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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
FORM 10-K
  
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
  
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2020
or
 FOR THE TRANSITION PERIOD FROM ___________ TO __________
 
COMMISSION FILE NUMBER001-38629
 
EQUITRANS MIDSTREAM CORPORATION
(Exact name of registrant as specified in its charter)
Pennsylvania83-0516635
(State or other jurisdiction of incorporation or organization)(IRS Employer Identification No.)

2200 Energy Drive, Canonsburg, Pennsylvania     15317
(Address of principal executive offices)      (Zip code)
Registrant's telephone number, including area code: (724) 271-7600
Securities registered pursuant to Section 12(b) of the Act
Title of each class Trading SymbolName of each exchange on which registered
Common Stock, no par value ETRNNew York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:  None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes    No   
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.     Yes     No   
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 FilerAccelerated Filer
Emerging Growth Company
Non-Accelerated Filer
Smaller Reporting 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 standards provided pursuant to Section 13(a) of the Exchange Act.    
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report.    
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes    No  
The aggregate market value of common stock held by non-affiliates of the registrant as of June 30, 2020: $3.4 billion
The number of shares of common stock outstanding (in thousands), as of January 31, 2021: 432,470

DOCUMENTS INCORPORATED BY REFERENCE

The Company's definitive proxy statement relating to the 2021 annual meeting of shareholders will be filed with the Securities and Exchange Commission within 120 days after the close of the Company's fiscal year ended December 31, 2020 and is incorporated by reference in Part III to the extent described therein.



EQUITRANS MIDSTREAM CORPORATION
Table of Contents
 Page No.
PART I
PART II
PART III
PART IV

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EQUITRANS MIDSTREAM CORPORATION
Glossary of Commonly Used Terms, Abbreviations and Measurements
Allowance for Funds Used During Construction (AFUDC) – carrying costs for the construction of certain long-lived regulated assets are capitalized and amortized over the related assets' estimated useful lives. The capitalized amount for construction of regulated assets includes interest cost and a designated cost of equity for financing the construction of these regulated assets.
Appalachian Basin – the area of the United States composed of those portions of West Virginia, Pennsylvania, Ohio, Maryland, Kentucky and Virginia that lie in the Appalachian Mountains.
associated gas – natural gas that is produced as a byproduct of principally oil production activities.
British thermal unit – a measure of the amount of energy required to raise the temperature of one pound of water one-degree Fahrenheit.
Code – the U.S. Internal Revenue Code of 1986, as amended, and the regulations and interpretations promulgated thereunder.
delivery point – the point where gas is delivered into a downstream gathering system or transmission pipeline.
Distribution – the distribution of 80.1% of the then-outstanding shares of common stock, no par value, of Equitrans Midstream Corporation (Equitrans Midstream common stock) to EQT (as defined below) shareholders of record as of the close of business on November 1, 2018.
EQGP – EQGP Holdings, LP and its subsidiaries.
EQM – EQM Midstream Partners, LP and its subsidiaries.
EQT – EQT Corporation (NYSE: EQT) and its subsidiaries.
EQT Global GGA – that certain Gas Gathering and Compression Agreement entered into on February 26, 2020 (the EQT Global GGA Effective Date) by the Company (through EQM) with EQT and certain affiliates of EQT for the provision of certain gas gathering services to EQT in the Marcellus and Utica Shales of Pennsylvania and West Virginia, as subsequently amended.
firm contracts – contracts for gathering, transmission, storage and water services that reserve an agreed upon amount of pipeline or storage capacity regardless of the capacity used by the customer during each month, and generally obligate the customer to pay a fixed, monthly charge.
firm reservation fee revenues contractually obligated revenues that include fixed monthly charges under firm contracts and fixed volumetric charges under MVC (defined below) contracts.
gas – natural gas.
liquefied natural gas (LNG) – natural gas that has been cooled to minus 161 degrees Celsius for transportation, typically by ship. The cooling process reduces the volume of natural gas by 600 times.
local distribution company (LDC) – LDCs are companies involved in the delivery of natural gas to consumers within a specific geographic area.
Minimum volume commitments (MVC or MVCs) – contracts for gathering or water services that obligate the customer to pay for a fixed amount of volumes daily, monthly, annually or over the life of the contract.
Mountain Valley Pipeline (MVP) – an estimated 300-mile, 42-inch diameter natural gas interstate pipeline with a targeted capacity of 2.0 Bcf per day that will span from the Company's existing transmission and storage system in Wetzel County, West Virginia to Pittsylvania County, Virginia, providing access to the growing Southeast demand markets.
Mountain Valley Pipeline, LLC (MVP Joint Venture) – a joint venture among the Company and, as applicable, affiliates of each of NextEra Energy, Inc., Consolidated Edison, Inc. (Con Edison), AltaGas Ltd. and RGC Resources, Inc. that is constructing the MVP and the MVP Southgate (defined below) projects.
MVP Southgate – a proposed 75-mile interstate pipeline that will extend from the MVP at Pittsylvania County, Virginia to new delivery points in Rockingham and Alamance Counties, North Carolina.

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natural gas liquids (NGLs) – those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption or other methods in gas processing plants. Natural gas liquids include ethane, propane, butane and iso-butane.
play – a proven geological formation that contains commercial amounts of hydrocarbons.
Predecessor period – the periods prior to the Separation Date (defined below).
Preferred Interest – the preferred interest that the Company has in EQT Energy Supply, LLC (EES), a subsidiary of EQT.
Proxy Statement – the Company's definitive proxy statement relating to the 2021 annual meeting of shareholders to be filed with the Securities and Exchange Commission.
receipt point – the point where gas is received by or into a gathering system or transmission pipeline.
reservoir a porous and permeable underground formation containing an individual and separate natural accumulation of producible hydrocarbons (crude oil and/or natural gas) which is confined by impermeable rock or water barriers and is characterized by a single natural pressure system.
Rice Merger On November 13, 2017, pursuant to the agreement and plan of merger dated June 19, 2017 by and among EQT, Rice Energy Inc. and a wholly owned subsidiary of EQT, Rice Energy became a wholly owned, indirect subsidiary of EQT.
RMP – RM Partners LP (formerly known as Rice Midstream Partners LP) and its subsidiaries.
Separation the separation of EQT's midstream business, which was composed of the assets and liabilities of EQT's separately-operated natural gas gathering, transmission and storage and water services operations of EQT, from EQT's upstream business, which was composed of the natural gas, oil and natural gas liquids development, production and sales and commercial operations of EQT, which occurred on the Separation Date.
Separation Date – November 12, 2018.
Successor period – the period from the Separation Date thereafter.
throughput – the volume of natural gas transported or passing through a pipeline, plant, terminal or other facility during a particular period.
Water Services Letter Agreement – that certain letter agreement entered into on February 26, 2020 by the Company (through EQM) and EQT, pursuant to which EQT agreed to utilize the Company for the provision of water services in Pennsylvania under existing water services agreements and new water services agreements if negotiated between the parties.
wellhead the equipment at the surface of a well used to control the well's pressure and the point at which the hydrocarbons and water exit the ground. 
working gas – the volume of natural gas in the storage reservoir that can be extracted during the normal operation of the storage facility.
Unless context otherwise requires, a reference to a “Note” herein refers to the accompanying Notes to Consolidated Financial Statements contained in "Item 8. Financial Statements and Supplementary Data."


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AbbreviationsMeasurements
ADIT – Accumulated Deferred Income Taxes
Btu = one British thermal unit
ARO – asset retirement obligations
BBtu = billion British thermal units
ASC – Accounting Standards Codification
Bcf   = billion cubic feet
ASU – Accounting Standards Update
Mcf = thousand cubic feet
CERCLA – Comprehensive Environmental Response, Compensation and Liability Act
MMBtu = million British thermal units
DOT – United States Department of Transportation
MMcf  = million cubic feet
EPA – United States Environmental Protection Agency
MMgal = million gallons
FASB Financial Accounting Standards Board
FERC – United States Federal Energy Regulatory Commission
GAAP – United States Generally Accepted Accounting Principles
GHG – greenhouse gas
IDRs – incentive distribution rights
IRS – United States Internal Revenue Service
NAAQS – National Ambient Air Quality Standards
NGA Natural Gas Act of 1938
NGPA – Natural Gas Policy Act of 1978
NYMEX – New York Mercantile Exchange
NYSE – New York Stock Exchange
PHMSA – Pipeline and Hazardous Materials Safety Administration of the DOT
RCRA Resource Conservation and Recovery Act
SEC – United States Securities and Exchange Commission

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EQUITRANS MIDSTREAM CORPORATION
Cautionary Statements
Disclosures in this Annual Report on Form 10-K contain certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and Section 27A of the Securities Act of 1933, as amended (the Securities Act). Statements that do not relate strictly to historical or current facts are forward-looking and usually identified by the use of words such as "anticipate," "estimate," "could," "would," "will," "may," "forecast," "approximate," "expect," "project," "intend," "plan," "believe," "target" and other words of similar meaning in connection with any discussion of future operating or financial matters. Without limiting the generality of the foregoing, forward-looking statements contained in this Annual Report on Form 10-K include the matters discussed in the sections captioned "Strategy" under "Developments, Market Trends and Competitive Conditions" in "Item 1. Business" and "Outlook" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations," and the expectations of plans, strategies, objectives, and growth and anticipated financial and operational performance of Equitrans Midstream Corporation (together with its subsidiaries, Equitrans Midstream or the Company), including:
guidance and any changes in such guidance regarding the Company’s gathering, transmission and storage and water services revenue and volume growth, including the anticipated effects associated with the EQT Global GGA and related documents entered into with EQT;
projected revenue (including from firm reservation fees) and volumes, deferred revenues, expenses and contract liabilities, and the effects on liquidity, projected revenue, deferred revenue and contract liabilities associated with the EQT Global GGA and the MVP project (including changes in the targeted full in-service date for such project);
the ultimate gathering fee relief provided to EQT under the EQT Global GGA and related agreements, including the exercise by EQT of any cash-out option as an alternative to receiving a portion of such relief;
the Company's ability to de-lever;
the weighted average contract life of gathering, transmission and storage contracts;
infrastructure programs (including the timing, cost, capacity and sources of funding with respect to gathering, transmission and storage and water projects);
the cost, capacity, shippers for, timing of regulatory approvals, final design (including expansions or extensions and capital related thereto), ability to contract additional capacity on and targeted in-service dates of current or in-service projects or assets, in each case as applicable;
the ultimate terms, partner relationships and structure of the MVP Joint Venture and ownership interests therein;
the impact of changes in the targeted full in-service date of the MVP project on, among other things, the fair value of the Henry Hub cash bonus provision of the EQT Global GGA;
expansion projects in the Company's operating areas and in areas that would provide access to new markets;
the Company's ability to provide produced water handling services and realize expansion opportunities and related capital avoidance;
the Company's ability to identify and complete acquisitions and other strategic transactions, including joint ventures, effectively integrate transactions into the Company’s operations, and achieve synergies, system optionality and accretion associated with transactions, including through increased scale;
the Company's ability to access commercial opportunities and new customers for its water services business, and the timing and final terms of any definitive water services agreement or agreements between EQT and the Company entered into pursuant to the terms of the Water Services Letter Agreement;
any credit rating impacts associated with the MVP project, customer credit ratings changes, including EQT's, and defaults, acquisitions, dispositions and financings and any changes in EQM's credit ratings;
the impact of the dispute with EQT (or resolution thereof) regarding the Hammerhead gathering agreement and/or ownership of the Hammerhead pipeline on the Company's business and results of operations;

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the impact of such dispute (or resolution thereof) on investors' perceptions of the Company's commercial relationship with EQT;
the effect and outcome of future litigation and other proceedings, including regulatory proceedings;
the effects of any consolidation of or effected by upstream gas producers, whether in or outside of the Appalachian Basin;
the ability of the Company's contracts to survive a customer bankruptcy or restructuring, the outcome of any attempt to reject such contracts in such contexts (or related negotiations) and the impact on the Company’s results of operations and liquidity of a customer bankruptcy or restructuring;
the timing and amount of future issuances or repurchases of the Company's securities;
the effects of conversion, if at all, of the Equitrans Midstream Preferred Shares (defined herein);
the effects of seasonality;
expected cash flows and MVCs, including those associated with the EQT Global GGA and any definitive agreement or agreements between EQT and the Company related to the Water Services Letter Agreement, and the potential impacts thereon of the commission timing and cost of the MVP project;
projected capital contributions and capital and operating expenditures, including the amount and timing of reimbursable capital expenditures, capital budget and sources of funds for capital expenditures;
dividend amounts, timing and rates;
changes in commodity prices and the effect of commodity prices on the Company's business, including future decisions of customers in respect of curtailing natural gas production, choke management, timing of turning wells in line, rig and completion activity and related impacts on the Company's business;
liquidity and financing requirements, including sources and availability;
interest rates;
the ability of the Company's subsidiaries (some of which are not wholly owned) to service debt under, and comply with the covenants contained in, their respective credit agreements;
expectations regarding production, gathered and water volumes in the Company's areas of operations;
the Company's ability to achieve anticipated benefits associated with the execution of the EQT Global GGA, the Water Services Letter Agreement and related agreements;
the impact on the Company and its subsidiaries of the coronavirus disease 2019 (COVID-19) pandemic, including, among other things, effects on demand for natural gas and the Company's services, levels of production of associated gas from basins such as the Permian Basin, commodity prices and access to capital;
the Company's ability to achieve its environmental, social and governance (ESG) goals (including goals set forth in its climate policy);
the effects of government regulation; and
tax status and position.
The forward-looking statements included in this Annual Report on Form 10-K involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The Company has based these forward-looking statements on management's current expectations and assumptions about future events. While the Company considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory, judicial and other risks and uncertainties, many of which are difficult to predict and are beyond the Company's control. The risks and uncertainties that may affect the operations, performance and results of the Company's business and forward-looking statements include, but are not limited to, those set forth under "Item 1A. Risk Factors," and elsewhere in this Annual Report on Form 10-K.

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Any forward-looking statement speaks only as of the date on which such statement is made and the Company does not intend to correct or update any forward-looking statement, unless required by securities law, whether as a result of new information, future events or otherwise.
Management believes the assumptions underlying the consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" are reasonable; however, as organizational structure and strategic focus dictate expenses incurred, the financial statements may not include all expenses that would have been incurred had the Company existed as a standalone, publicly traded company for the entirety of the three years ended December 31, 2020. Similarly, the financial statements may not reflect the results of operations, financial position and cash flows had the Company existed as a standalone, publicly traded company for the entirety of the periods presented.

