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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 September 30, 2019
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 SEPTEMBER 30, 2019
Common Stock, $0.10 par value |  | 540,311,707 |

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 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 ability to successfully execute an exit from commodity-based generation, including, without limitation, mitigating exposure for remedial activities associated with formerly owned generation assets.

• | The risks associated with the FES Bankruptcy that could adversely affect us, our liquidity or results of operations, including, without limitation, that conditions to the FES Bankruptcy settlement agreement may not be met or that the FES Bankruptcy settlement agreement may not be otherwise consummated, and if so, the potential for litigation and payment demands against us by FES or FENOC or their creditors.

• | The ability to accomplish or realize anticipated benefits from strategic and financial goals, including, but not limited to, our strategy to operate and grow as a fully regulated business, to execute our transmission and distribution investment plans, to continue to reduce costs through FE Tomorrow and other initiatives, and to improve our credit metrics, strengthen our balance sheet and grow 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 associated with the decommissioning of our retired and former nuclear facilities.

• | 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, including the Tax Act, 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 (Loss) | 1
Consolidated Statements of Comprehensive Income (Loss) | 2
Consolidated Balance Sheets | 3
Consolidated Statements of Cash Flows | 4
Notes To Consolidated Financial Statements | 5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations | 41
Item 3. Quantitative and Qualitative Disclosures About Market Risk | 78
Item 4. Controls and Procedures | 78
Part II. Other Information |
Item 1. Legal Proceedings | 78
Item 1A. Risk Factors | 78
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds | 78
Item 3. Defaults Upon Senior Securities | 78
Item 4. Mine Safety Disclosures | 78
Item 5. Other Information | 78
Item 6. Exhibits | 79

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 | Allegheny Energy, Inc., a Maryland utility holding company that merged with a subsidiary of FirstEnergy on February 25, 2011, which subsequently merged with and into FE on January 1, 2014
AE Supply | Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary
AGC | Allegheny Generating Company, formerly a generation subsidiary of AE Supply that became a wholly owned subsidiary of MP in May 2018
ATSI | American Transmission Systems, Incorporated, formerly a direct subsidiary of FE that became a subsidiary of FET in April 2012, which owns and operates transmission facilities
BSPC | Bay Shore Power Company
CEI | The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
CES | Competitive Energy Services, formerly a reportable operating segment of FirstEnergy
FE | FirstEnergy Corp., a public utility holding company
FENOC | FirstEnergy Nuclear Operating Company which operates NG’s nuclear generating facilities
FES | FirstEnergy Solutions Corp., together with its consolidated subsidiaries, FG, NG, FE Aircraft Leasing Corp., Norton Energy Storage LLC, and FGMUC, which provides energy-related products and services
FES Debtors | FES and FENOC
FESC | FirstEnergy Service Company, which provides legal, financial and other corporate support services
FET | FirstEnergy Transmission, LLC, formerly known as Allegheny Energy Transmission, LLC, which is the parent 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 | FirstEnergy Generation, LLC, a wholly owned subsidiary of FES, which owns and operates non-nuclear generating facilities
FGMUC | FirstEnergy Generation Mansfield Unit 1 Corp., a wholly owned subsidiary of FG, which has certain leasehold interests in a portion of Unit 1 at the Bruce Mansfield plant
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 | FirstEnergy Nuclear Generation, LLC, a wholly owned subsidiary of FES, 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 |  | ESP IV | Electric Security Plan IV
ADIT | Accumulated Deferred Income Taxes |  | Facebook® | Facebook is a registered trademark of Facebook, Inc.
AEP | American Electric Power Company, Inc. |  | FASB | Financial Accounting Standards Board
AFS | Available-for-sale |  | FERC | Federal Energy Regulatory Commission
AFUDC | Allowance for Funds Used During Construction |  | FE Tomorrow | FirstEnergy’s initiative launched in late 2016 to identify its optimal organizational structure and properly align corporate costs and systems to efficiently support a fully regulated company going forward
ALJ | Administrative Law Judge |  | FES Bankruptcy | FES Debtors’ voluntary petitions for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code with the Bankruptcy Court
AOCI | Accumulated Other Comprehensive Income |  | Fitch | Fitch Ratings
ARO | Asset Retirement Obligation |  | FMB | First Mortgage Bond
ARP | Alternative Revenue Program |  | FPA | Federal Power Act
ASC | Accounting Standard Codification |  | FTR | Financial Transmission Right
ASU | Accounting Standards Update |  | GAAP | Accounting Principles Generally Accepted in the United States of America
Bankruptcy Court | U.S. Bankruptcy Court in the Northern District of Ohio in Akron |  | GHG | Greenhouse Gases
Bath County | Bath County Pumped Storage Hydro-Power Station |  | IIP | Infrastructure Investment Program
BGS | Basic Generation Service |  | kW | Kilowatt
CAA | Clean Air Act |  | LBR | Little Blue Run
CCR | Coal Combustion Residuals |  | LCAPP | Long-Term Capacity Agreement Pilot Program
CERCLA | Comprehensive Environmental Response, Compensation, and Liability Act of 1980 |  | LIBOR | London Interbank Offered Rate
CFR | Code of Federal Regulations |  | LOC | Letter of Credit
CO 2 | Carbon Dioxide |  | LTIIPs | Long-Term Infrastructure Improvement Plans
CPP | EPA’s Clean Power Plan |  | MDPSC | Maryland Public Service Commission
CSAPR | Cross-State Air Pollution Rule |  | MGP | Manufactured Gas Plants
CTA | Consolidated Tax Adjustment |  | MISO | Midcontinent Independent System Operator, Inc.
CWA | Clean Water Act |  | mmBTU | One Million British Thermal Units
D.C. Circuit | United States Court of Appeals for the District of Columbia Circuit |  | Moody’s | Moody’s Investors Service, Inc.
DCR | Delivery Capital Recovery |  | MW | Megawatt
DMR | Distribution Modernization Rider |  | MWH | Megawatt-hour
DPM | Distribution Platform Modernization |  | NAAQS | National Ambient Air Quality Standards
DSIC | Distribution System Improvement Charge |  | NDT | Nuclear Decommissioning Trust
DSP | Default Service Plan |  | NERC | North American Electric Reliability Corporation
EDC | Electric Distribution Company |  | NJBPU | New Jersey Board of Public Utilities
EDCP | Executive Deferred Compensation Plan |  | NMB | Non-Market Based
EDIS | Electric Distribution Investment Surcharge |  | NOI | Notice of Inquiry
EE&C | Energy Efficiency and Conservation |  | NOL | Net Operating Loss
EEI | Edison Electric Institute |  | NOPR | Notice of Proposed Rulemaking
EGS | Electric Generation Supplier |  | NOx | Nitrogen Oxide
EGU | Electric Generation Units |  | NRC | Nuclear Regulatory Commission
EmPOWER Maryland | EmPOWER Maryland Energy Efficiency Act |  | NUG | Non-Utility Generation
ENEC | Expanded Net Energy Cost |  | NYPSC | New York State Public Service Commission
EPA | United States Environmental Protection Agency |  | OCA | Office of Consumer Advocate
EPS | Earnings per Share |  | OCC | Ohio Consumers’ Counsel
ERO | Electric Reliability Organization |  | OEPA | Ohio Environmental Protection Agency

iii

OMAEG | Ohio Manufacturers’ Association Energy Group |  | RTEP | Regional Transmission Expansion Plan
OPEB | Other Post-Employment Benefits |  | RTO | Regional Transmission Organization
OPIC | Other Paid-in Capital |  | S&P | Standard & Poor’s Ratings Service
OVEC | Ohio Valley Electric Corporation |  | SBC | Societal Benefits Charge
PA DEP | Pennsylvania Department of Environmental Protection |  | SCOH | Supreme Court of Ohio
PJM | PJM Interconnection, LLC |  | SEC | United States Securities and Exchange Commission
PJM Tariff | PJM Open Access Transmission Tariff |  | SIP | State Implementation Plan(s) Under the Clean Air Act
POLR | Provider of Last Resort |  | SO 2 | Sulfur Dioxide
POR | Purchase of Receivables |  | SOS | Standard Offer Service
PPA | Purchase Power Agreement |  | SPE | Special Purpose Entity
PPB | Parts per Billion |  | SREC | Solar Renewable Energy Credit
PPUC | Pennsylvania Public Utility Commission |  | SSO | Standard Service Offer
PUCO | Public Utilities Commission of Ohio |  | Tax Act | Tax Cuts and Jobs Act adopted December 22, 2017
PURPA | Public Utility Regulatory Policies Act of 1978 |  | TMI-2 | Three Mile Island Unit 2
RCRA | Resource Conservation and Recovery Act |  | Twitter® | Twitter is a registered trademark of Twitter, Inc.
REC | Renewable Energy Credit |  | UCC | Official committee of unsecured creditors appointed in connection with the FES Bankruptcy
Regulation FD | Regulation Fair Disclosure promulgated by the SEC |  | VIE | Variable Interest Entity
RFC | Reliability First Corporation |  | VMS | Vegetation Management Surcharge
RFP | Request for Proposal |  | VSCC | Virginia State Corporation Commission
RGGI | Regional Greenhouse Gas Initiative |  | WVPSC | Public Service Commission of West Virginia
ROE | Return on Equity |  | ZEC | Zero Emissions Certificate

iv

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

|  | For the Three Months Ended September 30, |  | For the Nine Months Ended September 30,
(In millions, except per share amounts) |  | 2019 |  | 2018 |  | 2019 |  | 2018
REVENUES: |  |  |  |  |  |  |  |
Distribution services and retail generation |  | $ | 2,411 |  |  | $ | 2,463 |  |  | $ | 6,651 |  |  | $ | 6,807 |
Transmission |  | 371 |  |  | 341 |  |  | 1,090 |  |  | 996 |
Other |  | 181 |  |  | 260 |  |  | 621 |  |  | 748 |
Total revenues(1) |  | 2,963 |  |  | 3,064 |  |  | 8,362 |  |  | 8,551 |
OPERATING EXPENSES: |  |  |  |  |  |  |  |  |  |
Fuel |  | 122 |  |  | 137 |  |  | 382 |  |  | 404 |
Purchased power |  | 798 |  |  | 876 |  |  | 2,190 |  |  | 2,393 |
Other operating expenses |  | 758 |  |  | 739 |  |  | 2,143 |  |  | 2,363 |
Provision for depreciation |  | 304 |  |  | 283 |  |  | 910 |  |  | 843 |
Amortization (deferral) of regulatory assets, net |  | 43 |  |  | 67 |  |  | 85 |  |  | (188 | )
General taxes |  | 257 |  |  | 252 |  |  | 757 |  |  | 746 |
Total operating expenses |  | 2,282 |  |  | 2,354 |  |  | 6,467 |  |  | 6,561 |
OPERATING INCOME |  | 681 |  |  | 710 |  |  | 1,895 |  |  | 1,990 |
OTHER INCOME (EXPENSE): |  |  |  |  |  |  |  |  |  |
Miscellaneous income, net |  | 57 |  |  | 49 |  |  | 191 |  |  | 164 |
Interest expense |  | (261 | ) |  | (255 | ) |  | (773 | ) |  | (858 | )
Capitalized financing costs |  | 19 |  |  | 16 |  |  | 53 |  |  | 47 |
Total other expense |  | (185 | ) |  | (190 | ) |  | (529 | ) |  | (647 | )
INCOME BEFORE INCOME TAXES |  | 496 |  |  | 520 |  |  | 1,366 |  |  | 1,343 |
INCOME TAXES |  | 107 |  |  | 121 |  |  | 281 |  |  | 455 |
INCOME FROM CONTINUING OPERATIONS |  | 389 |  |  | 399 |  |  | 1,085 |  |  | 888 |
Discontinued operations (Note 3)(2) |  | 2 |  |  | (857 | ) |  | (62 | ) |  | 322 |
NET INCOME (LOSS) |  | $ | 391 |  |  | $ | (458 | ) |  | $ | 1,023 |  |  | $ | 1,210 |
INCOME ALLOCATED TO PREFERRED STOCKHOLDERS (Note 4) |  | — |  |  | 54 |  |  | 7 |  |  | 357 |
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS |  | $ | 391 |  |  | $ | (512 | ) |  | $ | 1,016 |  |  | $ | 853 |
EARNINGS PER SHARE OF COMMON STOCK (Note 4): |  |  |  |  |  |  |  |  |  |
Basic - Continuing Operations |  | $ | 0.72 |  |  | $ | 0.68 |  |  | $ | 2.02 |  |  | $ | 1.10 |
Basic - Discontinued Operations |  | 0.01 |  |  | (1.70 | ) |  | (0.12 | ) |  | 0.66 |
Basic - Net Income (Loss) Attributable to Common Stockholders |  | $ | 0.73 |  |  | $ | (1.02 | ) |  | $ | 1.90 |  |  | $ | 1.76 |
Diluted - Continuing Operations |  | $ | 0.72 |  |  | $ | 0.68 |  |  | $ | 2.00 |  |  | $ | 1.09 |
Diluted - Discontinued Operations |  | — |  |  | (1.70 | ) |  | (0.11 | ) |  | 0.66 |
Diluted - Net Income (Loss) Attributable to Common Stockholders |  | $ | 0.72 |  |  | $ | (1.02 | ) |  | $ | 1.89 |  |  | $ | 1.75 |
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING: |  |  |  |  |  |  |  |
Basic |  | 538 |  |  | 503 |  |  | 533 |  |  | 485 |
Diluted |  | 542 |  |  | 505 |  |  | 541 |  |  | 487 |

(1) Includes excise and gross receipts tax collections of $100 million and $104 million during the three months ended September 30, 2019 and 2018, respectively, and $283 million and $293 million during the nine months ended September 30, 2019 and 2018, respectively.
(2) Net of income tax expense (benefits) of $2 million and $(342) million for the three months ended September 30, 2019 and 2018, respectively, and $46 million and $(1.2) billion for the nine months ended September 30, 2019 and 2018, respectively.
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
1

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)

|  | For the Three Months Ended September 30, |  | For the Nine Months Ended September 30,
(In millions) |  | 2019 |  | 2018 |  | 2019 |  | 2018
NET INCOME (LOSS) |  | $ | 391 |  |  | $ | (458 | ) |  | $ | 1,023 |  |  | $ | 1,210 |
OTHER COMPREHENSIVE INCOME (LOSS): |  |  |  |  |  |  |  |  |  |
Pension and OPEB prior service costs |  | (7 | ) |  | (18 | ) |  | (21 | ) |  | (55 | )
Amortized losses on derivative hedges |  | — |  |  | 2 |  |  | 1 |  |  | 19 |
Change in unrealized gains on AFS securities |  | — |  |  | — |  |  | — |  |  | (106 | )
Other comprehensive loss |  | (7 | ) |  | (16 | ) |  | (20 | ) |  | (142 | )
Income tax benefits on other comprehensive loss |  | (3 | ) |  | (4 | ) |  | (6 | ) |  | (61 | )
Other comprehensive loss, net of tax |  | (4 | ) |  | (12 | ) |  | (14 | ) |  | (81 | )
COMPREHENSIVE INCOME (LOSS) |  | $ | 387 |  |  | $ | (470 | ) |  | $ | 1,009 |  |  | $ | 1,129 |

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) |  | September 30, 2019 |  | December 31, 2018
ASSETS |  |  |  |  |  |
CURRENT ASSETS: |  |  |  |  |  |
Cash and cash equivalents |  | $ | 716 |  |  | $ | 367 |
Restricted cash |  | 34 |  |  | 62 |
Receivables- |  |  |  |  |
Customers, net of allowance for uncollectible accounts of $46 in 2019 and $50 in 2018 |  | 1,130 |  |  | 1,221 |
Affiliated companies, net of allowance for uncollectible accounts of $945 in 2019 and $920 in 2018 |  | — |  |  | 20 |
Other, net of allowance for uncollectible accounts of $7 in 2019 and $2 in 2018 |  | 206 |  |  | 270 |
Materials and supplies, at average cost |  | 258 |  |  | 252 |
Prepaid taxes and other |  | 239 |  |  | 175 |
Current assets - discontinued operations |  | 33 |  |  | 25 |
|  | 2,616 |  |  | 2,392 |
PROPERTY, PLANT AND EQUIPMENT: |  |  |  |  |  |
In service |  | 41,016 |  |  | 39,469 |
Less — Accumulated provision for depreciation |  | 11,234 |  |  | 10,793 |
|  | 29,782 |  |  | 28,676 |
Construction work in progress |  | 1,370 |  |  | 1,235 |
|  | 31,152 |  |  | 29,911 |
INVESTMENTS: |  |  |  |  |  |
Nuclear plant decommissioning trusts |  | 871 |  |  | 790 |
Nuclear fuel disposal trust |  | 271 |  |  | 256 |
Other |  | 283 |  |  | 253 |
|  | 1,425 |  |  | 1,299 |
DEFERRED CHARGES AND OTHER ASSETS: |  |  |  |  |  |
Goodwill |  | 5,618 |  |  | 5,618 |
Regulatory assets |  | 77 |  |  | 91 |
Other |  | 618 |  |  | 752 |
|  | 6,313 |  |  | 6,461 |
|  | $ | 41,506 |  |  | $ | 40,063 |
LIABILITIES AND CAPITALIZATION |  |  |  |  |  |
CURRENT LIABILITIES: |  |  |  |  |  |
Currently payable long-term debt |  | $ | 381 |  |  | $ | 503 |
Short-term borrowings |  | 1,000 |  |  | 1,250 |
Accounts payable |  | 893 |  |  | 965 |
Accounts payable - affiliated companies |  | 46 |  |  | — |
Accrued taxes |  | 537 |  |  | 533 |
Accrued compensation and benefits |  | 268 |  |  | 318 |
Collateral |  | 30 |  |  | 39 |
Other |  | 1,084 |  |  | 1,026 |
|  | 4,239 |  |  | 4,634 |
CAPITALIZATION: |  |  |  |  |  |
Stockholders’ equity- |  |  |  |  |  |
Common stock, $0.10 par value, authorized 700,000,000 shares - 540,311,707 and 511,915,450 shares outstanding as of September 30, 2019 and December 31, 2018, respectively |  | 54 |  |  | 51 |
Preferred stock, $100 par value, authorized 5,000,000 shares, of which 1,616,000 are designated Series A Convertible Preferred - none outstanding as of September 30, 2019, and 704,589 shares outstanding as of December 31, 2018 |  | — |  |  | 71 |
Other paid-in capital |  | 11,047 |  |  | 11,530 |
Accumulated other comprehensive income |  | 27 |  |  | 41 |
Accumulated deficit |  | (3,856 | ) |  | (4,879 | )
Total stockholders’ equity |  | 7,272 |  |  | 6,814 |
Long-term debt and other long-term obligations |  | 19,422 |  |  | 17,751 |
|  | 26,694 |  |  | 24,565 |
NONCURRENT LIABILITIES: |  |  |  |  |  |
Accumulated deferred income taxes |  | 2,900 |  |  | 2,502 |
Retirement benefits |  | 2,403 |  |  | 2,906 |
Regulatory liabilities |  | 2,605 |  |  | 2,498 |
Asset retirement obligations |  | 844 |  |  | 812 |
Adverse power contract liability |  | 66 |  |  | 89 |
Other |  | 1,755 |  |  | 2,057 |
|  | 10,573 |  |  | 10,864 |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 13) |  |  |  |  |  |
|  | $ | 41,506 |  |  | $ | 40,063 |

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

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

|  | For the Nine Months Ended September 30,
(In millions) |  | 2019 |  | 2018
CASH FLOWS FROM OPERATING ACTIVITIES: |  |  |  |
Net income |  | $ | 1,023 |  |  | $ | 1,210 |
Adjustments to reconcile net income to net cash from operating activities- |  |  |  |
Loss (gain) on disposal, net of tax (Note 3) |  | 16 |  |  | (405 | )
Depreciation and amortization, including regulatory assets, net, intangible assets and deferred debt-related costs |  | 1,069 |  |  | 1,003 |
Deferred income taxes and investment tax credits, net |  | 251 |  |  | 462 |
Retirement benefits, net of payments |  | (81 | ) |  | (113 | )
Pension trust contributions |  | (500 | ) |  | (1,250 | )
Changes in current assets and liabilities- |  |  |  |
Receivables |  | 228 |  |  | (254 | )
Materials and supplies |  | (14 | ) |  | 43 |
Prepaid taxes and other |  | (69 | ) |  | (114 | )
Accounts payable |  | (102 | ) |  | 125 |
Accrued taxes |  | (105 | ) |  | (125 | )
Accrued compensation and benefits |  | (68 | ) |  | (19 | )
Other current liabilities |  | 29 |  |  | (140 | )
Collateral, net |  | (9 | ) |  | (21 | )
Other |  | 69 |  |  | 156 |
Net cash provided from operating activities |  | 1,737 |  |  | 558 |
CASH FLOWS FROM FINANCING ACTIVITIES: |  |  |  |
New financing- |  |  |  |
Long-term debt |  | 2,100 |  |  | 624 |
Short-term borrowings, net |  | — |  |  | 1,400 |
Preferred stock issuance |  | — |  |  | 1,616 |
Common stock issuance |  | — |  |  | 850 |
Redemptions and repayments- |  |  |  |
Long-term debt |  | (784 | ) |  | (2,278 | )
Make-whole premiums paid on debt redemptions |  | — |  |  | (89 | )
Preferred stock dividend payments |  | (6 | ) |  | (52 | )
Common stock dividend payments |  | (609 | ) |  | (527 | )
Other |  | (36 | ) |  | (21 | )
Net cash provided from financing activities |  | 665 |  |  | 1,523 |
CASH FLOWS FROM INVESTING ACTIVITIES: |  |  |  |
Property additions |  | (1,912 | ) |  | (1,942 | )
Proceeds from asset sales |  | 18 |  |  | 419 |
Sales of investment securities held in trusts |  | 506 |  |  | 736 |
Purchases of investment securities held in trusts |  | (536 | ) |  | (780 | )
Notes receivable from affiliated companies |  | — |  |  | (500 | )
Asset removal costs |  | (158 | ) |  | (171 | )
Other |  | 1 |  |  | 1 |
Net cash used for investing activities |  | (2,081 | ) |  | (2,237 | )
Net change in cash, cash equivalents, and restricted cash |  | 321 |  |  | (156 | )
Cash, cash equivalents, and restricted cash at beginning of period |  | 429 |  |  | 643 |
Cash, cash equivalents, and restricted cash at end of period |  | $ | 750 |  |  | $ | 487 |
SUPPLEMENTAL CASH FLOW INFORMATION: |  |  |  |
Non-cash transaction, beneficial conversion feature (Note 4) |  | $ | — |  |  | $ | 296 |
Non-cash transaction, deemed dividend preferred stock (Note 4) |  | $ | — |  |  | $ | (296 | )

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
4

FIRSTENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note Number |  | Page Number
1 | Organization and Basis of Presentation | 6
2 | Revenue | 8
3 | Discontinued Operations | 12
4 | Earnings Per Share of Common Stock | 15
5 | Pension and Other Postemployment Benefits | 17
6 | Accumulated Other Comprehensive Income | 18
7 | Income Taxes | 19
8 | Leases | 20
9 | Capitalization | 23
10 | Variable Interest Entities | 25
11 | Fair Value Measurements | 25
12 | Regulatory Matters | 29
13 | Commitments, Guarantees and Contingencies | 34
14 | Segment Information | 39

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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, 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: Allegheny Energy Service Corporation, FirstEnergy Properties, Inc., FEV, FELHC, Inc., GPUN, and Allegheny Ventures, Inc.
FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity. FirstEnergy’s ten utility operating companies comprise one of the nation’s largest investor-owned electric systems, based on serving over six million customers in the Midwest and Mid-Atlantic regions. FirstEnergy’s transmission operations include approximately 24,500 miles of lines and two regional transmission operation centers. 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, 2018.
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 (see Note 10, “Variable Interest Entities”). Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but do not have a controlling financial interest, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage of FE’s ownership share of the entity’s earnings is reported in the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss).
Certain prior year amounts have been reclassified to conform to the current year presentation.
FES and FENOC Chapter 11 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). As a result of the bankruptcy filings, FirstEnergy concluded that it no longer had a controlling interest in the FES Debtors as the entities are subject to the jurisdiction of the Bankruptcy Court and, accordingly, as of March 31, 2018, the FES Debtors were deconsolidated from FirstEnergy’s consolidated financial statements. Since such time, FE has accounted and will account for its investments in the FES Debtors at fair values of zero. FE concluded that in connection with the disposal, FES and FENOC became discontinued operations. See Note 3, “Discontinued Operations,” for additional information.
On September 26, 2018, the Bankruptcy Court approved a FES Bankruptcy settlement agreement dated August 26, 2018, 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 resolves certain claims by FirstEnergy against the FES Debtors and all claims by the FES Debtors and the FES Key Creditor Groups against FirstEnergy, and includes the following terms, among others:

• | FE will pay certain pre-petition FES Debtors employee-related obligations, which include unfunded pension obligations and other employee benefits.

• | FE will waive all pre-petition claims (other than those claims under the Tax Allocation Agreement for the 2018 tax year) and certain post-petition claims, against the FES Debtors related to the FES Debtors and their businesses, including the full borrowings by FES under the $500 million secured credit facility, the $200 million credit agreement being used to

6

support surety bonds, the BNSF Railway Company/CSX Transportation, Inc. rail settlement guarantee, and the FES Debtors’ unfunded pension obligations.

• | A nonconsensual release of all claims against FirstEnergy by the FES Debtors’ creditors, which was subsequently waived pursuant to the Waiver Agreement, discussed below.

• | A $225 million cash payment from FirstEnergy.

• | A $628 million aggregate principal amount note issuance by FirstEnergy to the FES Debtors, which may be decreased by the amount, if any, of cash paid by FirstEnergy to the FES Debtors under the Intercompany Income Tax Allocation Agreement for the tax benefits related to the sale or deactivation of certain plants.

• | Transfer of the Pleasants Power Station and related assets, including the economic interests therein as of January 1, 2019, and a requirement that FE continue to provide access to the McElroy’s Run CCR Impoundment Facility, which is not being transferred. FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility.

