in the first quarter of 2020, as compared to the same period of 2019, primarily due to the $19 million pension and OPEB mark-to-market adjustment in 2020 and higher interest expense associated with new debt issuances at ATSI and FET.
Income Taxes —
Regulated Transmission’s effective tax rate was 22.5% and 23.0% for the three months ended March 31, 2020 and 2019, respectively.
Corporate / Other — First Quarter 2020 Compared with First Quarter 2019
Financial results at Corporate/Other resulted in a $151 million increase in loss from continuing operations in the first quarter of 2020, as compared to the same period of 2019, primarily due to the $147 million pension and OPEB mark-to-market adjustment in 2020.
For the three months ended March 31, 2020, FirstEnergy recorded income from discontinued operations, net of tax, of $50 million compared to a loss, net of tax, of $35 million for the three months ended March 31, 2019. The change in discontinued operations, net of tax was primarily due to lower settlement-related expenses, accelerated net pension and OPEB prior service credits, as well as adjustments to the estimated worthless stock deduction and Intercompany Tax Allocation Agreement with the FES Debtors.
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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 Transmission Companies net their regulatory assets and liabilities based on federal and state jurisdictions.
Management assesses the probability of recovery of regulatory assets at each balance sheet date and whenever new events occur. Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. Management applies judgment in evaluating the evidence available to assess the probability of recovery of regulatory assets from customers, including, but not limited to evaluating evidence related to precedent for similar items at the Company and information on comparable companies within similar jurisdictions, as well as assessing progress of communications between the Company and regulators. Certain of these regulatory assets, totaling approximately $112 million and $111 million as of March 31, 2020 and December 31, 2019, respectively, are recorded based on prior precedent or anticipated recovery based on rate making premises without a specific order.
The following table provides information about the composition of net regulatory assets and liabilities as of March 31, 2020, and December 31, 2019, and the changes during the three months ended March 31, 2020:

Net Regulatory Assets (Liabilities) by Source |  | March 31, 2020 |  | December 31, 2019 |  | Change
|  | (In millions)
Regulatory transition costs |  | $ | (10 | ) |  | $ | (8 | ) |  | $ | (2 | )
Customer payables for future income taxes |  | (2,558 | ) |  | (2,605 | ) |  | 47 |
Nuclear decommissioning and spent fuel disposal costs |  | (189 | ) |  | (197 | ) |  | 8 |
Asset removal costs |  | (740 | ) |  | (756 | ) |  | 16 |
Deferred transmission costs |  | 298 |  |  | 298 |  |  | — |
Deferred generation costs |  | 195 |  |  | 214 |  |  | (19 | )
Deferred distribution costs |  | 208 |  |  | 155 |  |  | 53 |
Contract valuations |  | 43 |  |  | 51 |  |  | (8 | )
Storm-related costs |  | 537 |  |  | 551 |  |  | (14 | )
Other |  | 41 |  |  | 36 |  |  | 5 |
Net Regulatory Liabilities included on the Consolidated Balance Sheets |  | $ | (2,175 | ) |  | $ | (2,261 | ) |  | $ | 86 |

The following is a description of the regulatory assets and liabilities described above:
Regulatory transition costs - Includes the recovery of PN above-market NUG costs; JCP&L costs incurred during the transition to a competitive retail market and under-recovered during the period from August 1, 1999 through July 31, 2003; and JCP&L costs associated with BGS, capacity and ancillary services, net of revenues from the sale of the committed supply in the wholesale market. Amounts are amortized through 2021.
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 tax rate changes such as tax reform. 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.
Nuclear decommissioning and spent fuel disposal costs - Reflects a regulatory liability representing amounts collected from customers and placed in external trusts including income, losses and changes in fair value thereon (as well as accretion of the related ARO) primarily for the future decommissioning of TMI-2.
Asset 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 ARO has been recognized, that are expected to be incurred at the time of retirement.
Deferred transmission costs - Primarily represents differences between revenues earned based on actual costs for the formula-rate Transmission Companies and the amounts billed. Amounts are recorded as a regulatory asset or liability and recovered or refunded, respectively, in subsequent periods.
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Deferred generation costs - Primarily relates to regulatory assets associated with the securitized recovery of certain electric customer heating discounts, 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. The ENEC rate is updated annually.
Deferred distribution costs - Primarily relates to the Ohio Companies’ deferral of certain expenses resulting from distribution and reliability related expenditures, including interest (amortized through 2036), as well as the Ohio Companies’ deferrals related to the decoupling mechanism which are recorded as a regulatory asset or liability and recovered or refunded, respectively, in subsequent periods.
Contract valuations - Includes the changes in fair value of PN above-market NUG costs and the amortization of purchase accounting adjustments at PE which were recorded in connection with the AE merger representing the fair value of NUG purchased power contracts (amortized over the life of the contracts with various end dates from 2027 through 2036).
Storm-related costs - Relates to the recovery of storm costs, which vary by jurisdiction. Approximately $164 million and $193 million are currently being recovered through rates as of March 31, 2020 and December 31, 2019, respectively.
The following table provides information about the composition of net regulatory assets that do not earn a current return as of March 31, 2020 and December 31, 2019, of which approximately $202 million and $228 million, respectively, are currently being recovered through rates over varying periods depending on the nature of the deferral and the jurisdiction.

Regulatory Assets by Source Not Earning a Current Return |  | March 31, 2020 |  | December 31, 2019 |  | Change
|  | (In millions)
Regulatory transition costs |  | $ | 9 |  |  | $ | 7 |  |  | $ | 2 |
Deferred transmission costs |  | 26 |  |  | 27 |  |  | (1 | )
Deferred generation costs |  | 11 |  |  | 15 |  |  | (4 | )
Storm-related costs |  | 467 |  |  | 471 |  |  | (4 | )
Other |  | 25 |  |  | 25 |  |  | — |
Regulatory Assets Not Earning a Current Return |  | $ | 538 |  |  | $ | 545 |  |  | $ | (7 | )