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PART I
Item 1.        Business
Overview of the Company
Equitrans Midstream is one of the largest natural gas gatherers in the U.S. and holds a significant transmission footprint in the Appalachian Basin. Equitrans Midstream, a Pennsylvania corporation, became an independent, publicly traded company on November 12, 2018, as a result of the Separation (defined below).
The Separation. On November 12, 2018, Equitrans Midstream, EQT and, for certain limited purposes, EQT Production Company, a wholly owned subsidiary of EQT, entered into a separation and distribution agreement (the Separation and Distribution Agreement), pursuant to which, among other things, EQT effected the separation of its midstream business, which was composed of the assets and liabilities of the separately-operated natural gas gathering, transmission and storage and water services operations of EQT (the Midstream Business), from EQT's upstream business, which was composed of the natural gas, oil and natural gas liquids development, production and sales and commercial operations of EQT (the Separation), to Equitrans Midstream, and distributed 80.1% of the then-outstanding shares of common stock, no par value, of Equitrans Midstream (Equitrans Midstream common stock) to EQT shareholders of record as of the close of business on November 1, 2018 (the Distribution). As part of the Separation, EQT retained the remaining 19.9% of the then-outstanding shares in Equitrans Midstream.
In connection with the Separation, the Company acquired control of the entities conducting the Midstream Business. See Note 1 to the consolidated financial statements for further information on the entities conducting the Midstream Business.
The Company's Post-Separation Relationship with EQT. The Company and EQT are separate companies with separate management teams and separate boards of directors. Although they operate separately, due to the approximately 5.8% of Equitrans Midstream's outstanding shares of common stock held by EQT as of December 31, 2020, the Company and EQT are characterized for certain purposes as related parties. In connection with the Separation and Distribution, the Company and EQT executed the Separation and Distribution Agreement and various other agreements to effect the Separation. See Notes 1 and 8 to the consolidated financial statements for further information on the relationship between the Company and EQT subsequent to the Separation.
EQGP Unit Purchases and Limited Call Right. On November 29, 2018, the Company entered into written agreements (the Unit Purchase Agreements) with certain investors owning an aggregate of 15,364,421 common units representing limited partner interests in EQGP (EQGP common units) for $20.00 per EQGP common unit that closed through a series of transactions ending on January 3, 2019 for an aggregate purchase price of $307.3 million (collectively, the EQGP Unit Purchases).
On December 31, 2018, the Company exercised a limited call right (the Limited Call Right) under EQGP's partnership agreement, pursuant to which, on January 10, 2019, the Company closed on the acquisition of the remaining 11,097,287 outstanding EQGP common units not owned by the Company or its affiliates for an aggregate purchase price of $221.9 million (such acquisition, together with the EQGP Unit Purchases, the EQGP Buyout), and EQGP became an indirect, wholly owned subsidiary of the Company. See Note 1 to the consolidated financial statements for further information on the EQGP Buyout.
EQM IDR Transaction. On February 22, 2019, Equitrans Midstream completed a simplification transaction pursuant to that certain Agreement and Plan of Merger, dated as of February 13, 2019 (the IDR Merger Agreement), by and among Equitrans Midstream and certain related parties, pursuant to which, among other things, (i) Equitrans Merger Sub, LP merged with and into EQGP (the Merger) with EQGP continuing as the surviving limited partnership and a wholly owned subsidiary of EQM, and (ii) each of (a) the IDRs in EQM, (b) the economic portion of the general partner interest in EQM and (c) the issued and outstanding EQGP common units were canceled, and, as consideration for such cancellation, certain affiliates of the Company received on a pro rata basis 80,000,000 newly-issued common units representing limited partner interests in EQM (EQM common units) and 7,000,000 newly-issued Class B units representing limited partner interests in EQM (Class B units), and EQGP Services, LLC (the EQM General Partner) retained the non-economic general partner interest in EQM (such transactions, collectively, the EQM IDR Transaction). Additionally, as part of the EQM IDR Transaction, the 21,811,643 EQM common units held by EQGP were canceled and 21,811,643 EQM common units were issued pro rata to certain subsidiaries of the Company. As a result of the EQM IDR Transaction, the EQM General Partner replaced EQM Midstream Services, LLC as the general partner of EQM. See Note 2 to the consolidated financial statements for further information on the EQM IDR Transaction.
EQM Series A Preferred Units. On March 13, 2019, EQM entered into a Convertible Preferred Unit Purchase Agreement, together with Joinder Agreements entered into on March 18, 2019, with certain investors (such investors, collectively, the Investors) to issue and sell in a private placement (the Private Placement) an aggregate of 24,605,291 Series A Perpetual

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Convertible Preferred Units (EQM Series A Preferred Units) representing limited partner interests in EQM for a cash purchase price of $48.77 per EQM Series A Preferred Unit, resulting in total gross proceeds of approximately $1.2 billion. The net proceeds from the Private Placement were used in part to fund the purchase price in the Bolt-on Acquisition (defined in Note 3 to the consolidated financial statements) and to pay certain fees and expenses related to the Bolt-on Acquisition, and the remainder was used for general partnership purposes. The Private Placement closed concurrently with the closing of the Bolt-on Acquisition on April 10, 2019. See Note 2 to the consolidated financial statements for further information on the EQM Series A Preferred Units, none of which remain outstanding and Note 3 to the consolidated financial statement for further information on the Bolt-on Acquisition.
EQM Merger. On June 17, 2020, pursuant to that certain Agreement and Plan of Merger, dated as of February 26, 2020 (the EQM Merger Agreement), by and among the Company, EQM LP Corporation, a wholly owned subsidiary of the Company (EQM LP), LS Merger Sub, LLC, a wholly owned subsidiary of EQM LP (Merger Sub), EQM and the EQM General Partner, Merger Sub merged with and into EQM (the EQM Merger), with EQM continuing and surviving as an indirect, wholly owned subsidiary of the Company. Upon consummation of the EQM Merger, the Company acquired all of the outstanding EQM common units that the Company and its subsidiaries did not already own. Following the closing of the EQM Merger, EQM was no longer a publicly traded entity. See Note 2 to the consolidated financial statements for further information on the EQM Merger.
Preferred Restructuring Agreement. On February 26, 2020, the Company and EQM entered into a Preferred Restructuring Agreement (the Restructuring Agreement) with all of the Investors pursuant to which, at the effective time of the EQM Merger (the Effective Time): (i) EQM redeemed $600 million aggregate principal amount of the Investors' EQM Series A Preferred Units issued and outstanding immediately prior to the Restructuring Closing (defined below), which occurred substantially concurrent with the closing of the EQM Merger, for cash at 101% of the EQM Series A Preferred Unit purchase price of $48.77 per such unit (the EQM Series A Preferred Unit Purchase Price) plus any accrued and unpaid distribution amounts and partial period distribution amounts, and (ii) immediately following such redemption, each remaining issued and outstanding EQM Series A Preferred Unit was exchanged for 2.44 shares of a newly authorized and created series of preferred stock, without par value, of Equitrans Midstream, convertible into Equitrans Midstream common stock (the Equitrans Midstream Preferred Shares) on a one for one basis, in each case, in connection with the occurrence of the “Series A Change of Control” (as defined in the Fourth Amended and Restated Agreement of Limited Partnership of EQM (as amended, the Former EQM Partnership Agreement)) that occurred upon the closing of the EQM Merger (collectively, the Restructuring and, the closing of the Restructuring, the Restructuring Closing). See Note 2 to the consolidated financial statements for further information on the Restructuring Agreement and the Restructuring.
The EQT Global GGA. On February 26, 2020 (the EQT Global GGA Effective Date), the Company entered into a Gas Gathering and Compression Agreement (the EQT Global GGA) with EQT for the provision by the Company of certain gas gathering services to EQT in the Marcellus and Utica Shales of Pennsylvania and West Virginia. Pursuant to the EQT Global GGA, EQT is subject to an initial annual MVC of 3.0 Bcf per day that gradually steps up to 4.0 Bcf per day for several years following the full in-service date of the MVP. The EQT Global GGA runs from the EQT Global GGA Effective Date through December 31, 2035, and will renew annually thereafter unless terminated by EQT or the Company pursuant to its terms. Pursuant to the EQT Global GGA, the Company has certain obligations to build connections to connect EQT wells to its gathering system, which are subject to geographical limitations in relation to the dedicated area in Pennsylvania and West Virginia, as well as the distance of such connections to the Company's then-existing gathering system. In addition to the fees related to gathering services, the EQT Global GGA provides for potential cash bonus payments payable by EQT to the Company during the period beginning on the first day of the calendar quarter in which the MVP in-service date occurs through the earlier of the twelfth calendar quarter from that point or the calendar quarter ending December 31, 2024 (the Henry Hub cash bonus payment provision). The potential cash bonus payments are conditioned upon the quarterly average of certain Henry Hub natural gas prices exceeding certain price thresholds.
The gathering MVC fees payable by EQT to the Company set forth in the EQT Global GGA are subject to potential reductions for certain contract years as set forth in the EQT Global GGA, conditioned upon the in-service date of the MVP, which provide for estimated aggregate fee relief of approximately $270 million in the first year after the in-service date of the MVP, approximately $230 million in the second year after the in-service date of the MVP and approximately $35 million in the third year after the in-service date of the MVP. In addition, if the MVP in-service date has not occurred by January 1, 2022, EQT has an option, exercisable for a period of twelve months (or such shorter period if the in-service date of the MVP occurs), to forgo approximately $145 million of the gathering fee relief in the first year after the MVP in-service date and approximately $90 million of the gathering fee relief in the second year after the MVP in-service date in exchange for a cash payment from the Company to EQT in the amount of approximately $196 million (the EQT Cash Option). See Note 6 to the consolidated financial statements for further information on the EQT Global GGA.

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Credit Letter Agreement. On February 26, 2020, in connection with the execution of the EQT Global GGA, the Company and EQT entered into a letter agreement (the Credit Letter Agreement) pursuant to which, among other things, (a) the Company agreed to relieve certain credit posting requirements for EQT, in an amount up to approximately $250 million, under its commercial agreements with the Company, subject to EQT maintaining a minimum credit rating from two of three rating agencies of (i) Ba3 with Moody’s Investors Service (Moody's), (ii) BB- with S&P Global Ratings (S&P) and (iii) BB- with Fitch Investor Services (Fitch) and (b) the Company agreed to use commercially reasonable good faith efforts to negotiate similar credit support arrangements for EQT in respect of its commitments to the MVP Joint Venture.
Water Services Letter Agreement. On February 26, 2020, the Company entered into a letter agreement with EQT, pursuant to which EQT agreed to utilize the Company for the provision of water services in Pennsylvania under existing water services agreements and new water services agreements if negotiated between the parties (such letter agreement, the Water Services Letter Agreement). The Water Services Letter Agreement is effective as of the first day of the first month following the MVP in-service date and will expire on the fifth anniversary of such date. During each year of the Water Services Letter Agreement, EQT agreed that fixed MVC fees payable to the Company for water services in Pennsylvania incurred on a volumetric basis, provided in accordance with existing agreements and new agreements entered into between the parties pursuant to the Water Services Letter Agreement (or the related agreements), will be equal to or greater than $60 million per year.
Share Purchase Agreements. On February 26, 2020, the Company entered into two share purchase agreements (the Share Purchase Agreements) with EQT, pursuant to which the Company agreed to (i) purchase 4,769,496 shares of Equitrans Midstream common stock (the Cash Shares) from EQT in exchange for approximately $46 million in cash, (ii) purchase 20,530,256 shares of Equitrans Midstream common stock (the Rate Relief Shares and, together with the Cash Shares, the Share Purchases) from EQT in exchange for a promissory note in the aggregate principal amount of approximately $196 million (which EQT subsequently assigned to EQM as consideration for certain commercial terms under the EQT Global GGA), and (iii) pay EQT cash in the amount of approximately $7 million (the Cash Amount). On March 5, 2020, the Company completed the Share Purchases and paid the Cash Amount. The Company used proceeds from the EQM Credit Facility (defined in Note 11 to the consolidated financial statements) to fund the purchase of the Cash Shares and to pay the Cash Amount in addition to other uses of proceeds. After the closing of the Share Purchases, the Company retired the Cash Shares and the Rate Relief Shares. On September 29, 2020, the Company made a prepayment to EQM of all principal, interest, fees and other obligations outstanding under the promissory note EQT assigned to EQM and the promissory note was terminated.


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The following diagram depicts the Company's organizational and ownership structure as of December 31, 2020:
etrn-20201231_g1.jpg

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Overview of Operations
The Company provides midstream services to its customers through its three primary assets: the gathering system, which includes predominantly dry gas gathering systems of high-pressure gathering lines; the transmission system, which includes FERC-regulated interstate pipelines and storage systems; and the water service system, which consists of water pipelines, impoundment facilities, pumping stations, take point facilities and measurement facilities that support well completion activities and collect flowback and produced water for recycling or disposal.
As of December 31, 2020, the Company provided a majority of its natural gas gathering, transmission and storage services under long-term contracts that generally include fixed monthly reservation fees or MVCs. The Company maintains a stable cash flow profile, with approximately 66% of the Company's revenues for the year ended December 31, 2020 generated from firm reservation fees. The percentage of the Company's revenues that are generated by firm reservation fees is expected to increase in future years as a result of the 15-year term EQT Global GGA, which includes an MVC that became effective on April 1, 2020 of 3.0 Bcf per day and gradually steps up to 4.0 Bcf per day for several years following the full in-service date of the MVP project, and the Hammerhead gathering agreement (which is subject to a pending dispute with EQT), which includes a 1.2 Bcf per day firm capacity commitment. These contract structures enhance the stability of the Company's cash flows and limits its direct exposure to commodity price risk.
The Company's operations are focused primarily in southwestern Pennsylvania, northern West Virginia and southeastern Ohio, which are prolific resource development areas in the natural gas shale plays known as the Marcellus and Utica Shales. These regions are also the primary operating areas of EQT, the Company's largest customer as of December 31, 2020. EQT accounted for approximately 64% of the Company's revenues for the year ended December 31, 2020.


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The following is a map of the Company's gathering, transmission and storage and water services operations as of December 31, 2020.
etrn-20201231_g2.jpg


14

Business Segments
The Company reports its operations in three segments that reflect its three lines of business: Gathering, Transmission and Water. These segments include all of the Company's operations. For discussion of the composition of the three segments, see Notes 1 and 5 to the consolidated financial statements.
The Company's three business segments correspond to the Company's three primary assets: the gathering system, transmission and storage system and water service system. The following table summarizes the composition of the Company's operating revenues by business segment.
 Years Ended December 31,
 202020192018
Gathering operating revenues67 %71 %67 %
Transmission operating revenues26 %24 %26 %
Water operating revenues%%%
The Company's largest customer is EQT, which was the largest natural gas producer in the United States based on average daily sales volumes as of December 31, 2020. EQT accounted for approximately 64%, 69% and 74% of the Company's total revenues for the years ended December 31, 2020, 2019 and 2018, respectively.
Gathering Customers. For the year ended December 31, 2020, EQT accounted for approximately 65% of Gathering's revenues. Subject to certain exceptions and limitations, as of December 31, 2020, Gathering had acreage dedications (inclusive of acreage dedications to Eureka Midstream Holdings, LLC (Eureka Midstream), a joint venture in which the Company has a 60% interest and that owns a 190-mile gathering header pipeline system in Ohio and West Virginia that services both dry Utica and wet Marcellus Shale production) through which the Company has the right to elect to gather all natural gas produced from wells under an area covering (i) approximately 475,000 gross acres in Pennsylvania pursuant to agreements with EQT, including the EQT Global GGA, and agreements with certain other third parties, (ii) approximately 344,000 gross acres in Ohio pursuant to agreements with EQT and other third parties and (iii) approximately 370,000 gross acres in West Virginia pursuant to the EQT Global GGA and agreements with certain other third parties.
The Company provides gathering services in two manners: firm service and interruptible service. Firm service contracts are typically long-term and can include firm reservation fees, which are fixed, monthly charges for the guaranteed reservation of pipeline access. Revenues under firm reservation fees also include fixed volumetric charges under MVCs. As of December 31, 2020, the gathering system had total contracted firm reservation capacity (including contracted MVCs) of approximately 7.0 Bcf per day (inclusive of Eureka Midstream contracted capacity), which included contracted firm reservation capacity of approximately 1.8 Bcf per day associated with the Company's high-pressure header pipelines (including 1.2 Bcf per day under the Hammerhead gathering agreement, which is currently subject to a dispute with EQT). Including future capacity expected from expansion projects that are not yet fully constructed for which the Company has executed firm contracts, the gathering system had total contracted firm reservation capacity (including contracted MVCs) of approximately 8.0 Bcf per day (inclusive of Eureka Midstream contracted capacity) as of December 31, 2020, which included contracted firm reservation capacity of approximately 1.8 Bcf per day associated with the Company's high-pressure header pipelines (including 1.2 Bcf per day under the Hammerhead gathering agreement, which is currently subject to a dispute with EQT). Volumetric-based fees can also be charged under firm contracts for each firm volume gathered as well as for volumes gathered in excess of the firm contracted volume, if system capacity exists. Based on total projected contractual revenues, including projected contractual revenues from future capacity expected from expansion projects that are not yet fully constructed for which the Company has executed firm contracts, the Company's firm gathering contracts had a weighted average remaining term of approximately 15 years as of December 31, 2020.
Interruptible service contracts include volumetric-based fees, which are charges for the volume of natural gas gathered and generally do not guarantee access to the pipeline. These contracts can be short- or long-term.
The Company generally does not take title to the natural gas gathered for its customers but retains a percentage of wellhead gas receipts to recover natural gas used to power its compressor stations and meet other requirements on the Company's gathering systems.
See “Gulfport Bankruptcy” under the caption “Outlook” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of the Gulfport Energy Corporation (Gulfport) bankruptcy proceedings.