• | FirstEnergy agrees to waive all pre-petition claims related to shared services and credit for nine months of the FES Debtors’ shared service costs beginning as of April 1, 2018 through December 31, 2018, in an amount not to exceed $112.5 million, and FirstEnergy agrees to extend the availability of shared services until no later than June 30, 2020.

• | Subject to a cap, FirstEnergy has 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 (approximately $14 million recognized in the first nine months of 2019).

• | FirstEnergy agrees to perform under the Intercompany Tax Allocation Agreement through the FES Debtors’ emergence from bankruptcy, at which time FirstEnergy will waive a 2017 overpayment for NOLs of approximately $71 million, reverse 2018 estimated payments for NOLs of approximately $88 million and pay the FES Debtors for the use of NOLs in an amount no less than $66 million for 2018. Based on the 2018 federal tax return filed in September 2019, FirstEnergy owes the FES debtors approximately $31 million associated with 2018, which will be paid upon emergence.

The FES Bankruptcy settlement agreement remains subject to satisfaction of certain conditions. There can be no assurance that such conditions will be satisfied or the FES Bankruptcy settlement agreement will be otherwise consummated, and the actual outcome of this matter may differ materially from the terms of the agreement described herein. FirstEnergy will continue to evaluate the impact of any new factors on the settlement and their relative impact on the financial statements.
In connection with the FES Bankruptcy settlement agreement, FirstEnergy entered into a separation agreement with the FES Debtors to implement the separation of the FES Debtors and their businesses from FirstEnergy. A business separation committee was established between FirstEnergy and the FES Debtors to review and determine issues that arise in the context of the separation of the FES Debtors’ businesses from those of FirstEnergy.
As contemplated under the FES Bankruptcy settlement agreement, AE Supply entered into an agreement on December 31, 2018, to transfer the 1,300 MW Pleasants Power Station and related assets to FG, while retaining certain specified liabilities. Under the terms of the agreement, FG acquired the economic interests in Pleasants as of January 1, 2019, and AE Supply will operate Pleasants until the transfer is completed. After closing, AE Supply will continue to provide access to the McElroy’s Run CCR Impoundment Facility, which is not being transferred, and FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility. The transfer of the Pleasants Power Station is subject to various customary and other closing conditions, including the effectiveness of a plan of reorganization for the FES Debtors in connection with the FES Bankruptcy. There can be no assurance that all closing conditions will be satisfied or that the transfer will be consummated.
On April 11, 2019, the Bankruptcy Court entered an order denying the FES Debtors’ disclosure statement approval motion. The Bankruptcy Court concluded that the nonconsensual third-party releases proposed under the plan of reorganization, which were a condition under the FES Bankruptcy settlement agreement for FirstEnergy’s benefit, were legally impermissible and rendered the plan unconfirmable. On April 18, 2019, FirstEnergy consented to the waiver of the condition. Additionally, the FES Debtors agreed to provide FirstEnergy with the same third-party release provided in favor of certain other parties in any plan of reorganization and to pay FirstEnergy approximately $60 million in cash (paid during the second quarter of 2019) to resolve certain outstanding pension and service charges totaling $87 million, which resulted in FirstEnergy recognizing a $27 million pre-tax charge to income in the first quarter of 2019 ($17 million of which was recognized in continuing operations). Further, the FES Debtors agreed to initiate negotiations with the EPA, OEPA, PA DEP and the NRC to obtain those parties’ cooperation with the FES Debtors’ revised plan of reorganization. FirstEnergy may choose to participate in those negotiations at its option. On May 20, 2019, the Bankruptcy Court approved the waiver and a revised disclosure statement.
In August 2019, the Bankruptcy Court held hearings to consider whether to confirm the FES Debtors’ plan of reorganization. Upon the conclusion of the hearing, the Bankruptcy Court ruled against the objections of several parties, including FERC and OVEC. However, the Bankruptcy Court ruled in favor of the objections made by certain of the FES Debtors’ unions regarding their collective bargaining agreements. The Bankruptcy Court adjourned the hearing without ruling on confirmation and explained that the only issue to be resolved was the acceptance or rejection by the FES Debtors of the collective bargaining agreements at issue.
In October 2019, the FES Debtors and the unions objecting to confirmation of the plan of reorganization reached an agreement framework and the unions agreed to withdraw their objections to the plan of reorganization. On October 15, 2019, the Bankruptcy Court held a hearing to confirm the FES Debtors’ plan of reorganization, and on October 16, 2019, entered a final order confirming the FES Debtors' plan of reorganization. On October 29, 2019, several parties, including FERC, filed notices of appeal with the
7

United States District Court for the Northern District of Ohio appealing the Bankruptcy Court’s final order approving FES Debtors’ plan of reorganization. The emergence of the FES Debtors from bankruptcy pursuant to the confirmed plan of reorganization is subject to the satisfaction of certain conditions, including approvals from the FERC and NRC.
Capitalized Financing Costs
For each of the three months ended September 30, 2019 and 2018, capitalized financing costs on FirstEnergy’s Consolidated Statements of Income (Loss) include $12 million and $11 million, respectively, of allowance for equity funds used during construction and $7 million and $5 million, respectively, of capitalized interest. For each of the nine months ended September 30, 2019 and 2018, capitalized financing costs on FirstEnergy’s Consolidated Statements of Income (Loss) include $34 million and $33 million, respectively, of allowance for equity funds used during construction and $19 million and $14 million, respectively, of capitalized interest.
Restricted Cash
Restricted cash primarily relates to the consolidated VIE’s discussed in Note 10, “Variable Interest Entities.” The cash collected from JCP&L, MP, PE and the Ohio Companies’ customers is used to service debt of their respective funding companies.
New Accounting Pronouncements
Recently Adopted Pronouncements
ASU 2016-02, "Leases (Topic 842)" (Issued February 2016 and subsequently updated to address implementation questions): The new guidance requires organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets, as well as new qualitative and quantitative disclosures. FirstEnergy implemented a third-party software tool that assisted with the initial adoption and will assist with ongoing compliance. FirstEnergy chose to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. Upon adoption, on January 1, 2019, FirstEnergy increased assets and liabilities by $186 million, with no impact to results of operations or cash flows. See Note 8, "Leases," for additional information on FirstEnergy's leases.
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 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. The ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. FirstEnergy has analyzed its financial instruments within the scope of this guidance, primarily trade receivables and AFS debt securities, and does not expect a material impact to its financial statements upon adoption in 2020.
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 requires 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. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. FirstEnergy does not expect a material impact to its financial statements upon adoption in 2020.
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, with the exception of JCP&L transmission, utilizes the optional short-term contract exemption for transmission revenues due to the annual establishment of revenue requirements, which eliminates the need to provide certain revenue disclosures regarding unsatisfied performance obligations.
FirstEnergy’s revenues are primarily derived from electric service provided by the Utilities and Transmission Companies.
8

The following tables represent a disaggregation of revenue from contracts with customers for the three months ended September 30, 2019 and 2018, by type of service from each reportable segment:

|  | For the Three Months Ended September 30, 2019
Revenues by Type of Service |  | Regulated Distribution |  | Regulated Transmission |  | Corporate/Other and Reconciling Adjustments (1) |  | Total
|  | (In millions)
Distribution services(2) |  | $ | 1,457 |  |  | $ | — |  |  | $ | (21 | ) |  | $ | 1,436 |
Retail generation |  | 989 |  |  | — |  |  | (14 | ) |  | 975 |
Wholesale sales |  | 100 |  |  | — |  |  | 2 |  |  | 102 |
Transmission(2) |  | — |  |  | 371 |  |  | — |  |  | 371 |
Other |  | 42 |  |  | — |  |  | — |  |  | 42 |
Total revenues from contracts with customers |  | $ | 2,588 |  |  | $ | 371 |  |  | $ | (33 | ) |  | $ | 2,926 |
ARP |  | 25 |  |  | — |  |  | — |  |  | 25 |
Other non-customer revenue |  | 23 |  |  | 4 |  |  | (15 | ) |  | 12 |
Total revenues |  | $ | 2,636 |  |  | $ | 375 |  |  | $ | (48 | ) |  | $ | 2,963 |

(1) Includes eliminations and reconciling adjustments of inter-segment revenues.
(2) Includes reductions to revenue related to amounts subject to refund resulting from the Tax Act ($4 million at Regulated Distribution and $4 million at Regulated Transmission) and Rider DMR as discussed in Note 12, “Regulatory Matters” (approximately $31 million at Regulated Distribution).

|  | For the Three Months Ended September 30, 2018
Revenues by Type of Service |  | Regulated Distribution |  | Regulated Transmission |  | Corporate/Other and Reconciling Adjustments (1) |  | Total
|  | (In millions)
Distribution services(2) |  | $ | 1,440 |  |  | $ | — |  |  | $ | (22 | ) |  | $ | 1,418 |
Retail generation |  | 1,059 |  |  | — |  |  | (14 | ) |  | 1,045 |
Wholesale sales |  | 133 |  |  | — |  |  | 6 |  |  | 139 |
Transmission(2) |  | — |  |  | 341 |  |  | — |  |  | 341 |
Other |  | 43 |  |  | — |  |  | — |  |  | 43 |
Total revenues from contracts with customers |  | $ | 2,675 |  |  | $ | 341 |  |  | $ | (30 | ) |  | $ | 2,986 |
ARP |  | 66 |  |  | — |  |  | — |  |  | 66 |
Other non-customer revenue |  | 25 |  |  | 5 |  |  | (18 | ) |  | 12 |
Total revenues |  | $ | 2,766 |  |  | $ | 346 |  |  | $ | (48 | ) |  | $ | 3,064 |

(1) Includes eliminations and reconciling adjustments of inter-segment revenues.
(2) Includes $29 million in net reductions to revenue related to amounts subject to refund resulting from the Tax Act ($27 million at Regulated Distribution and $2 million at Regulated Transmission).
Other non-customer revenue includes revenue from late payment charges of $9 million for both the three months ended September 30, 2019 and 2018, as well as revenue from derivatives of $2 million and $4 million, for the three months ended September 30, 2019 and 2018, respectively.
9

The following tables represent a disaggregation of revenue from contracts with customers for the nine months ended September 30, 2019 and 2018, by type of service from each reportable segment:

|  | For the Nine Months Ended September 30, 2019
Revenues by Type of Service |  | Regulated Distribution |  | Regulated Transmission |  | Corporate/Other and Reconciling Adjustments (1) |  | Total
|  | (In millions)
Distribution services(2) |  | $ | 3,903 |  |  | $ | — |  |  | $ | (63 | ) |  | $ | 3,840 |
Retail generation |  | 2,853 |  |  | — |  |  | (42 | ) |  | 2,811 |
Wholesale sales |  | 316 |  |  | — |  |  | 9 |  |  | 325 |
Transmission(2) |  | — |  |  | 1,090 |  |  | — |  |  | 1,090 |
Other |  | 113 |  |  | — |  |  | 1 |  |  | 114 |
Total revenues from contracts with customers |  | $ | 7,185 |  |  | $ | 1,090 |  |  | $ | (95 | ) |  | $ | 8,180 |
ARP |  | 142 |  |  | — |  |  | — |  |  | 142 |
Other non-customer revenue |  | 74 |  |  | 13 |  |  | (47 | ) |  | 40 |
Total revenues |  | $ | 7,401 |  |  | $ | 1,103 |  |  | $ | (142 | ) |  | $ | 8,362 |

(1) Includes eliminations and reconciling adjustments of inter-segment revenues.
(2) Includes reductions to revenue related to amounts subject to refund resulting from the Tax Act ($31 million at Regulated Distribution and $11 million at Regulated Transmission) and Rider DMR as discussed in Note 12, “Regulatory Matters” (approximately $31 million at Regulated Distribution).

|  | For the Nine Months Ended September 30, 2018
Revenues by Type of Service |  | Regulated Distribution |  | Regulated Transmission |  | Corporate/Other and Reconciling Adjustments (1) |  | Total
|  | (In millions)
Distribution services(2) |  | $ | 3,949 |  |  | $ | — |  |  | $ | (81 | ) |  | $ | 3,868 |
Retail generation |  | 2,981 |  |  | — |  |  | (42 | ) |  | 2,939 |
Wholesale sales |  | 377 |  |  | — |  |  | 16 |  |  | 393 |
Transmission(2) |  | — |  |  | 996 |  |  | — |  |  | 996 |
Other |  | 113 |  |  | — |  |  | 4 |  |  | 117 |
Total revenues from contracts with customers |  | $ | 7,420 |  |  | $ | 996 |  |  | $ | (103 | ) |  | $ | 8,313 |
ARP |  | 190 |  |  | — |  |  | — |  |  | 190 |
Other non-customer revenue |  | 84 |  |  | 14 |  |  | (50 | ) |  | 48 |
Total revenues |  | $ | 7,694 |  |  | $ | 1,010 |  |  | $ | (153 | ) |  | $ | 8,551 |

(1) Includes eliminations and reconciling adjustments of inter-segment revenues.
(2) Includes $113 million in reductions to revenue related to amounts subject to refund resulting from the Tax Act ($109 million at Regulated Distribution and $4 million at Regulated Transmission).
Other non-customer revenue includes revenue from late payment charges of $29 million and $28 million, as well as revenue from derivatives of $7 million and $18 million, for the nine months ended September 30, 2019 and 2018, respectively.
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 12, “Regulatory Matters,” for additional information on rate recovery mechanisms. Distribution and electric revenues are recognized over time as electricity is distributed and delivered to the customer and the customers consume the electricity immediately as delivery occurs.
Retail generation sales relate to POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland, as well as generation sales in West Virginia that are regulated by the WVPSC. Certain of the Utilities have default service
10

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 and nine months ended September 30, 2019 and 2018, by class:

|  | For the Three Months Ended September 30, |  | For the Nine Months Ended September 30,
Revenues by Customer Class |  | 2019 |  | 2018 |  | 2019 |  | 2018
|  | (In millions)
Residential |  | $ | 1,538 |  |  | $ | 1,572 |  |  | $ | 4,145 |  |  | $ | 4,290 |
Commercial |  | 600 |  |  | 628 |  |  | 1,759 |  |  | 1,778 |
Industrial |  | 286 |  |  | 276 |  |  | 786 |  |  | 792 |
Other |  | 22 |  |  | 23 |  |  | 66 |  |  | 70 |
Total Revenues |  | $ | 2,446 |  |  | $ | 2,499 |  |  | $ | 6,756 |  |  | $ | 6,930 |

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 gross as either revenues or purchased power on the Consolidated Statements of Income (Loss) 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 (Loss). 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, and in New Jersey. Please see Note 12, “Regulatory Matters,” for further discussion on Rider DMR.
Regulated Transmission
The Regulated Transmission segment provides transmission infrastructure owned and operated by ATSI, TrAIL, MAIT and certain of FirstEnergy’s utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment’s revenues are primarily derived from forward-looking formula rates at ATSI, TrAIL and MAIT, as well as stated transmission rates at JCP&L, MP, PE and WP. Both the forward-looking formula and stated rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. Revenue requirements under stated rates are calculated annually by multiplying the highest one-hour peak load in each respective transmission zone by the approved, stated rate in that zone. Revenues and cash receipts for the stand-ready obligation of providing transmission service are recognized ratably over time.
Effective January 1, 2018, JCP&L is subject to a FERC-approved settlement agreement that provides an annual revenue requirement of $155 million, which is recognized ratably as revenue over time.
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The following table represents a disaggregation of revenue from contracts with regulated transmission customers by transmission owner for the three and nine months ended September 30, 2019 and 2018, by transmission owner:

|  | For the Three Months Ended September 30, |  | For the Nine Months Ended September 30,
Transmission Owner |  | 2019 |  | 2018 |  | 2019 |  | 2018
|  | (In millions)
ATSI |  | $ | 184 |  |  | $ | 167 |  |  | $ | 542 |  |  | $ | 492 |
TrAIL |  | 55 |  |  | 60 |  |  | 172 |  |  | 183 |
MAIT |  | 58 |  |  | 43 |  |  | 157 |  |  | 106 |
Other |  | 74 |  |  | 71 |  |  | 219 |  |  | 215 |
Total Revenues |  | $ | 371 |  |  | $ | 341 |  |  | $ | 1,090 |  |  | $ | 996 |

3. DISCONTINUED OPERATIONS
FES, FENOC, BSPC and a portion of AE Supply (including the Pleasants Power Station), representing substantially all of FirstEnergy’s operations that previously comprised the CES reportable operating segment, are presented as discontinued operations in FirstEnergy’s consolidated financial statements resulting from the FES Bankruptcy and actions taken as part of the strategic review to exit commodity-exposed generation, as discussed below. Prior period results have been reclassified to conform with such presentation as discontinued operations.
FES and FENOC Chapter 11 Bankruptcy Filing
As discussed in Note 1, “Organization and Basis of Presentation,” on March 31, 2018, FES and FENOC announced the FES Bankruptcy. FirstEnergy concluded that it no longer had a controlling interest in the FES Debtors, as the entities are subject to the jurisdiction of the Bankruptcy Court and, accordingly, as of March 31, 2018, the FES Debtors were deconsolidated from FirstEnergy’s consolidated financial statements, and FirstEnergy has accounted and will account for its investments in the FES Debtors at fair values of zero. In connection with the disposal and the FES Bankruptcy settlement agreement approved by the Bankruptcy Court in September 2018, as further discussed in Note 1, “Organization and Basis of Presentation,” FE recorded an after-tax gain on disposal of $435 million in 2018.
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.
FES Borrowings from FE
On March 9, 2018, FES borrowed $500 million from FE under the secured credit facility, dated as of December 6, 2016, among FES, as Borrower, FG and NG as guarantors, and FE, as lender, which fully utilized the committed line of credit available under the secured credit facility. Following deconsolidation of FES, FE fully reserved for the $500 million associated with the borrowings under the secured credit facility. Under the terms of the FES Bankruptcy settlement agreement, FE will release any and all claims against the FES Debtors with respect to the $500 million borrowed under the secured credit facility.
On March 16, 2018, the FES Debtors withdrew from the unregulated companies’ money pool, which included FE, and the FES Debtors. Under the terms of the FES Bankruptcy settlement agreement, FE reinstated $88 million for 2018 estimated payments for NOLs applied against the FES Debtor’s position in the unregulated companies’ money pool prior to their withdrawal on March 16, 2018, which increased the amount the FES Debtors owed FE under the money pool to $92 million. In addition, as of March 31, 2018, AE Supply had a $102 million outstanding unsecured promissory note owed from FES. Following deconsolidation of the FES Debtors on March 31, 2018, and given the terms of the FES Bankruptcy settlement agreement, FE fully reserved the $92 million associated with the outstanding unsecured borrowings under the unregulated companies’ money pool and the $102 million associated with the AE Supply unsecured promissory note, under the terms of the FES Bankruptcy settlement agreement, FirstEnergy will release any and all claims against the FES Debtors with respect to the $92 million owed under the unregulated money pool and $102 million unsecured promissory note. For the nine months ended September 30, 2019 and 2018, approximately $26 million and $16 million of interest was accrued and subsequently reserved, respectively.
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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. 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. In addition to providing for certain notice requirements and other terms and conditions, the agreement provided for a credit to the FES Debtors in an amount up to $112.5 million for charges incurred for services provided under prior shared services agreements and the amended shared services agreement from April 1, 2018 through December 31, 2018. The entire credit for shared services provided to the FES Debtors ($112.5 million) has been recognized by FE and was included within the loss from discontinued operations as of December 31, 2018. The FES Debtors have paid approximately $20 million and $121 million for shared services for the three and nine months ended September 30, 2019, respectively.
Benefit Obligations
FirstEnergy will retain certain obligations for the FES Debtors’ employees for services provided prior to emergence from bankruptcy. The retention of this obligation at March 31, 2018, resulted in a net liability of $820 million (including EDCP, pension and OPEB) with a corresponding loss from discontinued operations. EDCP and pension/OPEB service costs earned by the FES Debtors’ employees during bankruptcy are billed under the shared services agreement. As FE continues to provide pension benefits to FES/FENOC employees, certain components of pension cost, including the mark to market, are seen as providing ongoing services and are reported in the continuing operations of FE, subsequent to the bankruptcy filing. FE has billed the FES Debtors approximately $9 million and $28 million for their share of pension and OPEB service costs for the three and nine months ended September 30, 2019, respectively.
Purchase Power
FES at times provides power through affiliated company power sales to meet a portion of the Utilities’ POLR and default service requirements and provides power to certain affiliates’ facilities. As of September 30, 2019, the Utilities owed FES approximately $6 million related to these purchases. The terms and conditions of the power purchase agreements are generally consistent with industry practices and other similar third-party arrangements. The Utilities purchased and recognized in continuing operations approximately $24 million and $74 million of power purchases from FES for the three months ended September 30, 2019 and 2018, respectively, and $150 million and $248 million for the nine months ended September 30, 2019 and 2018, respectively.
Income Taxes
For U.S. federal income taxes, until emergence from bankruptcy, the FES Debtors will continue to be consolidated in FirstEnergy’s tax return and taxable income will be determined based on the tax basis of underlying individual net assets. Deferred taxes previously recorded on the inside basis differences may not represent the actual tax consequence for the outside basis difference, causing a recharacterization of an existing consolidated-return NOL as a future worthless stock deduction. FirstEnergy currently estimates a future worthless stock deduction of approximately $4.7 billion ($1.0 billion, net of tax) and is net of unrecognized tax benefits of $448 million ($94 million, net of tax). The estimated worthless stock deduction is contingent upon the emergence of the FES Debtors from the FES Bankruptcy and such amounts may be materially impacted by future events.
Additionally, discontinued operations include tax expense of approximately $17 million and $12 million for the three months ended September 30, 2019 and 2018, respectively, and $45 million and $48 million for the nine months ended September 30, 2019 and 2018, respectively, due to certain aspects of the Tax Act that apply as a result of the FES Debtors remaining a part of FirstEnergy’s consolidated tax return.
See Note 1, “Organization and Basis of Presentation,” for further discussion of the settlement among FirstEnergy, the FES Key Creditor Groups, the FES Debtors and the UCC.
Competitive Generation Asset Sales
FirstEnergy announced in January 2017 that AE Supply and AGC had entered into an asset purchase agreement with a subsidiary of LS Power Equity Partners III, LP, as amended and restated in August 2017, to sell four natural gas generating plants, AE Supply’s interest in the Buchanan Generating facility and approximately 59% of AGC’s interest in Bath County (1,615 MWs of combined capacity). On December 13, 2017, AE Supply completed the sale of the natural gas generating plants. On March 1, 2018, AE Supply completed the sale of the Buchanan Generating Facility. On May 3, 2018, AE Supply and AGC completed the sale of approximately 59% of AGC’s interest in Bath County. Also, on May 3, 2018, following the closing of the sale by AGC of a portion of its ownership interest in Bath County, AGC completed the redemption of AE Supply’s shares in AGC and AGC became a wholly owned subsidiary of MP.
On March 9, 2018, BSPC and FG entered into an asset purchase agreement with Walleye Power, LLC (formerly Walleye Energy, LLC), for the sale of the Bay Shore Generating Facility, including the 136 MW Bay Shore Unit 1 and other retired coal-fired generating equipment owned by FG. The Bankruptcy Court approved the sale on July 13, 2018, and the transaction was completed on July 31, 2018.
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
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terms of the agreement, FG acquired the economic interests in Pleasants as of January 1, 2019, and AE Supply will operate Pleasants until the transfer is completed. After closing, AE Supply will continue to provide access to the McElroy’s Run CCR Impoundment Facility, which is not being transferred, and FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility. The transfer of the Pleasants Power Station is subject to various customary and other closing conditions, including the effectiveness of a plan of reorganization for the FES Debtors in connection with the FES Bankruptcy. There can be no assurance that all closing conditions will be satisfied or that the transfer will be consummated.
Individually, the AE Supply and BSPC asset sales and Pleasants Power Station transfer did not qualify for reporting as discontinued operations. However, in the aggregate, the transactions were part of management’s strategic review to exit commodity-exposed generation and, when considered with FES’ and FENOC’s bankruptcy filings on March 31, 2018, represent a collective elimination of substantially all of FirstEnergy’s competitive generation fleet and meet the criteria for discontinued operations.
Summarized Results of Discontinued Operations
Summarized results of discontinued operations for the three and nine months ended September 30, 2019 and 2018, were as follows:

|  | For the Three Months Ended September 30, |  | For the Nine Months Ended September 30,
(In millions) |  | 2019 |  | 2018 |  | 2019 |  | 2018
Revenues |  | $ | 62 |  |  | $ | 83 |  |  | $ | 147 |  |  | $ | 934 |
Fuel |  | (50 | ) |  | (52 | ) |  | (105 | ) |  | (269 | )
Purchased power |  | — |  |  | — |  |  | — |  |  | (85 | )
Other operating expenses |  | (16 | ) |  | (24 | ) |  | (42 | ) |  | (414 | )
Provision for depreciation |  | — |  |  | (18 | ) |  | — |  |  | (96 | )
General taxes |  | (2 | ) |  | (4 | ) |  | (11 | ) |  | (32 | )
Other income (expense) (1) |  | 2 |  |  | (1 | ) |  | 10 |  |  | (82 | )
Loss from discontinued operations, before tax |  | (4 | ) |  | (16 | ) |  | (1 | ) |  | (44 | )
Income tax expense |  | 17 |  |  | 7 |  |  | 45 |  |  | 39 |
Loss from discontinued operations, net of tax |  | (21 | ) |  | (23 | ) |  | (46 | ) |  | (83 | )
Gain (loss) on disposal of FES and FENOC, net of tax |  | 23 |  |  | (834 | ) |  | (16 | ) |  | 405 |
Income (loss) from discontinued operations |  | $ | 2 |  |  | $ | (857 | ) |  | $ | (62 | ) |  | $ | 322 |