CAPITAL RESOURCES AND LIQUIDITY
FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest payments, dividend payments, and contributions to its pension plan.
The $2.5 billion equity issuance in 2018 strengthened FirstEnergy’s balance sheet, supported the company’s transition to a fully regulated utility company and positions FirstEnergy for sustained investment-grade credit metrics. The shares of preferred stock participated in the dividend paid on common stock on an as-converted basis and were non-voting except in certain limited circumstances. Because of this investment, FirstEnergy does not currently anticipate the need to issue additional equity through 2021 and expects to issue, subject to, among other things, market conditions, pricing terms and business operations, up to $600 million of equity annually in 2022 and 2023, including approximately $100 million in equity for its regular stock investment and employee benefit plans.
In addition to this equity investment, FE and its distribution 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 2020 and beyond, FE and its distribution 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 the issuance of long-term debt by FE and certain of its distribution and transmission subsidiaries to, among other things, fund capital expenditures and refinance short-term and maturing long-term debt, subject to market conditions and other factors.
On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. FirstEnergy expects no required contributions through 2021.
With an operating territory of 65,000 square miles, the scale and diversity of the ten Utilities that comprise the Regulated Distribution business uniquely position this business for growth through opportunities for additional investment. Over the past several years, Regulated Distribution has experienced rate base growth through investments that have improved reliability and added operating flexibility to the distribution infrastructure, which provide benefits to the customers and communities those Utilities serve. Based on its current capital plan, which includes over $10 billion in forecasted capital investments from 2018 through 2023, Regulated Distribution’s rate base compounded annual growth rate is expected to be approximately 4% from 2018 through 2023. Additionally, this business is exploring other opportunities for growth, including investments in electric system improvement and modernization
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projects to increase reliability and improve service to customers, as well as exploring opportunities in customer engagement that focus on the electrification of customers’ homes and businesses by providing a full range of products and services.
FirstEnergy believes there are incremental investment opportunities for its existing transmission infrastructure of over $20 billion beyond those identified through 2023, 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.
In alignment with FirstEnergy’s strategy to invest in its Regulated Transmission and Regulated Distribution segments as a fully regulated company, FirstEnergy is also focused on improving the balance sheet over time consistent with its business profile and maintaining investment grade ratings at its regulated businesses and FE. 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 addition, FE and its consolidated subsidiaries expect to continually evaluate any planned financings, which may result in changes from time to time.
On March 31, 2018, the FES Debtors announced that, in order to facilitate an orderly financial restructuring, they filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code with the Bankruptcy Court (which is referred to throughout as the FES Bankruptcy). In September 2018, the Bankruptcy Court approved a FES Bankruptcy settlement agreement by and among FirstEnergy, two groups of key FES creditors (collectively, the FES Key Creditor Groups), the FES Debtors and the UCC. The FES Bankruptcy settlement agreement resolved certain claims by FirstEnergy against the FES Debtors, all claims by the FES Debtors and the FES Key Creditor Groups against FirstEnergy, as well as releases from third parties who voted in favor the FES Debtors' plan of reorganization, in return for among other things, a cash payment of $853 million upon emergence. The FES Bankruptcy settlement was conditioned on the FES Debtors confirming and effectuating a plan of reorganization acceptable to FirstEnergy.
On February 18, 2020, the FES Debtors and FirstEnergy entered into an IT Access Agreement that provided IT support to enable the Debtors to emerge from bankruptcy prior to full IT separation by the FES Debtors. As part of the IT Access Agreement, the FES Debtors and FirstEnergy resolved, among other things, the on-going reconciliation of outstanding tax sharing payments for tax years 2018, 2019 and 2020 for a total of $125 million. On February 25, 2020, the Bankruptcy Court approved the IT Access Agreement. On February 27, 2020, the FES Debtors effectuated their plan, emerged from bankruptcy and FirstEnergy tendered the settlement payments totaling $853 million and the $125 million tax sharing payment to the FES Debtors, with no material impact to net income in the first quarter of 2020.
The outbreak of COVID-19 has become a global pandemic. FirstEnergy is continuously evaluating the global outbreak and taking steps to mitigate known risks. The full impact on FirstEnergy’s business from the pandemic, including the governmental and regulatory responses, is unknown at this time and difficult to predict. FirstEnergy provides a critical and essential service to its customers and the health and safety of FirstEnergy’s employees and customers is its first priority. FirstEnergy is continuously monitoring its supply chain and is working with essential vendors to understand the impact to its business and does not currently expect service disruptions or any material impact to our capital spending plan.
Currently, FirstEnergy is effectively managing operations during the pandemic in order to continue to provide critical and essential service to customers and believes it is well positioned to manage the resulting economic slowdown. FirstEnergy Distribution and Transmission revenues benefit from geographic and economic diversity across a five-state service territory, which also allows for flexibility with capital investments and measures to maintain sufficient liquidity over the next twelve months. As of April 20, 2020, the Company had $3.5 billion of available liquidity, and projects to remain at this level for the next twelve months. However, the situation remains fluid and future impacts to FirstEnergy, that are presently unknown or unanticipated, may occur. Furthermore, the likelihood of an impact to FirstEnergy, and the severity of any impact that does occur, could increase the longer the global pandemic persists. The extent to which COVID-19 may materially impact results, if at all, is highly uncertain and will depend on future developments, which cannot be predicted at this time.
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As of March 31, 2020, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was due in large part to accounts payable of $898 million, short-term borrowings of $750 million, accrued taxes of $566 million, currently payable long-term debt of $381 million, and other current liabilities of $572 million, primarily attributable to customer deposits and dividends payable. Currently payable long-term debt as of March 31, 2020, consisted of the following:

Currently Payable Long-Term Debt |  | (In millions)
Unsecured notes |  | $ | 250 |
Secured notes |  | 50 |
Sinking fund requirements |  | 65 |
Other notes |  | 16 |
|  | $ | 381 |

FirstEnergy believes its cash from operations and available liquidity will be sufficient to meet its working capital needs.
Short-Term Borrowings / Revolving Credit Facilities
FE and the Utilities and FET and certain of its subsidiaries participate in two separate five-year syndicated revolving credit facilities providing for aggregate commitments of $3.5 billion, which are available until December 6, 2022. Under the FE credit facility, an aggregate amount of $2.5 billion is available to be borrowed, repaid and reborrowed, subject to separate borrowing sub-limits for each borrower including FE and its regulated distribution subsidiaries. Under the FET credit facility, an aggregate amount of $1.0 billion is available to be borrowed, repaid and reborrowed under a syndicated credit facility, subject to separate borrowing sub-limits for each borrower including FE's transmission subsidiaries.
Borrowings under the credit facilities may be used for working capital and other general corporate purposes, including intercompany loans and advances by a borrower to any of its subsidiaries. Generally, borrowings under each of the credit facilities are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Each of the credit facilities contains financial covenants requiring each borrower to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the credit facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter.
FirstEnergy had $750 million and $1,000 million of short-term borrowings as March 31, 2020 and December 31, 2019, respectively. FirstEnergy’s available liquidity from external sources as of April 20, 2020, was as follows:

Borrower(s) |  | Type |  | Maturity |  | Commitment |  | Available Liquidity
|  |  |  |  |  | (In millions)
FirstEnergy(1) |  | Revolving |  | December 2022 |  | $ | 2,500 |  |  | $ | 2,496 |
FET(2) |  | Revolving |  | December 2022 |  | 1,000 |  |  | 825 |
|  |  |  | Subtotal |  | $ | 3,500 |  |  | $ | 3,321 |
|  | Cash and cash equivalents |  | — |  |  | 212 |
|  |  |  | Total |  | $ | 3,500 |  |  | $ | 3,533 |

(1) | FE and the Utilities. Available liquidity includes impact of $4 million of LOCs issued under various terms.

(2) | Includes FET and the Transmission Companies.

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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 March 31, 2020:

Borrower |  | FirstEnergy Revolving Credit Facility Sub-Limit |  | FET Revolving Credit Facility Sub-Limit |  | Regulatory and Other Short-Term Debt Limitations |  |
|  | (In millions) |  |
FE |  |  | $ | 2,500 |  |  |  | $ | — |  |  |  | $ | — |  | (1) |
FET |  |  | — |  |  |  | 1,000 |  |  |  | — |  | (1) |
OE |  |  | 500 |  |  |  | — |  |  |  | 500 |  | (2) |
CEI |  |  | 500 |  |  |  | — |  |  |  | 500 |  | (2) |
TE |  |  | 300 |  |  |  | — |  |  |  | 300 |  | (2) |
JCP&L |  |  | 500 |  |  |  | — |  |  |  | 500 |  | (2) |
ME |  |  | 500 |  |  |  | — |  |  |  | 500 |  | (2) |
PN |  |  | 300 |  |  |  | — |  |  |  | 300 |  | (2) |
WP |  |  | 200 |  |  |  | — |  |  |  | 200 |  | (2) |
MP |  |  | 500 |  |  |  | — |  |  |  | 500 |  | (2) |
PE |  |  | 150 |  |  |  | — |  |  |  | 150 |  | (2) |
ATSI |  |  | — |  |  |  | 500 |  |  |  | 500 |  | (2) |
Penn |  |  | 100 |  |  |  | — |  |  |  | 100 |  | (2) |
TrAIL |  |  | — |  |  |  | 400 |  |  |  | 400 |  | (2) |
MAIT |  |  | — |  |  |  | 400 |  |  |  | 400 |  | (2) |

(1) | No limitations.