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Transmission Customers. For the year ended December 31, 2020, EQT accounted for approximately 58% of Transmission's throughput and approximately 53% of Transmission's revenues. As of December 31, 2020, Transmission had an acreage dedication from EQT through which the Company had the right to elect to transport all gas produced from wells drilled by EQT under an area covering approximately 60,000 acres in Allegheny, Washington and Greene Counties in Pennsylvania and Wetzel, Marion, Taylor, Tyler, Doddridge, Harrison and Lewis Counties in West Virginia. The Company's other customers include LDCs, marketers, producers and commercial and industrial users. The Company's transmission and storage system provides customers with access to adjacent markets in Pennsylvania, West Virginia and Ohio and to the Mid-Atlantic, Northeastern, Midwestern and Gulf Coast markets through interconnect points with major interstate pipelines.
The Company provides transmission and storage services in two manners: firm service and interruptible service. Firm service contracts are typically long-term and can include firm reservation fees, which are fixed, monthly charges for the guaranteed reservation of pipeline and storage capacity. Volumetric-based fees can also be charged under firm contracts for firm volume transported or stored as well as for volumes transported or stored in excess of the firm contracted volume, if there is system capacity. Customers are not assured capacity or service for volumes in excess of the firm contracted volume as such volumes have the same priority as interruptible service. Including future capacity expected from expansion projects that are not yet fully constructed for which the Company has executed firm transmission contracts, approximately 4.4 Bcf per day of transmission capacity, excluding, in the aggregate, 2.3 Bcf per day of firm capacity commitments associated with the MVP and MVP Southgate projects, and 30.5 Bcf of storage capacity were subscribed under firm transmission and firm storage contracts, respectively, as of December 31, 2020. Based on total projected contractual revenues, including projected contractual revenues from future capacity expected from expansion projects that are not yet fully constructed for which the Company has executed firm contracts, the Company's firm transmission and storage contracts had a weighted average remaining term of approximately 14 years as of December 31, 2020.
Interruptible service contracts include volumetric-based fees, which are charges for the volume of natural gas transported and generally do not guarantee access to the pipeline or storage facility. These contracts can be short- or long-term. Customers with interruptible service contracts are not assured capacity or service on the transmission and storage systems. To the extent that capacity reserved by customers with firm service contracts is not fully used or excess capacity exists, the transmission and storage systems can allocate capacity to interruptible services. The Company generally does not take title to the natural gas transported or stored for its customers.
As of December 31, 2020, approximately 97% of Transmission's contracted firm transmission capacity was subscribed by customers under negotiated rate agreements under its tariff, while the remainder was subscribed at discounted rates under its tariff, which are rates below the recourse rates and above a minimum level. As of December 31, 2020, Transmission did not have any contracted firm transmission capacity subscribed at recourse rates under its tariff, which are the maximum rates an interstate pipeline may charge for its services under its tariff. See also “FERC Regulation” under “Regulatory Environment” below and “Our natural gas gathering, transmission and storage services are subject to extensive regulation by federal, state and local regulatory authorities. Changes or additional regulatory measures adopted by such authorities could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends.” included in "Item 1A. Risk Factors" for additional information.
Water Customers. For the year ended December 31, 2020, EQT accounted for approximately 90% of Water's revenues. The Company has the exclusive right to provide fluid handling services to certain EQT-operated wells through 2029 (and thereafter such right continues on a month-to-month basis) within areas of dedication in Washington and Greene Counties, Pennsylvania and Belmont County, Ohio, including the delivery of fresh water for well completion operations and the collection and recycling or disposal of flowback and produced water. The Company also provides water services to other customers operating in the Marcellus and Utica Shales. The Company's water service revenues are primarily generated under variable price per volume contracts. The fees charged by the Company are generally tiered and, thus, are lower on a per gallon basis once certain thresholds are met.
See also “Water Services Letter Agreement” above for additional information on the Company's Water customers.
The Company's Assets
Gathering Assets. As of December 31, 2020, the gathering system, inclusive of Eureka Midstream's gathering system, included approximately 1,130 miles of high-pressure gathering lines and 132 compressor units with compression of approximately 485,000 horsepower and multiple interconnect points with the Company's transmission and storage system and to other interstate pipelines. The gathering system also included approximately 910 miles of FERC-regulated, low-pressure gathering lines.
Transmission and Storage Assets. As of December 31, 2020, the transmission and storage system included approximately 950 miles of FERC-regulated, interstate pipelines that have interconnect points to seven interstate pipelines and multiple LDCs. As

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of December 31, 2020, the transmission and storage system was supported by 42 compressor units, with total throughput capacity of approximately 4.4 Bcf per day and compression of approximately 136,000 horsepower, and 18 associated natural gas storage reservoirs, which had a peak withdrawal capacity of approximately 900 MMcf per day and a working gas capacity of approximately 43 Bcf.
Water Assets. As of December 31, 2020, the water system included approximately 200 miles of pipeline that deliver fresh water from the Monongahela River, the Ohio River, local reservoirs and several regional waterways. In addition, as of December 31, 2020, the water system assets included 24 fresh water impoundment facilities.
Developments, Market Trends and Competitive Conditions
Strategy. The Company's strategically-located assets overlay core acreage in the Appalachian Basin. The location of the Company's assets allows its producer customers to access major demand markets in the U.S. The Company is one of the largest natural gas gatherers in the U.S., and its largest customer, EQT, was the largest natural gas producer in the U.S. based on average daily sales volumes as of December 31, 2020. The Company maintains a stable cash flow profile, with approximately 66% of its revenue for the year ended December 31, 2020 generated from firm reservation fees. Further, as discussed above, the percentage of the Company's revenues that are generated by firm reservation fees is expected to increase in future years as a result of the 15-year term EQT Global GGA, which includes an MVC that became effective on April 1, 2020 of 3.0 Bcf per day and gradually steps up to 4.0 Bcf per day for several years following the full in-service date of the MVP project. This contract structure enhances the stability of the Company's cash flows and limits its direct exposure to commodity price risk.
The Company's principal strategy is to achieve greater scale and scope and enhance the durability of its financial strength, which the Company expects will drive future growth and investment. The Company is implementing its strategy by leveraging its existing assets, executing on its growth projects (including through potential expansion and extension opportunities), focusing on ESG initiatives, and, where appropriate, seeking and executing on strategically-aligned acquisition and joint venture opportunities and other strategic transactions, while strengthening its balance sheet through:
highly predictable cash flows backed by firm reservation fees;
actions to de-lever its balance sheet;
disciplined capital spending;
operating cost control; and
an appropriate dividend policy.
As part of its approach to organic growth, the Company is focused on its projects and assets outlined below, many of which are supported by contracts with firm capacity or MVC commitments. The Company believes that this approach will enable the Company to achieve its strategic goals.
The Company expects that the MVP project, together with the Hammerhead pipeline and Equitrans, L.P. Expansion Project (EEP), will primarily drive the Company's organic growth and that its future growth also will be supported by the MVP Southgate project and the water services business, as discussed in further detail below.
Mountain Valley Pipeline. The MVP is being constructed by a joint venture among the Company and affiliates of each of NextEra Energy, Inc., Consolidated Edison, Inc. (Con Edison), AltaGas Ltd. and RGC Resources, Inc. As of December 31, 2020, the Company owned an approximate 46.2% interest in the MVP project and will operate the MVP. The MVP is an estimated 300-mile, 42-inch diameter natural gas interstate pipeline with a targeted capacity of 2.0 Bcf per day that will span from the Company's existing transmission and storage system in Wetzel County, West Virginia to Pittsylvania County, Virginia, providing access to the growing southeast demand markets. The MVP Joint Venture has secured a total of 2.0 Bcf per day of firm capacity commitments at 20-year terms. Additional shippers have expressed interest in the MVP project and the MVP Joint Venture is evaluating an expansion opportunity that could add approximately 0.5 Bcf per day of capacity through the installation of incremental compression. The MVP Joint Venture is also evaluating other future pipeline extension projects.
In October 2017, the FERC issued the Certificate of Public Convenience and Necessity (the Certificate) for the MVP. In the first quarter of 2018, the MVP Joint Venture received limited notice to proceed with certain construction activities from the FERC and commenced construction. Following a comprehensive review of all outstanding stream and wetland crossings across the approximately 300-mile MVP project route, on February 19, 2021, the MVP Joint Venture submitted (i) a joint application package to each of the Huntington, Pittsburgh and Norfolk Districts of the U.S. Army Corps of Engineers (Army Corps) that requests an individual permit from the Army Corps to cross certain

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streams and wetlands utilizing open cut techniques (the Army Corps Individual Permit) and (ii) an application to amend the Certificate that seeks FERC authority to cross certain streams and wetlands utilizing alternative trenchless construction methods.
The Company believes this modified approach to seeking authorization to cross all remaining streams and wetlands on the project route, in lieu of continuing to pursue authority under Nationwide Permit 12 and the formerly pending FERC request to amend the Certificate to utilize trenchless construction methods to cross all streams and wetlands for the first 77 miles of the project route, presents the most efficient and effective path to project completion. The Company continues to target a full in-service date for the MVP project in late 2021 at a total project cost of $5.8 billion to $6.0 billion (excluding AFUDC).
As discussed under "The regulatory approval process for the construction of new midstream assets is very challenging, and decisions by regulatory and judicial authorities in pending or potential proceedings could impact our or the MVP Joint Venture's ability to obtain or maintain in effect all approvals and authorizations necessary to complete certain projects on the targeted time frame or at all or our ability to achieve the expected investment returns on the projects." included in "Item 1A. Risk Factors", there are pending legal and regulatory challenges to or otherwise affecting certain aspects of the MVP project that must be resolved before the project can be completed, and the MVP Joint Venture is working to resolve these challenges. In order to complete the project in accordance with the targeted full in-service date and cost, the MVP Joint Venture must, among other things: (i) timely receive the Army Corps Individual Permit, which will require Section 401 water quality certification approvals or waivers from each of the West Virginia Department of Environmental Protection and the Virginia Department of Environmental Quality and certain other state-level approvals; (ii) maintain and, as applicable, timely receive required authorizations, including authorization to proceed with construction, related to the Jefferson National Forest from the Bureau of Land Management (BLM), the U.S. Forest Service (USFS) and the FERC; (iii) timely receive authorization from the FERC to utilize alternative trenchless construction methods for certain stream and wetland crossings; (iv) continue to have available the orders previously issued by the FERC modifying its prior stop work orders and extending the MVP Joint Venture’s prescribed time to complete the MVP project; (v) timely receive authorization from the FERC to complete construction work in the portion of the project route currently remaining subject to the FERC’s previous stop work order; and (vi) continue to be authorized to work under the Biological Opinion and Incidental Take Statement issued by the United States Department of the Interior’s Fish and Wildlife Service (FWS) for the MVP project, in each case including the continued effectiveness of any such foregoing or other authorizations notwithstanding any pending or future challenge thereto. See the discussion of litigation and regulatory related delays affecting the completion of the MVP project set forth in "Item 3. Legal Proceedings".
On November 4, 2019, Con Edison exercised an option to cap its investment in the MVP project at approximately $530 million (excluding AFUDC). The Company and NextEra Energy, Inc. are obligated, and RGC Resources, Inc., another member of the MVP Joint Venture owning an interest in the MVP project, has opted, to fund the shortfall in Con Edison's capital contributions on a pro rata basis. Such funding by the Company and funding by other members has and will correspondingly increase the Company's and such other members' respective interests in the MVP project and decrease Con Edison's interest in the MVP project. As a result, based on the midpoint of the project's $5.8 billion to $6.0 billion (excluding AFUDC) targeted cost, the Company's ownership interest in the MVP project will progressively increase from approximately 46.2% to approximately 47.6%.
Through December 31, 2020, based on the midpoint of the MVP project's targeted cost, the Company had funded approximately $2.2 billion of its estimated total capital contributions of approximately $2.9 billion (inclusive of additional contributions required due to the Con Edison cap described above), including approximately $140 million to $150 million in excess of the Company's ownership interest. During the year ended December 31, 2020, the Company made approximately $268 million of capital contributions to the MVP Joint Venture for the MVP project. For 2021, the Company expects to make total capital contributions of $670 million to $720 million to the MVP Joint Venture for purposes of the MVP project, depending on the timing of construction of the project.
Wellhead Gathering Expansion Projects and Hammerhead Pipeline. During the year ended December 31, 2020, the Company invested approximately $345 million in gathering projects (inclusive of capital expenditures related to the noncontrolling interest in Eureka Midstream). For 2021, the Company expects to invest approximately $325 million to $355 million in gathering projects (inclusive of expected capital expenditures related to the noncontrolling interest in Eureka Midstream). The primary projects include infrastructure expansion of core development areas in the Marcellus and Utica Shales in southwestern Pennsylvania, southeastern Ohio and northern West Virginia for EQT, Range Resources Corporation (Range Resources) and other producers.

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The Hammerhead pipeline is a 1.6 Bcf per day gathering header pipeline that is primarily designed to connect natural gas produced in Pennsylvania and West Virginia to the MVP, Texas Eastern Transmission and Dominion Transmission, is supported by a 20-year term, 1.2 Bcf per day, firm capacity commitment from EQT, and cost approximately $540 million. The Company believes the Hammerhead pipeline was placed in-service effective August 1, 2020. See "Outlook" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for more information on the Hammerhead pipeline.
Transmission Projects and Equitrans Expansion Project. During the year ended December 31, 2020, the Company invested approximately $45 million in transmission projects, including the EEP. For 2021, the Company expects to invest approximately $25 million to $45 million in transmission projects.
The EEP is designed to provide north-to-south capacity on the mainline Equitrans, L.P. transmission system, including primarily for deliveries to the MVP. A portion of the EEP commenced operations with interruptible service in the third quarter of 2019. The EEP provides capacity of approximately 600 MMcf per day and offers access to several markets through interconnects with Texas Eastern Transmission, Dominion Transmission and Columbia Gas Transmission. Once the MVP is fully placed in service, firm transportation agreements for 550 MMcf per day of capacity will commence under 20-year terms.
MVP Southgate Project. In April 2018, the MVP Joint Venture announced the MVP Southgate project, a proposed 75-mile interstate pipeline that will extend from the MVP at Pittsylvania County, Virginia to new delivery points in Rockingham and Alamance Counties, North Carolina. The MVP Southgate project is backed by a 300 MMcf per day firm capacity commitment from Dominion Energy North Carolina. As designed, the MVP Southgate project has expansion capabilities that could provide up to 900 MMcf per day of total capacity. The MVP Southgate project is estimated to cost a total of approximately $450 million to $500 million, which is expected to be spent primarily in 2022. The Company expects to fund approximately $225 million of the overall project cost. During the year ended December 31, 2020, the Company made approximately $5 million of capital contributions to the MVP Joint Venture for the MVP Southgate project. For 2021, the Company expects to make capital contributions of approximately $20 million to the MVP Joint Venture for the MVP Southgate project. The Company will operate the MVP Southgate and, as of December 31, 2020, owned a 47.2% interest in the MVP Southgate project. The MVP Joint Venture submitted the MVP Southgate certificate application to the FERC in November 2018. The Final Environmental Impact Statement for the MVP Southgate project was issued on February 14, 2020. In June 2020, the FERC issued the Certificate of Public Convenience and Necessity for the MVP Southgate; however, the FERC, while authorizing the project, directed the Office of Energy Projects not to issue a notice to proceed with construction until necessary federal permits are received for the MVP project and the Director of the Office of Energy Projects lifts the stop work order and authorizes the MVP Joint Venture to continue constructing the MVP project. On August 11, 2020, North Carolina regulators denied the MVP Southgate project's application for a Clean Water Act Section 401 Individual Water Quality Certification and Jordan Lake Riparian Buffer Authorization due to uncertainty surrounding the completion of the MVP project, which denial was appealed by the MVP Joint Venture on September 10, 2020. The MVP Southgate project is targeted to be placed in-service in 2022, which such targeted in-service date is based on, among other things, favorable and timely resolution of this and other regulatory and legal decisions and processes. See the discussion of litigation and regulatory related delays affecting the completion of the MVP Southgate project set forth in "Item 3. Legal Proceedings".
Water Operations. During the year ended December 31, 2020, the Company invested approximately $12 million in its fresh water delivery infrastructure. For 2021, the Company expects to invest approximately $20 million in the operations of its fresh water delivery infrastructure in Pennsylvania and Ohio.
Competitive Condition. Key competitors for new natural gas gathering systems include companies that own major natural gas pipelines, independent gas gatherers and integrated energy companies. When compared to the Company or its customers, some of the Company's competitors have greater capital resources and access to, or control of, larger natural gas supplies.
Competition for natural gas transmission and storage is primarily based on rates, customer commitment levels, timing, performance, commercial terms, reliability, service levels, location, reputation and fuel efficiencies. The Company's principal competitors in its transmission and storage market include companies that own major natural gas pipelines in the Marcellus and Utica Shales. In addition, the Company competes with companies that are building high-pressure gathering facilities that are able to transport natural gas to interstate pipelines without being subject to FERC jurisdiction. Major natural gas transmission companies that compete with the Company also have storage facilities connected to their transmission systems that compete with certain of the Company's storage facilities.