(1) Other income (expense) for the three and nine months ended September 30, 2019, reflects the amounts owed to or from FG for its economic interests in Pleasants effective January 1, 2019, as further discussed above.
The gain (loss) on disposal of FES and FENOC recognized in the three and nine months ended September 30, 2019 and 2018, consisted of the following:

|  | For the Three Months Ended September 30, |  | For the Nine Months Ended September 30,
(In millions) |  | 2019 |  | 2018 |  | 2019 |  | 2018
Removal of investment in FES and FENOC |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 2,193 |
Assumption of benefit obligations retained at FE |  | — |  |  | — |  |  | — |  |  | (820 | )
Guarantees and credit support provided by FE |  | — |  |  | — |  |  | — |  |  | (139 | )
Reserve on receivables and allocated pension/OPEB mark-to-market |  | — |  |  | — |  |  | — |  |  | (914 | )
Settlement consideration and services credit |  | 8 |  |  | (1,183 | ) |  | (15 | ) |  | (1,183 | )
Gain (loss) on disposal of FES and FENOC, before tax |  | 8 |  |  | (1,183 | ) |  | (15 | ) |  | (863 | )
Income tax benefit (expense), including estimated worthless stock deduction |  | 15 |  |  | 349 |  |  | (1 | ) |  | 1,268 |
Gain (loss) on disposal of FES and FENOC, net of tax |  | $ | 23 |  |  | $ | (834 | ) |  | $ | (16 | ) |  | $ | 405 |

As of September 30, 2019, and December 31, 2018, material and supplies of $33 million and $25 million, respectively, are included in FirstEnergy’s Consolidated Balance Sheets as Current assets - discontinued operations.
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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. The following table summarizes the major classes of cash flow items from discontinued operations for the nine months ended September 30, 2019 and 2018:

|  | For the Nine Months Ended September 30,
(In millions) |  | 2019 |  | 2018
CASH FLOWS FROM OPERATING ACTIVITIES: |  |  |  |
Income (loss) from discontinued operations |  | $ | (62 | ) |  | $ | 322 |
Depreciation and amortization, including regulatory assets, net, intangible assets and deferred debt-related costs |  | — |  |  | 110 |
CASH FLOWS FROM INVESTING ACTIVITIES: |  |  |  |
Property additions |  | — |  |  | (27 | )
Sales of investment securities held in trusts |  | — |  |  | 109 |
Purchases of investment securities held in trusts |  | — |  |  | (122 | )

4. EARNINGS PER SHARE OF COMMON STOCK
The convertible preferred stock issued in January 2018 (see Note 9, “Capitalization”) is considered participating securities since these shares participate in dividends on common stock on an “as-converted” basis. As a result, EPS of common stock is computed using the two-class method required for participating securities.
The two-class method uses an earnings allocation formula that treats participating securities as having rights to earnings that otherwise would have been available only to common stockholders. Under the two-class method, net income attributable to common stockholders is derived by subtracting the following from income from continuing operations:

• | preferred stock dividends,

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

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

Net losses are not allocated to the convertible preferred stock as they do not have a contractual obligation to share in the losses of FirstEnergy. FirstEnergy allocates undistributed earnings based upon income from continuing operations.
The preferred stock includes an embedded conversion option at a price that is below the fair value of the common stock on the commitment date. This beneficial conversion feature, which was approximately $296 million, represents the difference between the fair value per share of the common stock and the conversion price, multiplied by the number of common shares issuable upon conversion. The beneficial conversion feature was amortized as a deemed dividend over the period from the issue date to the first allowable conversion date (July 22, 2018) as a charge to OPIC, since FE is in an accumulated deficit position with no retained earnings to declare a dividend. As noted above, for EPS reporting purposes, this beneficial conversion feature was reflected in net income attributable to common stockholders as a deemed dividend and was fully amortized in 2018.
Basic EPS available to common stockholders is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding during the period. Participating securities are excluded from basic weighted average ordinary shares outstanding. Diluted EPS available to common stockholders is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding, including all potentially dilutive common shares, if the effect of such common shares is dilutive.
Diluted EPS reflects the dilutive effect of potential common shares from share-based awards and convertible shares of preferred stock. The dilutive effect of outstanding share-based awards is computed using the treasury stock method, which assumes any proceeds that could be obtained upon the exercise of the award would be used to purchase common stock at the average market price for the period. The dilutive effect of the convertible preferred stock is computed using the if-converted method, which assumes conversion of the convertible preferred stock at the beginning of the period, giving income recognition for the add-back of the preferred stock dividends, amortization of beneficial conversion feature, and undistributed earnings allocated to preferred stockholders.
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The following table reconciles basic and diluted EPS of common stock:

|  | For the Three Months Ended September 30, |  | For the Nine Months Ended September 30,
Reconciliation of Basic and Diluted EPS of Common Stock |  | 2019 |  | 2018 |  | 2019 |  | 2018
(In millions, except per share amounts) |  |  |  |  |  |  |  |
EPS of Common Stock |  |  |  |  |  |  |  |
Income from continuing operations |  | $ | 389 |  |  | $ | 399 |  |  | $ | 1,085 |  |  | $ | 888 |
Less: Preferred dividends |  | — |  |  | (19 | ) |  | (3 | ) |  | (61 | )
Less: Amortization of beneficial conversion feature |  | — |  |  | (35 | ) |  | — |  |  | (296 | )
Less: Undistributed earnings allocated to preferred stockholders(1) |  | — |  |  | — |  |  | (4 | ) |  | — |
Income from continuing operations available to common stockholders |  | 389 |  |  | 345 |  |  | 1,078 |  |  | 531 |
Discontinued operations, net of tax |  | 2 |  |  | (857 | ) |  | (62 | ) |  | 322 |
Less: Undistributed earnings allocated to preferred stockholders (1) |  | — |  |  | — |  |  | — |  |  | — |
Income (loss) from discontinued operations available to common stockholders |  | 2 |  |  | (857 | ) |  | (62 | ) |  | 322 |
Income (loss) available to common stockholders, basic |  | $ | 391 |  |  | $ | (512 | ) |  | $ | 1,016 |  |  | $ | 853 |
Income allocated to preferred shareholders, preferred dilutive (2) |  | — |  |  | N/A |  |  | 7 |  |  | N/A |
Income (loss) available to common stockholders, dilutive |  | $ | 391 |  |  | $ | (512 | ) |  | $ | 1,023 |  |  | $ | 853 |
Share Count information: |  |  |  |  |  |  |  |
Weighted average number of basic shares outstanding |  | 538 |  |  | 503 |  |  | 533 |  |  | 485 |
Assumed exercise of dilutive stock options and awards |  | 2 |  |  | 2 |  |  | 2 |  |  | 2 |
Assumed conversion of preferred stock |  | 2 |  |  | — |  |  | 6 |  |  | — |
Weighted average number of diluted shares outstanding |  | 542 |  |  | 505 |  |  | 541 |  |  | 487 |
Income (loss) available to common stockholders, per common share: |  |  |  |  |  |  |  |
Income from continuing operations, basic |  | $ | 0.72 |  |  | $ | 0.68 |  |  | $ | 2.02 |  |  | $ | 1.10 |
Discontinued operations, basic |  | 0.01 |  |  | (1.70 | ) |  | (0.12 | ) |  | 0.66 |
Income (loss) available to common stockholders, basic |  | $ | 0.73 |  |  | $ | (1.02 | ) |  | $ | 1.90 |  |  | $ | 1.76 |
Income from continuing operations, diluted |  | $ | 0.72 |  |  | $ | 0.68 |  |  | $ | 2.00 |  |  | $ | 1.09 |
Discontinued operations, diluted |  | — |  |  | (1.70 | ) |  | (0.11 | ) |  | 0.66 |
Income (loss) available to common stockholders, diluted |  | $ | 0.72 |  |  | $ | (1.02 | ) |  | $ | 1.89 |  |  | $ | 1.75 |

(1) | Undistributed earnings were not allocated to participating securities for the three and nine months ended September 30, 2018, as well as the three months ended September 30, 2019, as income from continuing operations less dividends declared (common and preferred) and deemed dividends were a net loss.

(2) | The shares of common stock issuable upon conversion of the preferred shares (26 million shares) were not included for 2018 as their inclusion would be anti-dilutive to basic EPS from continuing operations.

For the three and nine months ended September 30, 2018, 1 million shares from stock options and awards were excluded from the calculation of diluted shares outstanding, as their inclusion would be anti-dilutive to basic EPS from continuing operations. For the three and nine months ended September 30, 2019, no shares from stock options and awards were excluded from the calculation of diluted shares outstanding.
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5. PENSION AND OTHER POSTEMPLOYMENT 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 September 30, |  | 2019 |  | 2018 |  | 2019 |  | 2018
|  | (In millions)
Service costs (1) |  | $ | 48 |  |  | $ | 56 |  |  | $ | 1 |  |  | $ | 1 |
Interest costs (2) |  | 93 |  |  | 93 |  |  | 6 |  |  | 6 |
Expected return on plan assets (2) |  | (135 | ) |  | (144 | ) |  | (7 | ) |  | (7 | )
Amortization of prior service costs (credits) (2) |  | 2 |  |  | 2 |  |  | (9 | ) |  | (20 | )
Special termination costs (2) (3) |  | — |  |  | 21 |  |  | — |  |  | 6 |
Net periodic costs (credits), including amounts capitalized |  | $ | 8 |  |  | $ | 28 |  |  | $ | (9 | ) |  | $ | (14 | )
Net periodic costs (credits), recognized in earnings |  | $ | (11 | ) |  | $ | 5 |  |  | $ | (10 | ) |  | $ | (15 | )
Components of Net Periodic Benefit Costs (Credits) |  | Pension | OPEB
For the Nine Months Ended September 30, |  | 2019 |  | 2018 |  | 2019 |  | 2018
|  | (In millions)
Service costs (1) |  | $ | 144 |  |  | $ | 168 |  |  | $ | 3 |  |  | $ | 3 |
Interest costs (2) |  | 279 |  |  | 279 |  |  | 16 |  |  | 18 |
Expected return on plan assets (2) |  | (405 | ) |  | (432 | ) |  | (21 | ) |  | (22 | )
Amortization of prior service costs (credits) (2) |  | 6 |  |  | 6 |  |  | (27 | ) |  | (60 | )
Special termination costs (2) (3) |  | 14 |  |  | 21 |  |  | — |  |  | 6 |
Net periodic costs (credits), including amounts capitalized |  | $ | 38 |  |  | $ | 42 |  |  | $ | (29 | ) |  | $ | (55 | )
Net periodic credits, recognized in earnings |  | $ | (19 | ) |  | $ | (27 | ) |  | $ | (30 | ) |  | $ | (57 | )

(1) Service costs, net of capitalization, are reported within Other operating expenses on FirstEnergy’s Consolidated Statements of Income (Loss).
(2) Non-service costs are reported within Miscellaneous income, net, within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income (Loss).
(3) Subject to a cap, FirstEnergy has 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 (approximately $14 million recognized in the first nine months of 2019).
Amounts in the tables above include the FES Debtors’ share of the net periodic pension and OPEB costs (credits) of $12 million and $(14) million, respectively, for the three months ended September 30, 2019, and $34 million and $(16) million, respectively, for the nine months ended September 30, 2019. The FES Debtors’ share of the net periodic pension and OPEB costs (credits) were $12 million and $(11) million, respectively, for the three months ended September 30, 2018, and $38 million and $(31) million, respectively, for the nine months ended September 30, 2018. The 2019 special termination costs associated with FES’ voluntary enhanced retirement package are a component of Discontinued operations in FirstEnergy’s Consolidated Statements of Income (Loss). Following the FES Debtors’ voluntary bankruptcy filing, FE has billed the FES Debtors approximately $9 million and $28 million for their share of pension and OPEB service costs for the three and nine months ended September 30, 2019, respectively.
On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. As a result of this contribution, FirstEnergy expects no required contributions through 2021.
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6. ACCUMULATED OTHER COMPREHENSIVE INCOME
The following tables show the changes in AOCI for the three and nine months ended September 30, 2019 and 2018, for FirstEnergy:

|  | Gains & Losses on Cash Flow Hedges (1) |  | Unrealized Gains on AFS Securities |  | Defined Benefit Pension & OPEB Plans |  | Total
|  | (In millions)
AOCI Balance, July 1, 2019 |  | $ | (10 | ) |  | $ | — |  |  | $ | 41 |  |  | $ | 31 |
Amounts reclassified from AOCI |  | — |  |  | — |  |  | (7 | ) |  | (7 | )
Other comprehensive loss |  | — |  |  | — |  |  | (7 | ) |  | (7 | )
Income tax benefits on other comprehensive loss |  | — |  |  | — |  |  | (3 | ) |  | (3 | )
Other comprehensive loss, net of tax |  | — |  |  | — |  |  | (4 | ) |  | (4 | )
AOCI Balance, September 30, 2019 |  | $ | (10 | ) |  | $ | — |  |  | $ | 37 |  |  | $ | 27 |
AOCI Balance, July 1, 2018 |  | $ | (14 | ) |  | $ | — |  |  | $ | 87 |  |  | $ | 73 |
Amounts reclassified from AOCI |  | 2 |  |  | — |  |  | (18 | ) |  | (16 | )
Other comprehensive income (loss) |  | 2 |  |  | — |  |  | (18 | ) |  | (16 | )
Income tax benefits on other comprehensive loss |  | — |  |  | — |  |  | (4 | ) |  | (4 | )
Other comprehensive income (loss), net of tax |  | 2 |  |  | — |  |  | (14 | ) |  | (12 | )
AOCI Balance, September 30, 2018 |  | $ | (12 | ) |  | $ | — |  |  | $ | 73 |  |  | $ | 61 |
|  | Gains & Losses on Cash Flow Hedges (1) |  | Unrealized Gains on AFS Securities |  | Defined Benefit Pension & OPEB Plans |  | Total
|  | (In millions)
AOCI Balance, January 1, 2019 |  | $ | (11 | ) |  | $ | — |  |  | $ | 52 |  |  | $ | 41 |
Amounts reclassified from AOCI |  | 1 |  |  | — |  |  | (21 | ) |  | (20 | )
Other comprehensive income (loss) |  | 1 |  |  | — |  |  | (21 | ) |  | (20 | )
Income tax benefits on other comprehensive loss |  | — |  |  | — |  |  | (6 | ) |  | (6 | )
Other comprehensive income (loss), net of tax |  | 1 |  |  | — |  |  | (15 | ) |  | (14 | )
AOCI Balance, September 30, 2019 |  | $ | (10 | ) |  | $ | — |  |  | $ | 37 |  |  | $ | 27 |
AOCI Balance, January 1, 2018 |  | $ | (22 | ) |  | $ | 67 |  |  | $ | 97 |  |  | $ | 142 |
Other comprehensive income before reclassifications |  | — |  |  | (97 | ) |  | — |  |  | (97 | )
Amounts reclassified from AOCI |  | 6 |  |  | (1 | ) |  | (55 | ) |  | (50 | )
Deconsolidation of FES and FENOC |  | 13 |  |  | (8 | ) |  | — |  |  | 5 |
Other comprehensive income (loss) |  | 19 |  |  | (106 | ) |  | (55 | ) |  | (142 | )
Income taxes (benefits) on other comprehensive income (loss) |  | 9 |  |  | (39 | ) |  | (31 | ) |  | (61 | )
Other comprehensive income (loss), net of tax |  | 10 |  |  | (67 | ) |  | (24 | ) |  | (81 | )
AOCI Balance, September 30, 2018 |  | $ | (12 | ) |  | $ | — |  |  | $ | 73 |  |  | $ | 61 |

(1) Relates to previous cash flow hedges used to hedge fixed rate long-term debt securities prior to their issuance.
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The following amounts were reclassified from AOCI for FirstEnergy in the three and nine months ended September 30, 2019 and 2018:

|  | For the Three Months Ended September 30, |  | For the Nine Months Ended September 30, |  | Affected Line Item in Consolidated Statements of Income (Loss)
Reclassifications from AOCI(1) |  | 2019 |  | 2018 |  | 2019 |  | 2018 (2) |
|  | (In millions) |  |
Gains & losses on cash flow hedges |  |  |  |  |  |  |  |  |  |
Commodity contracts |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 1 |  |  | Other operating expenses
Long-term debt |  | — |  |  | 2 |  |  | 1 |  |  | 5 |  |  | Interest expense
|  | — |  |  | — |  |  | — |  |  | (1 | ) |  | Income taxes
|  | $ | — |  |  | $ | 2 |  |  | $ | 1 |  |  | $ | 5 |  |  | Net of tax
Unrealized gains on AFS securities |  |  |  |  |  |  |  |  |  |
Realized gains on sales of securities |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | (1 | ) |  | Discontinued operations
Defined benefit pension and OPEB plans |  |  |  |  |  |  |  |  |  |
Prior-service costs |  | $ | (7 | ) |  | $ | (15 | ) |  | $ | (21 | ) |  | $ | (55 | ) |  | (3)
|  | 3 |  |  | 5 |  |  | 6 |  |  | 14 |  |  | Income taxes
|  | $ | (4 | ) |  | $ | (10 | ) |  | $ | (15 | ) |  | $ | (41 | ) |  | Net of tax
(1) Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI.
(2) Includes stranded tax amounts reclassified from AOCI in connection with the adoption of ASU 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.”
(3) Prior-service costs are reported within Miscellaneous income, net, within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income (Loss). Components are included in the computation of net periodic cost (credits), see Note 5, “Pension and Other Postemployment Benefits.”

7. INCOME TAXES
FirstEnergy’s interim effective tax rates reflect the estimated annual effective tax rates for 2019 and 2018. These tax rates are affected by estimated annual permanent items, such as AFUDC equity and other flow-through items, as well as discrete items that may occur in any given period, but are not consistent from period to period.
FirstEnergy’s effective tax rate for the three months ended September 30, 2019 and 2018, was 21.6% and 23.3%, respectively. The decrease in effective tax rate was primarily due to an increase in the amortization of net excess deferred income taxes. See Note 12, “Regulatory Matters,” for additional details.
FirstEnergy’s effective tax rate for the nine months ended September 30, 2019 and 2018, was 20.6% and 33.9%, respectively. In addition to the increase in amortization of net excess deferred income taxes, the decrease in the effective tax rate was primarily due to the absence of a one-time charge of approximately $126 million to income tax expense in continuing operations associated with the re-measurement of West Virginia state deferred income taxes, resulting from the legal and financial separation of FES and FENOC from FirstEnergy, which occurred in the first quarter of 2018. See Note 3, “Discontinued Operations,” for other tax matters relating to the FES Bankruptcy that were recognized in discontinued operations.
During the nine months ended September 30, 2019, FirstEnergy increased its reserve for uncertain tax positions taken in the current year by approximately $19 million, none of which had an impact on the effective tax rate. As of September 30, 2019, it is reasonably possible that FirstEnergy could record a net decrease to its reserve for uncertain tax positions by approximately $57 million within the next twelve months due to the statute of limitations expiring or resolution with taxing authorities, of which approximately $54 million would impact FirstEnergy’s effective tax rate.
In June 2019, the Internal Revenue Service completed its examination of FirstEnergy’s 2017 federal income tax return and issued a full acceptance letter with no changes or adjustments to FirstEnergy’s taxable income.
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8. LEASES
FirstEnergy primarily leases vehicles as well as building space, office equipment, and other property and equipment under cancelable and non-cancelable leases. FirstEnergy does not have any material leases in which it is the lessor.
FirstEnergy adopted ASU 2016-02, “Leases (Topic 842)” on January 1, 2019, and elected a number of transitional practical expedients provided within the standard. These included a “package of three” expedients that must be taken together and allowed entities to: (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. In addition, FirstEnergy elected the option to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. Adoption of the standard on January 1, 2019, did not result in a material cumulative effect adjustment upon adoption. FirstEnergy did not evaluate land easements under the new guidance as they were not previously accounted for as leases. FirstEnergy also elected not to separate lease components from non-lease components as non-lease components were not material.
Leases with an initial term of 12 months or less are recognized as lease expense on a straight-line basis over the lease term and not recorded on the balance sheet. Most leases include one or more options to renew, with renewal terms that can extend the lease term from 1 to 40 years, and certain leases include options to terminate. The exercise of lease renewal options is at FirstEnergy’s sole discretion. Renewal options are included within the lease liability if they are reasonably certain based on various factors relative to the contract. Certain leases also include options to purchase the leased property. The depreciable life of leased assets and leasehold improvements are limited by the expected lease term, unless there is a transfer of title or purchase option reasonably certain of exercise. FirstEnergy’s lease agreements do not contain any material restrictive covenants.
For vehicles leased under master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. As of September 30, 2019, the maximum potential loss for these lease agreements at the end of the lease term is approximately $15 million.
Finance leases for assets used in regulated operations are recognized in FirstEnergy’s Consolidated Statements of Income (Loss) such that amortization of the right-of-use asset and interest on lease liabilities equals the expense allowed for ratemaking purposes. Finance leases for regulated and non-regulated operations are accounted for as if the assets were owned and financed, with associated expense recognized in Interest expense and Provision for depreciation on FirstEnergy’s Consolidated Statements of Income (Loss), while all operating lease expenses are recognized in Other operating expense. The components of lease expense were as follows:

|  | For the Three Months Ended September 30, 2019
(In millions) |  | Vehicles |  | Buildings |  | Other |  | Total
Operating lease costs (1) |  | $ | 5 |  |  | $ | 3 |  |  | $ | 3 |  |  | $ | 11 |
Finance lease costs: |  |  |  |  |  |  |  |
Amortization of right-of-use assets |  | 4 |  |  | — |  |  | — |  |  | 4 |
Interest on lease liabilities |  | — |  |  | — |  |  | — |  |  | — |
Total finance lease cost |  | 4 |  |  | — |  |  | — |  |  | 4 |
Total lease cost |  | $ | 9 |  |  | $ | 3 |  |  | $ | 3 |  |  | $ | 15 |

(1) Includes $2 million of short-term lease costs.

|  | For the Nine Months Ended September 30, 2019
(In millions) |  | Vehicles |  | Buildings |  | Other |  | Total
Operating lease costs (1) |  | $ | 20 |  |  | $ | 6 |  |  | $ | 9 |  |  | $ | 35 |
Finance lease costs: |  |  |  |  |  |  |  |
Amortization of right-of-use assets |  | 12 |  |  | — |  |  | 1 |  |  | 13 |
Interest on lease liabilities |  | 2 |  |  | 2 |  |  | — |  |  | 4 |
Total finance lease cost |  | 14 |  |  | 2 |  |  | 1 |  |  | 17 |
Total lease cost |  | $ | 34 |  |  | $ | 8 |  |  | $ | 10 |  |  | $ | 52 |

(1) Includes $8 million of short-term lease costs.
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Supplemental cash flow information related to leases was as follows:

(In millions) |  | For the Three Months Ended September 30, 2019 |  | For the Nine Months Ended September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities |  |  |  |
Operating cash flows from operating leases |  | $ | 4 |  |  | $ | 19 |
Operating cash flows from finance leases |  | 1 |  |  | 4 |
Finance cash flows from finance leases |  | 12 |  |  | 21 |
Right-of-use assets obtained in exchange for lease obligations: |  |  |  |
Operating leases |  | $ | 47 |  |  | $ | 73 |
Finance leases |  | — |  |  | 2 |

Lease terms and discount rates were as follows:

|  | As of September 30, 2019
Weighted-average remaining lease terms (years) |  |
Operating leases |  | 8.39 |
Finance leases |  | 4.66 |
Weighted-average discount rate (1) |  |
Operating leases |  | 4.76 | %
Finance leases |  | 3.45 | %

(1) When an implicit rate is not readily determinable, an incremental borrowing rate is utilized, determining the present value of lease payments. The rate is determined based on expected term and information available at the commencement date.
Supplemental balance sheet information related to leases was as follows:

(In millions) |  | Financial Statement Line Item |  | As of September 30, 2019
Assets |  |  |  |
Operating lease assets, net of accumulated amortization of $17 million |  | Deferred charges and other assets |  | $ | 200 |
Finance lease assets, net of accumulated amortization of $91 million |  | Property, plant and equipment |  | 76 |
Total leased assets |  |  |  | $ | 276 |
Liabilities |  |  |  |
Current: |  |  |  |
Operating |  | Other current liabilities |  | $ | 34 |
Finance |  | Currently payable long-term debt |  | 16 |
Noncurrent: |  |  |  |
Operating |  | Other noncurrent liabilities |  | 212 |
Finance |  | Long-term debt and other long-term obligations |  | 47 |
Total leased liabilities |  |  |  | $ | 309 |

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Maturities of lease liabilities as of September 30, 2019, were as follows:

(In millions) |  | Operating Leases |  | Finance Leases |  | Total |
2019 |  | $ | 8 |  |  | $ | 12 |  |  | $ | 20 |  |
2020 |  | 42 |  |  | 19 |  |  | 61 |  |
2021 |  | 40 |  |  | 17 |  |  | 57 |  |
2022 |  | 39 |  |  | 15 |  |  | 54 |  |
2023 |  | 35 |  |  | 8 |  |  | 43 |  |
2024 |  | 30 |  |  | 4 |  |  | 34 |  |
Thereafter |  | 108 |  |  | 12 |  |  | 120 |  |
Total lease payments (1) |  | 302 |  |  | 87 |  |  | 389 |  |
Less imputed interest |  | (56 | ) |  | (24 | ) |  | (80 | ) |
Total net present value |  | $ | 246 |  |  | $ | 63 |  |  | $ | 309 |  |

(1) Operating lease payments for certain leases are offset by sublease receipts of $13 million over 13 years.
As of September 30, 2019, additional operating leases agreements, primarily for vehicles, that have not yet commenced are $15 million. These leases are expected to commence within the next 18 months with lease terms of 3 to 10 years.
The future minimum capital lease payments as of December 31, 2018, as reported in the Annual Report on Form 10-K for the year ended December 31, 2018 under ASC 840 ”Leases” are as follows:

Capital Leases |  |
|  | (In millions)
2019 |  | $ | 24 |
2020 |  | 19 |
2021 |  | 16 |
2022 |  | 13 |
2023 |  | 8 |
Years thereafter |  | 16 |
Total minimum lease payments |  | 96 |
Interest portion |  | (23 | )
Present value of net minimum lease payments |  | 73 |
Less current portion |  | 18 |
Noncurrent portion |  | $ | 55 |