(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, subject to each borrower's sub-limit, is available for the issuance of LOCs (subject to borrowings drawn under the 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 Facilities and against the applicable borrower’s borrowing sub-limit.
The 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 is related to the credit ratings of the company borrowing the funds. Additionally, borrowings under each of the 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 March 31, 2020, the borrowers were in compliance with the applicable debt-to-total-capitalization ratio covenants in each case as defined under the respective Facilities. The minimum interest charge coverage ratio no longer applies following FE's upgrade to an investment grade credit rating.
Term Loans
On October 19, 2018, FE entered into two separate syndicated term loan credit agreements, the first being a $1.25 billion 364-day facility with The Bank of Nova Scotia, as administrative agent, and the lenders identified therein, and the second being a $500 million two-year facility with JPMorgan Chase Bank, N.A., as administrative agent, and the lenders identified therein, respectively, the proceeds of each were used to reduce short-term debt. The term loans contain covenants and other terms and conditions substantially similar to those of the FE revolving credit facility described above, including a consolidated debt-to-total-capitalization ratio. Effective September 11, 2019, the two credit agreements noted above were amended to change the amounts available under the existing facilities from $1.25 billion and $500 million to $1 billion and $750 million, respectively, and extend the maturity dates until September 9, 2020, and September 11, 2021, respectively. As of March 31, 2020, only $750 million of the 364-day term loan was outstanding.
FirstEnergy’s term loans and revolving credit facilities bear interest at fluctuating interest rates, primarily based on LIBOR. LIBOR tends to fluctuate based on general interest rates, rates set by the U.S. Federal Reserve and other central banks, the supply of and demand for credit in the London interbank market and general economic conditions. 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 LIBOR and other variable interest rates. On July 27, 2017, the Financial Conduct Authority (the authority that regulates LIBOR) announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. The U.S. Federal Reserve,
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in conjunction with the Alternative Reference Rates Committee, is considering replacing U.S. dollar LIBOR with a newly created index, calculated based on repurchase agreements backed by treasury securities. It is not possible to predict the effect of these changes, other reforms or the establishment of alternative reference rates in the United Kingdom, the United States or elsewhere. To the extent these interest rates increase, interest expense will increase. If sources of capital for FirstEnergy are reduced, capital costs could increase materially. Restricted access to capital markets and/or increased borrowing costs could have an adverse effect on our results of operations, cash flows, financial condition and liquidity.
FirstEnergy Money Pools
FirstEnergy’s utility operating subsidiary companies also have the ability to borrow from each other and FE to meet their short-term working capital requirements. Similar but separate arrangements exist among FirstEnergy’s unregulated companies with AE Supply, FE, FET, FEV and certain other unregulated subsidiaries. FESC administers these money pools and tracks surplus funds of FE and the respective regulated and unregulated subsidiaries, as the case may be, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first three months of 2020 was 1.80% per annum for the regulated companies’ money pool and 1.90% per annum for the unregulated companies’ money pool.
Long-Term Debt Capacity
FE’s and its 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 April 20, 2020:

|  | Corporate Credit Rating |  | Senior Secured |  | Senior Unsecured |  | Outlook (1)
Issuer |  | S&P |  | Moody’s |  | Fitch |  | S&P |  | Moody’s |  | Fitch |  | S&P |  | Moody’s |  | Fitch |  | S&P |  | Moody’s |  | Fitch
FE |  | BBB |  | Baa3 |  | BBB |  | — |  | — |  | — |  | BBB- |  | Baa3 |  | BBB |  | S |  | S |  | S
AGC |  | BBB- |  | Baa2 |  | BBB |  | — |  | — |  | — |  | — |  | — |  | — |  | S |  | S |  | S
ATSI |  | BBB |  | A3 |  | BBB+ |  | — |  | — |  | — |  | BBB |  | A3 |  | A- |  | S |  | S |  | S
CEI |  | BBB |  | Baa2 |  | BBB+ |  | A- |  | A3 |  | A |  | BBB |  | Baa2 |  | A- |  | S |  | S |  | S
FET |  | BBB |  | Baa2 |  | BBB |  | — |  | — |  | — |  | BBB- |  | Baa2 |  | BBB |  | S |  | S |  | S
JCP&L |  | BBB |  | Baa1 |  | BBB+ |  | — |  | — |  | — |  | BBB |  | Baa1 |  | A- |  | S |  | RUR+ |  | S
ME |  | BBB |  | A3 |  | BBB+ |  | — |  | — |  | — |  | BBB |  | A3 |  | A- |  | S |  | S |  | S
MAIT |  | BBB |  | A3 |  | BBB+ |  | — |  | — |  | — |  | BBB |  | A3 |  | A- |  | S |  | S |  | S
MP |  | BBB |  | Baa2 |  | BBB |  | A- |  | A3 |  | A- |  | BBB |  | Baa2 |  | — |  | S |  | S |  | S
OE |  | BBB |  | A3 |  | BBB+ |  | A- |  | A1 |  | A |  | BBB |  | A3 |  | A- |  | S |  | P |  | S
PN |  | BBB |  | Baa1 |  | BBB+ |  | — |  | — |  | — |  | BBB |  | Baa1 |  | A- |  | S |  | S |  | S
Penn |  | BBB |  | A3 |  | BBB+ |  | — |  | A1 |  | A |  | — |  | — |  | — |  | S |  | P |  | S
PE |  | BBB |  | Baa2 |  | BBB |  | — |  | — |  | A- |  | — |  | — |  | — |  | S |  | S |  | S
TE |  | BBB |  | Baa1 |  | BBB+ |  | A- |  | A2 |  | A |  | — |  | — |  | — |  | S |  | S |  | S
TrAIL |  | BBB |  | A3 |  | BBB+ |  | — |  | — |  | — |  | BBB |  | A3 |  | A- |  | S |  | S |  | S
WP |  | BBB |  | A3 |  | BBB+ |  | — |  | — |  | A |  | — |  | — |  | — |  | S |  | S |  | S

(1) S = Stable, P = Positive, and RUR+ = Rating Under Review for Upgrade
Debt capacity is subject to the consolidated debt-to-total-capitalization limits in the credit facilities previously discussed. As of March 31, 2020, FE and its subsidiaries could issue additional debt of approximately $6.5 billion, or incur a $3.5 billion reduction to equity, and remain within the limitations of the financial covenants required by the FE Facility.
Changes in Cash Position
As of March 31, 2020, FirstEnergy had $152 million of cash and cash equivalents and approximately $33 million of restricted cash compared to $627 million of cash and cash equivalents and approximately $52 million of restricted cash as of December 31, 2019, on the Consolidated Balance Sheets.
Cash Flows From Operating Activities
FirstEnergy's most significant sources of cash are derived from electric service provided by its distribution and transmission operating subsidiaries. The most significant use of cash from operating activities is buying electricity to serve non-shopping customers and paying fuel suppliers, employees, tax authorities, lenders and others for a wide range of materials and services.
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FirstEnergy’s Consolidated Statement of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. For the three months ended March 31, 2020 and 2019, cash flows from operating activities includes income (loss) from discontinued operations of $50 million and $(35) million, respectively.
Net cash used for operating activities was $560 million during the first three months of 2020, compared to $182 million in the same period of 2019. The increase in cash used for operating activities is primarily due to the $978 million cash settlement and tax sharing payments made to FES upon their emergence in February 2020, partially offset by the absence of a $500 million cash contribution to the qualified pension plan in 2019.
Cash Flows From Financing Activities
In the first three months of 2020, cash provided from financing activities was $725 million compared to $593 million in the same period of 2019. The following table summarizes new debt financing, redemptions, repayments, short-term borrowings and dividends:

|  | For the Three Months Ended March 31,
Securities Issued or Redeemed / Repaid |  | 2020 |  | 2019
|  | (In millions)
New Issues - Unsecured notes |  | $ | 2,000 |  |  | $ | 1,400 |
Redemptions / Repayments |  |  |  |  |  |
Unsecured notes |  | $ | — |  |  | $ | (600 | )
Term loan |  | (750 | ) |  | — |
Senior secured notes |  | (28 | ) |  | (28 | )
|  | $ | (778 | ) |  | $ | (628 | )
Short-term borrowings, net |  | $ | (250 | ) |  | $ | 50 |
Preferred stock dividend payments |  | $ | — |  |  | $ | (3 | )
Common stock dividend payments |  | $ | (211 | ) |  | $ | (201 | )

On February 20, 2020, FE issued $1.75 billion in senior unsecured notes in three separate series: (i) $300 million aggregate principal amount of 2.050% Notes, Series A, due 2025, (ii) $600 million aggregate principal amount of 2.650% Notes, Series B, due 2030 and (iii) $850 million aggregate principal amount of 3.400% Notes, Series C, due 2050. Proceeds from the issuance of the notes, together with cash on hand, were used: (i) to repay the entire $750 million term loan due September 2021, (ii) to make the $853 million in bankruptcy settlement payments and $125 million tax sharing agreement payment with the FES Debtors as discussed above, (iii) to repay $250 million of the $1 billion outstanding 364-day term loan due September 2020, and (iv) for working capital needs and general corporate purposes.
On March 31, 2020, MAIT issued $125 million of 3.60% senior unsecured notes due 2032 and $125 million of 3.70% senior notes due 2035. Proceeds from the issuance of the senior notes were used: (i) to refinance existing debt, (ii) for capital expenditures, and (iii) for other general corporate purposes.
On April 20, 2020, PN issued $125 million of 3.61% senior notes due 2032 and $125 million of 3.71% senior notes due 2035. Proceeds of the issuance of the senior notes were used: (i) to refinance indebtedness, including short-term borrowings incurred under the FirstEnergy regulated money pool to repay a portion of the $250 million aggregate principle amount of PN’s 5.20% Senior Notes due April 1, 2020, (ii) to fund capital expenditures, (iii) to fund general corporate purposes, or (iv) for any combination of the above.
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Cash Flows From Investing Activities
Cash used for investing activities in the first three months of 2020 principally represented cash used for property additions. The following table summarizes investing activities for the first three months of 2020 and 2019:

|  | For the Three Months Ended March 31, |  | Increase
Cash Used for Investing Activities |  | 2020 |  | 2019 |  | (Decrease)
|  | (In millions)
Property Additions: |  |  |  |  |  |
Regulated Distribution |  | $ | 338 |  |  | $ | 318 |  |  | $ | 20 |
Regulated Transmission |  | 269 |  |  | 231 |  |  | 38 |
Corporate / Other |  | 9 |  |  | 5 |  |  | 4 |
Investments |  | 5 |  |  | 9 |  |  | (4 | )
Asset removal costs |  | 43 |  |  | 65 |  |  | (22 | )
Other |  | (5 | ) |  | 2 |  |  | (7 | )
|  | $ | 659 |  |  | $ | 630 |  |  | $ | 29 |