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Key competition for water services include natural gas producers that develop their own water distribution systems in lieu of employing the Company's water services assets and other natural gas midstream companies that offer water services. The Company's ability to attract customers to its water service business depends on its ability to evaluate and select suitable projects and to consummate transactions in a highly competitive environment.
Further, natural gas as a fuel competes with other forms of energy available to end-users, including coal, liquid fuels and, increasingly, renewable and alternative energy. Demand for renewable and alternative energy is increasing generally with changes in consumer preferences and as renewable and alternative energy becomes more cost competitive with traditional fuels and more widely available. Continued increases in the demand for renewable and alternative energy at the expense of natural gas (or increases in the demand for other sources of energy, particularly if prices for natural gas significantly increase relative to other forms of energy as fuel) could lead to a reduction in demand for natural gas gathering, transmission and storage, and water services.
Regulatory Environment
FERC Regulation. The Company's interstate natural gas transmission and storage operations are regulated by the FERC under the Natural Gas Act (NGA), the Natural Gas Policy Act (NGPA) and the regulations, rules and policies promulgated under those and other statutes. Certain portions of the Company's gathering operations are also currently rate-regulated by the FERC in connection with its interstate transmission operations. The Company's FERC-regulated operations are pursuant to tariffs approved by the FERC that establish rates (other than market-based rate authority), cost recovery mechanisms and terms and conditions of service to its customers. Generally, the FERC's authority extends to:
rates and charges for the Company's natural gas transmission and storage services and FERC-regulated gathering services;
certification and construction of new interstate transmission and storage facilities;
abandonment of interstate transmission and storage services and facilities and certificated gathering facilities;
maintenance of accounts and records;
relationships between pipelines and certain affiliates;
terms and conditions of services and service contracts with customers;
depreciation and amortization policies;
acquisitions and dispositions of interstate transmission and storage facilities; and
initiation and discontinuation of interstate transmission and storage services.
The FERC regulates the rates and charges for transmission and storage in interstate commerce. Unless market-based rates have been approved by the FERC, the maximum applicable recourse rates and terms and conditions for service are set forth in the pipeline's FERC-approved tariff. Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of providing service, including the recovery of a return on the pipeline's actual and prudent historical investment costs. Key determinants in the ratemaking process include the depreciated capital costs of the facilities, the costs of providing service, the allowed rate of return and income tax allowance, as well as volume throughput and contractual capacity commitment assumptions.
Interstate pipelines may not charge rates or impose terms and conditions of service that, upon review by the FERC, are found to be unjust or unreasonable, unduly discriminatory or preferential. Rate design and the allocation of costs also can affect a pipeline's profitability. While the ratemaking process establishes the maximum rate that can be charged, interstate pipelines such as the Company's transmission and storage system are permitted to discount their firm and interruptible rates without further FERC authorization down to a specified minimum level, provided they do not unduly discriminate. In addition, pipelines are allowed to negotiate different rates with their customers, under certain circumstances. Changes to rates or terms and conditions of service, and contracts can be proposed by a pipeline company under Section 4 of the NGA, or the existing interstate transmission and storage rates or terms and conditions of service, and contracts may be challenged by a complaint filed by interested persons including customers, state agencies or the FERC under Section 5 of the NGA. Rate increases proposed by a pipeline may be allowed to become effective subject to refund and/or a period of suspension, while rates or terms and conditions of service that are the subject of a complaint under Section 5 of the NGA are subject to prospective change by the FERC. Rate increases proposed by a regulated interstate pipeline may be challenged and such increases may ultimately be rejected by the FERC.

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The Company's interstate pipeline may also use negotiated rates that could involve rates above or below the recourse rate or rates that are subject to a different rate structure than the rates specified in the Company's interstate pipeline tariffs, provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement. A prerequisite for allowing the negotiated rates is that negotiated rate customers must have had the option to take service under the pipeline's recourse rates. As of December 31, 2020, approximately 97% of the system's contracted firm transmission capacity was subscribed by customers under negotiated rate agreements under its tariff. Some negotiated rate transactions are designed to fix the negotiated rate for the term of the firm transportation agreement and the fixed rate is generally not subject to adjustment for increased or decreased costs occurring during the contract term.
The FERC’s regulations also extend to the terms and conditions set forth in agreements for transmission and storage services executed between interstate pipelines and their customers. These service agreements are required to conform, in all material respects, with the form of service agreements set forth in the pipeline's FERC-approved tariff. Non-conforming agreements must be filed with and accepted by the FERC. In the event that the FERC finds that an agreement is materially non-conforming, in whole or in part, it could reject, or require the Company to seek modification of, the agreement, or alternatively require the Company to modify its tariff so that the non-conforming provisions are generally available to all customers or class of customers.
The FERC’s jurisdiction also extends to the certification and construction of new interstate transmission and storage facilities, including, but not limited to, acquisitions, facility replacements and upgrades, expansions, and abandonment of facilities and services. While the FERC currently exercises jurisdiction over the rates and terms of service for the Company’s FERC-regulated gathering services, these gathering facilities may not be subject to the FERC’s certification and construction authority. Prior to commencing construction of new or existing interstate transmission and storage facilities, an interstate pipeline must obtain (except in certain circumstances, such as where the activity is permitted under the FERC’s regulations or is authorized under the operator’s existing blanket certificate issued by the FERC) a certificate authorizing the construction, or file to amend its existing certificate, from the FERC.
On April 19, 2018, the FERC issued a Notice of Inquiry (Certificate Policy Statement NOI) seeking information regarding whether, and if so how, it should revise its approach under its currently effective policy statement on the certification of new natural gas transportation facilities (Certificate Policy Statement). The formal comment period in this proceeding closed on June 25, 2018 and there has been no further action. The Company cannot currently predict when the FERC will issue an order in the Certificate Policy Statement NOI proceeding, or what action the FERC may take in any such order.
The change of party control in Congress in 2021 raises the possibility of legislation revising the NGA or other statutes that may impact the Company’s existing facilities and operations or the ability to construct new facilities. Potential areas of revision include, but are not limited to, (i) amending Section 5 of the NGA to allow the FERC to require a pipeline to make refunds from the date that a NGA Section 5 complaint was filed with the FERC if rates are later found to be unjust and unreasonable; (ii) amending Section 7 of the NGA to require that condemnation authority not be exercised and construction may not begin until a FERC certificate order has been reviewed on rehearing; and (iii) amending Section 19(b) of the NGA to provide the FERC additional time to act on requests for rehearing.
The change of party control at the FERC in 2021 may also lead to regulation or policy changes (in response to court orders or the aforementioned potential statutory changes or for other reasons) including, but not limited to, (i) requiring additional review of greenhouse gas emissions attributable to a proposed pipeline project; (ii) requiring applications for new pipeline construction to contain more stringent climate change analysis; and (iii) revising the Certificate Policy Statement to require additional showing of the need for a project beyond the traditional precedent agreement analysis.
FERC Regulation of Gathering Rates and Terms of Service. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by the FERC under the NGA. While the FERC does not generally regulate the rates and terms of service over facilities determined to be performing a natural gas gathering function, it has traditionally regulated rates charged by interstate pipelines for gathering services performed on the pipeline's own gathering facilities when those gathering services are performed in connection with jurisdictional interstate transmission services. The Company currently maintains rates and terms of service in its tariff for unbundled gathering services performed on its gathering facilities in connection with the transmission service. Just as with rates and terms of service for transmission and storage services, the Company's rates and terms of service for its FERC-regulated low-pressure gathering system may be challenged by complaint and are subject to prospective change by the FERC. The Company has submitted an application to the FERC requesting authorization to abandon these low-pressure gathering facilities and services. As of December 31, 2020, the application remained pending before the FERC.
The Company believes that its high-pressure gathering systems meet the traditional tests the FERC has used to establish a pipeline's status as an exempt gatherer not subject to regulation as a jurisdictional natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is often the subject of

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litigation in the industry, so the classification and regulation of these systems are subject to change based on future determinations by the FERC, the courts or the U.S. Congress.
Pipeline Safety and Maintenance. The Company's interstate natural gas pipeline system is subject to regulation by PHMSA. PHMSA has established safety requirements pertaining to the design, installation, testing, construction, operation and maintenance of gas pipeline facilities, including requirements that pipeline operators develop a written qualification program for individuals performing covered tasks on pipeline facilities and implement pipeline integrity management programs. These integrity management plans require more frequent inspections and other preventive measures to ensure safe operation of oil and natural gas transportation pipelines in high population areas or facilities that are hard to evacuate and areas of daily concentrations of people.
Notwithstanding the investigatory and preventative maintenance costs incurred in the Company's performance of customary pipeline management activities, the Company may incur significant additional expenses if anomalous pipeline conditions are discovered or more stringent pipeline safety requirements are implemented. For example, in April 2016, PHMSA published a notice of proposed rulemaking addressing several integrity management topics and proposing new requirements to address safety issues for natural gas transmission and gathering lines (the Mega Rule). The proposed Mega Rule would strengthen existing integrity management requirements, expand assessment and repair requirements to pipelines in areas with medium population densities and extend regulatory requirements to onshore gas gathering lines that are currently exempt. Part one of the Mega Rule was finalized on July 1, 2020. Two remaining parts of the Mega Rule are awaiting finalization. Dates for finalization have not been updated or released by PHMSA due to COVID-19.
Further, in June 2016, then-President Obama signed the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the 2016 Pipeline Safety Act), extending PHMSA's statutory mandate under prior legislation through 2019. Although a reauthorization bill extending PHMSA’s statutory mandate until 2023 was introduced in 2019, Congress did not pass the bill in 2019 or 2020 and PHMSA is operating under a continuing resolution until a new bill is passed. In addition, the 2016 Pipeline Safety Act empowered PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing and also required PHMSA to develop new safety standards for natural gas storage facilities by June 2018. Pursuant to those provisions of the 2016 Pipeline Safety Act, PHMSA issued two separate Interim Final Rules in October 2016 and December 2016 that expanded the agency's authority to impose emergency restrictions, prohibitions and safety measures and strengthened the rules related to underground natural gas storage facilities, including well integrity, wellbore tubing and casing integrity. The December 2016 Interim Final Rule, relating to underground gas storage facilities, went into effect in January 2017. PHMSA determined, however, that it would not issue enforcement citations to any operators for violations of provisions of the December 2016 Interim Final Rule that had previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issued a final rule. The final rule related to underground gas storage facilities became effective as of March 13, 2020.
Following the October 2016 Interim Final Rule, PHMSA also published two final rules on pipeline safety applicable to the Company: "Enhanced Emergency Order Procedures;" and "Safety of Gas Transmission Pipelines: Maximum Allowable Operating Pressure Reconfirmation, Expansion of Assessment Requirements." The Enhanced Emergency Order Procedures rule, which became effective on December 2, 2019, implements an existing statutory authorization for PHMSA to issue emergency orders related to pipeline safety if an unsafe condition or practice, or a combination of unsafe conditions and practices, constitutes, or is causing an imminent hazard. The Safety of Gas Transmissions Pipelines rule, which went into effect on July 1, 2020, requires operators of certain gas transmission pipelines that have been tested or that have inadequate records to determine the material strength of their lines by reconfirming the Maximum Allowable Operating Pressure, and establishes a new Moderate Consequence Area for determining regulatory requirements for gas transmission pipeline segments outside of high consequence areas. The rule also establishes new requirements for conducting baseline assessments, incorporates into the regulations industry standards and guidelines regarding design, construction and in-line inspections, and new requirements for data integration and risk analysis in integrity management programs, including seismicity, manufacturing and construction defects, and crack and crack-like defects, and includes several requirements that allow operators to notify PHMSA of proposed alternative approaches to achieving the objectives of the minimum safety standards. In 2020, the Company did not incur material compliance costs in connection with complying with the PHMSA rules applicable to the Company, and it is in the process of assessing the impact of these rules on its future costs of operations and revenue from operations.
States are generally preempted by federal law in the area of pipeline safety, but state agencies may qualify to assume responsibility for enforcing federal regulations over intrastate pipelines. They may also promulgate additive pipeline safety regulations provided that the state standards are at least as stringent as the federal standards. Although many of the Company's natural gas facilities fall within a class that is not subject to integrity management requirements, the Company may incur significant costs and liabilities associated with repair, remediation, preventive or mitigation measures associated with its non-exempt transmission pipelines. The costs, if any, for repair, remediation, preventive or mitigating actions that may be

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determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down the Company's pipelines during the pendency of any such actions, could be material to capital expenditures, earnings and the Company's competitive position.
Should the Company fail to comply with DOT regulations adopted under authority granted to PHMSA, it could be subject to penalties and fines. PHMSA has the statutory authority to impose civil penalties for pipeline safety violations up to a maximum of approximately $220,000 per day for each violation and approximately $2.2 million for a related series of violations. This maximum penalty authority established by statute will continue to be adjusted periodically to account for inflation. In addition, the Company could be required to make additional maintenance capital expenditures in the future for the above described or similar regulatory compliance initiatives that are not reflected in its forecasted maintenance capital expenditures. The Company believes that its operations are in substantial compliance with all existing federal, state and local pipeline safety laws and regulations. However, the adoption of new laws and regulations, such as those proposed by PHMSA, could result in significant added costs or delays in service or the termination of projects, which could have a material adverse effect on the Company in the future.
On December 27, 2020, then-President Trump signed the “Protecting our Infrastructure of Pipelines and Enhancing Safety (PIPES Act) of 2020.” The PIPES Act identifies areas where Congress believed additional oversight, research, or regulations was needed. The PIPES Act includes new mandates for PHMSA to require operators to update, as needed, their emergency response plans and operating and maintenance plans. The PIPES Act also requires operators to manage records and update, as necessary, their existing district regulator stations to eliminate a common mode of failure. PHMSA will also require that leak detection and repair programs consider the environment, the use of advance lead detection practices and technologies, and for operators to be able to locate and categorize all leaks that are hazardous to human safety, the environment, or can become hazardous. The Company does not anticipate incurring material capital expenditures in connection with complying with the PIPES Act.
Environmental Matters
General. The Company's operations are subject to stringent federal, state and local laws and regulations relating to the protection of the environment, which may have the following effects on the Company:
requiring that the Company obtains various permits to conduct regulated activities;
requiring the installation of pollution-control equipment or otherwise regulating the way the Company can handle or dispose of its wastes;
limiting or prohibiting construction activities in sensitive areas, such as wetlands, water sources, or areas inhabited by endangered or threatened species; and
requiring investigatory and remedial actions to mitigate or eliminate pollution conditions caused by the Company's operations or attributable to former operations.
In addition, the Company's operations and construction activities may be subject to county and local ordinances that restrict the time, place or manner in which those operations and activities may be conducted.
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of investigatory and remedial obligations and the issuance of orders enjoining future operations or imposing additional compliance requirements. Also, certain environmental statutes impose strict, and in some cases joint and several, liability for the cleanup and restoration of sites where hydrocarbons or wastes have been disposed or otherwise released regardless of the fault of the current site owner or operator. Consequently, the Company may be subject to environmental liability at its currently owned or operated facilities for conditions caused by others prior to its involvement.
The Company has implemented programs and policies designed to keep its pipelines and other facilities in compliance with existing environmental laws and regulations, and the Company does not believe that its compliance with such legal requirements will have a material adverse effect on its business, financial condition, results of operations, liquidity or ability to pay dividends to its shareholders. Nonetheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment (and such trend will likely increase under the Biden Administration). Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be significantly in excess of the amounts the Company currently anticipates. For example, in October 2015, the EPA revised the National Ambient Air Quality Standards (NAAQS) for ozone from 75 parts per billion for the current eight-hour primary and secondary ozone standards to 70 parts per billion for both standards. The EPA may designate