The future minimum operating lease payments as of December 31, 2018, as reported in the Annual Report on Form 10-K for the year ended December 31, 2018 under ASC 840 ”Leases” are as follows:

Operating Leases |  |
|  | (In millions)
2019 |  | $ | 34 |
2020 |  | 36 |
2021 |  | 34 |
2022 |  | 30 |
2023 |  | 28 |
Years thereafter |  | 127 |
Total minimum lease payments |  | $ | 289 |

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9. CAPITALIZATION
Stockholders’ Equity
The changes in stockholders’ equity for the three and nine months ended September 30, 2019 for FirstEnergy are included in the following table:

|  | 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) |  |  |  |  |  |  |  |  |  | (202 | ) |  |  |  |  |  | (202 | )
Cash dividends declared on preferred stock ($0.38/as-converted share) |  |  |  |  |  |  |  |  |  | (3 | ) |  |  |  |  |  | (3 | )
Conversion of Series A Convertible Preferred Stock |  | (0.5 | ) |  | (50 | ) |  | 18 |  |  | 2 |  |  | 48 |  |  |  |  |  |  | — |
Balance, March 31, 2019 |  | 0.2 |  |  | $ | 21 |  |  | 531 |  |  | $ | 53 |  |  | $ | 11,381 |  |  | $ | 36 |  |  | $ | (4,559 | ) |  | $ | 6,932 |
Net income |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 312 |  |  | 312 |
Other comprehensive loss, net of tax |  |  |  |  |  |  |  |  |  |  |  |  |  | (5 | ) |  |  |  |  | (5 | )
Stock-based compensation |  |  |  |  |  |  |  |  |  |  | 9 |  |  |  |  |  |  |  |  | 9 |
Stock Investment Plan and certain share-based benefit plans |  |  |  |  |  | 1 |  |  |  |  |  | 21 |  |  |  |  |  |  |  |  | 21 |
Balance, June 30, 2019 |  | 0.2 |  |  | $ | 21 |  |  | 532 |  |  | $ | 53 |  |  | $ | 11,411 |  |  | $ | 31 |  |  | $ | (4,247 | ) |  | $ | 7,269 |
Net income |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 391 |  |  | 391 |
Other comprehensive loss, net of tax |  |  |  |  |  |  |  |  |  |  |  |  |  | (4 | ) |  |  |  |  | (4 | )
Stock-based compensation |  |  |  |  |  |  |  |  |  |  | 7 |  |  |  |  |  |  |  |  | 7 |
Stock Investment Plan and certain share-based benefit plans |  |  |  |  |  | 1 |  |  |  |  | 20 |  |  |  |  |  |  | 20 |
Cash dividends declared on common stock ($0.38/share in July and September) |  |  |  |  |  |  |  |  |  | (411 | ) |  |  |  |  |  | (411 | )
Conversion of Series A Convertible Preferred Stock |  | (0.2 | ) |  | (21 | ) |  | 7 |  |  | 1 |  |  | 20 |  |  |  |  |  |  |  |  | — |
Balance, September 30, 2019 |  | — |  |  | $ | — |  |  | 540 |  |  | $ | 54 |  |  | $ | 11,047 |  |  | $ | 27 |  |  | $ | (3,856 | ) |  | $ | 7,272 |

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The changes in stockholders’ equity for the three and nine months ended September 30, 2018 for FirstEnergy are included in the following table:

|  | Series A Convertible Preferred Stock |  | Common Stock |  | OPIC |  | AOCI |  | Accumulated Deficit |  | Total Stockholders’ Equity
(In millions) |  | Shares |  | Amount |  | Shares |  | Amount |  |  |
Balance, January 1, 2018 |  | — |  |  | $ | — |  |  | 445 |  |  | $ | 44 |  |  | $ | 10,001 |  |  | $ | 142 |  |  | $ | (6,262 | ) |  | $ | 3,925 |
Net income |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,369 |  |  | 1,369 |
Other comprehensive loss, net of tax |  |  |  |  |  |  |  |  |  |  |  | (56 | ) |  |  |  | (56 | )
Stock-based compensation |  |  |  |  |  |  |  |  |  | 19 |  |  |  |  |  |  | 19 |
Stock Investment Plan and certain share-based benefit plans |  |  |  |  |  | 2 |  |  | 1 |  |  | 5 |  |  |  |  |  |  | 6 |
Cash dividends declared on common stock ($0.36/common share in January and March) |  |  |  |  |  |  |  |  |  | (343 | ) |  |  |  |  |  | (343 | )
Cash dividends declared on preferred stock ($0.36/as-converted share in January and March) |  |  |  |  |  |  |  |  |  | (42 | ) |  |  |  |  |  | (42 | )
Stock issuance (1) |  | 1.6 |  |  | 162 |  |  | 30 |  |  | 3 |  |  | 2,297 |  |  |  |  |  |  | 2,462 |
Impact of adopting new accounting pronouncements (2) |  |  |  |  |  |  |  |  |  |  |  |  |  | 35 |  |  | 35 |
Balance, March 31, 2018 |  | 1.6 |  |  | $ | 162 |  |  | 477 |  |  | $ | 48 |  |  | $ | 11,937 |  |  | $ | 86 |  |  | $ | (4,858 | ) |  | $ | 7,375 |
Net income |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 299 |  |  | $ | 299 |
Other comprehensive loss, net of tax |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (13 | ) |  |  |  |  | (13 | )
Stock-based compensation |  |  |  |  |  |  |  |  |  |  |  |  |  | 19 |  |  |  |  |  |  |  |  | 19 |
Stock Investment Plan and certain share-based benefit plans |  |  |  |  |  |  |  | 1 |  |  |  |  |  | 19 |  |  |  |  |  |  |  |  | 19 |
Balance, June 30, 2018 |  | 1.6 |  |  | $ | 162 |  |  | 478 |  |  | $ | 48 |  |  | $ | 11,975 |  |  | $ | 73 |  |  | $ | (4,559 | ) |  | $ | 7,699 |
Net loss |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | (458 | ) |  | $ | (458 | )
Other comprehensive loss, net of tax |  |  |  |  |  |  |  |  |  |  |  | (12 | ) |  |  |  | (12 | )
Stock-based compensation |  |  |  |  |  |  |  |  |  | 10 |  |  |  |  |  |  |  | 10 |
Stock Investment Plan and certain share-based benefit plans |  |  |  |  |  | 1 |  |  |  |  | 21 |  |  |  |  |  |  | 21 |
Cash dividends declared on common stock ($0.36/common share in July and September) |  |  |  |  |  |  |  |  |  | (368 | ) |  |  |  |  |  | (368 | )
Cash dividends declared on preferred stock ($0.36/as-converted share in July and September) |  |  |  |  |  |  |  |  |  | (19 | ) |  |  |  |  |  | (19 | )
Conversion of Series A Convertible Preferred Stock |  | (0.9 | ) |  | (92 | ) |  | 33 |  |  | 3 |  |  | 89 |  |  |  |  |  |  | — |
Balance, September 30, 2018 |  | 0.7 |  |  | $ | 70 |  |  | 512 |  |  | $ | 51 |  |  | $ | 11,708 |  |  | $ | 61 |  |  | $ | (5,017 | ) |  | $ | 6,873 |

(1) The preferred stock included an embedded conversion option at a price that was below the fair value of the common stock on the commitment date. This beneficial conversion feature (BCF), which was approximately $296 million, was recorded to OPIC as well as the amortization of the BCF (deemed dividend of $35 million and $296 million for the three and nine months ended September 30, 2018, respectively) through the period from the issue date to the first allowable conversion date (July 22, 2018). There is no net impact to OPIC for the three and nine months ended September 30, 2018. Please see below and Note 4, “Earnings Per Share” for additional information.
(2) FirstEnergy adopted ASU 2016-01, “Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities” standard on January 1, 2018, and subsequently recorded a cumulative effect adjustment to retained earnings of $57 million representing unrealized gains on equity securities with FES NDTs that were previously recorded to AOCI. In addition, FirstEnergy adopted ASU 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income” and upon adoption, recorded a $22 million cumulative effect adjustment for stranded tax effects, such as pension and OPEB prior service costs and losses on derivative hedges, to retained earnings on January 1, 2018. These amounts are offset in other comprehensive loss and do not have an impact on total stockholders’ equity.
Preferred Stock
On January 22, 2018, FirstEnergy entered into agreements for the private placement of its equity securities representing an approximately $2.5 billion investment in FE. FE entered into a Preferred Stock Purchase Agreement (the Preferred SPA) for the private placement of 1,616,000 shares of mandatorily convertible preferred stock, designated as the Series A Convertible Preferred Stock, par value $100 per share, representing an investment of nearly $1.62 billion ($162 million of mandatorily convertible preferred
24

stock and $1.46 billion of OPIC). FE also entered into a Common Stock Purchase Agreement for the private placement of 30,120,482 shares of FE’s common stock, par value $0.10 per share, representing an investment of $850 million ($3 million of Common Stock and $847 million of OPIC).
During 2018, 911,411 shares of preferred stock were converted into 33,238,910 shares of common stock at the option of the preferred stockholders. Also at the option of the preferred stockholders, 494,767 shares of preferred stock were converted into 18,044,018 shares of common stock in January 2019. On July 22, 2019, 28,302 shares of preferred stock automatically converted into 1,032,165 shares of common stock, and 181,520 shares of preferred stock remained unconverted as the holder reached the 4.9% cap as outlined in the terms of the preferred stock. The remaining 181,520 preferred stock shares were converted on August 1, 2019, into 6,619,985 shares of common stock. As of September 30, 2019, there are no preferred shares outstanding and 1,616,000 shares of preferred stock were converted into 58,935,078 shares of common stock.
The preferred stock participated in dividends on the common stock on an as-converted basis based on the number of shares of common stock a holder of preferred stock would receive if its shares of preferred stock were converted on the dividend record date at the conversion price in effect at that time. Such dividends were paid at the same time that the dividends on common stock were paid.
The preferred stock included an embedded conversion option at a price that was below the fair value of the common stock on the commitment date. This beneficial conversion feature, which was approximately $296 million, represents the difference between the fair value per share of the common stock and the conversion price, multiplied by the number of common shares issuable upon conversion. The beneficial conversion feature was amortized as a deemed dividend over the period from the issue date to the first allowable conversion date (July 22, 2018) as a charge to OPIC, since FE is in an accumulated deficit position with no retained earnings to declare a dividend. As noted above, for EPS reporting purposes, this beneficial conversion feature was reflected in net income attributable to common stockholders as a deemed dividend. The beneficial conversion feature ($296 million) was fully amortized during the third quarter of 2018.
Each share of preferred stock was convertible at the holder’s option into a number of shares of common stock equal to the $1,000 liquidation preference, divided by the conversion price then in effect ($27.42 per share). The conversion price was subject to anti-dilution adjustments and adjustments for subdivisions and combinations of the common stock, as well as dividends on the common stock paid in common stock and for certain equity issuances below the conversion price then in effect.
10. VARIABLE INTEREST ENTITIES
FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has: (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance; and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary.
In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregates variable interests into categories based on similar risk characteristics and significance.
Consolidated VIEs
VIEs in which FirstEnergy is the primary beneficiary consist of the following (included in FirstEnergy’s consolidated financial statements):

• | Ohio Securitization - In September 2012, the Ohio Companies created separate, wholly owned limited liability company SPEs which issued phase-in recovery bonds to securitize the recovery of certain all-electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds are payable only from, and secured by, phase-in recovery property owned by the SPEs. The bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and administers the phase-in recovery property including the billing, collection and remittance of usage-based charges payable by retail electric customers. In the aggregate, the Ohio Companies are entitled to annual servicing fees of $445 thousand that are recoverable through the usage-based charges. The SPEs are considered VIEs and each one is consolidated into its applicable utility. As of September 30, 2019, and December 31, 2018, $268 million and $292 million of the phase-in recovery bonds were outstanding, respectively.

• | JCP&L Securitization - In August 2006, JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy’s Consolidated Balance Sheets. The transition bonds are the sole obligations of JCP&L Transition Funding II and are collateralized by its equity and assets, which consist primarily of bondable transition property. As of September 30, 2019, and December 31, 2018, $29 million and $41 million of the transition bonds were outstanding, respectively.

• | MP and PE Environmental Funding Companies - The entities issued bonds, the proceeds of which were used to construct environmental control facilities. The limited liability company SPEs own the irrevocable right to collect non-bypassable environmental control charges from all customers who receive electric delivery service in MP’s and PE’s West Virginia service territories. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. Creditors of FirstEnergy, other than the limited liability company SPEs, have no recourse to any assets or revenues of the special purpose limited liability companies. As of September 30, 2019, and December 31, 2018, $333 million and $358 million of the environmental control bonds were outstanding, respectively.

Unconsolidated VIEs
FirstEnergy is not the primary beneficiary of the following VIEs:

• | Global Holding - FEV holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales in U.S. and international markets. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint ventures economic performance. FEV’s ownership interest is subject to the equity method of accounting. As of September 30, 2019, the carrying value of the equity method investment was $19 million.

As discussed in Note 13, “Commitments, Guarantees and Contingencies,” FE is the guarantor under Global Holding’s $300 million term loan facility, which matures in March 2020, and has an outstanding principal balance of $145 million as of September 30, 2019. Failure by Global Holding to meet the terms and conditions under its term loan facility could require FE to perform its obligations under the provisions of its guarantee, resulting in consolidation of Global Holding by FE.

• | PATH WV - PATH, a proposed transmission line from West Virginia through Virginia into Maryland, which PJM cancelled in 2012, is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of FE owns 100% of the Allegheny Series (PATH-Allegheny) and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of PATH-WV. FirstEnergy’s ownership interest in PATH-WV is subject to the equity method of accounting. As of September 30, 2019, the carrying value of the equity method investment was $18 million.

• | Purchase Power Agreements - FirstEnergy evaluated its PPAs and determined that certain NUG entities at its Regulated Distribution segment may be VIEs to the extent that they own a plant that sells substantially all of its output to the applicable utilities and the contract price for power is correlated with the plant’s variable costs of production.

FirstEnergy maintains 11 long-term PPAs with NUG entities that were entered into pursuant to PURPA. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, any of these entities. FirstEnergy has determined that, for all but one of these NUG entities, it does not have a variable interest or the entities do not meet the criteria to be considered a VIE. FirstEnergy may hold a variable interest in the remaining one entity; however, it applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.
Because FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred at its Regulated Distribution segment to be recovered from customers. Purchased power costs related to the contract that may contain a variable interest during the three months ended September 30, 2019 and 2018, were $30 million and $27 million, respectively, and $91 million and $85 million during the nine months ended September 30, 2019 and 2018, respectively.

• | FES and FENOC - As a result of the Chapter 11 bankruptcy filing discussed in Note 3, “Discontinued Operations,” FE evaluated its investments in FES and FENOC and determined they are VIEs. FE is not the primary beneficiary because it lacks a controlling interest in FES and FENOC, which are subject to the jurisdiction of the Bankruptcy Court. The carrying values of the equity investments in FES and FENOC were zero at September 30, 2019.

11. 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

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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 September 30, 2019, from those used as of December 31, 2018. 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:

| September 30, 2019 |  | December 31, 2018
| Level 1 |  | Level 2 |  | Level 3 |  | Total |  | Level 1 |  | Level 2 |  | Level 3 |  | Total
Assets | (In millions)
Corporate debt securities | $ | — |  |  | $ | 446 |  |  | $ | — |  |  | $ | 446 |  |  | $ | — |  |  | $ | 405 |  |  | $ | — |  |  | $ | 405 |
Derivative assets FTRs(1) | — |  |  | — |  |  | 6 |  |  | 6 |  |  | — |  |  | — |  |  | 10 |  |  | 10 |
Equity securities(2) | 362 |  |  | — |  |  | — |  |  | 362 |  |  | 339 |  |  | — |  |  | — |  |  | 339 |
Foreign government debt securities | — |  |  | 17 |  |  | — |  |  | 17 |  |  | — |  |  | 13 |  |  | — |  |  | 13 |
U.S. government debt securities | — |  |  | 18 |  |  | — |  |  | 18 |  |  | — |  |  | 20 |  |  | — |  |  | 20 |
U.S. state debt securities | — |  |  | 266 |  |  | — |  |  | 266 |  |  | — |  |  | 250 |  |  | — |  |  | 250 |
Other(3) | 716 |  |  | 71 |  |  | — |  |  | 787 |  |  | 367 |  |  | 34 |  |  | — |  |  | 401 |
Total assets | $ | 1,078 |  |  | $ | 818 |  |  | $ | 6 |  |  | $ | 1,902 |  |  | $ | 706 |  |  | $ | 722 |  |  | $ | 10 |  |  | $ | 1,438 |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Derivative liabilities FTRs(1) | $ | — |  |  | $ | — |  |  | $ | (3 | ) |  | $ | (3 | ) |  | $ | — |  |  | $ | — |  |  | $ | (1 | ) |  | $ | (1 | )
Derivative liabilities NUG contracts(1) | — |  |  | — |  |  | (24 | ) |  | (24 | ) |  | — |  |  | — |  |  | (44 | ) |  | (44 | )
Total liabilities | $ | — |  |  | $ | — |  |  | $ | (27 | ) |  | $ | (27 | ) |  | $ | — |  |  | $ | — |  |  | $ | (45 | ) |  | $ | (45 | )
Net assets (liabilities)(4) | $ | 1,078 |  |  | $ | 818 |  |  | $ | (21 | ) |  | $ | 1,875 |  |  | $ | 706 |  |  | $ | 722 |  |  | $ | (35 | ) |  | $ | 1,393 |

(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, MSCI World Index and MSCI AC World IMI Index.

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

(4) | Excludes $(15) million and $4 million as of September 30, 2019 and December 31, 2018, 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 September 30, 2019, and December 31, 2018:

| NUG Contracts(1) |  | FTRs(1)
| Derivative Assets |  | Derivative Liabilities |  | Net |  | Derivative Assets |  | Derivative Liabilities |  | Net
| (In millions)
January 1, 2018 Balance | $ | — |  |  | $ | (79 | ) |  | $ | (79 | ) |  | $ | 3 |  |  | $ | — |  |  | $ | 3 |
Unrealized gain | — |  |  | 2 |  |  | 2 |  |  | 8 |  |  | 1 |  |  | 9 |
Purchases | — |  |  | — |  |  | — |  |  | 5 |  |  | (5 | ) |  | — |
Settlements | — |  |  | 33 |  |  | 33 |  |  | (6 | ) |  | 3 |  |  | (3 | )
December 31, 2018 Balance | $ | — |  |  | $ | (44 | ) |  | $ | (44 | ) |  | $ | 10 |  |  | $ | (1 | ) |  | $ | 9 |
Unrealized loss | — |  |  | (8 | ) |  | (8 | ) |  | — |  |  | (1 | ) |  | (1 | )
Purchases | — |  |  | — |  |  | — |  |  | 6 |  |  | (4 | ) |  | 2 |
Settlements | — |  |  | 28 |  |  | 28 |  |  | (10 | ) |  | 3 |  |  | (7 | )
September 30, 2019 Balance | $ | — |  |  | $ | (24 | ) |  | $ | (24 | ) |  | $ | 6 |  |  | $ | (3 | ) |  | $ | 3 |

(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 September 30, 2019:

|  | Fair Value, Net (In millions) |  | Valuation Technique |  | Significant Input |  | Range |  | Weighted Average |  | Units
FTRs |  | $ | 3 |  |  | Model |  | RTO auction clearing prices |  | $0.60 to $3.60 |  | $1.20 |  | Dollars/MWH
NUG Contracts |  | $ | (24 | ) |  | Model |  | Generation |  | 400 to 553,000 |  | 115,000 |  |  | MWH
|  |  | Regional electricity prices |  | $26.20 to $28.30 |  | $27.20 |  | Dollars/MWH

INVESTMENTS
All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include 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.
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 September 30, 2019, and December 31, 2018:

|  | September 30, 2019(1) |  | December 31, 2018(1)
|  | Cost Basis |  | Unrealized Gains |  | Unrealized Losses |  | Fair Value |  | Cost Basis |  | Unrealized Gains |  | Unrealized Losses |  | Fair Value
|  | (In millions)
Debt securities |  | $ | 736 |  |  | $ | 27 |  |  | $ | (14 | ) |  | $ | 749 |  |  | $ | 714 |  |  | $ | 2 |  |  | $ | (28 | ) |  | $ | 688 |
Equity securities |  | $ | 312 |  |  | $ | 50 |  |  | $ | (2 | ) |  | $ | 360 |  |  | $ | 339 |  |  | $ | 15 |  |  | $ | (16 | ) |  | $ | 338 |

(1) Excludes $33 million and $20 million as of September 30, 2019 and December 31, 2018, respectively, of short-term cash investments, taxes, receivables, payables and accrued income.
Proceeds from the sale of investments in equity and AFS debt securities, realized gains and losses on those sales and interest and dividend income for the three and nine months ended September 30, 2019 and 2018, were as follows:

|  | For the Three Months Ended September 30, |  | For the Nine Months Ended September 30,
|  | 2019 |  | 2018 |  | 2019 |  | 2018
|  | (In millions)
Sale proceeds |  | $ | 204 |  |  | $ | 261 |  |  | $ | 506 |  |  | $ | 627 |
Realized gains |  | 8 |  |  | 3 |  |  | 20 |  |  | 31 |
Realized losses |  | (7 | ) |  | (7 | ) |  | (18 | ) |  | (34 | )
Interest and dividend income |  | 10 |  |  | 11 |  |  | 30 |  |  | 31 |

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 September 30, 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.
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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 $283 million and $253 million as of September 30, 2019, and December 31, 2018, 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 September 30, 2019 and December 31, 2018:

| September 30, 2019 |  | December 31, 2018
| (In millions)
Carrying value (1) | $ | 19,880 |  |  | $ | 18,315 |
Fair value | $ | 22,910 |  |  | $ | 19,266 |