Cash used for investing activities for the first three months of 2020 increased $29 million, compared to the same period of 2019, primarily due to higher property additions, partially offset by lower asset removal costs due to the timing of projects.
The increase in property additions was due to the following:

• | an increase of $20 million at Regulated Distribution due to investments in electric system improvements and modernization projects to increase reliability; and

• | an increase of $38 million at Regulated Transmission due to timing of capital investments associated with its Energizing the Future investment program.

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GUARANTEES AND OTHER ASSURANCES
FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. The maximum potential amount of future payments FirstEnergy and its subsidiaries could be required to make under these guarantees as of March 31, 2020, was approximately $1.7 billion, as summarized below:

Guarantees and Other Assurances |  | Maximum Exposure
|  | (In millions)
FE’s Guarantees on Behalf of its Consolidated Subsidiaries |  |
AE Supply asset sales(1) |  | $ | 570 |
Deferred compensation arrangements |  | 477 |
Fuel related contracts and other |  | 4 |
|  | 1,051 |
FE’s Guarantees on Other Assurances |  |
Global holding facility |  | 114 |
Deferred compensation arrangements |  | 150 |
Surety Bonds |  | 336 |
LOCs and other |  | 16 |
|  | 616 |
Total Guarantees and Other Assurances |  | $ | 1,667 |

(1) | As a condition to closing AE Supply’s sale of four natural gas generating plants in December 2017, FE provided the purchaser two limited three-year guarantees totaling $555 million of certain obligations of AE Supply and AGC. In addition, as a condition to closing AE Supply’s transfer of Pleasants Power Station and as contemplated under the FES Bankruptcy settlement agreement, FE has provided two guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility.

Collateral and Contingent-Related Features
In the normal course of business, FE and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain bilateral agreements and derivative instruments contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE’s or its subsidiaries’ credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements.
Bilateral agreements and derivative instruments entered into by FE and its subsidiaries have margining provisions that require posting of collateral. As of March 31, 2020, no collateral has been posted by FE or its subsidiaries.
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, 2020:

Potential Collateral Obligations |  |  | Utilities and FET |  | FE |  | Total
|  | (In millions)
Contractual Obligations for Additional Collateral |  |  |  |  |  |  |
Upon further downgrade |  |  | $ | 33 |  |  | $ | — |  |  | $ | 33 |
Surety Bonds (collateralized amount)(1) |  |  | 63 |  |  | 257 |  |  | 320 |
Total Exposure from Contractual Obligations |  |  | $ | 96 |  |  | $ | 257 |  |  | $ | 353 |

(1) | Surety Bonds are not tied to a credit rating. Surety Bonds’ impact assumes maximum contractual obligations (typical obligations require 30 days to cure).