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the areas in which the Company operates as nonattainment areas. States that contain any areas designated as nonattainment areas will be required to develop implementation plans demonstrating how the areas will attain the applicable standard within a prescribed period of time. These plans may require the installation of additional equipment to control emissions. In addition, in May 2016, the EPA finalized rules that impose volatile organic compound and methane emissions limits (and collaterally reduce methane emissions) on certain types of compressors and pneumatic pumps, as well as requiring the development and implementation of leak monitoring plans for compressor stations. The EPA finalized amendments to some requirements in these standards in March 2018, September 2018 and September 2020, including rescission of certain requirements and revisions to other requirements such as fugitive emissions monitoring frequency. In September 2020, the EPA issued a correction to the regulations, removing transmission and storage segments from the source category subject to the rule and removing the methane emissions limits from the rule. President Biden has ordered the EPA to review these rules. Compliance with these or other new regulations could, among other things, require installation of new emission controls on some of the Company's equipment, result in longer permitting timelines, and significantly increase the Company's capital expenditures and operating costs, which could adversely affect the Company's business. The Company tries to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. While the Company believes that it is in substantial compliance with existing environmental laws and regulations, there is no assurance that the current conditions will continue in the future.
Finally, pursuant to the Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis, on January 20, 2021, President Biden directed the heads of all federal agencies to review “all existing regulations, orders, guidance documents, policies, and any other similar agency actions (agency actions) promulgated, issued, or adopted” during the Trump administration for consistency with the policies established in the new Biden Administration order. Regulatory actions resulting from this review could adversely affect the Company’s business, including by requiring additional capital expenditures and increasing operating costs.
The following is a discussion of several of the material environmental laws and regulations, as amended from time to time, that relate to the Company's business.
Hazardous Substances and Waste. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include current and prior owners or operators of the site where a release of hazardous substances occurred and companies that transported, disposed or arranged for the transportation or disposal of the hazardous substances found at the site. Under CERCLA, these "responsible persons" may be subject to strict and joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. The Company generates materials in the course of its ordinary operations that are regulated as "hazardous substances" under CERCLA or similar state laws and, as a result, may be jointly and severally liable under CERCLA, or such laws, for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
In the ordinary course of the Company's operations, the Company generates wastes constituting solid wastes, and in some instances hazardous wastes, which are subject to the requirements of the Resource Conservation and Recovery Act (RCRA) and comparable state statutes. While the RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. While certain petroleum production wastes are excluded from RCRA's hazardous waste regulations, it is possible that these wastes will in the future be designated as "hazardous wastes" and be subject to more rigorous and costly disposal requirements, which could have a material adverse effect on the Company's maintenance capital expenditures and operating expenses.
The Company owns, leases or operates properties where petroleum hydrocarbons are being or have been handled for many years. The Company has generally utilized operating and disposal practices that are standard in the industry at the time, although petroleum hydrocarbons or other wastes may have been disposed of or released on or under the properties owned, leased or operated by the Company, or on or under the other locations where these petroleum hydrocarbons and wastes have been transported for treatment or disposal. Petroleum hydrocarbons or other wastes may have been disposed or released on certain of these properties by third parties that previously operated, owned or leased these properties and whose treatment and disposal or release of petroleum hydrocarbons and other wastes were not under the Company's control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or

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operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination.
Air Emissions. The federal Clean Air Act and comparable state laws and regulations restrict the emission of air pollutants from various industrial sources, including the Company's compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that the Company obtain pre-approval for the construction or modification of certain projects or facilities, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. The Company's failure to comply with these requirements could subject it to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. The Company may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining permits and approvals for air emissions. These types of capital expenditures could also be required in areas that are nonattainment for the ozone national ambient air quality standards depending on the design of the relevant state’s implementation plan to meet the air quality standards. Compliance with these requirements may require modifications to certain of the Company's operations, including the installation of new equipment to control emissions from the Company's compressors that could result in significant costs, including increased capital expenditures and operating costs, and could adversely affect the Company's business.
Climate Change. Legislative and regulatory measures to address climate change and greenhouse gas (GHG) emissions are in various phases of discussion or implementation and will be a major focus of the Biden Administration. On January 27, 2021, President Biden signed an Executive Order on “Tackling the Climate Crisis at Home and Abroad.” This Executive Order contains sweeping direction to the executive branch to address climate issues. Among other things, the order put a “pause” on any new oil and natural gas leases on public lands or in offshore waters pending completion of a review by the Department of the Interior. The Interior Department is also to consider whether to adjust oil and gas royalties associated with fossil fuels extracted from public lands and offshore waters.
The EPA regulates GHG emissions from new and modified facilities that are potential major sources of criteria pollutants under the Clean Air Act's Prevention of Significant Deterioration and Title V programs and has adopted regulations that require, among other things, preconstruction and operating permits for certain large stationary sources and the monitoring and reporting of GHGs from certain onshore oil and natural gas production sources on an annual basis.
The EPA has also regulated methane and volatile organic compound emissions from the oil and gas sector through its new source performance standard program. In September 2020, the EPA issued a final rule that removed the transmission and storage segments from the source category subject to the methane and volatile organic compound emissions limitations. That regulation also removed the methane emissions limitations. In an Executive Order issued on January 20, 2021, President Biden directed the EPA to review this rule and consider suspending, revising, or rescinding it.
In addition, in 2015, the U.S., Canada, and the U.K. participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the U.S. in April 2016, requires countries to review and "represent a progression" in their intended nationally determined contributions (which set GHG emission reduction goals) every five years beginning in 2020. The United States withdrew from the Paris Agreement in 2020; however, President Biden signed an executive order on January 20, 2021, for the United States to rejoin the Paris Agreement. Depending on the United States’ nationally determined contribution and how it is achieved, the Company could be required to reduce its GHG emissions, which would increase the Company’s cost of environmental compliance.
The U.S. Congress, along with federal and state agencies, has considered measures to reduce the emissions of GHGs. Legislation or regulation that restricts carbon emissions could increase the Company's cost of environmental compliance by requiring the Company to install new equipment to reduce emissions from larger facilities and/or, depending on any future legislation, purchase emission allowances. The effect of climate change legislation or regulation on the Company's business is currently uncertain. If the Company incurs additional costs to comply with such legislation or regulations, it may not be able to pass on the higher costs to its customers or recover all the costs related to complying with such requirements and any such recovery may depend on events beyond the Company's control, including the outcome of future rate proceedings before the FERC or state regulatory agencies and the provisions of any final legislation or implementing regulations. The Company's future results of operations, cash flows or financial condition could be adversely affected if such costs are not recovered through regulated rates or otherwise passed on to its customers. Additionally, the Company's producer customers may also be affected by legislation or regulation, which may, directly or indirectly, adversely impact their ability and willingness to produce natural gas and accordingly affect such producers' financial health or reduce the volumes delivered to the Company and demand for its services. Climate change and GHG legislation or regulation could delay or otherwise negatively affect efforts to obtain and maintain permits and other regulatory approvals for existing and new facilities, impose additional monitoring and reporting requirements or adversely affect demand for the natural gas the Company gathers, transports and stores. The effect on the

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Company of any new legislative or regulatory measures on the Company will depend on the particular provisions that are ultimately adopted.
Water Discharges. The federal Clean Water Act and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants or dredged and fill material into state waters as well as waters of the United States, including adjacent wetlands. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of permits issued by the EPA, the Army Corps or an analogous state agency. In September 2015, new EPA and Army Corps rules defining the scope of the EPA's and the Army Corps' jurisdiction became effective (the 2015 Clean Water Rule). But the 2015 Clean Water Rule was promptly challenged in courts and was enjoined by judicial action in some states. Further, in October 2019 the EPA issued a rule repealing the 2015 Clean Water Rule and recodifying the preexisting regulations. In June 2020, new EPA and Army Corps regulations narrowing the regulatory scope of the Clean Water Act became effective (the 2020 Navigable Waters Protection Rule). Like the 2015 Clean Water Rule, the 2020 Navigable Water Protection Rule was promptly challenged in courts and has been enjoined by judicial action in at least one state. To the extent that any future rules expand the scope of the Clean Water Act's jurisdiction, the Company could face increased costs and delays with respect to obtaining permits for activities in jurisdictional waters, including wetlands.
Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws. The Company believes that compliance with existing permits and foreseeable new permit requirements will not have a material adverse effect on its business, financial condition, results of operations, liquidity or ability to pay dividends to its shareholders.
National Environmental Policy Act. The construction of interstate natural gas transportation pipelines pursuant to the NGA requires authorization from the FERC. The FERC actions are subject to the National Environmental Policy Act (NEPA). NEPA requires federal agencies, such as the FERC, to evaluate major federal actions having the potential to significantly affect the environment. In the course of such evaluations, an agency will either prepare an environmental assessment that examines the potential direct, indirect and cumulative effects of a proposed project or, if necessary, a more detailed Environmental Impact Statement. Any proposed plans for future construction activities that require FERC authorization will be subject to the requirements of NEPA. This process has the potential to significantly delay or limit, and significantly increase the cost of, development of midstream infrastructure. In September 2020, new Council on Environmental Quality regulations intended to streamline the NEPA evaluation process went into effect. These rules have been challenged in courts, although initial efforts to enjoin enforcement of the rule were unsuccessful.
Endangered Species Act. The federal Endangered Species Act (ESA) restricts activities that may adversely affect endangered and threatened species or their habitats. Federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of the Company's facilities are located in areas that are designated as habitats for endangered or threatened species, the Company is confident that it is in substantial compliance with the ESA. The designation of previously unprotected species as being endangered or threatened, or the designation of previously unprotected areas as a critical habitat for such species, could cause the Company to incur additional costs, result in delays in construction of pipelines and facilities, or cause the Company to become subject to operating restrictions in areas where the species are known to exist. For example, the FWS continues to receive hundreds of petitions to consider listing additional species as endangered or threatened and is being regularly sued or threatened with lawsuits to address these petitions. Some of these legal actions may result in the listing of species located in areas in which the Company operates. Throughout 2020, the United States Department of Interior narrowed the ESA regulations and their applicability. These regulations have been challenged in the courts.
Employee Health and Safety. The Company is subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (OSHA) and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community "right-to-know" regulations and comparable state laws and regulations require that information be maintained concerning hazardous materials used or produced in the Company's operations and that this information be provided to employees, state and local government authorities and citizens. The Company is confident that it is in substantial compliance with all applicable laws and regulations relating to worker health and safety.



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Seasonality
Weather affects natural gas demand for power generation and heating purposes. Peak demand for natural gas typically occurs during the winter months as a result of the heating load.
Human Capital Management
To ensure that we are well positioned to provide innovative solutions and reliable energy infrastructure services in a safe, efficient and responsible manner, the Company seeks to employ a team of highly dedicated and accomplished people who genuinely care about the success of the Company. Creating an engaging workplace environment that provides for competitive pay and benefits, attractive career development opportunities, and a collaborative, respectful culture further enables the Company to achieve continued success.
As of December 31, 2020, the Company had 771 employees; during 2020, the Company's overall turnover was just above 6% (with less than 4% being voluntary turnover) of the total employee population. While most of the Company's employees work a full-time schedule, the Company does offer several flexible work opportunities including the option for part-time and remote work, as applicable based on job duties, as well as alternative work schedules.
Company Culture. The Company’s culture is shaped by its five core values of Safety, Integrity, Collaboration, Transparency, and Excellence. These values are the essence of the Company's identity and provide the framework for the conduct of its employees, as well as the relationships the Company has with its stakeholders, including its customers, communities, vendors, and shareholders.
In July 2019, the Company formed a Culture Champions Group, which consists of a diverse representation of employees across the organization below the director level, with the objective of soliciting suggestions from employees on ways to enhance the Company's culture. In early 2020, the Company also conducted an anonymous culture survey to seek feedback from employees on a variety of topics, including understanding of the Company's strategy, vision, departmental coordination, employee development, and empowerment. Based on the results of the survey, as well as feedback provided to the Culture Champions Group, the Company has implemented a number of actions within the organization to improve and enhance employee recognition, leadership visibility and communication, and integration and collaboration between departments, including but not limited to coffee talks (informational sessions on various topics), peer networking initiatives, lunches with leaders, and employee communication sessions.
Diversity and Inclusion. The Company believes each employee is essential to its continued success and the Company seeks to provide every employee with the foundation and environment needed to achieve the employee’s goals. This objective begins with the Company's commitment to diversity and inclusion. In July 2020, the Company formally launched its Inclusion program, which focuses on the Company's core value of Collaboration through cultivating an inclusive, respectful work environment that values differing perspectives and encourages the power of teamwork and accountability. The Company's program is composed of four pillars – Accountability, External Recruitment Outreach, Internal Outreach, and External Partnerships. Through each of these pillars, the Company seeks to touch every aspect of its business. During 2020, under this program, the Company launched a micro-learning platform providing employees with inclusion-related content on a bi-weekly basis; conducted manager inclusion training; completed a review of human resources policies in support of an inclusive work environment; created an Inclusion scorecard to capture relevant employee demographics for discussion with leadership; and began the steps to establish the Company's first gender neutral restroom in its headquarters location.
The Company also partners with several diverse organizations from a networking and recruitment perspective. Through these partnerships, the Company aims to broaden and extend its recruitment outreach efforts with an emphasis on finding and hiring diverse individuals, including veterans and ethnically diverse individuals, and persons who identify as having a disability. The Company's supply chain organization also recognizes the value of supplier diversity and acknowledges and tracks its spend with diverse contract suppliers.
Total Rewards. The Company believes its employees are critical to the success of its business, and the Company structures its total rewards and benefits offerings to attract and retain a talented and engaged workforce. These benefits include, but are not limited to, the following:
Comprehensive health insurance, including access to health savings accounts, to all full-time employees and part-time employees working at least 20 hours per week;
A Take Charge Wellness program, through which the Company offers wellness information, education and special programs, including in certain instances health coaches, to employees and their family members on topics such as nutrition, fitness, safety and disease prevention;

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Annual flu immunizations;
Access to an Employee Assistance Program;
Tuition reimbursement through an Education Assistance Program;
Adoption assistance;
Paid time off for holidays, vacation, bereavement, jury duty, military and volunteer time;
Paid short-term and long-term disability and life insurance and business travel insurance;
Medical spending accounts for eligible retirees;
Flexible work arrangements, including a new telecommuting policy beginning in 2019 for employees, upon approval, to work remotely on a temporary or permanent basis and alternative work schedules;
Competitive base salaries and annual incentive plan and long-term incentive opportunities; and
A retirement plan in which the Company matches 50% of every dollar the employee contributes up to a maximum of 3% of base compensation, including overtime, pay in lieu of vacation and annual incentive awards and a retirement contribution equal to 6% of the employee’s salary and annual incentive award.
Safety. Above all else, safety is the Company's main priority – this includes the safety of its employees, contractors, and communities – always. The Company is committed to maintaining a strong safety culture and to emphasizing the importance of its employees’ role in identifying, mitigating and communicating safety risks. The Company's Board of Directors (Board) provides oversight for the Company's safety initiatives through the Health, Safety, Security and Environmental (HSSE) Committee of the Board. The Company tracks numerous safety-related metrics to evaluate its safety performance and has incorporated safety metrics into the Company's annual incentive plan. By linking these metrics to employees’ compensation, the Company believes it can more effectively and proactively address safety issues, increase the safety of the Company's worksites and offices, and achieve employee buy-in. Additionally, the Company's President and Chief Operating Officer distributes monthly comprehensive safety memorandums to all employees and members of the Board keeping them abreast of the Company’s safety performance. In 2020, the Company experienced the following safety highlights:
612% increase in safety observations over 2019;
197 proactive corrected safety hazards;
36% decrease in employee OSHA Days Away Restricted or Transferred (DART) rate over 2019;
11% decrease in employee OSHA Total Recordable Incident Rate over 2019; and
10% decrease in employee incident with serious potential rate over 2019.
In connection with the COVID-19 pandemic, the Company has proactively undertaken a number of company-wide measures intended to promote the safety of field and office-based employees and contractors (including, among other things, establishing an Infectious Disease Response Team, instituting enhanced self-protection and office sanitation measures, eliminating non-essential business travel, implementing a mandatory work-from-home protocol for a substantial majority of the Company’s employees through at least June 1, 2021, instituting face covering protocols, providing certain medical benefit enhancements, practicing social distancing in field operations where possible, sharing the Company’s infectious disease response plan with suppliers and contractors, and timely communicating updates to employees and other relevant parties). In addition, the Company has implemented additional mitigation efforts in connection with the remobilization of certain field employees and contractors. The Company’s Infectious Disease Response Team continues to monitor and assist in implementing mitigation efforts in respect of potential areas of risk for the Company and its stakeholders.
Talent Development. The Company believes it has a robust talent and leadership development framework. The Management Development and Compensation Committee of the Board oversees the development program for the Company's executive officers and other key members of management. The Company provides leadership training to multiple levels of Company leaders and managers. The Company also offers customized, executive-level assessment and development programs for its senior leaders. In addition to the structured leadership programs offered, several of the Company's employees have participated in individual coaching sessions with professional coaches.