(1) The carrying value as of September 30, 2019, includes $2.1 billion of debt issuances and $784 million of redemptions that occurred in the first nine months of 2019.
The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy. FirstEnergy classified short-term borrowings, long-term debt and other long-term obligations as Level 2 in the fair value hierarchy as of September 30, 2019, and December 31, 2018.
12. 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
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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.
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 July 13, 2018, JCP&L filed an infrastructure plan, JCP&L Reliability Plus, which proposed to accelerate $386.8 million of electric distribution infrastructure investment over four years to enhance the reliability and resiliency of its distribution system and reduce the frequency and duration of power outages. On January 23, 2019, the NJBPU granted JCP&L’s request to temporarily suspend the procedural schedule in the matter pending settlement discussions. On April 23, 2019, JCP&L filed a Stipulation of Settlement with the NJBPU on behalf of the JCP&L, Rate Counsel, NJBPU Staff and New Jersey Large Energy Users Coalition, which provides that JCP&L will invest up to approximately $97 million in capital investments beginning on June 1, 2019 through December 31, 2020. 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. On May 8, 2019, the NJBPU issued an order approving the Stipulation of Settlement without modifications. Pursuant to the Stipulation, JCP&L filed a petition on September 16, 2019, to seek approval of rate adjustments to provide for cost recovery established with JCP&L Reliability Plus.
On January 31, 2018, the NJBPU instituted a proceeding to examine the impacts of the Tax Act on the rates and charges of New Jersey utilities. The NJBPU ordered New Jersey utilities to: (1) defer on their books the impacts of the Tax Act effective January 1, 2018; (2) to file tariffs effective April 1, 2018, reflecting the rate impacts of changes in current taxes; and (3) to file tariffs effective July 1, 2018, reflecting the rate impacts of changes in deferred taxes. On March 2, 2018, JCP&L filed a petition with the NJBPU, which included proposed tariffs for a base rate reduction of $28.6 million effective April 1, 2018, and a rider to reflect $1.3 million in rate impacts of changes in deferred taxes. On March 26, 2018, the NJBPU approved JCP&L’s rate reduction effective April 1, 2018, on an interim basis subject to refund, pending the outcome of this proceeding. On April 23, 2019, JCP&L filed a Stipulation of Settlement on behalf of the Rate Counsel, NJBPU Staff, and the New Jersey Large Energy Users Coalition with the NJBPU. The terms of the Stipulation of Settlement provide that between January 1, 2018 and March 31, 2018, JCP&L’s refund obligation is estimated to be approximately $7 million, which will be refunded to customers. The Stipulation of Settlement also provides for a base rate reduction of $28.6 million, which was reflected in rates on April 1, 2018, and a Rider Tax Act Adjustment for certain items over a five-year period. On May 8, 2019, the NJBPU issued an order approving the Stipulation of Settlement without modification.
OHIO
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 continues a base distribution rate freeze through May 31, 2024 and continues Rider DCR, which supports continued investment related to the
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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. ESP IV also includes: (1) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (2) a goal across FirstEnergy to reduce CO 2 emissions by 90% below 2005 levels by 2045; and (3) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio.
In addition, ESP IV 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. Revenues from Rider DMR are excluded from the significantly excessive earnings test. 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. The Ohio Companies filed revised tariffs to implement the refund of Rider DMR funds collected since July 2, 2019. On October 1, 2019, the Ohio Companies implemented PUCO approved tariffs to refund approximately $28 million to customers, including Rider DMR revenues billed from July 2, 2019 through August 31, 2019.
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 intend to contest this appeal but are unable to predict the outcome of this matter.
Under Ohio law, the Ohio Companies are required to implement energy efficiency programs that achieve certain annual energy savings and total peak demand reductions. The Ohio Companies’ 2017-2019 plan includes a portfolio of energy efficiency programs targeted to a variety of customer segments. The Ohio Companies anticipate the cost of the plan will be approximately $268 million over the life of the plan and such costs are expected to be recovered through the Ohio Companies’ existing rate mechanisms. On November 21, 2017, the PUCO issued an order that approved the proposed plan with several modifications, including a cap on the Ohio Companies’ collection of program costs and shared savings set at 4% of the Ohio Companies’ total sales to customers. On October 15, 2019, the SCOH reversed the PUCO’s decision to impose the 4% cost-recovery cap and remanded the matter to the PUCO for approval of the portfolio plans without the cost-recovery cap.
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. The legislation also is ending current energy efficiency program mandates on December 31, 2020, provided statewide energy efficiency mandates are achieved as determined by the PUCO. On October 23, 2019, the PUCO solicited comments on whether the PUCO should terminate the energy efficiency programs once the statewide energy efficiency mandates are achieved. The Ohio Companies plan to apply to the PUCO for approval of the decoupling mechanism later this year, 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. Opponents to the legislation are petitioning to submit the legislation to a statewide referendum on the November 2020 ballot, and stay its effect unless and until approved by a majority of Ohio voters. On September 4, 2019, a lawsuit was filed with the SCOH, challenging the referendum on the grounds that the provisions supporting nuclear energy are a new tax and taxes cannot be overturned by referendum. On October 7, 2019, petitioners filed a lawsuit in the U.S. District Court for the Southern District of Ohio challenging various Ohio legal requirements for a referendum, and seeking additional time to gather signatures in support of a referendum. Petitioners did not meet the October 21, 2019 deadline to file the necessary number of petition signatures. On October 23, 2019, legislation went into effect. The U.S. District Court denied petitioners’ request for more time, and certified questions of state law to the SCOH to answer.
In February 2016, the Ohio Companies filed a Grid Modernization Business Plan for PUCO consideration and approval, as required by the terms of ESP IV. On December 1, 2017, the Ohio Companies filed an application with the PUCO for approval of a DPM Plan, a portfolio of distribution platform investment projects, which are designed to modernize the Ohio Companies’ distribution grid, prepare it for further grid modernization projects, and provide customers with immediate reliability benefits. Also, on January 10, 2018, the PUCO opened a case to consider the impacts of the Tax Act on Ohio utilities’ rates and determine the appropriate course of action to pass benefits on to customers. On November 9, 2018, the Ohio Companies filed a settlement agreement that provides for the implementation of the 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. As part of the agreement, the Ohio Companies also filed an application for approval of a rider to return the remaining tax savings to customers following PUCO approval of the settlement. On January 25, 2019, the Ohio Companies filed a supplemental settlement agreement that keeps intact the provisions of the settlement described above and adds further customer benefits and protections, which broadened support for the settlement. The settlement has 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. On July 17, 2019, the PUCO approved the settlement agreement with no material
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modifications. On August 16, 2019, environmental advocates who were not parties to the settlement filed an application for rehearing challenging the PUCO’s approval of the settlement. On September 11, 2019, the PUCO denied the application for rehearing.
The Ohio Companies’ Rider NMB is designed to recover NMB transmission-related costs imposed on or charged to the Ohio Companies by FERC or PJM. On December 14, 2018, the Ohio Companies filed an application for a review of their 2019 Rider NMB, including recovery of future Legacy RTEP costs and previously absorbed Legacy RTEP costs, net of refunds received from PJM. On February 27, 2018, the PUCO issued an order directing the Ohio Companies to file revised final tariffs recovering Legacy RTEP costs incurred since May 31, 2018, but excluding recovery of approximately $95 million in Legacy RTEP costs incurred prior to May 31, 2018, net of refunds received from PJM. The PUCO solicited comments on whether the Ohio Companies should be permitted to recover the Legacy RTEP charges incurred prior to May 31, 2018. The Ohio Companies, OCC and OMAEG filed comments on March 29, 2019. The Ohio Companies filed reply comments on April 15, 2019. On October 9, 2019, the PUCO approved the recovery of the $95 million of previously excluded Legacy RTEP charges.
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 must also be separately tracked for treatment 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. The 2019-2023 DSPs also include modifications to the Pennsylvania Companies’ POR programs in order to continue their clawback pilot program as a long-term, permanent program term, modifications to the Pennsylvania Companies’ customer class definitions to allow for the introduction of hourly priced default service to customers at or above 100kW, customer assistance program shopping limitations, and script modifications related to the Pennsylvania Companies’ customer referral programs.
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.
Pennsylvania EDCs may establish a DSIC to recover costs of infrastructure improvements and costs related to highway relocation projects with PPUC approval. LTIIPs outlining infrastructure improvement plans for PPUC review and approval must be filed prior to approval of a DSIC. On June 14, 2017, the PPUC approved modified LTIIPs for ME, PN and Penn for the remaining years of 2017 through 2020 to provide additional support for reliability and infrastructure investments. On September 20, 2018, following a periodic review of the LTIIPs as required by regulation once every five years, the PPUC entered an Order concluding that the Pennsylvania Companies have substantially adhered to the schedules and expenditures outlined in their LTIIPs, but that changes to the LTIIPs as designed are necessary to maintain and improve reliability and directed the Pennsylvania Companies to file modified or new LTIIPs. On January 18, 2019, the Pennsylvania Companies filed modifications to their current LTIIPs that would terminate those LTIIPs at the end of 2019, and proposed revised LTIIP spending in 2019 of approximately $45 million by ME, $25 million by PN, $26 million by Penn and $51 million by WP. The Pennsylvania Companies also committed to making filings later in 2019, which would propose new LTIIPs for the 2020 through 2024 period. On May 23, 2019, the PPUC issued an order approving the Pennsylvania Companies’ Modified LTIIPs as filed. On August 30, 2019, the Pennsylvania Companies filed individual Petitions for approval of proposed 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 September 30, 2019, the Pennsylvania OCA submitted comments on the Pennsylvania Companies’ LTIIPs. A PPUC decision is expected by year-end.
The Pennsylvania Companies’ approved DSIC riders for quarterly cost recovery went into effect July 1, 2016, subject to hearings and refund or reallocation among customer classes. In the January 19, 2017 order approving the Pennsylvania Companies’ general rate cases, the PPUC added an additional issue to the DSIC proceeding to include whether ADIT should be included in DSIC calculations. On February 2, 2017, the parties to the DSIC proceeding submitted a Joint Settlement to the ALJ that resolved the issues that were pending from the order issued on June 9, 2016. On April 19, 2018, the PPUC approved the Joint Settlement without modification and reversed the ALJ’s previous decision that would have required the Pennsylvania Companies to reflect all federal and state income tax deductions related to DSIC-eligible property in currently effective DSIC rates. On May 21, 2018, the Pennsylvania OCA filed an appeal with the Pennsylvania Commonwealth Court of the PPUC’s decision of April 19, 2018. On June 11, 2018, the Pennsylvania Companies filed a Notice of Intervention in the Pennsylvania OCA’s appeal to the Commonwealth Court. On July 11, 2019, the Commonwealth Court issued an opinion and order reversing the PPUC’s decision of April 19, 2018 and remanding the matter to the PPUC to require the Pennsylvania Companies to revise their tariffs and DSIC calculations to include ADIT and state income taxes. On July 25, 2019, the PPUC and the Pennsylvania Companies filed separate Applications for Reargument of the Commonwealth Court’s July 11, 2019 Opinion and Order. The Applications were denied by the Commonwealth Court by Orders entered September 4, 2019. On October 7, 2019, the PPUC and the Pennsylvania Companies filed separate Petitions for Allowance of Appeal of the Commonwealth Court’s Opinion and Order to the Pennsylvania Supreme Court. On August
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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. The Pennsylvania Office of Small Business Advocate and the Pennsylvania OCA have opposed Penn’s Petition. On September 20, 2019, Penn filed its direct testimony in support of its Petition.
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. A hearing has been set for December 11, 2019 to consider the settlement, and an order is expected in December 2019 for rates effective January 1, 2020.
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. The hearing in this matter has been set for December 11, 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, AGC, 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 $78.8 million until such time as ATSI submits a cost/benefit analysis demonstrating net benefits to customers from the transfer to PJM. Subsequently, FERC rejected a proposed
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settlement agreement to resolve the exit fee and transmission cost allocation issues, stating that its action is without prejudice to ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh the exit fee and transmission cost allocation charges. 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 issued a NOI seeking information regarding whether and how FERC should 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 15, 2018, FERC issued a NOPR suggesting mechanisms to revise transmission rates to address the Tax Act’s effect on ADIT. Specifically, FERC proposed utilities with transmission formula rates would include mechanisms to (i) deduct any excess ADIT from or add any deficient ADIT to their rate bases; (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. Utilities with transmission stated rates would determine the amount of excess and deferred income tax caused by the reduced federal corporate income tax rate and return or recover this amount to or from customers. To assist with implementation of the proposed rule, 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. FESC, on behalf of its affiliated transmission owners, supported comments submitted by EEI requesting additional clarification on the ratemaking and accounting treatment for ADIT in formula and stated transmission rates. FERC’s final rule remains pending.
Transmission ROE Methodology
In June 2014, FERC issued Opinion No. 531 revising its approach for calculating the discounted cash flow element of FERC’s ROE methodology and announcing the potential for a qualitative adjustment to the ROE methodology results. Parties appealed to the D.C. Circuit, and on April 14, 2017, that court issued a decision vacating FERC’s order and remanding the matter to FERC for further review. On October 16, 2018, FERC issued its order on remand, in which it proposed a revised ROE methodology. Specifically, in complaint proceedings alleging that an existing ROE is not just and reasonable, FERC proposes to 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. 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 NOI comments, and any subsequent rulemaking and other proceedings.
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.
13. 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 September 30, 2019, outstanding guarantees and other assurances aggregated approximately $1.6 billion, consisting of guarantees on behalf of FES and FENOC ($343 million), parental guarantees on behalf of its consolidated subsidiaries ($1 billion), and other guarantees and assurances ($301 million). FirstEnergy has also committed to provide additional guarantees to the FES Debtors for certain retained environmental liabilities of AE Supply related to the Pleasants Power Station and McElroy’s Run CCR disposal facility as part of the settlement agreement in connection with the FES Bankruptcy.
COLLATERAL AND CONTINGENT-RELATED FEATURES
Certain bilateral agreements contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE’s or its subsidiaries’ credit ratings from each of the major
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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 entered into by FE and its subsidiaries have margining provisions that require posting of collateral. The Utilities have posted collateral totaling $2 million.
These credit-risk-related contingent features, or the margining provisions within bilateral agreements, stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining, which is the ability to secure additional collateral when needed, could be required. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of September 30, 2019:

Potential Collateral Obligations |  |  | AE Supply |  | Utilities and FET |  | FE |  | Total
|  | (In millions)
Contractual Obligations for Additional Collateral |  |  |  |  |  |  |  |  |
At current credit rating |  |  | $ | 1 |  |  | $ | — |  |  | $ | — |  |  | $ | 1 |
Upon further downgrade |  |  | — |  |  | 40 |  |  | — |  |  | 40 |
Surety Bonds (collateralized amount)(1) |  |  | 1 |  |  | 63 |  |  | 246 |  |  | 310 |
Total Exposure from Contractual Obligations |  |  | $ | 2 |  |  | $ | 103 |  |  | $ | 246 |  |  | $ | 351 |

(1) | Surety Bonds are not tied to a credit rating. Surety Bonds’ impact assumes maximum contractual obligations (typical obligations require 30 days to cure). FE provides credit support for FG surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR CCR impoundment closure and post-closure activities and the Hatfield’s Ferry CCR disposal site, respectively.

OTHER COMMITMENTS AND CONTINGENCIES
FE is a guarantor under a $300 million syndicated senior secured term loan facility due March 3, 2020, under which Global Holding’s outstanding principal balance is $145 million as of September 30, 2019. 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.
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
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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 September 30, 2019, 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 and Pleasants Units 1 and 2, 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 9 states (including Ohio, Pennsylvania and West Virginia) significantly contribute to New York’s inability to attain the ozone NAAQS. The petition seeks suitable emission rate limits for large stationary sources that are affecting New York’s air quality within the three years allowed by CAA Section 126. 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. 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
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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. 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.
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.
FirstEnergy or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of September 30, 2019, 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 $119 million have been accrued through September 30, 2019. Included in the total are accrued liabilities of approximately $83 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 September 30, 2019, JCP&L, ME and PN had in total approximately $871 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 September 30, 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.
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. See Note 3, “Discontinued Operations,” for additional information.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to FE
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or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 12, “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.
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14. SEGMENT INFORMATION
Regulated Distribution and Regulated Transmission are FirstEnergy’s reportable segments.
On March 31, 2018, as discussed in Note 3, “Discontinued Operations,” FirstEnergy deconsolidated FES and FENOC and presented FES, FENOC, BSPC and a portion of AE Supply, representing substantially all of FirstEnergy’s operations that previously comprised the CES reportable operating segment, as discontinued operations in FirstEnergy’s consolidated financial statements resulting from actions taken as part of the strategic review to exit commodity-exposed generation. The financial information for all periods has been revised to present the discontinued operations within Reconciling Adjustments. The remaining business activities that previously comprised the CES reportable operating segment were not material and, as such, have been combined into Corporate/Other for reporting purposes.
The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. The segment’s results reflect the 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. 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.
The Corporate/Other segment reflects corporate support not charged to FE’s subsidiaries, 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 September 30, 2019, 67 MWs of electric generating capacity, representing AE Supply’s OVEC capacity entitlement, was included in continuing operations of the Corporate/Other reportable segment. As of September 30, 2019, Corporate/Other had approximately $7.1 billion of FE holding company debt.
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Financial information for each of FirstEnergy’s reportable segments is presented in the tables below:
Segment Financial Information

For the Three Months Ended |  | Regulated Distribution |  | Regulated Transmission |  | Corporate/ Other |  | Reconciling Adjustments |  | Consolidated
|  | (In millions)
September 30, 2019 |  |  |  |  |  |  |  |  |  |
External revenues |  | $ | 2,590 |  |  | $ | 371 |  |  | $ | 2 |  |  | $ | — |  |  | $ | 2,963 |
Internal revenues |  | 46 |  |  | 4 |  |  | — |  |  | (50 | ) |  | — |
Total revenues |  | $ | 2,636 |  |  | $ | 375 |  |  | $ | 2 |  |  | $ | (50 | ) |  | $ | 2,963 |
Depreciation |  | 215 |  |  | 71 |  |  | — |  |  | 18 |  |  | 304 |
Amortization of regulatory assets, net |  | 42 |  |  | 1 |  |  | — |  |  | — |  |  | 43 |
Miscellaneous income (expense), net |  | 36 |  |  | 4 |  |  | 24 |  |  | (7 | ) |  | 57 |
Interest expense |  | 124 |  |  | 49 |  |  | 95 |  |  | (7 | ) |  | 261 |
Income taxes (benefits) |  | 103 |  |  | 26 |  |  | (22 | ) |  | — |  |  | 107 |
Income (loss) from continuing operations |  | 370 |  |  | 113 |  |  | (94 | ) |  | — |  |  | 389 |
Property additions |  | 365 |  |  | 304 |  |  | 15 |  |  | — |  |  | 684 |
September 30, 2018 |  |  |  |  |  |  |  |  |  |
External revenues |  | $ | 2,717 |  |  | $ | 341 |  |  | $ | 6 |  |  | $ | — |  |  | $ | 3,064 |
Internal revenues |  | 49 |  |  | 5 |  |  | — |  |  | (54 | ) |  | — |
Total revenues |  | $ | 2,766 |  |  | $ | 346 |  |  | $ | 6 |  |  | $ | (54 | ) |  | $ | 3,064 |
Depreciation |  | 202 |  |  | 64 |  |  | 1 |  |  | 16 |  |  | 283 |
Amortization of regulatory assets, net |  | 65 |  |  | 2 |  |  | — |  |  | — |  |  | 67 |
Miscellaneous income (expense), net |  | 34 |  |  | 4 |  |  | 19 |  |  | (8 | ) |  | 49 |
Interest expense |  | 127 |  |  | 43 |  |  | 93 |  |  | (8 | ) |  | 255 |
Income taxes (benefits) |  | 126 |  |  | 34 |  |  | (39 | ) |  | — |  |  | 121 |
Income (loss) from continuing operations |  | 416 |  |  | 99 |  |  | (116 | ) |  | — |  |  | 399 |
Property additions |  | 356 |  |  | 262 |  |  | 5 |  |  | 12 |  |  | 635 |
For the Nine Months Ended |  |  |  |  |  |  |  |  |  |
September 30, 2019 |  |  |  |  |  |  |  |  |  |
External revenues |  | $ | 7,261 |  |  | $ | 1,091 |  |  | $ | 10 |  |  | $ | — |  |  | $ | 8,362 |
Internal revenues |  | 140 |  |  | 12 |  |  | — |  |  | (152 | ) |  | — |
Total revenues |  | $ | 7,401 |  |  | $ | 1,103 |  |  | $ | 10 |  |  | $ | (152 | ) |  | $ | 8,362 |
Depreciation |  | 644 |  |  | 211 |  |  | 3 |  |  | 52 |  |  | 910 |
Amortization of regulatory assets, net |  | 79 |  |  | 6 |  |  | — |  |  | — |  |  | 85 |
Miscellaneous income (expense), net |  | 128 |  |  | 12 |  |  | 73 |  |  | (22 | ) |  | 191 |
Interest expense |  | 370 |  |  | 142 |  |  | 283 |  |  | (22 | ) |  | 773 |
Income taxes (benefits) |  | 259 |  |  | 87 |  |  | (65 | ) |  | — |  |  | 281 |
Income (loss) from continuing operations |  | 957 |  |  | 333 |  |  | (205 | ) |  | — |  |  | 1,085 |
Property additions |  | 1,037 |  |  | 835 |  |  | 40 |  |  | — |  |  | 1,912 |
September 30, 2018 |  |  |  |  |  |  |  |  |  |
External revenues |  | $ | 7,540 |  |  | $ | 996 |  |  | $ | 15 |  |  | $ | — |  |  | $ | 8,551 |
Internal revenues |  | 154 |  |  | 14 |  |  | 13 |  |  | (181 | ) |  | — |
Total revenues |  | $ | 7,694 |  |  | $ | 1,010 |  |  | $ | 28 |  |  | $ | (181 | ) |  | $ | 8,551 |
Depreciation |  | 598 |  |  | 187 |  |  | 6 |  |  | 52 |  |  | 843 |
Amortization (deferral) of regulatory assets, net |  | (194 | ) |  | 6 |  |  | — |  |  | — |  |  | (188 | )
Miscellaneous income (expense), net |  | 146 |  |  | 11 |  |  | 34 |  |  | (27 | ) |  | 164 |
Interest expense |  | 384 |  |  | 124 |  |  | 377 |  |  | (27 | ) |  | 858 |
Income taxes (benefits) |  | 357 |  |  | 104 |  |  | (6 | ) |  | — |  |  | 455 |
Income (loss) from continuing operations |  | 1,115 |  |  | 302 |  |  | (529 | ) |  | — |  |  | 888 |
Property additions |  | 1,011 |  |  | 836 |  |  | 68 |  |  | 27 |  |  | 1,942 |
As of September 30, 2019 |  |  |  |  |  |  |  |  |  |
Total assets |  | $ | 29,428 |  |  | $ | 11,255 |  |  | $ | 790 |  |  | $ | 33 |  |  | $ | 41,506 |
Total goodwill |  | 5,004 |  |  | 614 |  |  | — |  |  | — |  |  | 5,618 |
As of December 31, 2018 |  |  |  |  |  |  |  |  |  |
Total assets |  | $ | 28,690 |  |  | $ | 10,404 |  |  | $ | 944 |  |  | $ | 25 |  |  | $ | 40,063 |
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.
On March 31, 2018, FirstEnergy deconsolidated FES and FENOC and presented FES, FENOC, BSPC and a portion of AE Supply, representing substantially all of FirstEnergy’s operations that previously comprised the CES reportable operating segment, as discontinued operations in FirstEnergy’s consolidated financial statements resulting from actions taken as part of the strategic review to exit commodity-exposed generation. The financial information for all periods has been revised to present the discontinued operations within Reconciling Adjustments. The remaining business activities that previously comprised the CES reportable operating segment were not material and, as such, have been combined into Corporate/Other for reporting purposes.
The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. The segment’s results reflect the 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. 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.
The Corporate/Other segment reflects corporate support not charged to FE’s subsidiaries, 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 September 30, 2019, 67 MWs of electric generating capacity, representing AE Supply’s OVEC capacity entitlement, was included in continuing operations of the Corporate/Other reportable segment. As of September 30, 2019, Corporate/Other had approximately $7.1 billion of FE holding company debt.
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EXECUTIVE SUMMARY
FirstEnergy’s strategy is to be a fully regulated utility company, focusing 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. Together, the Regulated Distribution and Regulated Transmission businesses are expected to provide stable, predictable earnings and cash flows that support FE’s dividend.
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 $6.2 to $6.7 billion in forecasted capital investments from 2018 through 2021, Regulated Distribution’s rate base growth rate is expected to be approximately 5% from 2018 through 2021. 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 in operations, the Regulated Transmission business is the centerpiece of FirstEnergy’s regulated investment strategy with approximately 80% of its capital investments recovered under the forward-looking formula rates at ATSI, TrAIL and MAIT. Regulated Transmission has also experienced significant growth as part of its Energizing the Future transmission plan with plans to invest up to $4.8 billion in capital from 2018 to 2021, which is expected to result in Regulated Transmission rate base growth of approximately 11% through 2021.
As part of the Energizing the Future initiative, a Center for Advanced Technology was opened in Akron, Ohio in April 2019. The 88,000 square feet facility was designed to be a hands-on environment where engineers and technicians can develop and evaluate new technology and grid solutions and simulate a variety of real-world conditions.
FirstEnergy believes there are incremental investment opportunities for its existing transmission infrastructure of over $20 billion beyond those identified through 2021, 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.
On December 22, 2017, the President signed the Tax Act into law. Substantially all of the provisions of the Tax Act are effective for taxable years beginning after December 31, 2017. As discussed below, various state regulatory proceedings have been initiated to investigate the impact of the Tax Act on the Utilities’ rates and charges. FirstEnergy continues to work with various state regulatory commissions to determine appropriate changes to customer rates resulting from the Tax Act. Several states have since implemented rate reductions to reflect the impact of the Tax Act, while in the remaining states, FirstEnergy continues to track and apply regulatory accounting treatment for the expected rate impact of changes resulting from the Tax Act. FERC also recently took action to address the impact of the Tax Act on FERC-jurisdictional rates, including transmission and electric wholesale rates. FirstEnergy has reflected the impact of changes to current taxes in its normal update to FERC-jurisdictional transmission rates and will continue to work with FERC regarding whether and how it should address possible changes to transmission and wholesale rates resulting from the Tax Act.
As previously disclosed, on January 22, 2018, FirstEnergy announced a $2.5 billion equity issuance, which included $1.62 billion in mandatorily convertible preferred equity with an initial conversion price of $27.42 per share and $850 million of common equity issued at $28.22 per share. The equity investment strengthened the Company’s balance sheet, supports 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 at least 2021 outside of its regular stock investment and employee benefit plans. On July 22, 2019, 28,302 shares of preferred stock automatically converted into 1,032,165 shares of common stock, and 181,520 shares of preferred stock remained unconverted as the holder reached the 4.9% cap as outlined in the terms of the preferred stock. The remaining 181,520 preferred stock shares were converted on August 1, 2019, into 6,619,985 shares of common stock. As of September 30, 2019, there are no preferred shares outstanding and 1,616,000 shares of preferred stock were converted into 58,935,078 shares of common stock.
On March 31, 2018, FirstEnergy’s competitive subsidiary FES and FENOC voluntarily filed petitions under Chapter 11 of the Federal Bankruptcy Code with the U.S. Bankruptcy Court. FirstEnergy and its other subsidiaries - including its Utilities and AE Supply - are not part of the filing and are not subject to the Chapter 11 process. The voluntary bankruptcy filings by the FES Debtors represented a significant event 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. As a result of the bankruptcy filings, as of March 31, 2018, the FES Debtors were deconsolidated from FirstEnergy’s financial statements. Additionally, the operating results of the FES Debtors, as well as BSPC and a portion of AE Supply (including the Pleasants Power Station) that were subject to completed or pending asset sales, collectively representing substantially all of FirstEnergy’s operations that comprised the CES reportable segment, are presented as discontinued operations. Prior periods have been reclassified to conform with such presentation as discontinued operations.
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On April 23, 2018, FirstEnergy and the FES Key Creditor Groups reached an agreement in principle to resolve certain claims by FirstEnergy against the FES Debtors and all claims by the FES Debtors and their creditors against FirstEnergy. On September 26, 2018, the Bankruptcy Court approved a FES Bankruptcy settlement agreement dated August 26, 2018, 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 resolves certain claims by FirstEnergy against the FES Debtors and all claims by the FES Debtors and the FES Key Creditor Groups against FirstEnergy, and includes the following terms, among others:

• | FE will pay certain pre-petition FES Debtors employee-related obligations, which include unfunded pension obligations and other employee benefits.

• | A nonconsensual release of all claims against FirstEnergy by the FES Debtors’ creditors, which was subsequently waived pursuant to the Waiver Agreement, discussed below.

• | A $225 million cash payment from FirstEnergy.

• | A $628 million aggregate principal amount note issuance by FirstEnergy to the FES Debtors, which may be decreased by the amount, if any, of cash paid by FirstEnergy to the FES Debtors under the Intercompany Income Tax Allocation Agreement for the tax benefits related to the sale or deactivation of certain plants.

• | Transfer of the Pleasants Power Station and related assets, including the economic interests therein as of January 1, 2019, and a requirement that FE continue to provide access to the McElroy’s Run CCR Impoundment Facility, which is not being transferred. FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility.

• | FirstEnergy agrees to waive all pre-petition claims related to shared services and credit for nine months of the FES Debtors’ shared service costs beginning as of April 1, 2018 through December 31, 2018, in an amount not to exceed $112.5 million, and FirstEnergy agrees to extend the availability of shared services until no later than June 30, 2020.

• | Subject to a cap, FirstEnergy has 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 (approximately $14 million recognized in the first nine months of 2019).

• | FirstEnergy agrees to perform under the Intercompany Tax Allocation Agreement through the FES Debtors’ emergence from bankruptcy, at which time FirstEnergy will waive a 2017 overpayment for NOLs of approximately $71 million, reverse 2018 estimated payments for NOLs of approximately $88 million and pay the FES Debtors for the use of NOLs in an amount no less than $66 million for 2018. Based on the 2018 federal tax return filed in September 2019, FirstEnergy owes the FES debtors approximately $31 million associated with 2018, which will be paid upon emergence.