Other Commitments and Contingencies
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FE is a guarantor under a $120 million syndicated senior secured term loan facility due November 12, 2024, under which Global Holding’s outstanding principal balance is $114 million as of March 31, 2020. 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.
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 Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.
Commodity Price Risk
FirstEnergy has limited exposure to financial risks resulting from fluctuating commodity prices, including prices for electricity, natural gas, coal and energy transmission. FirstEnergy’s Risk Management 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.
The valuation of derivative contracts is based on observable market information. As of March 31, 2020, FirstEnergy has a net liability of $7 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.
Equity Price Risk
As of March 31, 2020, the FirstEnergy pension plan assets were allocated approximately as follows: 25% in equity securities, 43% in fixed income securities, 10% in absolute return strategies, 9% in real estate, 4% in private equity, 4% in derivatives and 5% in cash and short-term securities. A decline in the value of pension plan assets could result in additional funding requirements. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. As a result of this contribution and pension investment performance returns to date, FirstEnergy expects no required contributions through 2021. As of March 31, 2020,
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FirstEnergy’s OPEB plan assets were allocated approximately 47% in equity securities, 49% in fixed income securities and 4% in cash and short-term securities. See Note 5, “Pension and Other Post-Employment Benefits,” of the Notes to Consolidated Financial Statements for additional details on FirstEnergy’s pension and OPEB plans.
Through March 31, 2020, FirstEnergy’s pension and OPEB plan assets have lost approximately 4.4% and 9.2%, respectively, as compared to an annual expected return on plan assets of 7.5%. On February 27, 2020, FirstEnergy remeasured its plan assets, and from that date through March 31, 2020, FirstEnergy’s pension and OPEB plan assets have lost approximately 7.0% and 10.5%, respectively.
NDT funds have been established to satisfy JCP&L, ME and PN’s nuclear decommissioning obligations associated with TMI-2. As of March 31, 2020, approximately 14% of the funds were invested in fixed income securities and 86% 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 $124 million and $767 million for fixed income securities and short-term investments, respectively, as of March 31, 2020, excluding $16 million of net receivables, payables and accrued income. A decline in the value of JCP&L, ME and PN’s NDTs or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During the three months ended March 31, 2020, JCP&L, ME and PN 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 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.
Under the approved bankruptcy settlement agreement discussed above, upon emergence, FES and FENOC employees ceased earning years of service under the FirstEnergy pension and OPEB plans. The emergence on February 27, 2020, triggered a remeasurement of the affected pension and OPEB plans and as a result, FirstEnergy recognized a non-cash, pre-tax pension and OPEB mark-to-market adjustment of approximately $423 million in the first quarter of 2020. The pension and OPEB mark-to-market adjustment primarily reflects a 38 bps decrease in the discount rate used to measure benefit obligations from December 31, 2019, partially offset by a slightly higher than expected return on assets.
Based on discount rates of 2.96% for pension and 2.80% for OPEB as well as an estimated return on assets of 7.50% for pension and OPEB, FirstEnergy expects its 2020 pre-tax net periodic benefit cost to be approximately $246 million, including the $423 million pension and OPEB mark-to-market adjustment in the first quarter of 2020.
At this time, FirstEnergy is unable to determine or project the mark-to-market that may be recorded as of December 31, 2020.
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 requirement that counterparties maintain specified credit ratings) and require other assurances in the form of credit support or collateral in certain circumstance in order to limit counterparty credit risk. In addition, in response to the recent COVID-19 pandemic, FirstEnergy has increased reviews of counterparties, customers and industries that have been negatively impacted, which could affect meeting contractual obligations with FirstEnergy. 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, Pennsylvania Companies, 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 collateral requirements, and surveys to determine negative impacts to essential vendors as a result of the COVID-19 pandemic. 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
CARES ACT
On March 27, 2020, the President signed into law the CARES Act, an economic stimulus package in response to the COVID-19 global pandemic. The CARES Act contains several corporate income tax provisions, including making remaining AMT credits immediately refundable; providing a 5-year carryback of NOLs generated in tax years 2018, 2019, and 2020, and removing the 80% taxable income limitation on utilization of those NOLs if carried back to prior tax years or utilized in tax years beginning before
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2021; and temporarily liberalizing the interest deductibility rules under Section 163(j) of the Tax Act, by raising the adjusted taxable income limitation from 30% to 50% for tax years 2019 and 2020 and giving taxpayers the election of using 2019 adjusted taxable income for purposes of computing 2020 interest deductibility. FirstEnergy has approximately $18 million of refundable AMT credits that will be fully refundable through the CARES Act, however, does not expect to generate additional income tax refunds from the NOL carryback provision and expects interest to be fully deductible starting in 2020. FirstEnergy does not currently expect the other provisions of the CARES Act to have a material effect on current income tax expense or the realizability of deferred income tax assets, however, new or additional changes to proposed regulations or guidelines by the IRS on Section 163(j), including their impact resulting from the CARES Act, could have a material impact.
STATE REGULATION
Each of the Utilities’ retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia are subject to certain regulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. 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 March 23, 2019. PE also provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third-party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS.
The EmPOWER Maryland program requires each electric utility to file a plan to reduce electric consumption and demand 0.2% per year, up to the ultimate goal of 2% annual savings, for the duration of the 2018-2020 and 2021-2023 EmPOWER Maryland program cycles, to the extent the MDPSC determines that cost-effective programs and services are available. PE’s approved 2018-2020 EmPOWER Maryland plan continues and expands upon prior years’ programs, and adds new programs, for a projected total cost of $116 million over the three-year period. PE recovers program costs subject to a five-year amortization. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding, and to date, such recovery has not been sought or obtained by PE.
On January 19, 2018, PE filed a joint petition along with other utility companies, work group stakeholders and the MDPSC electric vehicle work group leader to implement a statewide electric vehicle portfolio in connection with a 2016 MDPSC 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. PE proposed an electric vehicle charging infrastructure program at a projected total cost of $12 million, to be recovered over a five-year amortization. On January 14, 2019, the MDPSC approved the petition subject to certain reductions in the scope of the program. The MDPSC approved PE’s compliance filing, which implements the pilot program, with minor modifications, on July 3, 2019.
On August 24, 2018, PE filed a base rate case with the MDPSC, which it supplemented on October 22, 2018, to update the partially forecasted test year with a full twelve months of actual data. The rate case requested an annual increase in base distribution rates of $19.7 million, plus creation of an EDIS to fund four enhanced service reliability programs. In responding to discovery, PE revised its request for an annual increase in base rates to $17.6 million. The proposed rate increase reflected $7.3 million in annual savings for customers resulting from the recent federal tax law changes. On March 22, 2019, the MDPSC issued a final order that approved a rate increase of $6.2 million, approved three of the four EDIS programs for four years, directed PE to file a new depreciation study within 18 months, and ordered the filing of a new base rate case in four years to correspond to the ending of the approved EDIS programs.
Maryland’s Governor issued an order on March 16, 2020, forbidding utilities from terminating residential service or charging late fees for non-payment for the duration of the COVID-19 emergency. On April 9, 2020, the MDPSC issued an order allowing utilities to track and create a regulatory asset for future recovery of all prudently-incurred incremental costs arising from the COVID-19 emergency.
NEW JERSEY
JCP&L operates under NJBPU approved rates that were effective as of January 1, 2017. 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.
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On April 18, 2019, pursuant to the May 2018 New Jersey enacted legislation establishing a ZEC program to provide ratepayer funded subsidies of New Jersey nuclear energy supply, the NJBPU approved the implementation of a non-bypassable, irrevocable ZEC charge for all New Jersey electric utility customers, including JCP&L’s customers. Once collected from customers by JCP&L, these funds will be remitted to eligible nuclear energy generators.
In December 2017, the NJBPU issued proposed rules to modify its current CTA policy in base rate cases to: (i) calculate savings using a five-year look back from the beginning of the test year; (ii) allocate savings with 75% retained by the company and 25% allocated to ratepayers; and (iii) exclude transmission assets of electric distribution companies in the savings calculation, which were published in the NJ Register in the first quarter of 2018. JCP&L filed comments supporting the proposed rulemaking. On January 17, 2019, the NJBPU approved the proposed CTA rules with no changes. On May 17, 2019, the Rate Counsel filed an appeal with the Appellate Division of the Superior Court of New Jersey. JCP&L is contesting this appeal but is unable to predict the outcome of this matter.
Also in December 2017, the NJBPU approved its IIP rulemaking. The IIP creates a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing components that enhance reliability, resiliency, and/or safety. On May 8, 2019, the NJBPU approved a Stipulation of Settlement submitted by JCP&L, Rate Counsel, NJBPU Staff and New Jersey Large Energy Users Coalition to implement JCP&L’s infrastructure plan, JCP&L Reliability Plus. The plan provides that JCP&L will invest up to approximately $97 million in capital investments beginning on June 1, 2019 through December 31, 2020, to enhance the reliability and resiliency of JCP&L’s distribution system and reduce the frequency and duration of power outages. JCP&L shall seek recovery of the capital investment through an accelerated cost recovery mechanism, provided for in the rules, that includes a revenue adjustment calculation and a process for two rate adjustments. The NJBPU approved adjusted rates that took effect on March 1, 2020.
On February 18, 2020, JCP&L submitted a filing with the NJBPU requesting a distribution base rate increase of $186.9 million on an annual basis, which represents an overall average increase in JCP&L rates of 7.8%. The filing seeks to recover certain costs associated with providing safe and reliable electric service to JCP&L customers, along with recovery of previously incurred storm costs. JCP&L proposed a rate effective date of March 19, 2020. On March 9, 2020, the Board issued an order suspending JCP&L’s proposed rates for four months. Based on the historical procedures of the NJBPU Board a second suspension order is expected with revised base rates becoming effective in late November 2020.
On April 6, 2020, JCP&L signed an asset purchase agreement with Yard’s Creek Energy, LLC, a subsidiary of LS Power to sell its 50% interest in the Yards Creek pumped-storage hydro generation facility in NJ (210 MWs). Subject to terms and conditions of the agreement, the base purchase price is $155 million. Completion of the transaction is subject to several closing conditions, including approval by the NJBPU and FERC. There can be no assurance that all regulatory approvals will be obtained and/or all closing conditions will be satisfied or that the transaction will be consummated. JCP&L currently anticipates closing of the transaction to occur in the first half of 2021. As of March 31, 2020, Yards Creek’s net book value is approximately $44 million, which is included in the regulated distribution segment. Treatment of the gain is subject to NJBPU approval.
OHIO
The Ohio Companies operate under base distribution rates approved by the PUCO effective in 2009. The Ohio Companies’ residential and commercial base distribution revenues are decoupled, through a mechanism that took effect on February 1, 2020, to the base distribution revenue and lost distribution revenue associated with energy efficiency and peak demand reduction programs recovered as of the twelve-month period ending on December 31, 2018. The Ohio Companies currently operate under ESP IV effective June 1, 2016, and continuing through May 31, 2024, that continues the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continues Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024. In addition, ESP IV includes: (1) continuation of a base distribution rate freeze through May 31, 2024; (2) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (3) a goal across FirstEnergy to reduce CO 2 emissions by 90% below 2005 levels by 2045; and (4) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio. ESP IV further provided for the Ohio Companies to collect through Rider DMR $132.5 million annually for three years beginning in 2017, grossed up for federal income taxes, resulting in an approved amount of approximately $168 million annually in 2018 and 2019. On appeal, the SCOH, on June 19, 2019, reversed the PUCO’s determination that Rider DMR is lawful, and remanded the matter to the PUCO with instructions to remove Rider DMR from ESP IV. On August 20, 2019, the SCOH denied the Ohio Companies’ motion for reconsideration. The PUCO entered an Order directing the Ohio Companies to cease further collection through Rider DMR, credit back to customers a refund of Rider DMR funds collected since July 2, 2019, and remove Rider DMR from ESP IV. On July 15, 2019, OCC filed a Notice of Appeal with the SCOH, challenging the PUCO’s exclusion of Rider DMR revenues from the determination of the existence of significantly excessive earnings under ESP IV for calendar year 2017 and claiming a $42 million refund is due to OE customers. The Ohio Companies are contesting this appeal but are unable to predict the outcome of this matter. The SCOH is scheduled to hear argument on this matter on May 12, 2020.