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In addition, the Company offers other learning opportunities for employees across the organization to enhance their skill sets. The Company has a partnership with an external organization that offers a broad range of training centered on professional skills, desktop applications, and technical knowledge. Additionally, all of the Company's employees participate in required compliance training and a certain population of the Company's employees participate in operational and important safety trainings geared towards their individual roles within the organization. For 2020, the Company's employees completed an aggregate of more than 8,330 hours of training covering the aforementioned topics.
Additional Information. The Company publishes an annual Corporate Sustainability Report (CSR), which contains the most recent available data on a variety of topics, including those discussed above under the heading “Human Capital Management.” Copies of the 2020 CSR are available free of charge on the Company’s website (www.equitransmidstream.com), by selecting the “Sustainability” tab on the main page and then the “Sustainability Reporting” link. Information included in the CSR is not incorporated into this Annual Report on Form 10-K.
Availability of Reports
The Company makes certain filings with the SEC, including its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments and exhibits to those reports, available free of charge through its website, www.equitransmidstream.com, as soon as reasonably practicable after they are filed with or furnished to the SEC. Reports filed with, or furnished to, the SEC are also available on the SEC's website at www.sec.gov.
Item 1A.    Risk Factors
In addition to the other information contained in this Annual Report on Form 10-K, the following risk factors (and related summary) should be considered in evaluating our business and future prospects. The following discussion of risk factors, including the summary, contains forward-looking statements. The summary below is not exhaustive and is qualified by reference to the full set of risk factors set forth in this section.
The risk factors may be important for understanding any statement in this Annual Report on Form 10-K or elsewhere. The following information, including the full set of risk factors set forth in this section, should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and accompanying notes included in “Item 8. Financial Statements and Supplementary Data.” Note that additional risks not presently known to us or that are currently considered immaterial may also have a negative impact on our business and operations. If any of the events or circumstances described below actually occurs, our business, financial condition, results of operations, liquidity or ability to pay dividends could suffer and the trading price of our common stock could decline.
Because of the following factors, as well as other variables affecting our results of operations, past performance may not be a reliable indicator of future performance, and historical trends should not be used to anticipate results or trends in future periods.


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Summary of Risk Factors
Risks Related to Our Operations
We depend on EQT for a substantial majority of our revenues and future growth and therefore are subject to the business and liquidity risks of EQT, and any further decrease in EQT’s drilling or completion activity could adversely affect us.
Decreases in production of natural gas in our areas of operation, and the lack of diversification of our assets and geographic locations, could further adversely affect us.
The challenging regulatory approval process for the construction of new midstream assets could impact our or the MVP Joint Venture’s ability to obtain or maintain all approvals necessary to complete certain projects on time or at all or our ability to achieve the expected investment returns on the project. If we do not complete expansion projects, our future growth may be limited and expanding our business by constructing new midstream assets subjects us to risk.
Reviews of our goodwill and intangible and other long-lived assets have resulted in and could result in significant impairment charges, including with respect to our investment in the MVP Joint Venture.
Our subsidiaries’ significant indebtedness, and any future indebtedness, as well as the restrictions under our subsidiaries’ debt agreements, could adversely affect us.
Increased competition from other companies that provide gathering, transmission and storage, and water services, or from alternative fuel sources, could have a negative impact on customer throughput and the demand for our services and could limit our ability to grow.
We are exposed to the credit risk of our counterparties in the ordinary course of our business.
We may not be able to realize the expected investment return under certain of our existing contracts, or renew or replace expiring contracts at favorable rates, on a long-term basis or at all.
Our Hammerhead gathering agreement and pipeline are the subject of a dispute with EQT and we may be affected adversely by this dispute.
The outbreak of COVID-19 (or any future pandemic), and related declines in economic output and demand for natural gas, could harm our business and adversely affect us.
The demand for the services provided by our water services business could decline, including because of competition.
Third-party pipelines and other facilities interconnected to our pipelines and facilities may become unavailable to transport or process natural gas.
Joint ventures that we have entered into (or may in the future enter into) might restrict our operational and corporate flexibility and divert our management’s time and our resources and it may be difficult or impossible for us to cause these joint ventures to take actions that we believe would be in our or the joint venture’s best interests.
Acquisitions that we may make could reduce, rather than increase, our results of operations and liquidity, and adversely affect our ability to pay dividends to our shareholders.
We may be unable to obtain financing on satisfactory terms and any financing transactions may increase our financial leverage or cause dilution to our shareholders. A further downgrade of EQM’s credit ratings, including in connection with the MVP project or customer credit ratings changes, including EQT’s, could impact our liquidity, access to capital, and costs of doing business.
We face and will continue to face opposition and negative public perception to the development of our expansion projects and the operation of our pipelines and facilities from various groups.
We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.
Terrorist or cyber security attacks or threats thereof aimed at our pipelines or facilities or surrounding areas and new laws and regulations governing data privacy could adversely affect us.
Events caused by climate change could affect our operations.

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Significant portions of our pipeline systems have been in service for several decades. We do not own all of the land on which our assets are located, which could disrupt our operations and future development.
Our exposure to direct commodity price risk may increase in the future.
The loss or disengagement of key personnel could adversely affect our ability to execute our plans.
Changes in the method of determining the London Interbank Offered Rate (LIBOR), or the replacement of the LIBOR with an alternative reference rate, may adversely affect interest related to our outstanding debt.
Legal and Regulatory Risk
Our natural gas gathering, transmission and storage services are subject to extensive regulation. Changes in or additional regulatory measures, and related litigation, could have a material adverse effect on us.
We may incur significant costs and liabilities as a result of adverse events and increased maintenance or repair expenses and downtime or as a result of increasingly stringent pipeline safety regulation.
Risks Related to an Investment in Us
We face certain risks related to the tax treatment of EQM and any potential audit adjustment to EQM’s income tax returns for tax years beginning after 2017.
Our stock price may fluctuate significantly and your percentage of ownership in us may be diluted in the future.
We cannot guarantee the timing, amount or payment of dividends on our common stock.
Anti-takeover provisions contained in our governing documents and Pennsylvania law could impair an attempt to acquire us and our exclusive forum provision in our governing documents could discourage lawsuits against us and our directors and officers.
We may experience difficulties with implementation and operation of our new enterprise resource planning software solution.
Equitrans Midstream Preferred Shares issued as part of the EQM Merger and the related Restructuring present a number of risks to current and future holders of our common stock.
Risks Related to the Separation
We continue to face risks related to the Separation including, among others, those related to U.S. federal income taxes, contingent liabilities allocated to us following the Separation, EQT's obligations under certain Separation-related agreements, potential conflicts arising from certain members of management and directors holding stock in both EQT and us, and potential indemnification liabilities.


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Risk Factors
Risks Related to Our Operations
We depend on EQT for a substantial majority of our revenues and future growth. Therefore, we are subject to the business and liquidity risks of EQT, and any further decrease in EQT’s drilling or completion activity (or significant production curtailments) could adversely affect our business and operating results.
Historically, we have provided EQT a substantial percentage of its natural gas gathering, transmission and storage and water services. EQT accounted for approximately 64% of our revenues for the year ended December 31, 2020. We expect to derive a substantial majority of our revenues from EQT for the foreseeable future, including as a result of the EQT Global GGA.
Given the scope of our business relationship with EQT, any event, whether in our areas of operations or otherwise, that adversely affects EQT’s production, financial condition, leverage, results of operations or cash flows may adversely affect us. Accordingly, we are subject to the business risks of EQT, including the following:
prevailing and projected natural gas, natural gas liquids (NGLs) and oil prices and the effect thereon of the significant reduction in the number of operating drilling rigs in the United States in 2020 as a result of the COVID-19 pandemic’s impact on already declining gas demand, that reduced or curtailed production of associated natural gas from oil wells in other formations such as the Permian Basin;
natural gas price volatility or a sustained period of lower commodity prices, which may have an adverse effect on EQT’s drilling operations, revenue, profitability, future rate of growth, creditworthiness and liquidity;
decisions of EQT’s management in respect of curtailing (or subsequently bringing back online) natural gas production, choke management, timing of turning wells in line, and rig and completion activity;
a further reduction in or slowing of EQT’s anticipated drilling and production schedule, which would directly and adversely impact demand for our services;
the proximity, capacity, cost and availability of gathering and transportation facilities, and other factors that result in differentials to benchmark prices;
the availability and cost of capital on a satisfactory economic basis to fund EQT’s operations and refinance existing indebtedness as it becomes due, any changes in EQT’s credit ratings and the effects of EQT’s credit support obligations on such availability;
the costs of producing natural gas and the availability and costs of drilling rigs and crews and other equipment;
infrastructure capacity constraints and interruptions;
geologic considerations;
risks associated with the operation of EQT’s wells and facilities, including potential environmental liabilities;
EQT’s ability to identify exploration, development and production opportunities based on market conditions;
uncertainties inherent in projecting future rates of production, levels of reserves, and demand for natural gas, NGLs and oil;
EQT’s ability to develop additional reserves that are economically recoverable, to optimize existing well production and to sustain production, including by use of large-scale, sequential, highly choreographed drilling and hydraulic fracturing, including combo and return-to-pad development;
EQT’s ability or intention to develop additional reserves not covered by our assets or obligations to build;
EQT’s ability to achieve anticipated efficiencies associated with its strategic plan, execute on strategic transactions, if any, and continue to execute on its de-levering plan;
adverse effects of governmental and environmental regulation, including the availability of drilling permits, the regulation of hydraulic fracturing (including limitations in respect of engaging in hydraulic fracturing in specific areas), the potential removal of certain federal income tax deductions with respect to natural gas and oil exploration and development or additional state taxes on natural gas extraction, changes in tax laws and negative public perception regarding EQT’s operations;

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availability of water sources relative to EQT's operating areas;
the loss of key personnel and/or the effectiveness of their replacements; and
risk associated with cyber security, environmental activists and other threats.
On February 17, 2021, EQT announced a projected 2021 capital expenditure forecast of $1.10 billion to $1.20 billion compared to 2020 actual capital expenditures of $1.08 billion. EQT may reduce its capital spending in the future based on commodity prices or other factors. Unless we are successful in attracting significant new customers, our ability to maintain or increase the capacity subscribed and volumes transported or gathered under service arrangements on our gathering, transmission and storage and water systems will depend on receiving consistent or increasing commitments from EQT. While EQT has dedicated a significant amount of its acreage to us, and executed long-term contracts with substantial firm reservation and MVCs on our systems, it may determine in the future that drilling in areas outside of our current areas of operations is strategically more attractive to it, and other than the firm reservations and MVCs, it is under no contractual obligation to maintain its production dedicated to us. Moreover, EQT’s publicly-disclosed strategy continues to focus on capital efficiency, reducing indebtedness and free cash flow generation as opposed to volume growth. On February 17, 2021, EQT publicly disclosed that its development program is expected to result in approximately flat sales volumes for 2021 relative to EQT's pro-forma 2020 levels (reflecting acreage acquired by EQT from Chevron U.S.A. Inc. in 2020 (the Chevron Acquisition)). A reduction in the capacity subscribed or volumes transported or gathered on our systems by EQT (or lack of growth in respect of such volumes) could have a material adverse effect on our business, financial condition, results of operations, liquidity and our ability to pay dividends to our shareholders.
EQT may also elect to reduce its drilling activity or curtail production if commodity prices, including natural gas prices in the Appalachian Basin, do not improve to levels EQT determines to be sufficient to justify drilling and production or if such prices decrease below EQT's preferred levels. Fluctuations in energy prices can also greatly affect the development of EQT’s and other producers’ respective reserves and declining prices could have a negative impact on EQT’s and other producers’ development and production activity which could be material depending on the severity of the downturn in prices. In general terms, the prices of natural gas, oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include worldwide political and economic conditions, the length and severity of the COVID-19 outbreak and its effect on oil, NGLs and natural gas prices (and the positive impact lower oil prices have had and are expected to have on natural gas prices in the near- and medium-term, primarily as a result of corresponding declines in the production of associated gas in the United States), weather conditions and seasonal trends, the levels of domestic production and consumer demand, new exploratory finds of natural gas, the levels of imported and exported natural gas, oil and LNG, the availability of transportation systems with adequate capacity, the volatility and uncertainty of regional pricing differentials, the price and availability of (and adoption rate of) alternative fuels, the effect of energy conservation measures, the nature and extent of governmental regulation and taxation, and the anticipated future prices of natural gas, oil, LNG and other commodities. Due to these and other factors, even if reserves are known to exist in areas serviced by our assets, producers have chosen, and may choose in the future, not to develop those reserves. Sustained reductions in development or production activity in our areas of operation could lead to reduced utilization of our services, including our water services which are directly associated with producers’ well completion activities and fresh and produced water needs (which are partially driven by horizontal lateral lengths and the number of completion stages per well).
Any sustained reductions in development or production activity in our areas of operation, particularly from EQT, could adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Additionally, the execution of the EQT Global GGA was based upon assumptions, including regarding EQT’s forecasted drilling and production levels and volumes on our system, that our management believed appropriate at the time of execution. If any of the assumptions fail to be realized, or if actual results differ from these assumptions, we may not achieve anticipated benefits associated with the EQT Global GGA. Failure to achieve anticipated benefits associated with the EQT Global GGA may have a negative impact on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. Further, if EQT's volumes on our systems do not meet levels we assumed at the time of executing the EQT Global GGA and, during the period of such lower volumes, gathering fee reductions take effect following the in-service date of the MVP as required under the EQT Global GGA, our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders may be adversely affected. See “EQT Global GGA” in Note 6 to the consolidated financial statements for additional information.