The FES Bankruptcy settlement agreement remains subject to satisfaction of certain conditions. There can be no assurance that such conditions will be satisfied or the FES Bankruptcy settlement agreement will be otherwise consummated, and the actual outcome of this matter may differ materially from the terms of the agreement described herein. FirstEnergy will continue to evaluate the impact of any new factors on the settlement and their relative impact on the financial statements.
On April 11, 2019, the Bankruptcy Court entered an order denying the FES Debtors’ disclosure statement approval motion. The Bankruptcy Court concluded that the nonconsensual third-party releases proposed under the plan of reorganization, which were a condition under the FES Bankruptcy settlement agreement for FirstEnergy’s benefit, were legally impermissible and rendered the plan unconfirmable. On April 18, 2019, FirstEnergy consented to the waiver of the condition. Additionally, the FES Debtors agreed to provide FirstEnergy with the same third-party release provided in favor of certain other parties in any plan of reorganization and to pay FirstEnergy approximately $60 million in cash (paid during the second quarter of 2019) to resolve certain outstanding pension and service charges totaling $87 million, which resulted in FirstEnergy recognizing a $27 million pre-tax charge to income in the first quarter of 2019 ($17 million of which was recognized in continuing operations). Further, the FES Debtors agreed to initiate negotiations with the EPA, OEPA, PA DEP and the NRC to obtain those parties’ cooperation with the FES Debtors’ revised plan of reorganization. FirstEnergy may choose to participate in those negotiations at its option. On May 20, 2019, the Bankruptcy Court approved the waiver and a revised disclosure statement.
In August 2019, the Bankruptcy Court held hearings to consider whether to confirm the FES Debtors’ plan of reorganization. Upon the conclusion of the hearing, the Bankruptcy Court ruled against the objections of several parties, including FERC and OVEC. However, the Bankruptcy Court ruled in favor of the objections made by certain of the FES Debtors’ unions regarding their collective bargaining agreements. The Bankruptcy Court adjourned the hearing without ruling on confirmation and explained that the only issue to be resolved was the acceptance or rejection by the FES Debtors of the collective bargaining agreements at issue.
In October 2019, the FES Debtors and the unions objecting to confirmation of the plan of reorganization reached an agreement framework and the unions agreed to withdraw their objections to the plan of reorganization. On October 15, 2019, the Bankruptcy Court held a hearing to confirm the FES Debtors’ plan of reorganization, and on October 16, 2019, entered a final order confirming the FES Debtors' plan of reorganization. On October 29, 2019, several parties, including FERC, filed notices of appeal with the United States District Court for the Northern District of Ohio appealing the Bankruptcy Court’s final order approving FES Debtors’ plan of reorganization. The emergence of the FES Debtors from bankruptcy pursuant to the confirmed plan of reorganization is subject to the satisfaction of certain conditions, including approvals from the FERC and NRC.
In connection with the FES Bankruptcy settlement agreement, FirstEnergy entered into a separation agreement with the FES Debtors to implement the separation of the FES Debtors and their businesses from FirstEnergy. A business separation committee was established between FirstEnergy and the FES Debtors to review and determine issues that arise in the context of the separation of the FES Debtors’ businesses from those of FirstEnergy.
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With the bankruptcy filings of FES and FENOC, and the completed sale of the previously announced competitive Bath hydroelectric station, FirstEnergy’s electric generation fleet is now made up of 3,790 MW of regulated generation, including four plants in West Virginia, Virginia and New Jersey. This excludes AE Supply’s remaining competitive generation assets - the 1,300 MW Pleasants Power Station, which will be transferred to FG pursuant to the settlement agreement, and its 67 MW OVEC capacity entitlement.
FINANCIAL OVERVIEW AND RESULTS OF OPERATIONS

(In millions) |  | For the Three Months Ended September 30, |  | For the Nine Months Ended September 30,
|  | 2019 |  | 2018 |  | Change |  | 2019 |  | 2018 |  | Change
Revenues |  | $ | 2,963 |  |  | $ | 3,064 |  |  | $ | (101 | ) |  | (3 | )% |  | $ | 8,362 |  |  | $ | 8,551 |  |  | $ | (189 | ) |  | (2 | )%
Operating expenses |  | 2,282 |  |  | 2,354 |  |  | (72 | ) |  | (3 | )% |  | 6,467 |  |  | 6,561 |  |  | (94 | ) |  | (1 | )%
Operating income |  | 681 |  |  | 710 |  |  | (29 | ) |  | (4 | )% |  | 1,895 |  |  | 1,990 |  |  | (95 | ) |  | (5 | )%
Other expenses, net |  | (185 | ) |  | (190 | ) |  | 5 |  |  | 3 | % |  | (529 | ) |  | (647 | ) |  | 118 |  |  | 18 | %
Income before income taxes |  | 496 |  |  | 520 |  |  | (24 | ) |  | (5 | )% |  | 1,366 |  |  | 1,343 |  |  | 23 |  |  | 2 | %
Income taxes |  | 107 |  |  | 121 |  |  | (14 | ) |  | (12 | )% |  | 281 |  |  | 455 |  |  | (174 | ) |  | (38 | )%
Income from continuing operations |  | 389 |  |  | 399 |  |  | (10 | ) |  | (3 | )% |  | 1,085 |  |  | 888 |  |  | 197 |  |  | 22 | %
Discontinued operations, net of tax |  | 2 |  |  | (857 | ) |  | 859 |  |  | NM |  |  | (62 | ) |  | 322 |  |  | (384 | ) |  | NM |
Net income (loss) |  | $ | 391 |  |  | $ | (458 | ) |  | $ | 849 |  |  | 185 | % |  | $ | 1,023 |  |  | $ | 1,210 |  |  | $ | (187 | ) |  | (15 | )%

* 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 14, “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 — Third Quarter 2019 Compared with Third Quarter 2018
Financial results for FirstEnergy’s business segments in the third quarter of 2019 and 2018 were as follows:

Third Quarter 2019 Financial Results |  | Regulated Distribution |  | Regulated Transmission |  | Corporate/Other and Reconciling Adjustments |  | FirstEnergy Consolidated
|  | (In millions)
Revenues: |  |  |  |  |  |  |  |  |  |  |
Electric |  | $ | 2,571 |  |  | $ | 371 |  |  | $ | (33 | ) |  | $ | 2,909 |
Other |  | 65 |  |  | 4 |  |  | (15 | ) |  | 54 |
Total Revenues |  | 2,636 |  |  | 375 |  |  | (48 | ) |  | 2,963 |
Operating Expenses: |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  | 122 |  |  | — |  |  | — |  |  | 122 |
Purchased power |  | 794 |  |  | — |  |  | 4 |  |  | 798 |
Other operating expenses |  | 715 |  |  | 75 |  |  | (32 | ) |  | 758 |
Provision for depreciation |  | 215 |  |  | 71 |  |  | 18 |  |  | 304 |
Amortization of regulatory assets, net |  | 42 |  |  | 1 |  |  | — |  |  | 43 |
General taxes |  | 197 |  |  | 53 |  |  | 7 |  |  | 257 |
Total Operating Expenses |  | 2,085 |  |  | 200 |  |  | (3 | ) |  | 2,282 |
Operating Income (Loss) |  | 551 |  |  | 175 |  |  | (45 | ) |  | 681 |
Other Income (Expense): |  |  |  |  |  |  |  |  |  |  |  |
Miscellaneous income, net |  | 36 |  |  | 4 |  |  | 17 |  |  | 57 |
Interest expense |  | (124 | ) |  | (49 | ) |  | (88 | ) |  | (261 | )
Capitalized financing costs |  | 10 |  |  | 9 |  |  | — |  |  | 19 |
Total Other Expense |  | (78 | ) |  | (36 | ) |  | (71 | ) |  | (185 | )
Income (Loss) Before Income Taxes (Benefits) |  | 473 |  |  | 139 |  |  | (116 | ) |  | 496 |
Income taxes (benefits) |  | 103 |  |  | 26 |  |  | (22 | ) |  | 107 |
Income (Loss) From Continuing Operations |  | 370 |  |  | 113 |  |  | (94 | ) |  | 389 |
Discontinued operations, net of tax |  | — |  |  | — |  |  | 2 |  |  | 2 |
Net Income (Loss) |  | $ | 370 |  |  | $ | 113 |  |  | $ | (92 | ) |  | $ | 391 |

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Third Quarter 2018 Financial Results |  | Regulated Distribution |  | Regulated Transmission |  | Corporate/Other and Reconciling Adjustments |  | FirstEnergy Consolidated
|  | (In millions)
Revenues: |  |  |  |  |  |  |  |  |  |  |
Electric |  | $ | 2,698 |  |  | $ | 341 |  |  | $ | (30 | ) |  | $ | 3,009 |
Other |  | 68 |  |  | 5 |  |  | (18 | ) |  | 55 |
Total Revenues |  | 2,766 |  |  | 346 |  |  | (48 | ) |  | 3,064 |
Operating Expenses: |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  | 137 |  |  | — |  |  | — |  |  | 137 |
Purchased power |  | 873 |  |  | — |  |  | 3 |  |  | 876 |
Other operating expenses |  | 663 |  |  | 68 |  |  | 8 |  |  | 739 |
Provision for depreciation |  | 202 |  |  | 64 |  |  | 17 |  |  | 283 |
Amortization of regulatory assets, net |  | 65 |  |  | 2 |  |  | — |  |  | 67 |
General taxes |  | 197 |  |  | 49 |  |  | 6 |  |  | 252 |
Total Operating Expenses |  | 2,137 |  |  | 183 |  |  | 34 |  |  | 2,354 |
Operating Income (Loss) |  | 629 |  |  | 163 |  |  | (82 | ) |  | 710 |
Other Income (Expense): |  |  |  |  |  |  |  |  |  |  |  |
Miscellaneous income, net |  | 34 |  |  | 4 |  |  | 11 |  |  | 49 |
Interest expense |  | (127 | ) |  | (43 | ) |  | (85 | ) |  | (255 | )
Capitalized financing costs |  | 6 |  |  | 9 |  |  | 1 |  |  | 16 |
Total Other Expense |  | (87 | ) |  | (30 | ) |  | (73 | ) |  | (190 | )
Income (Loss) Before Income Taxes (Benefits) |  | 542 |  |  | 133 |  |  | (155 | ) |  | 520 |
Income taxes (benefits) |  | 126 |  |  | 34 |  |  | (39 | ) |  | 121 |
Income (Loss) From Continuing Operations |  | 416 |  |  | 99 |  |  | (116 | ) |  | 399 |
Discontinued operations, net of tax |  | — |  |  | — |  |  | (857 | ) |  | (857 | )
Net Income (Loss) |  | $ | 416 |  |  | $ | 99 |  |  | $ | (973 | ) |  | $ | (458 | )

46

Changes Between Third Quarter 2019 and Third Quarter 2018 Financial Results |  | Regulated Distribution |  | Regulated Transmission |  | Corporate/Other and Reconciling Adjustments |  | FirstEnergy Consolidated
|  | (In millions)
Revenues: |  |  |  |  |  |  |  |  |  |  |
Electric |  | $ | (127 | ) |  | $ | 30 |  |  | $ | (3 | ) |  | $ | (100 | )
Other |  | (3 | ) |  | (1 | ) |  | 3 |  |  | (1 | )
Total Revenues |  | (130 | ) |  | 29 |  |  | — |  |  | (101 | )
Operating Expenses: |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  | (15 | ) |  | — |  |  | — |  |  | (15 | )
Purchased power |  | (79 | ) |  | — |  |  | 1 |  |  | (78 | )
Other operating expenses |  | 52 |  |  | 7 |  |  | (40 | ) |  | 19 |
Provision for depreciation |  | 13 |  |  | 7 |  |  | 1 |  |  | 21 |
Amortization of regulatory assets, net |  | (23 | ) |  | (1 | ) |  | — |  |  | (24 | )
General taxes |  | — |  |  | 4 |  |  | 1 |  |  | 5 |
Total Operating Expenses |  | (52 | ) |  | 17 |  |  | (37 | ) |  | (72 | )
Operating Income (Loss) |  | (78 | ) |  | 12 |  |  | 37 |  |  | (29 | )
Other Income (Expense): |  |  |  |  |  |  |  |  |  |  |  |
Miscellaneous income, net |  | 2 |  |  | — |  |  | 6 |  |  | 8 |
Interest expense |  | 3 |  |  | (6 | ) |  | (3 | ) |  | (6 | )
Capitalized financing costs |  | 4 |  |  | — |  |  | (1 | ) |  | 3 |
Total Other Expense |  | 9 |  |  | (6 | ) |  | 2 |  |  | 5 |
Income (Loss) Before Income Taxes (Benefits) |  | (69 | ) |  | 6 |  |  | 39 |  |  | (24 | )
Income taxes (benefits) |  | (23 | ) |  | (8 | ) |  | 17 |  |  | (14 | )
Income (Loss) From Continuing Operations |  | (46 | ) |  | 14 |  |  | 22 |  |  | (10 | )
Discontinued operations, net of tax |  | — |  |  | — |  |  | 859 |  |  | 859 |
Net Income (Loss) |  | $ | (46 | ) |  | $ | 14 |  |  | $ | 881 |  |  | $ | 849 |

47

Regulated Distribution — Third Quarter 2019 Compared with Third Quarter 2018
Regulated Distribution’s operating results decreased $46 million in the third quarter of 2019, as compared to the same period of 2018, primarily resulting from the SCOH ruling that ceased collection of Rider DMR and lower weather-related customer usage.
Revenues —
The $130 million decrease in total revenues resulted from the following sources:

|  | For the Three Months Ended September 30, |  |
Revenues by Type of Service |  | 2019 |  | 2018 |  | Decrease
|  | (In millions)
Distribution services(1) |  | $ | 1,482 |  |  | $ | 1,506 |  |  | $ | (24 | )
Generation sales: |  |  |  |  |  |
Retail |  | 989 |  |  | 1,059 |  |  | (70 | )
Wholesale |  | 100 |  |  | 133 |  |  | (33 | )
Total generation sales |  | 1,089 |  |  | 1,192 |  |  | (103 | )
Other |  | 65 |  |  | 68 |  |  | (3 | )
Total Revenues |  | $ | 2,636 |  |  | $ | 2,766 |  |  | $ | (130 | )

(1) Includes $25 million and $66 million of ARP revenues for the three months ended September 30, 2019 and 2018, respectively.
Distribution services revenues decreased $24 million in the third quarter of 2019, as compared to the same period of 2018, primarily resulting from the SCOH ruling that ceased collection of Rider DMR and lower weather-related customer usage, partially offset by the implementation of NJ Zero Emission Program in June 2019 and higher rates associated with the recovery of deferred costs. Distribution deliveries by customer class are summarized in the following table:

|  | For the Three Months Ended September 30, |  |
Electric Distribution MWH Deliveries |  | 2019 |  | 2018 |  | Decrease
|  | (In thousands)
Residential |  | 15,306 |  |  | 15,657 |  |  | (2.2 | )%
Commercial |  | 10,013 |  |  | 10,412 |  |  | (3.8 | )%
Industrial |  | 14,477 |  |  | 14,618 |  |  | (1.0 | )%
Other |  | 135 |  |  | 137 |  |  | (1.5 | )%
Total Electric Distribution MWH Deliveries |  | 39,931 |  |  | 40,824 |  |  | (2.2 | )%

Lower distribution deliveries to residential and commercial customers primarily reflect lower weather-related usage resulting from cooling degree days that were 9% below 2018, but 22% above normal. Deliveries to industrial customers reflect lower automotive, steel and chemical customer usage, partially offset by higher shale customer usage.
48

The following table summarizes the price and volume factors contributing to the $103 million decrease in generation revenues for the third quarter of 2019, as compared to the same period of 2018:

Source of Change in Generation Revenues |  | Increase (Decrease)
|  | (In millions)
Retail: |  |  |
Change in sales volumes |  | $ | 6 |
Change in prices |  | (76 | )
|  | (70 | )
Wholesale: |  |
Change in sales volumes |  | (2 | )
Change in prices |  | (8 | )
Capacity revenue |  | (23 | )
|  | (33 | )
Decrease in Generation Revenues |  | $ | (103 | )

Total generation provided by alternative suppliers as a percentage of total MWH deliveries was flat. The decrease in retail generation prices primarily resulted from lower non-shopping generation auction rates in Pennsylvania and New Jersey, lower ENEC rate in West Virginia and rate reductions resulting from the Tax Act.
Wholesale generation revenues decreased $33 million in the third quarter of 2019, as compared to the same period in 2018, 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 $52 million in the third quarter of 2019, as compared to the same period of 2018, primarily due to the following:

• | Fuel expense decreased $15 million in 2019, as compared to the same period of 2018, primarily due to lower unit costs.

• | Purchased power costs were $79 million lower in the third quarter of 2019, as compared to the same period in 2018, primarily due to lower unit costs and 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 from non-affiliates: |  |
| Change due to decreased unit costs |  | $ | (41 | )
| Change due to volumes |  | 47 |
|  |  | 6 |
| Purchases from affiliates: |  |
| Change due to decreased unit costs |  | (3 | )
| Change due to volumes |  | (48 | )
|  |  | (51 | )
| Capacity expense |  | (34 | )
| Decrease in Purchased Power Costs |  | $ | (79 | )

49

• | Other operating expenses increased $52 million in the third quarter of 2019, as compared to the same period of 2018, primarily due to the following:

• | Increased storm restoration costs of $19 million, which were mostly deferred for future recovery, resulting in no material impact on current period earnings.

• | Higher network transmission expenses of $44 million, reflecting increased transmission costs as well as the absence of the FERC settlement during the third quarter of 2018, which reallocated certain transmission costs across utilities in PJM and resulted in a refund to the Ohio Companies. Except for certain transmission costs and credits at the Ohio Companies recognized in 2018, the difference between current revenues and transmission costs incurred are deferred for future recovery or refund, resulting in no material impact on current period earnings.

• | Higher operating and maintenance expense of $5 million, primarily associated with higher employee benefit costs and regulated generation maintenance activities, partially offset by lower regulated generation support costs and transactions now accounted for as finance leases. As a result of the adoption of the new lease accounting standard, financing lease expenses that were recognized in other operating expenses are now recognized in depreciation and interest expense.

• | Higher vegetation management spend of $6 million, partially offset by lower energy efficiency and other program costs of $2 million. These costs are deferred for future recovery, resulting in no material impact on current period earnings.

• | The absence of $20 million in costs associated with the 2018 voluntary enhanced retirement package.

• | Depreciation expense increased $13 million in the third quarter of 2019, as compared to the same period of 2018, primarily due to a higher asset base and transactions now accounted for as finance leases, as discussed above.

• | Amortization expense decreased $23 million in the third quarter of 2019, as compared to the same period of 2018, primarily due to higher storm restoration cost deferrals, partially offset by lower deferrals of generation and transmission expenses, including the FERC settlement discussed above.

Other Expenses —
Other Expense decreased $9 million in the third quarter of 2019, as compared to the same period of 2018, primarily due to lower interest expense from debt maturities and refinancings, higher capitalized financing costs, and the absence of 2018 special termination costs, partially offset by higher pension and OPEB non-service costs and transactions now accounted for as finance leases, as discussed above.
Income Taxes —
Regulated Distribution’s effective tax rate was 21.8% and 23.2% for the three months ended September 30, 2019 and 2018, respectively. The lower effective tax rate in 2019 was primarily due to the amortization of net excess deferred income taxes resulting from Tax Act settlements and orders with certain regulatory commissions.
Regulated Transmission — Third Quarter 2019 Compared with Third Quarter 2018
Regulated Transmission’s operating results increased $14 million in the third quarter of 2019, as compared to the same period of 2018, primarily due to the impact of a higher rate base at ATSI and MAIT, partially offset by a lower rate base at TrAIL.
Revenues —
Total revenues increased $29 million in the third quarter of 2019, as compared to the same period of 2018, primarily due to recovery of incremental operating expenses and a higher rate base at ATSI and MAIT, partially offset by a lower rate base at TrAIL.
The following table shows revenues by transmission asset owner:

|  | For the Three Months Ended September 30, |  | Increase
Revenues by Transmission Asset Owner |  | 2019 |  | 2018 |  | (Decrease)
|  | (In millions)
ATSI |  | $ | 185 |  |  | $ | 168 |  |  | $ | 17 |
TrAIL |  | 57 |  |  | 62 |  |  | (5 | )
MAIT |  | 59 |  |  | 44 |  |  | 15 |
Other |  | 74 |  |  | 72 |  |  | 2 |
Total Revenues |  | $ | 375 |  |  | $ | 346 |  |  | $ | 29 |

50

Operating Expenses —
Total operating expenses increased $17 million in the third quarter of 2019, as compared to the same period of 2018, primarily due to higher operating and maintenance expenses as well as higher property taxes and depreciation due to a higher asset base. The majority of the increases were recovered through formula rates at ATSI and MAIT, resulting in no material impact on current period earnings.
Other Expense —
Total other expense increased $6 million in the third quarter of 2019, as compared to the same period of 2018, primarily due to higher interest expense associated with new debt issuances at FET.
Income Taxes —
Regulated Transmission’s effective tax rate was 18.7% and 25.6% for the three months ended September 30, 2019 and 2018, respectively. The lower effective tax rate in 2019 was primarily due to the amortization of net excess deferred income taxes resulting from FERC guidance related to the Tax Act.
Corporate / Other — Third Quarter 2019 Compared with Third Quarter 2018
Financial results from the Corporate/Other operating segment resulted in a $22 million increase in income from continuing operations in the third quarter of 2019, as compared to the same period of 2018, primarily due to lower operating expenses as a result of the absence of remeasuring the ARO of McElroy’s Run, higher returns on certain equity method investments and lower non-operating expenses.
For the three months ended September 30, 2019, FirstEnergy recorded income from discontinued operations, net of tax of $2 million compared to a loss of $857 million for the three months ended September 30, 2018. The change in discontinued operations, net of tax was primarily due to the absence of an $834 million loss on deconsolidation of FES and FENOC.
51

Summary of Results of Operations — First Nine Months of 2019 Compared with First Nine Months of 2018
Financial results for FirstEnergy’s business segments in the first nine months of 2019 and 2018 were as follows:

First Nine Months 2019 Financial Results |  | Regulated Distribution |  | Regulated Transmission |  | Corporate/Other and Reconciling Adjustments |  | FirstEnergy Consolidated
|  | (In millions)
Revenues: |  |  |  |  |  |  |  |  |  |  |
Electric |  | $ | 7,214 |  |  | $ | 1,090 |  |  | $ | (96 | ) |  | $ | 8,208 |
Other |  | 187 |  |  | 13 |  |  | (46 | ) |  | 154 |
Total Revenues |  | 7,401 |  |  | 1,103 |  |  | (142 | ) |  | 8,362 |
Operating Expenses: |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  | 382 |  |  | — |  |  | — |  |  | 382 |
Purchased power |  | 2,177 |  |  | — |  |  | 13 |  |  | 2,190 |
Other operating expenses |  | 2,116 |  |  | 205 |  |  | (178 | ) |  | 2,143 |
Provision for depreciation |  | 644 |  |  | 211 |  |  | 55 |  |  | 910 |
Amortization of regulatory assets, net |  | 79 |  |  | 6 |  |  | — |  |  | 85 |
General taxes |  | 572 |  |  | 156 |  |  | 29 |  |  | 757 |
Total Operating Expenses |  | 5,970 |  |  | 578 |  |  | (81 | ) |  | 6,467 |
Operating Income (Loss) |  | 1,431 |  |  | 525 |  |  | (61 | ) |  | 1,895 |
Other Income (Expense): |  |  |  |  |  |  |  |  |  |  |  |
Miscellaneous income, net |  | 128 |  |  | 12 |  |  | 51 |  |  | 191 |
Interest expense |  | (370 | ) |  | (142 | ) |  | (261 | ) |  | (773 | )
Capitalized financing costs |  | 27 |  |  | 25 |  |  | 1 |  |  | 53 |
Total Other Expense |  | (215 | ) |  | (105 | ) |  | (209 | ) |  | (529 | )
Income (Loss) Before Income Taxes (Benefits) |  | 1,216 |  |  | 420 |  |  | (270 | ) |  | 1,366 |
Income taxes (benefits) |  | 259 |  |  | 87 |  |  | (65 | ) |  | 281 |
Income (Loss) From Continuing Operations |  | 957 |  |  | 333 |  |  | (205 | ) |  | 1,085 |
Discontinued operations, net of tax |  | — |  |  | — |  |  | (62 | ) |  | (62 | )
Net Income (Loss) |  | $ | 957 |  |  | $ | 333 |  |  | $ | (267 | ) |  | $ | 1,023 |

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First Nine Months 2018 Financial Results |  | Regulated Distribution |  | Regulated Transmission |  | Corporate/Other and Reconciling Adjustments |  | FirstEnergy Consolidated
|  | (In millions)
Revenues: |  |  |  |  |  |  |  |  |  |  |
Electric |  | $ | 7,497 |  |  | $ | 996 |  |  | $ | (107 | ) |  | $ | 8,386 |
Other |  | 197 |  |  | 14 |  |  | (46 | ) |  | 165 |
Total Revenues |  | 7,694 |  |  | 1,010 |  |  | (153 | ) |  | 8,551 |
Operating Expenses: |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  | 404 |  |  | — |  |  | — |  |  | 404 |
Purchased power |  | 2,391 |  |  | — |  |  | 2 |  |  | 2,393 |
Other operating expenses |  | 2,227 |  |  | 182 |  |  | (46 | ) |  | 2,363 |
Provision for depreciation |  | 598 |  |  | 187 |  |  | 58 |  |  | 843 |
Amortization (deferral) of regulatory assets, net |  | (194 | ) |  | 6 |  |  | — |  |  | (188 | )
General taxes |  | 576 |  |  | 144 |  |  | 26 |  |  | 746 |
Total Operating Expenses |  | 6,002 |  |  | 519 |  |  | 40 |  |  | 6,561 |
Operating Income (Loss) |  | 1,692 |  |  | 491 |  |  | (193 | ) |  | 1,990 |
Other Income (Expense): |  |  |  |  |  |  |  |  |  |  |  |
Miscellaneous income, net |  | 146 |  |  | 11 |  |  | 7 |  |  | 164 |
Interest expense |  | (384 | ) |  | (124 | ) |  | (350 | ) |  | (858 | )
Capitalized financing costs |  | 18 |  |  | 28 |  |  | 1 |  |  | 47 |
Total Other Expense |  | (220 | ) |  | (85 | ) |  | (342 | ) |  | (647 | )
Income (Loss) Before Income Taxes (Benefits) |  | 1,472 |  |  | 406 |  |  | (535 | ) |  | 1,343 |
Income taxes (benefits) |  | 357 |  |  | 104 |  |  | (6 | ) |  | 455 |
Income (Loss) From Continuing Operations |  | 1,115 |  |  | 302 |  |  | (529 | ) |  | 888 |
Discontinued operations, net of tax |  | — |  |  | — |  |  | 322 |  |  | 322 |
Net Income (Loss) |  | $ | 1,115 |  |  | $ | 302 |  |  | $ | (207 | ) |  | $ | 1,210 |