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On July 23, 2019, Ohio enacted legislation establishing support for nuclear energy supply in Ohio. In addition to the provisions supporting nuclear energy, the legislation included a provision implementing a decoupling mechanism for Ohio electric utilities and ending current energy efficiency program mandates on December 31, 2020, provided that statewide energy efficiency mandates are achieved as determined by the PUCO. On February 26, 2020, the PUCO ordered (i) that a wind-down of statutorily required energy efficiency programs shall commence on September 30, 2020, and the programs shall terminate on December 31, 2020, and (ii) that the Ohio Companies’ existing portfolio plans are extended through 2020 without changes.
On November 21, 2019, the Ohio Companies applied to the PUCO for approval of a decoupling mechanism, which would set residential and commercial base distribution related revenues at the levels collected in 2018. As such, those base distribution revenues would no longer be based on electric consumption, which allows continued support of energy efficiency initiatives while also providing revenue certainty to the Ohio Companies. On January 15, 2020, the PUCO approved the Ohio Companies’ decoupling application, and the decoupling mechanism took effect on February 1, 2020.
On July 17, 2019, the PUCO approved, with no material modifications, a settlement agreement that provides for the implementation of the Ohio Companies’ first phase of grid modernization plans, including the investment of $516 million over three years to modernize the Ohio Companies’ electric distribution system, and for all tax savings associated with the Tax Act to flow back to customers. The settlement had broad support, including PUCO Staff, the OCC, representatives of industrial and commercial customers, a low-income advocate, environmental advocates, hospitals, competitive generation suppliers and other parties.
PENNSYLVANIA
The Pennsylvania Companies operate under rates approved by the PPUC, effective as of January 27, 2017. These rates were adjusted for the net impact of the Tax Act, effective March 15, 2018. The net impact of the Tax Act for the period January 1, 2018 through March 14, 2018 was separately tracked and its treatment will be addressed in a future rate proceeding. The Pennsylvania Companies operate under DSPs for the June 1, 2019 through May 31, 2023 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 2019-2023 DSPs, supply will be provided by wholesale suppliers through a mix of 3, 12 and 24-month energy contracts, as well as two RFPs for 2-year SREC contracts for ME, PN and Penn.
Pursuant to Pennsylvania Act 129 of 2008 and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs. The Pennsylvania Companies’ Phase III EE&C plans for the June 2016 through May 2021 period, which were approved in March 2016, with expected costs up to $390 million, are designed to achieve the targets established in the PPUC’s Phase III Final Implementation Order with full recovery through the reconcilable EE&C riders. On March 12, 2020, the PPUC entered a Tentative Implementation Order for a Phase IV EE&C Plan, operating from June 2021 through May 2026.
Pennsylvania EDCs may file with the PPUC for 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 August 30, 2019, the Pennsylvania Companies filed Petitions for approval of new LTIIPs for the five-year period beginning January 1, 2020 and ending December 31, 2024 for a total capital investment of approximately $572 million for certain infrastructure improvement initiatives. On January 16, 2020, the PPUC approved the LTIIPs without modification. The Pennsylvania Companies’ approved DSIC riders for quarterly cost recovery went into effect July 1, 2016. On August 30, 2019, Penn filed a Petition seeking approval of a waiver of the statutory DSIC cap of 5% of distribution rate revenue and approval to increase the maximum allowable DSIC to 11.81% of distribution rate revenue for the five-year period of its proposed LTIIP. On March 12, 2020, an order was entered approving a settlement by all parties to that case which provides for a temporary increase in the recoverability cap from 5% to 7.5%, to expire on the earlier of the effective date of new base rates following Penn’s next base rate case or the expiration of its LTIIP II program.
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, which decision was appealed by the Pennsylvania OCA to the Pennsylvania Commonwealth Court. The Commonwealth Court reversed the PPUC’s decision and remanded the matter to require the Pennsylvania Companies to revise their tariffs and DSIC calculations to include ADIT and state income taxes. On April 7, 2020, the Pennsylvania Supreme Court issued an Order granting Petitions for Allowance of Appeal by both the PPUC and the Pennsylvania Companies of the Commonwealth Court’s Opinion and Order. A briefing schedule is pending. An adverse ruling by the Pennsylvania Supreme Court is not expected to result in a material impact to FirstEnergy.
WEST VIRGINIA
MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operates under rates approved by the WVPSC effective February 2015. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP’s and PE’s ENEC rate is updated annually.
On August 21, 2019, MP and PE filed with the WVPSC their annual ENEC case requesting a decrease in ENEC rates of $6.1 million beginning January 1, 2020, representing a 0.4% decrease in rates versus those in effect on August 21, 2019. On October 11, 2019, MP and PE filed a supplement requesting approval of the termination of the 50 MW PPA with Morgantown Energy Associates, a
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NUG entity. A settlement between MP, PE, and the majority of the intervenors fully resolving the ENEC case, which maintains 2019 ENEC rates into 2020, and supports the termination of the Morgantown Energy Associates PPA was filed with the WVPSC on October 18, 2019. An order was issued on December 20, 2019, approving the ENEC settlement and termination of the PPA with Morgantown Energy Associates.
On August 21, 2019, MP and PE filed with the WVPSC for a reconciliation of their VMS and a periodic review of its vegetation management program requesting an increase in VMS rates of $7.6 million beginning January 1, 2020. The increase is due to moving from a 5-year maintenance cycle to a 4-year cycle and performing more operation and maintenance work and less capital work on the rights of way. The increase is a 0.5% increase in rates versus those in effect on August 21, 2019. All the parties reached a settlement in the case, and the WVPSC issued its order approving the settlement without change on December 20, 2019.
FERC REGULATORY MATTERS
Under the FPA, FERC regulates rates for interstate wholesale sales, transmission of electric power, accounting 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, WP and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE, WP 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.
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 been authorized by FERC to sell wholesale power in interstate commerce at market-based rates and have a market-based rate tariff on file with FERC, although major wholesale purchases remain subject to 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 ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to 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.
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 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 exceed the costs. In a subsequent order, FERC affirmed its prior ruling that ATSI must submit the cost/benefit analysis. ATSI is evaluating the cost/benefit approach.
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FERC Actions on Tax Act
On March 15, 2018, FERC initiated proceedings on the question of how to address possible changes to ADIT and bonus depreciation as a result of the Tax Act. Such possible changes could impact FERC-jurisdictional rates, including transmission rates. On November 21, 2019, FERC issued a final rule (Order No. 864). Order No. 864 requires utilities with transmission formula rates to update their formula rate templates to include mechanisms to (i) deduct any excess ADIT from or add any deficient ADIT to their rate base; (ii) raise or lower their income tax allowances by any amortized excess or deficient ADIT; and (iii) incorporate a new permanent worksheet into their rates that will annually track information related to excess or deficient ADIT. Alternatively, formula rate utilities can demonstrate to FERC that their formula rate template already achieves these outcomes. Utilities with transmission stated rates are required to address these new requirements as part of their next transmission rate case. FERC also issued on November 15, 2018, a policy statement providing accounting and ratemaking guidance for treatment of ADIT for all FERC-jurisdictional public utilities. The policy statement also addresses the accounting and ratemaking treatment of ADIT following the sale or retirement of an asset after December 31, 2017. FirstEnergy’s formula rate transmission utilities will make the required filings on or before the deadlines established in FERC’s order. FirstEnergy’s stated rate transmission utilities will address the requirements as part of their next transmission rate case. JCP&L is addressing the requirements in the course of its pending transmission rate case.
Transmission ROE Methodology
FERC’s methodology for calculating electric transmission utility ROE has been in transition as a result of an April 14, 2017 ruling by the D.C. Circuit that vacated FERC’s then-effective methodology. On October 16, 2018, FERC issued an order in which it proposed a revised ROE methodology. FERC proposed that, for complaint proceedings alleging that an existing ROE is not just and reasonable, FERC will rely on three financial models - discounted cash flow, capital-asset pricing, and expected earnings - to establish a composite zone of reasonableness to identify a range of just and reasonable ROEs. FERC then will utilize the transmission utility’s risk relative to other utilities within that zone of reasonableness to assign the transmission utility to one of three quartiles within the zone. FERC would take no further action (i.e., dismiss the complaint) if the existing ROE falls within the identified quartile. However, if the replacement ROE falls outside the quartile, FERC would deem the existing ROE presumptively unjust and unreasonable and would determine the replacement ROE. FERC would add a fourth financial model risk premium to the analysis to calculate a ROE based on the average point of central tendency for each of the four financial models. On March 21, 2019, FERC established NOIs to collect industry and stakeholder comments on the revised ROE methodology that is described in the October 16, 2018 decision, and also whether to make changes to FERC’s existing policies and practices for awarding transmission rates incentives. On November 21, 2019, FERC announced in a complaint proceeding involving MISO utilities that FERC would rely on the discounted cash flow and capital-asset pricing models as the basis for establishing ROE. It is not clear at this time whether FERC’s November ruling will be applied more broadly. Any changes to FERC’s transmission rate ROE and incentive policies would be applied on a prospective basis. FirstEnergy currently is participating through various trade groups in the FERC dockets where the ROE methodology is being reviewed, and on December 23, 2019, JCP&L filed a request for rehearing of FERC’s November decision in the MISO utilities docket.
FERC’s ROE policy may also impact PATH’s regulatory proceedings regarding recovery of investments and costs associated with a proposed transmission line from West Virginia through Virginia and into Maryland that PJM canceled in 2012. Specifically, on January 24, 2020, FERC issued an order in the PATH transmission abandonment rate case that noted FERC’s recent actions on transmission utility ROE methodologies and directed parties to brief the applicability of the October 2018 methodology to the PATH ROE. Initial briefs are due May 1, 2020 and reply briefs are due June 1, 2020.
On March 20, 2020, FERC initiated a rulemaking proceeding on the transmission rate incentives provisions of Section 219 of the 2005 Energy Policy Act. Initial comments are due July 1, 2020. FirstEnergy currently is participating through EEI and other industry groups.
JCP&L Transmission Formula Rate
On October 30, 2019, JCP&L filed tariff amendments with FERC to convert JCP&L’s existing stated transmission rate to a forward-looking formula transmission rate. JCP&L requested that the tariff amendments become effective January 1, 2020. On December 19, 2019, FERC issued its initial order in the case, allowing JCP&L to transition to a forward-looking formula rate as of January 1, 2020 as requested, subject to refund, pending further hearing and settlement proceedings. JCP&L and the parties to the FERC proceeding are engaged in settlement negotiations.
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.
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Clean Air Act
FirstEnergy complies with SO 2 and NOx emission reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls and/or using emission allowances.