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Decreases in production of natural gas in our areas of operation have adversely affected, and future decreases could further adversely affect, our business and operating results and reduce our cash available to pay cash dividends to our shareholders.
Our business is dependent on the continued availability of natural gas production and reserves in our areas of operation. A sustained low-price environment for natural gas or regulatory limitations has adversely affected and could in the future adversely affect development of additional reserves and production that is accessible by our pipeline and storage assets and fresh water sources. Production from natural gas wells naturally declines over time. The amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Additionally, producers may determine in the future that drilling activities in areas outside of our current areas of operations are strategically more attractive to them due to the price environment for natural gas, including locally, or other reasons. A further reduction, or lack of growth, in the natural gas volumes supplied by producers could result in reduced throughput on our systems and adversely impact our ability to sustain and/or grow our operations and pay dividends to our shareholders. Accordingly, maintaining or increasing the contracted capacity or the volume of natural gas gathered, transported and stored on our systems and cash flows associated therewith is substantially dependent on our customers continually accessing additional reserves of natural gas in or accessible to our current areas of operations.
The primary factors affecting our ability to obtain non-dedicated sources of natural gas include the level of successful drilling activity near our systems and our ability to compete for volumes from successful new wells, and most development areas in our areas of operation are already dedicated to us or one of our competitors. While EQT has dedicated production from a substantial portion of its leased properties to us, we have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our gathering and transmission systems or the rate at which production from a well declines. In addition, we have no control over EQT or other producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, producers’ focus on generating free cash flow and/or de-levering, prevailing and projected energy prices, hedging strategies, demand for hydrocarbons, levels of reserves, the producers’ contractual obligations to us and other midstream companies, geological considerations, environmental or other governmental regulations, the availability of drilling permits, the availability of drilling rigs and crews, and other production and development costs.
Fluctuations in energy prices can also greatly affect the development of new natural gas reserves. In general terms, the prices of natural gas, oil and other hydrocarbon products fluctuate in response to certain factors such as those described under the heading “We depend on EQT for a substantial majority of our revenues and future growth. Therefore, we are subject to the business and liquidity risks of EQT, and any further decrease in EQT’s drilling or completion activity (or significant production curtailments) could adversely affect our business and operating results.” Henry Hub spot and local spot natural gas prices, which were under pressure prior to the COVID-19 outbreak due primarily to a warmer than normal 2019 - 2020 winter heating season, a temperate spring 2020 season and an oversupply of natural gas (caused in part by the significant increase in production of associated gas from the Permian Basin and similar basins in recent years), were further pressured by a reduction in global demand for natural gas during 2020 (for which the COVID-19 outbreak was a contributing factor), lack of available natural gas storage and the continued significant supplies of natural gas produced, particularly from the Appalachian Basin. The Henry Hub natural gas price ranged from $1.33 per MMbtu to $3.03 per MMbtu between January 1, 2020 and December 31, 2020, with some prices reflecting the lowest natural gas prices in more than 20 years. Further, market prices for natural gas in the Appalachian Basin continue to be lower than Henry Hub natural gas prices and were significantly lower during portions of 2020. Natural gas prices have improved since the spring of 2020 and are expected to further improve during 2021, as reflected by the natural gas forward price strip as of February 19, 2021, primarily due to demand, such as in the winter months, for natural gas potentially exceeding available supply (as a result of, in part, the decrease in associated gas production from the Permian Basin given the dramatic decrease in oil production caused by historical low oil prices during the first half of 2020). However, the length and extent of that price recovery (if any) and its effect on the development plans of our customers, which impact both our ability to execute new commercial agreements with our customers as well as the volumetric-based fee revenues we earn under existing contracts, will be impacted by global demand for natural gas, the length and severity of the 2020-2021 winter heating season, rates of natural gas production (including amounts of associated gas from the Permian Basin, which certain analysts are projecting will increase in 2021 and later years), and the length and severity of the COVID-19 outbreak. There is no assurance that the elevated natural gas prices indicated by the forward natural gas price strip as of February 19, 2021 will be realized or be realized for any particular length of time or that producers will increase production volume as a result of any particular price level.
Low natural gas prices, particularly in the Appalachian Basin, have had a negative impact on exploration, development and production activity and on utilization of our systems and, if sustained, could lead to a material decrease in such activity and further decreases in such utilization. Because of these factors, even if new natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. Moreover, EQT and other producers may not develop the acreage they have dedicated to us. If reductions in drilling activity result in our inability to maintain levels of contracted

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capacity and throughput, there could be a material adverse effect on our business, results of operations, financial condition, liquidity and ability to pay dividends to our shareholders.
We do not obtain independent evaluations of natural gas reserves connected to our systems. Accordingly, we do not have independent estimates of total reserves connected to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our systems are less than we anticipate, or the timeline for the development of reserves is longer than we anticipate, and we are unable to secure additional sources of natural gas, there could be a material adverse effect on our business, results of operations, financial condition, liquidity and ability to pay dividends to our shareholders.
If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply basins in our areas of operation, or if natural gas supplies are diverted to serve other markets, the overall volume of natural gas gathered, transported and stored on our systems would decline, which could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
The regulatory approval process for the construction of new midstream assets is very challenging, and decisions by regulatory and judicial authorities in pending or potential proceedings could impact our or the MVP Joint Venture’s ability to obtain or maintain in effect all approvals and authorizations necessary to complete certain projects on the targeted time frame or at all or our ability to achieve the expected investment returns on the projects.
Certain of our internal growth projects require regulatory approval from federal, state and/or local authorities prior to and/or in the course of construction, including any extensions from, expansions of or additions to our and the MVP Joint Venture’s transmission and storage systems. The approval process for certain projects has become increasingly slower and more difficult, due in part to state and local concerns related to exploration and production, transmission and gathering activities in production areas, including the Marcellus and Utica Shales, and the increasingly negative public perception regarding the oil and gas industry, including major pipeline projects like the MVP and MVP Southgate. Further, regulatory approvals and authorizations, even when obtained, have increasingly been subject to judicial challenge by pipeline opponents seeking that issued approvals and authorizations be stayed and vacated.
Accordingly, authorizations needed for our internal growth projects, including the MVP and MVP Southgate projects, may not be granted or, if granted, such authorizations may include burdensome or expensive conditions or may later be stayed or revoked or vacated.
In addition, significant delays in the regulatory approval process for growth projects, including the MVP and MVP Southgate projects, have significantly increased costs and negatively impacted the targeted in-service dates for the projects, and further delays, such as because of a stay or loss of a critical authorization, may cause similar adverse effects, including to the MVP project’s targeted full in-service date in late 2021 and the MVP Southgate project’s targeted in-service date in 2022. Significant delays and cost increases in turn could adversely affect our ability, and, in the case of the MVP and MVP Southgate projects, the ability for the MVP Joint Venture and its owners, including us, to achieve the expected investment returns and/or cause other-than-temporary declines in value associated with the projects. The MVP and MVP Southgate projects in particular are subject to several agency actions and judicial challenges (and will likely become subject to further actions and challenges) that must be resolved before the MVP and MVP Southgate projects can be completed, as described in more detail in “Item 3. Legal Proceedings” and “Outlook” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
There is no guarantee that the MVP Joint Venture will ultimately (or timely) receive authorizations or that such authorizations will be maintained in effect following challenge. Even if the MVP Joint Venture does succeed in resolving challenges or restoring or obtaining the necessary permits and other authorizations, this may not occur within the MVP Joint Venture’s targeted time frame for placing the MVP project or the MVP Southgate project in service or enable the MVP Joint Venture to meet the targeted project costs.
As the MVP project nears completion and in light of the abandonment by third parties of certain other similar pipeline projects, we have experienced and may further experience increased opposition from activists in the form of lawsuits, intervention in regulatory proceedings and otherwise, which has been and/or may be focused on the few remaining portions of the project. Such focused opposition may make it increasingly difficult to complete the project and place it in service within the targeted time frame or at all and may also affect the ability to effect extensions and/or expansions of the project. We also expect that as pre-construction activity in respect of the MVP Southgate project increases (or if construction were to commence), the MVP Southgate project may be subject to similar heightened opposition. These and other challenges to our internal growth projects, particularly the MVP project, could adversely affect our business (including by increasing the possibility of investor activism), financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

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The gathering fees payable by EQT to us set forth in the EQT Global GGA are subject to potential reductions for certain contract years set forth in the EQT Global GGA, conditioned upon the in-service date of the MVP, which provide for estimated aggregate fee relief of $270 million in the first year after the in-service date of the MVP, $230 million in the second year after the in-service date of the MVP and $35 million in the third year after the in-service date of the MVP. In addition, if the MVP in-service date has not occurred by January 1, 2022, EQT has an option, exercisable for a period of twelve months, to forgo approximately $145 million of the gathering fee relief in the first year after the MVP in-service date and approximately $90 million of the gathering fee relief in the second year after the MVP in-service date in exchange for a cash payment from us to EQT in the amount of approximately $196 million. In addition, among the other benefits to us pursuant to the EQT Global GGA, EQT is subject to an initial annual MVC of 3.0 Bcf per day that gradually steps up to 4.0 Bcf per day for several years following the in-service date of the MVP. Any further delay in the MVP in-service date may prevent us from achieving a portion of the anticipated benefits associated with the execution of the EQT Global GGA. See “EQT Global GGA” in Note 6 to the consolidated financial statements for additional information.
Reviews of our goodwill, intangible and other long-lived assets have resulted in significant impairment charges, and reviews of our goodwill, intangible and other long-lived assets could result in future significant impairment charges, including with respect to our investment in the MVP Joint Venture.
GAAP requires us to perform an assessment of goodwill at the reporting unit level for impairment at least annually and whenever events or changes in circumstances indicate that the fair value of a reporting unit is more likely than not less than its carrying amount.
We may perform either a qualitative or quantitative assessment of potential impairment. Our qualitative assessment of potential impairment may result in the determination that a quantitative impairment analysis is not necessary. Under this elective process, we assess qualitative factors to determine whether the existence of events or circumstances leads us to determine that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If after assessing the totality of events or circumstances, we determine that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then performing a quantitative analysis is not required. However, if we conclude otherwise, then we perform a quantitative impairment analysis. If we choose not to perform a qualitative assessment, or if we choose to perform a qualitative assessment but are unable to qualitatively conclude that no impairment has occurred, then we will perform a quantitative assessment. In the case of a quantitative assessment, we estimate the fair value of the reporting unit with which the goodwill is associated and compare it to the carrying value. If the estimated fair value of a reporting unit is less than its carrying value, an impairment charge is recognized for the excess of the reporting unit’s carrying value over its fair value.
Assessing goodwill for potential impairment requires significant judgments and estimates by management. Fair value of the reporting unit to which goodwill is recorded is estimated using a combination of an income and market approach which, in the case of the income approach, applies significant inputs not observable in the public market (Level 3), including estimates and assumptions related to the use of an appropriate discount rate, future throughput volumes, operating costs, capital spending and changes in working capital, and, in the case of the market approach, applies metrics and multiples derived from comparable companies and reference transactions. All of our goodwill as of December 31, 2020 relates to a business that was acquired and valued by EQT’s management in the November 2017 acquisition by EQT of Rice Energy Inc. The reporting unit to which goodwill is recorded as of December 31, 2020 is the EQM Opco reporting unit (defined and discussed in Note 4 to the consolidated financial statements). See Note 4 to the consolidated financial statements for additional information on our reporting units and impairment previously recognized.
We evaluate long-lived assets and equity method investments for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable (meaning, in the case of equity method investments, that such investments have suffered other-than-temporary declines in value). With respect to property, plant and equipment and finite lived assets, asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost, commencement of operations, resolution of relevant legal and regulatory matters, and other factors. If the carrying amount exceeds the expected future undiscounted cash flows, we recognize an impairment equal to the excess of carrying value over fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to evaluations of recoverability and the recognition of additional impairments. The evaluation and measurement of impairments for equity method investments involves similar uncertainties, judgments and estimates as those applicable to other long-lived assets. If the equity method investment carrying value exceeds the fair value and it is determined that the decline in value is other-than-temporary, we will recognize an impairment equal to the excess of the carrying value over fair value. The fair value of equity method investments is generally estimated using an income approach

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under which significant judgments and assumptions include expected future cash flows, the appropriate discount rate and probability-weighted scenarios.
Estimates and assumptions used in reviews of our goodwill, intangible and other long-lived assets (including equity method investments) are inherently subjective, subject to significant business, economic, competitive, regulatory, judicial and other risks, and require complex judgments. If actual results differ from the estimates or assumptions are not realized (or if estimates or assumptions, such as of the probability of success of the projects to which an equity method investment relates, change), we may be required to recognize an impairment.
As of December 31, 2020, we had approximately $486.7 million of goodwill (all associated with the EQM Opco reporting unit) and $11.3 billion of other long-lived assets, which will be monitored for future impairment.
If the operations or projected operating results of our businesses decline, we could incur additional goodwill, property, plant and equipment and intangible asset impairment charges. Further, if we determine that the carrying value of long-lived assets is not recoverable or the value associated with our equity method investment in the MVP Joint Venture has suffered an other-than-temporary decline, we would incur additional impairment charges. Future impairment charges could be significant and could have a material adverse impact on our financial condition and results of operations for the period in which the impairment is recorded. As of the filing of this Annual Report on Form 10-K, we cannot predict the likelihood or magnitude of any future impairment. However, our closing stock price decreased by approximately 17% between January 15, 2021 and January 20, 2021. If our stock price does not recover before the end of the first quarter of 2021, such change in our market value during the first quarter may trigger a quantitative assessment for impairment for the first quarter of 2021, which may result in our realizing impairments, the magnitude of which we are unable to estimate as of the filing of this Annual Report on Form 10-K.
See Note 4 to the consolidated financial statements and “Outlook—Potential Future Impairments” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information.
Our subsidiaries’ significant indebtedness, and any future indebtedness, as well as the restrictions under our subsidiaries’ debt agreements, could adversely affect our operating flexibility, business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
The respective debt agreements of EQM and Eureka Midstream, LLC (Eureka), a wholly owned subsidiary of Eureka Midstream, contain various covenants and restrictive provisions that limit EQM’s and Eureka, as applicable, ability to, among other things:
incur or guarantee additional debt;
make distributions on or redeem or repurchase units;
incur or permit liens on assets;
enter into certain types of transactions with affiliates;
enter into burdensome agreements, subject to certain specified exceptions;
enter into certain mergers or acquisitions; and
dispose of all or substantially all of their respective assets.
See Note 11 to the consolidated financial statements for a discussion of the Amended EQM Credit Facility and the Eureka Credit Facility. The Amended EQM Credit Facility contains certain negative covenants, that, among other things, establish for EQM a maximum consolidated leverage ratio that varies over the course of the term ranging from not more than 5.75 to 1.00 to not more than 5.00 to 1.00, tested as of the end of each fiscal quarter (which in limited circumstances is increased for certain measurement periods following the consummation of certain acquisitions). EQM's consolidated leverage ratio is derived from a number of components, including the amount of projected Consolidated EBITDA (as defined in the Amended EQM Credit Facility) from certain approved projects, including the MVP project, that is available to be included in the consolidated leverage ratio calculation under the Amended EQM Credit Facility. If the targeted in-service date for the MVP project is further delayed, such delay could result in a decrease in the amount of projected Consolidated EBITDA for future quarters, which, absent other actions which may be available to the Company to reduce its then-leverage, may further limit the Company's ability to borrow under the Amended EQM Credit Facility. Under the Eureka Credit Facility, Eureka is required to maintain a consolidated leverage ratio of not more than 4.75 to 1.00 (which in limited circumstances is increased for certain measurement periods following the consummation of certain acquisitions). Additionally, as of the end of any fiscal quarter, Eureka may not permit the ratio of consolidated EBITDA (as defined in the Eureka Credit Facility) for the four fiscal quarters then ending to