53

Changes Between First Nine Months 2019 and First Nine Months 2018 Financial Results |  | Regulated Distribution |  | Regulated Transmission |  | Corporate/Other and Reconciling Adjustments |  | FirstEnergy Consolidated
|  | (In millions)
Revenues: |  |  |  |  |  |  |  |  |  |  |
Electric |  | $ | (283 | ) |  | $ | 94 |  |  | $ | 11 |  |  | $ | (178 | )
Other |  | (10 | ) |  | (1 | ) |  | — |  |  | (11 | )
Total Revenues |  | (293 | ) |  | 93 |  |  | 11 |  |  | (189 | )
Operating Expenses: |  |  |  |  |  |  |  |  |  |  |  |
Fuel |  | (22 | ) |  | — |  |  | — |  |  | (22 | )
Purchased power |  | (214 | ) |  | — |  |  | 11 |  |  | (203 | )
Other operating expenses |  | (111 | ) |  | 23 |  |  | (132 | ) |  | (220 | )
Provision for depreciation |  | 46 |  |  | 24 |  |  | (3 | ) |  | 67 |
Amortization (deferral) of regulatory assets, net |  | 273 |  |  | — |  |  | — |  |  | 273 |
General taxes |  | (4 | ) |  | 12 |  |  | 3 |  |  | 11 |
Total Operating Expenses |  | (32 | ) |  | 59 |  |  | (121 | ) |  | (94 | )
Operating Income (Loss) |  | (261 | ) |  | 34 |  |  | 132 |  |  | (95 | )
Other Income (Expense): |  |  |  |  |  |  |  |  |  |  |  |
Miscellaneous income (expense), net |  | (18 | ) |  | 1 |  |  | 44 |  |  | 27 |
Interest expense |  | 14 |  |  | (18 | ) |  | 89 |  |  | 85 |
Capitalized financing costs |  | 9 |  |  | (3 | ) |  | — |  |  | 6 |
Total Other Expense |  | 5 |  |  | (20 | ) |  | 133 |  |  | 118 |
Income (Loss) Before Income Taxes (Benefits) |  | (256 | ) |  | 14 |  |  | 265 |  |  | 23 |
Income taxes (benefits) |  | (98 | ) |  | (17 | ) |  | (59 | ) |  | (174 | )
Income (Loss) From Continuing Operations |  | (158 | ) |  | 31 |  |  | 324 |  |  | 197 |
Discontinued operations, net of tax |  | — |  |  | — |  |  | (384 | ) |  | (384 | )
Net Income (Loss) |  | $ | (158 | ) |  | $ | 31 |  |  | $ | (60 | ) |  | $ | (187 | )

54

Regulated Distribution — First Nine Months of 2019 Compared with First Nine Months of 2018
Regulated Distribution’s net income decreased $158 million in the first nine months of 2019, as compared to the same period of 2018, primarily resulting from the SCOH ruling that ceased collection of Rider DMR, the absence of the reversal of a reserve on recoverability of certain REC purchases in Ohio, the net impact of a FERC settlement that reallocated certain transmission costs, and lower revenues associated with decreased weather-related usage.
Revenues —
The $293 million decrease in total revenues resulted from the following sources:

|  | For the Nine Months Ended September 30, |  |
Revenues by Type of Service |  | 2019 |  | 2018 |  | Decrease
|  | (In millions)
Distribution services(1) |  | $ | 4,045 |  |  | $ | 4,139 |  |  | $ | (94 | )
Generation sales: |  |  |  |  |  |
Retail |  | 2,853 |  |  | 2,981 |  |  | (128 | )
Wholesale |  | 316 |  |  | 377 |  |  | (61 | )
Total generation sales |  | 3,169 |  |  | 3,358 |  |  | (189 | )
Other |  | 187 |  |  | 197 |  |  | (10 | )
Total Revenues |  | $ | 7,401 |  |  | $ | 7,694 |  |  | $ | (293 | )

(1) Includes $142 million and $190 million of ARP revenues for the nine months ended September 30, 2019 and 2018, respectively.
Distribution services revenues decrease d $94 million in the first nine months of 2019, as compared to the same period of 2018, primarily resulting from the SCOH ruling that ceased collection of Rider DMR, lower weather-related customer usage, and the implementation of rate orders and settlements related to the Tax Act, partially offset by implementation of NJ Zero Emission Program in June 2019 and higher rates associated with the recovery of deferred costs. Distribution deliveries by customer class are summarized in the following table:

|  | For the Nine Months Ended September 30, |  |
Electric Distribution MWH Deliveries |  | 2019 |  | 2018 |  | Decrease
|  | (In thousands)
Residential |  | 41,311 |  |  | 42,730 |  |  | (3.3 | )%
Commercial |  | 28,496 |  |  | 29,365 |  |  | (3.0 | )%
Industrial |  | 42,032 |  |  | 42,663 |  |  | (1.5 | )%
Other |  | 413 |  |  | 418 |  |  | (1.2 | )%
Total Electric Distribution MWH Deliveries |  | 112,252 |  |  | 115,176 |  |  | (2.5 | )%

Lower distribution deliveries to residential and commercial customers primarily reflect lower weather-related usage resulting from cooling degree days that were 14% below 2018, but 15% above normal, as well as, heating degree days that were 4% below 2018, and 5% below normal. Deliveries to industrial customers reflect lower steel and automotive customer usage, partially offset by higher shale customer usage.
55

The following table summarizes the price and volume factors contributing to the $189 million decrease in generation revenues for the first nine months of 2019, as compared to the same period of 2018:

Source of Change in Generation Revenues |  | Increase (Decrease)
|  | (In millions)
Retail: |  |  |
Change in sales volumes |  | $ | 8 |
Change in prices |  | (136 | )
|  | (128 | )
Wholesale: |  |
Change in sales volumes |  | (9 | )
Change in prices |  | (33 | )
Capacity revenue |  | (19 | )
|  | (61 | )
Decrease in Generation Revenues |  | $ | (189 | )

Total generation provided by alternative suppliers as a percentage of total MWH deliveries was flat. The decrease in retail generation prices primarily resulted from lower non-shopping generation auction rates in Pennsylvania and lower ENEC rate in West Virginia, which included rate reductions resulting from the Tax Act.
Wholesale generation revenues decreased $61 million in the first nine months of 2019, as compared to the same period in 2018, 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 $32 million, primarily due to the following:

• | Fuel costs were $22 million lower during the first nine months of 2019, as compared to the same period of 2018, primarily due to lower unit costs.

• | Purchased power costs decreased $214 million during the first nine months of 2019, as compared to the same period of 2018, primarily due to lower unit costs, 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 from non-affiliates: |  |
| Change due to decreased unit costs |  | $ | (148 | )
| Change due to volumes |  | 56 |
|  |  | (92 | )
| Purchases from affiliates: |  |
| Change due to decreased unit costs |  | (7 | )
| Change due to volumes |  | (93 | )
|  |  | (100 | )
| Capacity |  | (22 | )
| Decrease in Purchased Power Costs |  | $ | (214 | )

56

• | Other operating expenses decreased $111 million in the first nine months of 2019, as compared to the same period of 2018, primarily due to:

• | Decreased storm restoration costs of $123 million, which were deferred for future recovery, resulting in no material impact on current period earnings.

• | Lower energy efficiency and other program costs of $19 million, partially offset by higher vegetation management spend of $8 million. These costs are deferred for future recovery, resulting in no material impact on current period earnings.

• | Lower operating and maintenance expenses of $40 million, primarily associated with lower corporate support costs and transactions now accounted for as finance leases, partially offset by higher contractor spend and regulated generation maintenance activities. As a result of the adoption of the new lease accounting standard, financing lease expenses that were recognized in other operating expenses are now recognized in depreciation and interest expense in 2019.

• | The absence of $19 million in costs associated with the 2018 voluntary enhanced retirement package.

• | Higher net network transmission expenses of $82 million, reflecting increased transmission costs as well as the absence of the FERC settlement during the third quarter of 2018, which reallocated certain transmission costs across utilities in PJM and resulted in a refund to the Ohio Companies. Except for certain transmission costs and credits at the Ohio Companies recognized in 2018, the difference between current revenues and transmission costs incurred are deferred for future recovery or refund, resulting in no material impact on current period earnings.

• | Depreciation expense increased $46 million in the first nine months of 2019, as compared to the same period of 2018, primarily due to a higher rate base and transactions now accounted for as finance leases, as discussed above.

• | Amortization expense increased $273 million in the first nine months of 2019, as compared to the same period of 2018, primarily due to decreased deferral of storm restoration costs, the absence of the reversal of a liability at the Ohio Companies for an Ohio Supreme Court ruling regarding purchase of RECs, as well as lower deferrals of generation and transmission expenses, including the FERC settlement discussed above.

Other Expense —
Total other expense decreased $5 million in the first nine months of 2019, as compared to the same period of 2018, primarily due to lower interest expense from debt maturities and refinancings, higher capitalized financing costs, and the absence of 2018 special termination costs, partially offset by higher pension and OPEB non-service costs and transactions now accounted for as finance leases, as discussed above.
Income Taxes —
Regulated Distribution’s effective tax rate was 21.3% and 24.3% for the nine months ended September 30, 2019 and 2018, respectively. The lower effective tax rate in 2019 was primarily due to the amortization of net excess deferred income taxes resulting from Tax Act settlements and orders with certain regulatory commissions, and the remeasurement of uncertain tax positions during 2019.
Regulated Transmission — First Nine Months of 2019 Compared with First Nine Months of 2018
Regulated Transmission’s net income increased $31 million in the first nine months of 2019, as compared to the same period of 2018, primarily resulting from the impact of a higher rate base at ATSI and MAIT, partially offset by a lower rate base at TrAIL.
Revenues —
Total revenues increased $93 million, primarily due to the recovery of incremental operating expenses and a higher rate base at ATSI and MAIT, partially offset by a lower rate base at TrAIL.
57

The following table shows revenues by transmission asset owner:

|  | For the Nine Months Ended September 30, |  |
Revenues by Transmission Asset Owner |  | 2019 |  | 2018 |  | Increase (Decrease)
|  | (In millions)
ATSI |  | $ | 545 |  |  | $ | 495 |  |  | $ | 50 |
TrAIL |  | 178 |  |  | 190 |  |  | (12 | )
MAIT |  | 160 |  |  | 109 |  |  | 51 |
Other |  | 220 |  |  | 216 |  |  | 4 |
Total Revenues |  | $ | 1,103 |  |  | $ | 1,010 |  |  | $ | 93 |

Operating Expenses —
Total operating expenses increased $59 million in the first nine months of 2019, as compared to the same period of 2018, primarily due to higher operating and maintenance expenses as well as higher property taxes and depreciation due to a higher asset base. The majority of the increases were recovered through formula rates at ATSI and MAIT, resulting in no material impact on current period earnings.
Other Expense —
Total other expense increased $20 million in the first nine months of 2019, as compared to the same period of 2018, primarily due to higher interest expense associated with new debt issuances at ATSI, MAIT and FET.
Income Taxes —
Regulated Transmission’s effective tax rate was 20.7% and 25.6% for the nine months ended September 30, 2019 and 2018, respectively. The lower effective tax rate in 2019 was primarily due to the amortization of net excess deferred income taxes resulting from FERC guidance related to the Tax Act.
Corporate / Other — First Nine Months of 2019 Compared with First Nine Months of 2018
Financial results from the Corporate/Other operating segment and reconciling adjustments resulted in a $324 million increase in income from continuing operations in the first nine months of 2019, as compared to the same period of 2018, primarily due to lower income taxes from the absence of a $126 million charge in the first quarter of 2018 associated with the remeasurement of state deferred taxes in West Virginia when FES and FENOC were removed from the unitary group following their bankruptcy filing on March 31, 2018. Lower interest expense of $89 million was due to the absence of make-whole payments, and lower other operating expenses of $132 million were primarily due to lower incurred corporate support costs in continuing operations related to FES and FENOC and the absence of remeasuring the ARO of McElroy’s Run. Although the operations of FES and FENOC for the first quarter of 2018 (prior to deconsolidation on March 31, 2018) are reflected as discontinued operations, certain allocated corporate support costs to FES and FENOC continue to be reflected in continuing operations. Additionally, higher net miscellaneous income was primarily due to higher returns on certain equity method investments and lower non-operating expenses.
For the nine months ended September 30, 2019, FirstEnergy recorded a loss from discontinued operations, net of tax of $62 million compared to income of $322 million for the nine months ended September 30, 2018. The change in discontinued operations, net of tax was primarily due to the absence of a $405 million gain on deconsolidation of FES and FENOC.
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.
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The following table provides information about the composition of net regulatory assets and liabilities as of September 30, 2019, and December 31, 2018, and the changes during the nine months ended September 30, 2019:

Net Regulatory Assets (Liabilities) by Source |  | September 30, 2019 |  | December 31, 2018 |  | Change
|  | (In millions)
Regulatory transition costs |  | $ | (4 | ) |  | $ | 49 |  |  | $ | (53 | )
Customer payables for future income taxes |  | (2,682 | ) |  | (2,725 | ) |  | 43 |
Nuclear decommissioning and spent fuel disposal costs |  | (198 | ) |  | (148 | ) |  | (50 | )
Asset removal costs |  | (771 | ) |  | (787 | ) |  | 16 |
Deferred transmission costs |  | 145 |  |  | 170 |  |  | (25 | )
Deferred generation costs |  | 186 |  |  | 202 |  |  | (16 | )
Deferred distribution costs |  | 169 |  |  | 208 |  |  | (39 | )
Contract valuations |  | 65 |  |  | 72 |  |  | (7 | )
Storm-related costs |  | 541 |  |  | 500 |  |  | 41 |
Other |  | 21 |  |  | 52 |  |  | (31 | )
Net Regulatory Liabilities included on the Consolidated Balance Sheets |  | $ | (2,528 | ) |  | $ | (2,407 | ) |  | $ | (121 | )

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.
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, and are amortized through 2036.
Contract valuations - Includes the changes in fair value of PN above-market NUG costs and the amortization of purchase accounting adjustments at MP and 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 $204 million and $232 million are currently being recovered through rates as of September 30, 2019 and December 31, 2018, respectively.
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The following table provides information about the composition of net regulatory assets that do not earn a current return as of September 30, 2019 and December 31, 2018, a majority of which are currently being recovered through rates over varying periods depending on the nature of the deferral and the jurisdiction. Additionally, certain regulatory assets, totaling approximately $110 million as of September 30, 2019, are recorded based on prior precedent or anticipated recovery based on rate making premises without a specific order.

Regulatory Assets by Source Not Earning a Current Return |  | September 30, 2019 |  | December 31, 2018 |  | Change
|  | (In millions)
Regulatory transition costs |  | $ | 9 |  |  | $ | 10 |  |  | $ | (1 | )
Deferred transmission costs |  | 35 |  |  | 87 |  |  | (52 | )
Storm-related costs |  | 449 |  |  | 363 |  |  | 86 |
Other |  | 47 |  |  | 43 |  |  | 4 |
Regulatory Assets Not Earning a Current Return |  | $ | 540 |  |  | $ | 503 |  |  | $ | 37 |

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.
On January 22, 2018, FirstEnergy announced a $2.5 billion equity issuance, which included $1.62 billion in mandatorily convertible preferred equity with an initial conversion price of $27.42 per share and $850 million of common equity issued at $28.22 per share. 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. The shares of preferred stock contain an optional conversion right, requiring mandatory conversion in July 2019, subject to certain exceptions noted below. Proceeds from the investment were used to reduce holding company debt by $1.45 billion and fund FirstEnergy’s pension plan as discussed below, with the remainder used for general corporate purposes. At the option of the preferred stockholders, 494,767 shares of preferred stock were converted into 18,044,018 shares of common stock in January 2019. On July 22, 2019, 28,302 shares of preferred stock automatically converted into 1,032,165 shares of common stock, and 181,520 shares of preferred stock remained unconverted as the holder reached the 4.9% cap as outlined in the terms of the preferred stock. The remaining 181,520 preferred stock shares were converted on August 1, 2019, into 6,619,985 shares of common stock. As of September 30, 2019, there are no preferred shares outstanding and 1,616,000 shares of preferred stock were converted into 58,935,078 shares of common stock.
The equity investment strengthened FirstEnergy’s balance sheet and supports the company’s transition to a fully regulated utility company. By deleveraging the company, the investment also enables FirstEnergy to enhance its investment grade credit metrics and FirstEnergy does not currently anticipate the need to issue additional equity through at least 2021 outside of 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 2019 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 certain 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. As a result of this contribution, FirstEnergy expects no required contributions through 2021.
FirstEnergy’s transmission growth program, Energizing the Future, provides a stable and proven investment platform, while producing important customer benefits. Through the program, $4.4 billion in capital investments were made from 2014 through 2017, and the company plans to invest up to an additional $4.8 billion in the 2018-2021 time frame, which includes a target of $1.2 billion annually through 2021. As noted above, over 80% of these capital investments are recoverable through formula rate mechanisms, reducing regulatory lag in recovering a return on investment, while offering a reasonable rate of return. These investments are expected to continue to improve the performance and condition of the transmission system while increasing automation and communication, adding capacity to the system and improving customer reliability. Beyond 2021, FirstEnergy believes there are incremental investment opportunities for its existing transmission infrastructure of over $20 billion, 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 the Regulated Distribution segment, FirstEnergy remains committed to providing customer service-oriented growth opportunities by investing between $6.2 billion and $6.7 billion over 2018 to 2021. Approximately 40% of capital expenditures are recoverable
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through various rate mechanisms, riders and trackers. Beginning in 2019, expected investments at the Ohio Companies include the pending Ohio Grid Modernization plan which includes installation of approximately 700,000 advanced meters, distribution automation, and integrated ‘volt/var’ controls. Additionally, the JCP&L Reliability Plus infrastructure improvement plan will reduce outages and strengthen the system while preparing for the grid of the future in New Jersey. FirstEnergy continues to explore other opportunities for growth in its Regulated Distribution business, 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 electrification of customers’ homes and businesses by providing a full range of products and services.
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.
As of September 30, 2019, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was due in large part to short-term borrowings of $1,000 million, currently payable long-term debt of $381 million, and other current liabilities of $1,084 million primarily attributable to interest, customer deposits and anticipated payments under the FES Bankruptcy settlement. Currently payable long-term debt as of September 30, 2019, 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 (Facilities), which are available until December 6, 2022. Under the FE 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 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 their 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 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 Facilities contains financial covenants requiring each borrower to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the Facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter.
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FirstEnergy had $1,000 million and $1,250 million of short-term borrowings as September 30, 2019 and December 31, 2018, respectively. FirstEnergy’s available liquidity from external sources as of October 31, 2019, was as follows:

Borrower(s) |  | Type |  | Maturity |  | Commitment |  | Available Liquidity
|  |  |  |  |  | (In millions)
FirstEnergy(1) |  | Revolving |  | December 2022 |  | $ | 2,500 |  |  | $ | 2,494 |
FET(2) |  | Revolving |  | December 2022 |  | 1,000 |  |  | 1,000 |
|  |  |  | Subtotal |  | $ | 3,500 |  |  | $ | 3,494 |
|  | Cash and cash equivalents |  | — |  |  | 743 |
|  |  |  | Total |  | $ | 3,500 |  |  | $ | 4,237 |

(1) | FE and the Utilities. Available liquidity includes impact of $6 million of LOCs issued under various terms.

(2) | Includes FET and the Transmission Companies.

The following table summarizes the borrowing sub-limits for each borrower under the facilities, the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of September 30, 2019:

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 September 30, 2019, 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.
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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.
The initial borrowing of $1.75 billion under the new term loans, which took the form of a Eurodollar rate advance, may be converted from time to time, in whole or in part, to alternate base rate advances or other Eurodollar rate advances. Outstanding alternate base rate advances will bear interest at a fluctuating interest rate per annum equal to the sum of an applicable margin for alternate base rate advances determined by reference to FE’s reference ratings plus the highest of (i) the administrative agent’s publicly-announced “prime rate,” (ii) the sum of 1/2 of 1% per annum plus the Federal Funds Rate in effect from time to time and (iii) the rate of interest per annum appearing on a nationally-recognized service such as the Dow Jones Market Service (Telerate) equal to one-month LIBOR on each day plus 1%. Outstanding Eurodollar rate advances will bear interest at LIBOR for interest periods of one week or one, two, three or six months plus an applicable margin determined by reference to FE’s reference ratings. Changes in FE’s reference ratings would lower or raise its applicable margin depending on whether ratings improved or were lowered, respectively.
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 nine months of 2019 was 2.43% per annum for the regulated companies’ money pool and 2.92% 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 October 31, 2019:

|  | 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 |  | P
AGC |  | BBB- |  | Baa2 |  | BBB |  | — |  | — |  | — |  | — |  | — |  | — |  | S |  | S |  | S
ATSI |  | BBB |  | A3 |  | BBB |  | — |  | — |  | — |  | BBB |  | A3 |  | BBB+ |  | S |  | S |  | P
CEI |  | BBB |  | Baa2 |  | BBB |  | A- |  | A3 |  | A- |  | BBB |  | Baa2 |  | BBB+ |  | S |  | S |  | P
FET |  | BBB |  | Baa2 |  | BBB- |  | — |  | — |  | — |  | BBB- |  | Baa2 |  | BBB- |  | S |  | S |  | P
JCP&L |  | BBB |  | Baa1 |  | BBB |  | — |  | — |  | — |  | BBB |  | Baa1 |  | BBB+ |  | S |  | P |  | P
ME |  | BBB |  | A3 |  | BBB |  | — |  | — |  | — |  | BBB |  | A3 |  | BBB+ |  | S |  | S |  | P
MAIT |  | BBB |  | A3 |  | BBB |  | — |  | — |  | — |  | BBB |  | A3 |  | BBB+ |  | S |  | S |  | P
MP |  | BBB |  | Baa2 |  | BBB |  | A- |  | A3 |  | A- |  | BBB |  | Baa2 |  | — |  | S |  | S |  | S
OE |  | BBB |  | A3 |  | BBB |  | A- |  | A1 |  | A- |  | BBB |  | A3 |  | BBB+ |  | S |  | P |  | P
PN |  | BBB |  | Baa1 |  | BBB |  | — |  | — |  | — |  | BBB |  | Baa1 |  | BBB+ |  | S |  | S |  | P
Penn |  | BBB |  | A3 |  | BBB |  | — |  | A1 |  | A- |  | — |  | — |  | — |  | S |  | P |  | P
PE |  | BBB |  | Baa2 |  | BBB |  | — |  | — |  | A- |  | — |  | — |  | — |  | S |  | S |  | S
TE |  | BBB |  | Baa1 |  | BBB |  | A- |  | A2 |  | A- |  | — |  | — |  | — |  | S |  | S |  | P
TrAIL |  | BBB |  | A3 |  | BBB |  | — |  | — |  | — |  | BBB |  | A3 |  | BBB+ |  | S |  | S |  | P
WP |  | BBB |  | A3 |  | BBB |  | — |  | — |  | A- |  | — |  | — |  | — |  | S |  | S |  | P

(1) S = Stable and P = Positive
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Debt capacity is subject to the consolidated debt-to-total-capitalization limits in the credit facilities previously discussed. As of September 30, 2019, FE and its subsidiaries could issue additional debt of approximately $8.5 billion, or incur a $4.6 billion reduction to equity, and remain within the limitations of the financial covenants required by the FE Facility.
Changes in Cash Position
As of September 30, 2019, FirstEnergy had $716 million of cash and cash equivalents and approximately $34 million of restricted cash compared to $367 million of cash and cash equivalents and approximately $62 million of restricted cash as of December 31, 2018, 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.
FirstEnergy’s Consolidated Statement of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. The following table summarizes the major classes of cash flow items from discontinued operations for the nine months ended September 30, 2019 and 2018:

|  | For the Nine Months Ended September 30,
(In millions) |  | 2019 |  | 2018
CASH FLOWS FROM OPERATING ACTIVITIES: |  |  |  |
Income (loss) from discontinued operations |  | $ | (62 | ) |  | $ | 322 |
Depreciation and amortization, including regulatory assets, net, intangible assets and deferred debt-related costs |  | — |  |  | 110 |

Net cash provided from operating activities was $1,737 million during the first nine months of 2019, compared to $558 million in the same period of 2018. Key changes were as follows:

• | a $750 million decrease in cash contributions to the qualified pension plan;

• | higher transmission revenue reflecting a higher base rate and recovery of incremental operating expenses at ATSI and MAIT;

• | an increase in working capital primarily due to the timing of payments from customers;

• | lower storm costs; partially offset by

• | the absence of FES’ cash from operations from the first quarter of 2018.