CSAPR requires reductions of NOx and SO 2 emissions in two phases (2015 and 2017), ultimately capping SO 2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO 2 emission allowances between power plants located in the same state and interstate trading of NOx and SO 2 emission allowances with some restrictions. The D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO 2 emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia. This follows the 2014 U.S. Supreme Court ruling generally upholding the EPA’s regulatory approach under CSAPR, but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR update rule on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR update rule to the D.C. Circuit in November and December 2016. On September 6, 2017, the D.C. Circuit rejected the industry’s bid for a lengthy pause in the litigation and set a briefing schedule. On September 13, 2019, the D.C. Circuit remanded the CSAPR update rule 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. Depending on the outcome of the appeals, the EPA’s reconsideration of the CSAPR update rule and how the EPA and the states ultimately implement CSAPR, the future cost of compliance may materially impact FirstEnergy’s operations, cash flows and financial condition.
In February 2019, the EPA announced its final decision to retain without changes the NAAQS for SO 2, specifically retaining the 2010 primary (health-based) 1-hour standard of 75 PPB. As of March 31, 2020, FirstEnergy has no power plants operating in areas designated as non-attainment by the EPA.
In August 2016, the State of Delaware filed a CAA Section 126 petition with the EPA alleging that the Harrison generating facility’s NOx emissions significantly contribute to Delaware’s inability to attain the ozone NAAQS. The petition sought a short-term NOx emission rate limit of 0.125 lb./mmBTU over an averaging period of no more than 24 hours. In November 2016, the State of Maryland filed a CAA Section 126 petition with the EPA alleging that NOx emissions from 36 EGUs, including Harrison Units 1, 2 and 3, significantly contribute to Maryland’s inability to attain the ozone NAAQS. The petition sought NOx emission rate limits for the 36 EGUs by May 1, 2017. On September 14, 2018, the EPA denied both the States of Delaware and Maryland’s petitions under CAA Section 126. In October 2018, Delaware and Maryland appealed the denials of their petitions to the D.C. Circuit. In March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from nine states (including West Virginia) significantly contribute to New York’s inability to attain the ozone NAAQS. The petition seeks suitable emission rate limits for large stationary sources that are affecting New York’s air quality within the three years allowed by CAA Section 126. On May 3, 2018, the EPA extended the time frame for acting on the CAA Section 126 petition by six months to November 9, 2018. 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. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss.
Climate Change
There are a number of initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.
At the international level, the United Nations Framework Convention on Climate Change resulted in the Kyoto Protocol requiring participating countries, which does not include the U.S., to reduce GHGs commencing in 2008 and has been extended through 2020. The Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide GHG emissions by 26 to 28 percent below 2005 levels by 2025. In 2015, FirstEnergy set a goal of reducing company-wide CO 2 emissions by at least 90 percent below 2005 levels by 2045. As of December 31, 2018, FirstEnergy has reduced its CO 2 emissions by approximately 62 percent. In September 2016, the U.S. joined in adopting the agreement reached on December 12, 2015, at the United Nations Framework Convention on Climate Change meetings in Paris. The Paris Agreement’s non-binding obligations to limit global warming to below two degrees Celsius became effective on November 4, 2016. On June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the Paris Agreement. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO 2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations.
In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for GHG under the Clean Air Act” concluding that concentrations of several key GHGs constitutes an “endangerment” and may be regulated as “air pollutants” under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. The EPA released its final CPP regulations in August 2015 to reduce CO 2 emissions from existing fossil fuel-fired EGUs and finalized separate regulations imposing CO 2 emission limits for new, modified, and reconstructed fossil fuel fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. On February 9, 2016, the U.S.
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Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court. On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On October 16, 2017, the EPA issued a proposed rule to repeal the CPP. To replace the CPP, the EPA proposed the ACE rule on August 21, 2018, which would establish emission guidelines for states to develop plans to address GHG emissions from existing coal-fired power plants. On June 19, 2019, the EPA repealed the CPP and replaced it with the ACE rule that establishes guidelines for states to develop standards of performance to address GHG emissions from existing coal-fired power plants. Depending on the outcomes of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy’s facilities. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy’s operations.
The EPA finalized CWA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts of a cooling water intake system to a 12% annual average and requiring cooling water intake structures exceeding 125 million gallons per day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a facility’s cooling water system. Depending on any final action taken by the states with respect to impingement and entrainment, the future capital costs of compliance with these standards may be material.
On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations phase-in as permits are renewed on a five-year cycle from 2018 to 2023. 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 November 4, 2019, the EPA issued a proposed rule revising the effluent limits for discharges from wet scrubber systems and extending the deadline for compliance to December 31, 2025. The EPA’s proposed rule retains the zero discharge standard and 2023 compliance date for ash transport water, but adds some allowances for discharge under certain circumstances. 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. Depending on the outcome of appeals and how any final rules are ultimately implemented, the future costs of compliance with these standards may be substantial and changes to FirstEnergy’s operations may result.
On September 29, 2016, FirstEnergy received a request from the EPA for information pursuant to CWA Section 308(a) for information concerning boron exceedances of effluent limitations established in the NPDES Permit for the former Mitchell Power Station’s Mingo landfill, owned by WP. On November 1, 2016, WP provided an initial response that contained information related to a similar boron issue at the former Springdale Power Station’s landfill. The EPA requested additional information regarding the Springdale landfill and on November 15, 2016, WP provided a response and intends to fully comply with the Section 308(a) information request. On March 3, 2017, WP proposed to the PA DEP a re-route of its wastewater discharge to eliminate potential boron exceedances at the Springdale landfill. On January 29, 2018, WP submitted an NPDES permit renewal application to PA DEP proposing to re-route its wastewater discharge to eliminate potential boron exceedances at the Mingo landfill. On February 20, 2018, the DOJ issued a letter and tolling agreement on behalf of EPA alleging violations of the CWA at the Mingo landfill while seeking to enter settlement negotiations in lieu of filing a complaint. The EPA has proposed a penalty of $900,000 to settle alleged past boron exceedances at the Mingo and Springdale landfills. Negotiations are continuing and WP is unable to predict the outcome of this matter.
Regulation of Waste Disposal
Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act. Certain CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation.
In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 17, 2018, the EPA Administrator signed a final rule extending the deadline for certain CCR facilities to cease disposal and commence closure activities, as well as, establishing less stringent groundwater monitoring and protection requirements. On August 21, 2018, the D.C. Circuit remanded sections of the CCR Rule to the EPA to provide additional safeguards for unlined CCR impoundments that are more protective of human health and the environment. On December 2, 2019, the EPA published a proposed rule accelerating the date that certain CCR impoundments must cease accepting waste and initiate closure to August 31, 2020. The proposed rule, which includes a 60-day comment period, provides exceptions, which could allow extensions to closure dates.
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
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joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of March 31, 2020, 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 $109 million have been accrued through March 31, 2020. Included in the total are accrued liabilities of approximately $70 million for environmental remediation of former MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. FE or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time.
OTHER LEGAL PROCEEDINGS
Nuclear Plant Matters
Under NRC regulations, JCP&L, ME and PN must ensure that adequate funds will be available to decommission their retired nuclear facility, TMI-2. As of March 31, 2020, JCP&L, ME and PN had in total approximately $875 million invested in external trusts to be used for the decommissioning and environmental remediation of their retired TMI-2 nuclear generating facility. The values of these NDTs also fluctuate based on market conditions. If the values of the trusts decline by a material amount, the obligation to JCP&L, ME and PN to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDTs.
On October 15, 2019, JCP&L, ME, PN and GPUN executed an asset purchase and sale agreement with TMI-2 Solutions, LLC, a subsidiary of Energy Solutions, LLC, concerning the transfer and dismantlement of TMI-2. This transfer of TMI-2 to TMI-2 Solutions, LLC will include the transfer of: (i) the ownership and operating NRC licenses for TMI-2; (ii) the external trusts for the decommissioning and environmental remediation of TMI-2; and (iii) related liabilities of approximately $900 million as of December 31, 2019. There can be no assurance that the transfer will receive the required regulatory approvals and, even if approved, whether the conditions to the closing of the transfer will be satisfied. On November 12, 2019, JCP&L filed a Petition with the NJBPU seeking approval of the transfer and sale of JCP&L’s entire 25% interest in TMI-2 to TMI-2 Solutions, LLC. Also on November 12, 2019, JCP&L, ME, PN, GPUN and TMI-2 Solutions, LLC filed an application with the NRC seeking approval to transfer the NRC license for TMI-2 to TMI-2 Solutions, LLC. Both proceedings are ongoing. Assets and liabilities held for sale on the FirstEnergy Consolidated Balance Sheet associated with the transaction consist of asset retirement obligations of $700 million, NDTs of $875 million as well as property, plant and equipment with a net book value of zero, which are included in the regulated distribution segment.
FES Bankruptcy
On March 31, 2018, FES, including its consolidated subsidiaries, FG, NG, FE Aircraft Leasing Corp., Norton Energy Storage L.L.C. and FGMUC, and FENOC filed voluntary petitions for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court and emerged on February 27, 2020. See Note 3, “Discontinued Operations,” for additional discussion.
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 9, “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
Recently Adopted Pronouncements
ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (Issued June 2016 and subsequently updated): ASU 2016-13 removes all recognition thresholds and will require companies to recognize an allowance for credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that the company expects to collect over the instrument’s contractual life. Prior to adoption, FirstEnergy analyzed its financial instruments within the scope of this guidance, primarily trade receivables and AFS debt securities. The adoption of this standard upon January 1, 2020 did not have a material impact to FirstEnergy’s financial statements and required additional disclosures in these Notes to the Consolidated Financial Statements.
ASU 2018-15, "Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract" (Issued August 2018): ASU 2018-15 allows implementation costs incurred by customers in cloud computing arrangements to be deferred and recognized over the term of the
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arrangement, if those costs would be capitalized by the customers in a software licensing arrangement. FirstEnergy adopted this standard as of January 1, 2020, with no material impact to its financial statements.
ASU 2020-04, "Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (Issued March 2020): ASU 2020-04 provides temporary optional expedients and exceptions to the current guidance on contract modifications to ease the financial reporting burdens related to the expected market transition from LIBOR and other interbank offered rates to alternative reference rates. FirstEnergy’s term loan maturing September 2020 with $750 million currently outstanding and $3.5 billion Revolving Credit Facility bear interest at fluctuating interest rates based on LIBOR. These agreements contain provisions (requiring an amendment) in the event that LIBOR can no longer be used. As of March 31, 2020, FirstEnergy has not utilized any of the expedients discussed within this ASU, however, it continues to assess other areas to determine if LIBOR is included and if the expedients would be utilized through the allowed period of December 2022.
Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB has not yet been adopted. Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable. FirstEnergy has assessed other FASB issuances of new standards not described below based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting.
ASU 2019-12, "Simplifying the Accounting for Income Taxes" (Issued in December 2019): ASU 2019-12 enhances and simplifies various aspects of the income tax accounting guidance including the elimination of certain exceptions related to the approach for intra-period tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. The new guidance also simplifies aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020, with early adoption permitted.
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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” in Item 2 above.

ITEM 4. | CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures
The management of FirstEnergy, with the participation of the Chief Executive Officer and Chief Financial Officer, have reviewed and evaluated the effectiveness of its disclosure controls and procedures, as defined under the Securities Exchange Act of 1934, as amended, in Rules 13a-15(e) and 15d-15(e), as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of FirstEnergy have concluded that its 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 March 31, 2020, there were no changes in internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) that have materially affected, or are reasonably likely to materially affect, 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 9, “Regulatory Matters,” and Note 10, “Commitments, Guarantees and Contingencies,” of the 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 "Item 1A. Risk Factors" in the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2019, which could materially affect the Registrants' business, financial condition or future results. The information set forth in this report, including without limitation, the risk factor presented below, updates and should be read in conjunction with, the risk factors and information disclosed in the Registrant’s Annual Report on Form 10-K. In addition, because we cannot predict the impact that COVID-19 will ultimately have, the actual impact may also exacerbate other risks discussed in Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019, any of which could have a material effect on us. The situation remains fluid and while we have not incurred significant disruptions thus far from the COVID-19 global pandemic, the likelihood of an adverse impact could increase the longer the global pandemic persists.
The COVID-19 Global Pandemic Has Impacted Us and Could Have an Adverse Effect on Our Business, Results of Operations, Cash Flows and Financial Condition
The outbreak of COVID-19 has become a global pandemic and has impacted FirstEnergy. For instance, FirstEnergy’s Utilities discontinued power shutoffs as of March 13, 2020, across its five-state service territory and ceased billing for certain late payment charges. Furthermore, in response to the pandemic and related mitigation measures, FirstEnergy has implemented its pandemic plan as well as other precautionary measures on behalf of its customers and employees, including supporting remote work opportunities for most of its employees. While FirstEnergy believes that all these measures have been necessary or appropriate, they have resulted in additional costs and may adversely impact its business and results of operation in the future or expose it to additional unknown risks.
Although it is not possible to predict the ultimate impact of COVID-19, including on FirstEnergy’s business, results of operations, cash flows or financial positions, such impacts that may be material include, but are not limited to: (i) lower commercial and industrial customer demand for electricity, (ii) impacts of rapidly-changing governmental and public health directives to contain and combat the pandemic, (iii) increased credit risk, including increased failure by customers to make their utility payments, (iv) reduced availability and productivity of its employees, (v) increased operational risks as a result of remote work arrangements, including the potential effects on internal controls, as well as cybersecurity risks and increased vulnerability to security breaches, information technology disruptions and other similar events, (vi) delays and disruptions in the availability of and timely delivery of materials and components used in its operations, as well as increased costs for such materials and components, (vii) continued volatility in market prices for our securities, and (viii) hampering our ability to access funds from financial institutions and the capital markets. To the extent the duration of any of these conditions extends for a longer period of time, the adverse impact will generally be more severe.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
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ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS

Exhibit Number | Description
(A) (B) | 10.1 |  | Form of 2020-2022 Cash-Based Performance-Adjusted Restricted Stock Unit Award Agreement.
(A) (B) | 10.2 |  | Form of 2020-2022 Stock-Based Performance-Adjusted Restricted Stock Unit Award Agreement.
(A) (B) | 10.3 |  | Form of 2020 Restricted Stock Award Agreement.
(A) | 31.1 |  | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a).
(A) | 31.2 |  | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a).
(A) | 32 |  | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
| 101 |  | The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended March 31, 2020, formatted in iXBRL (Inline Extensible Business Reporting Language): (i) Consolidated Statements of Income and Consolidated Statements of Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements and (v) document and entity information.
| 104 |  | Cover Page Interactive Data File (the cover page XBRL tags are embedded within the Inline XBRL document)

(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 FirstEnergy has 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 hereby agrees to furnish to the SEC on request any such documents.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
April 23, 2020

| FIRSTENERGY CORP.
| Registrant
| /s/ Jason J. Lisowski
| Jason J. Lisowski
| Vice President, Controller and Chief Accounting Officer

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