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Cash Flows From Financing Activities
In the first nine months of 2019, cash provided from financing activities was $665 million compared to $1,523 million in the same period of 2018. The following table summarizes new equity and debt financing, redemptions, repayments, make-whole premiums paid on debt redemptions, short-term borrowings and dividends:

|  | For the Nine Months Ended September 30,
Securities Issued or Redeemed / Repaid |  | 2019 |  | 2018
|  | (In millions)
New Issues |  |  |  |  |  |
Unsecured notes |  | $ | 1,850 |  |  | $ | 550 |
Pollution Control Revenue Bonds |  | — |  |  | 74 |
FMBs |  | 250 |  |  | — |
|  | $ | 2,100 |  |  | $ | 624 |
Preferred stock issuance |  | $ | — |  |  | $ | 1,616 |
Common stock issuance |  | $ | — |  |  | $ | 850 |
Redemptions / Repayments |  |  |  |  |  |
Unsecured notes |  | $ | (725 | ) |  | $ | (555 | )
Term loan |  | — |  |  | (1,450 | )
Pollution Control Revenue Bonds |  | — |  |  | (216 | )
Senior secured notes |  | (59 | ) |  | (57 | )
|  | $ | (784 | ) |  | $ | (2,278 | )
Make-whole premiums paid on debt redemptions |  | $ | — |  |  | $ | (89 | )
Short-term borrowings, net |  | $ | — |  |  | $ | 1,400 |
Preferred stock dividend payments |  | $ | (6 | ) |  | $ | (52 | )
Common stock dividend payments |  | $ | (609 | ) |  | $ | (527 | )

On January 10, 2019, ME issued $500 million of 4.30% senior notes due 2029. Proceeds from the issuance of senior notes were primarily used to refinance existing indebtedness, including ME’s $300 million of 7.70% senior notes due 2019, and borrowings outstanding under the FE regulated utility money pool and the FE Facility, to fund capital expenditures, and for other general corporate purposes.
On February 8, 2019, JCP&L issued $400 million of 4.30% senior notes due 2026. Proceeds from the issuance of the senior notes were primarily used to refinance existing indebtedness, including amounts under the FE regulated utility money pool incurred in connection with the repayment at maturity of JCP&L’s $300 million of 7.35% senior notes due 2019 and the funding of storm recovery and restoration costs and expenses, to fund capital expenditures and working capital requirements and for other general corporate purposes.
On March 28, 2019, FET issued $500 million of 4.55% senior notes due 2049. Proceeds from the issuance of the senior notes were used primarily to support FET’s capital structure, to repay short-term borrowings outstanding under the FE unregulated money pool, to finance capital improvements, and for other general corporate purposes, including funding working capital needs and day-to-day operations.
On April 15, 2019, ATSI issued $100 million of 4.38% senior notes due 2031. Proceeds from the issuance of the senior notes were used primarily to repay short-term borrowings, to fund capital expenditures and working capital needs, and for other general corporate purposes.
On May 21, 2019, WP issued $100 million of 4.22% FMBs due 2059. Proceeds from the issuance of the FMBs were or are, as the case may be, used to refinance existing indebtedness, to fund capital expenditures, and for other general corporate purposes.
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On June 3, 2019, PN issued $300 million of 3.60% senior notes due 2029. Proceeds from the issuance of the senior notes were used to refinance existing indebtedness, including amounts outstanding under the FE regulated companies’ money pool incurred in connection with the repayment at maturity of PN’s $125 million of 6.63% senior notes due 2019, to fund capital expenditures, and for other general corporate purposes.
On June 5, 2019, AGC issued $50 million of 4.47% senior unsecured notes due 2029. Proceeds from the issuance of the senior notes were used to improve liquidity, re-establish the debt component within its capital structure following the recent redemption of all of its existing long-term debt, and satisfy working capital requirements and other general corporate purposes.
On August 13, 2019, MP agreed to sell $200 million of FMBs in two tranches. On November 14, 2019, MP will settle $155 million of 3.23% FMBs due 2029 and $45 million of 3.93% FMBs due 2049.
On August 15, 2019, WP issued $150 million of 4.22% FMBs due 2059. Proceeds were used to refinance existing indebtedness, fund capital expenditures and for other general corporate purposes.
Cash Flows From Investing Activities
Cash used for investing activities in the first nine months of 2019 principally represented cash used for property additions. The following table summarizes investing activities for the first nine months of 2019 and 2018:

|  | For the Nine Months Ended September 30, |  | Increase
Cash Used for Investing Activities(1) |  | 2019 |  | 2018 |  | (Decrease)
|  | (In millions)
Property Additions: |  |  |  |  |  |
Regulated Distribution |  | $ | 1,037 |  |  | $ | 1,011 |  |  | $ | 26 |
Regulated Transmission |  | 835 |  |  | 836 |  |  | (1 | )
Corporate / Other |  | 40 |  |  | 95 |  |  | (55 | )
Proceeds from asset sales |  | (18 | ) |  | (419 | ) |  | 401 |
Investments |  | 30 |  |  | 44 |  |  | (14 | )
Notes receivable from affiliated companies |  | — |  |  | 500 |  |  | (500 | )
Asset removal costs |  | 158 |  |  | 171 |  |  | (13 | )
Other |  | (1 | ) |  | (1 | ) |  | — |
|  | $ | 2,081 |  |  | $ | 2,237 |  |  | $ | (156 | )

(1) See Note 3, “Discontinued Operations,” for major classes of discontinued operations for cash used for investing activities.
Cash used for investing activities for the first nine months of 2019 decreased $156 million, compared to the same period of 2018, primarily due to the absence of FES’ borrowings from the committed line of credit available under the secured credit facility with FE during the first quarter of 2018, lower property additions and asset removal costs, partially offset by lower proceeds from asset sales.
The decrease in property additions was due to the following:

• | a decrease of $55 million at Corporate/Other due to lower competitive generation related investments; partially offset by

• | an increase of $26 million at Regulated Distribution due to investments in electric system improvements and modernization projects to increase reliability.

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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 September 30, 2019, was approximately $1.6 billion, as summarized below:

Guarantees and Other Assurances |  | Maximum Exposure
|  | (In millions)
FE’s Guarantees on Behalf of FES and FENOC |  |  |
Surety Bonds - FG(1) |  | $ | 200 |
Deferred compensation arrangements |  | 143 |
|  | 343 |
FE’s Guarantees on Behalf of its Consolidated Subsidiaries |  |
AE Supply asset sales(2) |  | 555 |
Deferred compensation arrangements |  | 424 |
Fuel related contracts and other |  | 13 |
|  | 992 |
FE’s Guarantees and Other Assurances |  |
Global holding facility |  | 145 |
Surety Bonds |  | 135 |
LOCs and other |  | 21 |
|  | 301 |
Total Guarantees and Other Assurances |  | $ | 1,636 |

(1) | FE provides credit support for FG surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR CCR impoundment closure and post-closure activities and the Hatfield’s Ferry CCR disposal site, respectively.

(2) | 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 connection with the FES Bankruptcy settlement agreement, FirstEnergy has also committed to provide additional guarantees to FG for certain retained environmental liabilities of AE Supply related to the Pleasants Power Station and the McElroy’s Run CCR disposal facility.

Collateral and Contingent-Related Features
Certain bilateral agreements contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE’s or its subsidiaries’ credit ratings from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements.
Bilateral agreements entered into by FE and its subsidiaries have margining provisions that require posting of collateral. The Utilities have posted collateral totaling $2 million.
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These credit-risk-related contingent features, or the margining provisions within bilateral agreements, stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining, which is the ability to secure additional collateral when needed, could be required. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of September 30, 2019:

Potential Collateral Obligations |  |  | AE Supply |  | Utilities and FET |  | FE |  | Total
|  | (In millions)
Contractual Obligations for Additional Collateral |  |  |  |  |  |  |  |  |
At current credit rating |  |  | $ | 1 |  |  | $ | — |  |  | $ | — |  |  | $ | 1 |
Upon further downgrade |  |  | — |  |  | 40 |  |  | — |  |  | 40 |
Surety Bonds (collateralized amount)(1) |  |  | 1 |  |  | 63 |  |  | 246 |  |  | 310 |
Total Exposure from Contractual Obligations |  |  | $ | 2 |  |  | $ | 103 |  |  | $ | 246 |  |  | $ | 351 |

(1) | Surety Bonds are not tied to a credit rating. Surety Bonds’ impact assumes maximum contractual obligations (typical obligations require 30 days to cure). FE provides credit support for FG surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR CCR impoundment closure and post-closure activities and the Hatfield’s Ferry CCR disposal site, respectively.

Other Commitments and Contingencies
FE is a guarantor under a $300 million syndicated senior secured term loan facility due March 3, 2020, under which Global Holding’s outstanding principal balance is $145 million as of September 30, 2019. 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 September 30, 2019, FirstEnergy has a net liability of $20 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 September 30, 2019, the FirstEnergy pension plan assets were allocated approximately as follows: 29% in equity securities, 37% in fixed income securities, 10% in absolute return strategies, 7% in real estate, 2% in private equity, 4% in derivatives and 11% 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, FirstEnergy expects no required contributions through 2021. See Note 5, “Pension and Other Postemployment Benefits,” of the Notes to Consolidated Financial Statements for additional details on FirstEnergy’s pension and OPEB plans. Through September 30, 2019, FirstEnergy’s pension plan assets have earned approximately 17.4% as compared to an annual expected return on plan assets of 7.5%.
As of September 30, 2019, FirstEnergy’s OPEB plans were invested in fixed income and equity securities. Through September 30, 2019, FirstEnergy’s OPEB plans have earned approximately 12.8% as compared to an annual expected return on plan assets of 7.5%.
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NDT funds have been established to satisfy JCP&L, ME and PN’s nuclear decommissioning obligations associated with TMI-2. As of September 30, 2019, approximately 54% of the funds were invested in fixed income securities, 41% of the funds were invested in equity securities and 5% 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 $482 million, $361 million and $43 million for fixed income securities, equity securities and short-term investments, respectively, as of September 30, 2019, excluding $15 million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $36 million reduction in fair value as of September 30, 2019. 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 nine months ended September 30, 2019, 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 of December 31 and the difference between expected and actual returns on the plans’ assets. FirstEnergy would anticipate an after-tax mark-to-market loss to be in the range of approximately $400 million to $1 billion assuming a discount rate of approximately 3.00% to 3.50% and a return on the pension and OPEB plans’ assets based on actual investment performance through September 30, 2019.
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. However, FirstEnergy, as applicable, 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, 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. 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
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.
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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.
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 July 13, 2018, JCP&L filed an infrastructure plan, JCP&L Reliability Plus, which proposed to accelerate $386.8 million of electric distribution infrastructure investment over four years to enhance the reliability and resiliency of its distribution system and reduce the frequency and duration of power outages. On January 23, 2019, the NJBPU granted JCP&L’s request to temporarily suspend the procedural schedule in the matter pending settlement discussions. On April 23, 2019, JCP&L filed a Stipulation of Settlement with the NJBPU on behalf of the JCP&L, Rate Counsel, NJBPU Staff and New Jersey Large Energy Users Coalition, which provides that JCP&L will invest up to approximately $97 million in capital investments beginning on June 1, 2019 through December 31, 2020. 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. On May 8, 2019, the NJBPU issued an order approving the Stipulation of Settlement without modifications. Pursuant to the Stipulation, JCP&L filed a petition on September 16, 2019, to seek approval of rate adjustments to provide for cost recovery established with JCP&L Reliability Plus.
On January 31, 2018, the NJBPU instituted a proceeding to examine the impacts of the Tax Act on the rates and charges of New Jersey utilities. The NJBPU ordered New Jersey utilities to: (1) defer on their books the impacts of the Tax Act effective January 1, 2018; (2) to file tariffs effective April 1, 2018, reflecting the rate impacts of changes in current taxes; and (3) to file tariffs effective July 1, 2018, reflecting the rate impacts of changes in deferred taxes. On March 2, 2018, JCP&L filed a petition with the NJBPU, which included proposed tariffs for a base rate reduction of $28.6 million effective April 1, 2018, and a rider to reflect $1.3 million in rate impacts of changes in deferred taxes. On March 26, 2018, the NJBPU approved JCP&L’s rate reduction effective April 1, 2018, on an interim basis subject to refund, pending the outcome of this proceeding. On April 23, 2019, JCP&L filed a Stipulation of Settlement on behalf of the Rate Counsel, NJBPU Staff, and the New Jersey Large Energy Users Coalition with the NJBPU. The terms of the Stipulation of Settlement provide that between January 1, 2018 and March 31, 2018, JCP&L’s refund obligation is estimated to be approximately $7 million, which will be refunded to customers. The Stipulation of Settlement also provides for a base rate reduction of $28.6 million, which was reflected in rates on April 1, 2018, and a Rider Tax Act Adjustment for certain items over a five-year period. On May 8, 2019, the NJBPU issued an order approving the Stipulation of Settlement without modification.
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OHIO
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 continues a base distribution rate freeze through May 31, 2024 and 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. ESP IV also includes: (1) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (2) a goal across FirstEnergy to reduce CO 2 emissions by 90% below 2005 levels by 2045; and (3) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio.
In addition, ESP IV 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. Revenues from Rider DMR are excluded from the significantly excessive earnings test. 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. The Ohio Companies filed revised tariffs to implement the refund of Rider DMR funds collected since July 2, 2019. On October 1, 2019, the Ohio Companies implemented PUCO approved tariffs to refund approximately $28 million to customers, including Rider DMR revenues billed from July 2, 2019 through August 31, 2019.
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 intend to contest this appeal but are unable to predict the outcome of this matter.
Under Ohio law, the Ohio Companies are required to implement energy efficiency programs that achieve certain annual energy savings and total peak demand reductions. The Ohio Companies’ 2017-2019 plan includes a portfolio of energy efficiency programs targeted to a variety of customer segments. The Ohio Companies anticipate the cost of the plan will be approximately $268 million over the life of the plan and such costs are expected to be recovered through the Ohio Companies’ existing rate mechanisms. On November 21, 2017, the PUCO issued an order that approved the proposed plan with several modifications, including a cap on the Ohio Companies’ collection of program costs and shared savings set at 4% of the Ohio Companies’ total sales to customers. On October 15, 2019, the SCOH reversed the PUCO’s decision to impose the 4% cost-recovery cap and remanded the matter to the PUCO for approval of the portfolio plans without the cost-recovery cap.
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. The legislation also is ending current energy efficiency program mandates on December 31, 2020, provided statewide energy efficiency mandates are achieved as determined by the PUCO. On October 23, 2019, the PUCO solicited comments on whether the PUCO should terminate the energy efficiency programs once the statewide energy efficiency mandates are achieved. The Ohio Companies plan to apply to the PUCO for approval of the decoupling mechanism later this year, 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. Opponents to the legislation are petitioning to submit the legislation to a statewide referendum on the November 2020 ballot, and stay its effect unless and until approved by a majority of Ohio voters. On September 4, 2019, a lawsuit was filed with the SCOH, challenging the referendum on the grounds that the provisions supporting nuclear energy are a new tax and taxes cannot be overturned by referendum. On October 7, 2019, petitioners filed a lawsuit in the U.S. District Court for the Southern District of Ohio challenging various Ohio legal requirements for a referendum, and seeking additional time to gather signatures in support of a referendum. Petitioners did not meet the October 21, 2019 deadline to file the necessary number of petition signatures. On October 23, 2019, legislation went into effect. The U.S. District Court denied petitioners’ request for more time, and certified questions of state law to the SCOH to answer.
In February 2016, the Ohio Companies filed a Grid Modernization Business Plan for PUCO consideration and approval, as required by the terms of ESP IV. On December 1, 2017, the Ohio Companies filed an application with the PUCO for approval of a DPM Plan, a portfolio of distribution platform investment projects, which are designed to modernize the Ohio Companies’ distribution grid, prepare it for further grid modernization projects, and provide customers with immediate reliability benefits. Also, on January 10, 2018, the PUCO opened a case to consider the impacts of the Tax Act on Ohio utilities’ rates and determine the appropriate course of action to pass benefits on to customers. On November 9, 2018, the Ohio Companies filed a settlement agreement that provides for the implementation of the 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. As part of the agreement, the Ohio Companies also filed an application for approval of a rider to return the remaining
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tax savings to customers following PUCO approval of the settlement. On January 25, 2019, the Ohio Companies filed a supplemental settlement agreement that keeps intact the provisions of the settlement described above and adds further customer benefits and protections, which broadened support for the settlement. The settlement has 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. On July 17, 2019, the PUCO approved the settlement agreement with no material modifications. On August 16, 2019, environmental advocates who were not parties to the settlement filed an application for rehearing challenging the PUCO’s approval of the settlement. On September 11, 2019, the PUCO denied the application for rehearing.
The Ohio Companies’ Rider NMB is designed to recover NMB transmission-related costs imposed on or charged to the Ohio Companies by FERC or PJM. On December 14, 2018, the Ohio Companies filed an application for a review of their 2019 Rider NMB, including recovery of future Legacy RTEP costs and previously absorbed Legacy RTEP costs, net of refunds received from PJM. On February 27, 2018, the PUCO issued an order directing the Ohio Companies to file revised final tariffs recovering Legacy RTEP costs incurred since May 31, 2018, but excluding recovery of approximately $95 million in Legacy RTEP costs incurred prior to May 31, 2018, net of refunds received from PJM. The PUCO solicited comments on whether the Ohio Companies should be permitted to recover the Legacy RTEP charges incurred prior to May 31, 2018. The Ohio Companies, OCC and OMAEG filed comments on March 29, 2019. The Ohio Companies filed reply comments on April 15, 2019. On October 9, 2019, the PUCO approved the recovery of the $95 million of previously excluded Legacy RTEP charges.
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 must also be separately tracked for treatment 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. The 2019-2023 DSPs also include modifications to the Pennsylvania Companies’ POR programs in order to continue their clawback pilot program as a long-term, permanent program term, modifications to the Pennsylvania Companies’ customer class definitions to allow for the introduction of hourly priced default service to customers at or above 100kW, customer assistance program shopping limitations, and script modifications related to the Pennsylvania Companies’ customer referral programs.
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.
Pennsylvania EDCs may establish a DSIC to recover costs of infrastructure improvements and costs related to highway relocation projects with PPUC approval. LTIIPs outlining infrastructure improvement plans for PPUC review and approval must be filed prior to approval of a DSIC. On June 14, 2017, the PPUC approved modified LTIIPs for ME, PN and Penn for the remaining years of 2017 through 2020 to provide additional support for reliability and infrastructure investments. On September 20, 2018, following a periodic review of the LTIIPs as required by regulation once every five years, the PPUC entered an Order concluding that the Pennsylvania Companies have substantially adhered to the schedules and expenditures outlined in their LTIIPs, but that changes to the LTIIPs as designed are necessary to maintain and improve reliability and directed the Pennsylvania Companies to file modified or new LTIIPs. On January 18, 2019, the Pennsylvania Companies filed modifications to their current LTIIPs that would terminate those LTIIPs at the end of 2019, and proposed revised LTIIP spending in 2019 of approximately $45 million by ME, $25 million by PN, $26 million by Penn and $51 million by WP. The Pennsylvania Companies also committed to making filings later in 2019, which would propose new LTIIPs for the 2020 through 2024 period. On May 23, 2019, the PPUC issued an order approving the Pennsylvania Companies’ Modified LTIIPs as filed. On August 30, 2019, the Pennsylvania Companies filed individual Petitions for approval of proposed 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 September 30, 2019, the Pennsylvania OCA submitted comments on the Pennsylvania Companies’ LTIIPs. A PPUC decision is expected by year-end.
The Pennsylvania Companies’ approved DSIC riders for quarterly cost recovery went into effect July 1, 2016, subject to hearings and refund or reallocation among customer classes. In the January 19, 2017 order approving the Pennsylvania Companies’ general rate cases, the PPUC added an additional issue to the DSIC proceeding to include whether ADIT should be included in DSIC calculations. On February 2, 2017, the parties to the DSIC proceeding submitted a Joint Settlement to the ALJ that resolved the issues that were pending from the order issued on June 9, 2016. On April 19, 2018, the PPUC approved the Joint Settlement without modification and reversed the ALJ’s previous decision that would have required the Pennsylvania Companies to reflect all federal and state income tax deductions related to DSIC-eligible property in currently effective DSIC rates. On May 21, 2018, the Pennsylvania OCA filed an appeal with the Pennsylvania Commonwealth Court of the PPUC’s decision of April 19, 2018. On June 11, 2018, the Pennsylvania Companies filed a Notice of Intervention in the Pennsylvania OCA’s appeal to the Commonwealth Court. On July 11, 2019, the Commonwealth Court issued an opinion and order reversing the PPUC’s decision of April 19, 2018 and
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remanding the matter to the PPUC to require the Pennsylvania Companies to revise their tariffs and DSIC calculations to include ADIT and state income taxes. On July 25, 2019, the PPUC and the Pennsylvania Companies filed separate Applications for Reargument of the Commonwealth Court’s July 11, 2019 Opinion and Order. The Applications were denied by the Commonwealth Court by Orders entered September 4, 2019. On October 7, 2019, the PPUC and the Pennsylvania Companies filed separate Petitions for Allowance of Appeal of the Commonwealth Court’s Opinion and Order to the Pennsylvania Supreme Court. 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. The Pennsylvania Office of Small Business Advocate and the Pennsylvania OCA have opposed Penn’s Petition. On September 20, 2019, Penn filed its direct testimony in support of its Petition.
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. A hearing has been set for December 11, 2019 to consider the settlement, and an order is expected in December 2019 for rates effective January 1, 2020.
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. The hearing in this matter has been set for December 11, 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, AGC, 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 $78.8 million until such time as ATSI submits a cost/benefit analysis demonstrating net benefits to customers from the transfer to PJM. Subsequently, FERC rejected a proposed settlement agreement to resolve the exit fee and transmission cost allocation issues, stating that its action is without prejudice to ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh the exit fee and transmission cost allocation charges. 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 issued a NOI seeking information regarding whether and how FERC should 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 15, 2018, FERC issued a NOPR suggesting mechanisms to revise transmission rates to address the Tax Act’s effect on ADIT. Specifically, FERC proposed utilities with transmission formula rates would include mechanisms to (i) deduct any excess ADIT from or add any deficient ADIT to their rate bases; (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. Utilities with transmission stated rates would determine the amount of excess and deferred income tax caused by the reduced federal corporate income tax rate and return or recover this amount to or from customers. To assist with implementation of the proposed rule, 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. FESC, on behalf of its affiliated transmission owners, supported comments submitted by EEI requesting additional clarification on the ratemaking and accounting treatment for ADIT in formula and stated transmission rates. FERC’s final rule remains pending.
Transmission ROE Methodology
In June 2014, FERC issued Opinion No. 531 revising its approach for calculating the discounted cash flow element of FERC’s ROE methodology and announcing the potential for a qualitative adjustment to the ROE methodology results. Parties appealed to the D.C. Circuit, and on April 14, 2017, that court issued a decision vacating FERC’s order and remanding the matter to FERC for further review. On October 16, 2018, FERC issued its order on remand, in which it proposed a revised ROE methodology. Specifically, in complaint proceedings alleging that an existing ROE is not just and reasonable, FERC proposes to 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. 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 NOI comments, and any subsequent rulemaking and other proceedings.
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.
ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. While FirstEnergy’s environmental policies and procedures are designed to achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and potential revision by the implementing agencies. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof may materially impact its business, results of operations, cash flows and financial condition.
Clean Air Act
FirstEnergy complies with SO 2 and NOx emission reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls and/or using emission allowances.
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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 September 30, 2019, 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 and Pleasants Units 1 and 2, 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 9 states (including Ohio, Pennsylvania and West Virginia) significantly contribute to New York’s inability to attain the ozone NAAQS. The petition seeks suitable emission rate limits for large stationary sources that are affecting New York’s air quality within the three years allowed by CAA Section 126. 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. 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
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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. 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.
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.
FirstEnergy or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of September 30, 2019, 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 $119 million have been accrued through September 30, 2019. Included in the total are accrued liabilities of approximately $83 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 September 30, 2019, JCP&L, ME and PN had in total approximately $871 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 September 30, 2019. There
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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.
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. See Note 3, “Discontinued Operations,” for additional information.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to FE or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 12, “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 2016-02, "Leases (Topic 842)" (Issued February 2016 and subsequently updated to address implementation questions): The new guidance requires organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets, as well as new qualitative and quantitative disclosures. FirstEnergy implemented a third-party software tool that assisted with the initial adoption and will assist with ongoing compliance. FirstEnergy chose to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. Upon adoption, on January 1, 2019, FirstEnergy increased assets and liabilities by $186 million, with no impact to results of operations or cash flows. See Note 8, "Leases," for additional information on FirstEnergy's leases.
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 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. The ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. FirstEnergy has analyzed its financial instruments within the scope of this guidance, primarily trade receivables and AFS debt securities, and does not expect a material impact to its financial statements upon adoption in 2020.
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 requires 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. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. FirstEnergy does not expect a material impact to its financial statements upon adoption in 2020.
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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 September 30, 2019, 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 12, “Regulatory Matters,” and Note 13, “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
During the quarter ended September 30, 2019, there were no material changes to the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2018.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. OTHER INFORMATION
None.
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ITEM 6. EXHIBITS

Exhibit Number | Description
| 10.1 |  | Amendment No. 1 to Term Loan Credit Agreement, dated as of September 11, 2019, among FirstEnergy Corp., as borrower, the banks named therein and The Bank of Nova Scotia, as administrative agent (incorporated by reference to FE’s Form 8-K filed September 17, 2019, Exhibit 10.1, File No. 333-21011).
| 10.2 |  | Amendment No. 1 to Term Loan Credit Agreement, dated as of September 11, 2019, among FirstEnergy Corp., as borrower, the banks named therein and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to FE’s Form 8-K filed September 17, 2019, Exhibit 10.2, File No. 333-21011).
(A) (B) | 10.3 |  | Amendment No. 2 to FirstEnergy Corp. Amended and Restated Executive Deferred Compensation Plan, dated January 14, 2009, dated as of September 18, 2019.
(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 September 30, 2019, formatted in iXBRL (Inline Extensible Business Reporting Language): (i) Consolidated Statements of Income (Loss) and Consolidated Statements of Comprehensive Income (Loss), (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements and (v) document and entity information.

(A) Provided herein in electronic format as an exhibit.
(B) Management contract or compensatory plan contract or arrangement filed pursuant to Item 601 of Regulation S-K.
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, except as set forth above 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.
November 4, 2019

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

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