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Consolidated Interest Charges (as defined in the Eureka Credit Facility) to be less than 2.50 to 1.00. EQM’s and Eureka’s ability to meet these covenants can be affected by events beyond their respective control and we cannot assure our shareholders that EQM or Eureka will continue to meet these covenants. In addition, the Amended EQM Credit Facility and the Eureka Credit Facility each contain certain events of default, including the occurrence of a change of control.
In addition to the above-described facilities, EQM has issued senior unsecured notes which remain outstanding.
The provisions of the debt agreements may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of the debt agreements could result in an event of default, which could enable creditors to, subject to the terms and conditions of the applicable agreement, declare any outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of the debt is accelerated, our assets may be insufficient to repay such debt in full, and in turn our shareholders could experience a partial or total loss of their investments. The Amended EQM Credit Facility also has a cross default provision that applies to any other indebtedness EQM may have with an aggregate principal amount in excess of $25 million.
We and our subsidiaries may in the future incur additional debt. Our and our subsidiaries’ levels of debt could have important consequences to us, including the following:
our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired, or such financing may not be available on favorable terms;
our funds available for operations, future business opportunities and dividends to our shareholders may be reduced by that portion of our cash flow required to make interest payments on our or our subsidiaries’ debt;
we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
our flexibility in responding to changing business and economic conditions may be limited.
Our ability to service our subsidiaries’ current, or our or our subsidiaries’ future, respective debts, will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our subsidiaries’ current, or our or our subsidiaries’ future, indebtedness, as applicable, or our operating results affect our ability to comply with covenants in our debt agreements, we will be forced to take actions such as reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.
Our subsidiaries’ current substantial indebtedness and the additional debt we and/or our subsidiaries will incur in the future for, among other things, working capital, capital expenditures, capital contributions to the MVP Joint Venture, acquisitions or operating activities may adversely affect our liquidity and therefore our ability to pay dividends to our shareholders.
In addition, our subsidiaries’ significant indebtedness may be viewed negatively by credit rating agencies, which could result in increased costs for us to access the capital markets. Any future additional downgrade of the debt issued by EQM could significantly increase our capital costs or adversely affect our ability to raise capital in the future.
If we do not complete expansion projects, our future growth may be limited, and we face and will continue to face opposition to the development of our expansion projects and the operation of our pipelines and facilities from various groups, which could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Our ability to grow organically depends primarily upon our ability to complete expansion projects, including, without limitation, the MVP and MVP Southgate projects (and related expansions and extensions thereof), that result in an increase in the cash we generate. We may be unable to complete successful, accretive expansion projects for many reasons, including, but not limited to, the following:
an inability to identify attractive expansion projects;
an inability to obtain and/or maintain necessary rights-of-way, real-estate rights or permits or other government approvals, including approvals by regulatory agencies;
an inability to successfully integrate the infrastructure we build with our existing systems;
an inability to obtain and/or maintain sources of fresh water;

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an inability to raise financing for expansion projects on economically acceptable terms;
incorrect assumptions about volumes, revenues, costs and in-service timing, as well as potential growth; or
an inability to secure or maintain adequate customer commitments to use the newly expanded facilities.
Additionally, we face and expect to continue to face opposition to the development of expansion projects (such as the MVP project) and operation of our pipelines and facilities from environmental groups, landowners, local and national groups opposed to the natural gas industry and/or fossil fuels, activists and other advocates. Such opposition has taken and will likely continue to take many forms, including organized protests, attempts to block, vandalize or sabotage our development or operations, intervention in regulatory or administrative proceedings involving our assets directly or indirectly, lawsuits, legislation or other actions designed to prevent, disrupt or delay the development or operation of our assets and business.
Any event that delays or interrupts the completion of expansion projects, and/or revenues generated, or expected to be generated, by our operations or that causes us to make significant expenditures not covered by insurance, could adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Expanding our business by constructing new midstream assets subjects us to risks.
Organic and greenfield growth projects are a significant component of our growth strategy. The development and construction of pipelines and storage facilities involves numerous regulatory, environmental, political and legal uncertainties that are beyond our control and require the expenditure of significant amounts of capital. The development and construction of pipeline infrastructure and storage facilities exposes us to risks such as the failure to meet customer contractual requirements, delays caused by landowners, advocacy groups or activists opposed to the natural gas industry in the form of lawsuits, intervention in regulatory proceedings, environmental hazards, vandalism, adverse weather conditions, the performance of third-party contractors, the lack of available skilled labor, equipment and materials and the inability to obtain necessary rights-of-way or approvals and permits from regulatory agencies on a timely basis or at all (and maintain such rights-of-way, approvals and permits once obtained). These types of projects may not be completed on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase for some time after completion of a particular project. For instance, we are required to pay construction costs generally as they are incurred but construction typically occurs over an extended period of time, and we will not receive revenues or material increases in revenues until the project is placed into service. Moreover, we may construct facilities to capture anticipated future growth in production and/or demand in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Increased competition from other companies that provide gathering, transmission and storage, and water services, or from alternative fuel sources, could have a negative impact on the demand for our services, which could adversely affect our financial results.
Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. Our systems compete primarily with other interstate and intrastate pipelines and storage facilities in the gathering, transmission and storage of natural gas. Some of our competitors have greater financial resources and may be better positioned to compete as the midstream industry moves towards greater consolidation; further, some of such competitors may now, or in the future, have access to greater supplies of natural gas or water than we do. Some of these competitors may expand or construct gathering systems, transmission and storage systems and water systems that would create additional competition for the services we provide to our customers. In addition, our customers may develop or acquire their own gathering, transmission or storage, or water services instead of using ours.
The policies of the FERC promoting competition in natural gas markets are having the effect of increasing the natural gas transmission and storage options for our traditional customer base. As a result, we have experienced, and in the future could experience, “turnback” of firm capacity as existing agreements expire. If we are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, we may have to bear the costs associated with the turned back capacity. Increased competition could reduce the volumes of natural gas transported or stored on our systems or, in cases where we do not have long-term firm contracts, could force us to lower our transmission or storage rates. Increased competition could also adversely affect demand for our water services.
Further, natural gas as a fuel competes with other forms of energy available to end-users, including coal, liquid fuels and, increasingly, renewable and alternative energy. Demand for renewable and alternative energy is increasing generally with changes in consumer preferences and as renewable and alternative energy becomes more cost competitive with traditional fuels and more widely available. Continued increases in the demand for renewable and alternative energy at the expense of natural

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gas (or increases in the demand for other sources of energy, particularly if prices for natural gas significantly increase relative to other forms of energy as fuel) could lead to a reduction in demand for natural gas gathering, transmission and storage, and water services.
All of these competitive pressures could make it more difficult for us to retain our existing customers and/or attract new customers and/or additional volumes from existing customers as we seek to maintain and expand our business, which could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. In addition, competition could intensify the negative impact of factors that decrease demand for natural gas in the markets served by our systems, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.
We are exposed to the credit risk of our counterparties in the ordinary course of our business.
We are exposed to the risk of loss resulting from the nonpayment and/or nonperformance of our customers, suppliers, joint venture partners and other counterparties as further described in “Credit Risk” under “Item 7A. Quantitative and Qualitative Disclosure About Market Risk.” We extend credit to our customers as a normal part of our business. While we have established credit policies, including assessing the creditworthiness of our customers as permitted by our FERC-approved natural gas tariffs, and may require appropriate terms or credit support from them based on the results of such assessments, including in the form of prepayments, letters of credit, or guaranties, we may not have adequately assessed the creditworthiness of our existing or future customers. Pursuant to the EQT Global GGA and the Credit Letter Agreement, amongst other things, (a) we agreed to relieve certain credit posting requirements for EQT, in an amount up to approximately $250 million under its commercial agreements with us, subject to EQT maintaining a minimum credit rating from two of three rating agencies of (i) Ba3 with Moody’s, (ii) BB- with S&P and (iii) BB- with Fitch. As of February 22, 2021, EQT’s public debt had sub-investment grade credit ratings of BB with a stable outlook at S&P, Ba2 with a stable outlook at Moody’s, and BB with a positive outlook at Fitch. We cannot predict the extent to which the businesses of our counterparties would be impacted if commodity prices decline, commodity prices are depressed for a sustained period of time, or other conditions in the energy industry were to further deteriorate, nor can we estimate the impact such conditions would have on the abilities of our customers to perform under their gathering, transmission and storage and water services agreements with us. The recent low commodity price environment negatively impacted natural gas producers causing some producers significant economic stress including, in certain cases, to file for bankruptcy protection or to renegotiate contracts. To the extent one or more of our counterparties, including EQT, is in financial distress or commences bankruptcy proceedings (such as the bankruptcy proceedings commenced by Gulfport on November 13, 2020), contracts with these counterparties may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code (Bankruptcy Code). On November 24, 2020, Gulfport moved to reject its gas gathering agreements with certain of our subsidiaries and made certain related court filings attempting to reject the agreements, which motions we have opposed. For the year ended December 31, 2020, Gulfport accounted for approximately 9% of the Company's operating revenues. Nonpayment and/or nonperformance by our counterparties occurring as a result of changes in the conditions in energy industry and/or any unfavorable renegotiation or rejection of contracts under the Bankruptcy Code could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
We may not be able to renew or replace expiring contracts at favorable rates, on a long-term basis or at all.
One of our exposures to market risk occurs at the time our existing contracts expire and are subject to renegotiation and renewal. Based on total projected contractual revenues, including projected contractual revenues from future capacity expected from expansion projects that are not yet fully constructed for which we have executed firm contracts, our firm gathering contracts and firm transmission and storage contracts had weighted average remaining terms of approximately 15 years and 14 years, respectively, as of December 31, 2020. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:
the level of existing and new competition to provide services to our markets;
the macroeconomic factors affecting natural gas economics for our current and potential customers;
the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;
the extent to which the customers in our markets are willing to contract on a long-term basis or require capacity on our systems; and
the effects of federal, state or local regulations on the contracting practices of our customers.

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Any failure to extend or replace a significant portion of our existing contracts or to extend or replace our more significant contracts, or extending or replacing contracts at unfavorable or lower rates or with lower or no associated firm reservation fee revenues, could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Our Hammerhead gathering agreement and pipeline are the subject of a dispute with EQT and we may be affected adversely by the pendency of such dispute and/or if the dispute is resolved in a manner adverse to us.
On September 23, 2020, EQT and certain of its affiliates instituted arbitration proceedings against us relating to the Hammerhead gathering agreement, pursuant to which we agreed to construct the Hammerhead pipeline and related facilities and gather gas for EQT. See “Hammerhead Pipeline” under “Outlook” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information. The dispute, during its pendency, could adversely affect our business and operating results, including by causing us to incur expenses in arbitration or additional proceedings in excess of those currently expected and by diverting management time and resources. Also, while the dispute is ongoing, we believe the market price of our common stock may continue to be adversely affected by the perception that the dispute is negatively affecting our overall commercial relationship with EQT. In addition, if the dispute is resolved in a manner adverse to us, such resolution could result in EQT’s acquisition of Hammerhead assets in exchange for a reimbursement payment or otherwise affect or negate our ability to recognize revenue and generate operating cash flows in the future from such assets.
The lack of diversification of our assets and geographic locations could adversely affect our ability to pay dividends to our shareholders.
We rely exclusively on revenues generated from our gathering, transmission and storage and water systems, substantially all of which are located in the Appalachian Basin in Pennsylvania, West Virginia and Ohio. Due to our lack of diversification in assets and geographic location, an adverse development in these businesses or our areas of operations, including adverse developments due to catastrophic events, pandemics, epidemics, weather, regulatory action, local prices, producer liquidity, decreases in demand for natural gas, specifically dry gas, from the Appalachian Basin or increases in supply of natural gas (such as if oil production, and consequently associated gas production, were to substantially recover) could have a more significant impact on our business, financial condition, results of operations, liquidity and our ability to pay dividends than if we maintained more diverse assets and locations.
The outbreak of COVID-19 (or any future pandemic), and related declines in economic output and demand for natural gas, could harm our business, results of operations and financial condition.
The natural gas forward price strip as of February 19, 2021 indicated higher prices relative to the lower prices during portions of 2020 resulting from the COVID-19 outbreak and related effects thereof on the natural gas market. However, a slower, shorter or limited recovery in natural gas prices, such as because of continued economic malaise due to continuing effects of COVID-19 (despite increasing availability of a vaccine), may result in further curtailments by our customers (beyond those effected in 2020) or otherwise continue to adversely impact the demand for our services.
Given the ongoing and dynamic nature of the circumstances, it is difficult to predict the further impact of the COVID-19 outbreak (or any other outbreak) on the domestic economy, the natural gas industry, or us; however, our business, results of operations and financial condition could be negatively affected in numerous ways, including, without limitation, that:
our customers and suppliers may be adversely affected due to the economic downturn and recession resulting from the outbreak and may be adversely affected if the outbreak causes further or long-duration declines in the price of, demand for and production of natural gas or prevents such customers (particularly EQT) from conducting, or curtails their ability to conduct, field operations and continue natural gas production, which could reduce demand for our services, negatively affect throughput on our systems or heighten our exposure to risk of loss resulting from the nonpayment and/or nonperformance of our customers;
our operations may be disrupted or become less efficient if a significant number of our employees or contractors are unavailable due to illness or if our field operations, including in respect of projects in development, were to be suspended or temporarily shut down or restricted due to outbreak control measures;
legal and regulatory processes relating to our projects in development, including the MVP and MVP Southgate projects, may be disrupted or slowed, such as if relevant governmental authorities suffer reduced workforce availability due to the virus; and
resultant disruption to, and instability in, financial and credit markets may adversely affect our access to capital, leverage and liquidity levels and credit ratings, as well as our counterparties’ access to capital, business continuity,

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financial stability, leverage and liquidity levels and credit ratings (which could heighten counterparty credit risk to which we are exposed in the ordinary course of our business).
Although we believe that we are following best practices under COVID-19 guidance and intend to continue to refine our practices as additional guidance is released, there is no guarantee that efforts by us or any other entity or authority to mitigate potential adverse impacts of the COVID-19 outbreak, whether on a local, state or national level, will be effective.
We also may incur additional costs to further attempt to mitigate potential impacts caused by COVID-19 related disruptions, which could adversely affect our financial condition and results of operations. Further, the COVID-19 outbreak (including federal, state and local governmental responses, broad economic impacts and market disruptions) has heightened and may further heighten many of the other risks set forth herein. The extent of the impact of COVID-19 on us will depend on future developments, which are highly uncertain and cannot be predicted, including new information which may emerge concerning the severity of COVID-19, appearance of new strains of the virus, duration of the outbreak, and related economic effects and aftereffects (including on the natural gas industry), and actions taken to contain COVID-19 or its impact, including, vaccine acceptance, distribution and effectiveness, among others.
The demand for the services provided by our water services business could decline as a result of several factors.
Our water services business includes fresh water distribution for use in our customers’ natural gas, NGL and oil exploration and production activities. Water is an essential component of natural gas, NGL and oil production during the drilling and the hydraulic fracturing process. As a result, the demand for our fresh water distribution and produced water handling services is tied to the level of drilling and completion activity of our customers, including EQT (which is currently and anticipated to continue to be our primary customer for such services). More specifically, the demand for our water distribution and produced water handling services has been and could be further adversely affected by any further reduction in or slowing of EQT’s or other customers’ well completions, any reduction in produced water attributable to completion activity, or the extent to which EQT or other customers complete wells with shorter lateral lengths, which would lessen the volume of fresh water required for completion activity, and may also be affected by other companies that provide water services. In addition, increased regulation of hydraulic fracturing could result in reductions or delays in natural gas, NGL and oil production by our water service customers, which could reduce the number of wells for which we provide water services.
The availability of our water supply may be limited due to reasons including, but not limited to, prolonged drought, difficulty obtaining permits or regulatory delays associated with infrastructure development. Restrictions on the ability to obtain water, changes in wastewater disposal requirements, or changes in the regulation of water withdrawal and use may incentivize water recycling efforts by oil and natural gas producers, which could decrease the demand for our fresh water distribution services. Customers also have, in some cases, elected and may elect to develop their own water services businesses to service their assets. For example, on February 17, 2021, EQT announced that it expects to invest $45 million to $55 million during 2021 to build a 45-mile mixed-use water system in West Virginia to service the development of portions of its West Virginia acreage.
We may not be able to increase our customer throughput and resulting revenue due to competition and other factors, which could limit our ability to grow.
Our ability to increase our customer-subscribed capacity and throughput and resulting revenue is subject to numerous factors beyond our control, including competition from third-party producers’ existing contractual obligations to competitors, the location of our assets relative to those of competitors for potential producer customers, and the extent to which we have available capacity when shippers require it. To the extent that we lack available capacity on our systems for volumes, we may not be able to compete effectively with third-party systems for additional natural gas production in our areas of operation.
Our efforts to attract new customers or larger commitments from existing customers may be adversely affected by our desire to provide services pursuant to long-term firm contracts and contracts with MVCs. Our potential customers may prefer to obtain services under other forms of contractual arrangements under which we would be required to assume direct commodity exposure.
If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport or process natural gas, our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders could be adversely affected.
We depend on third-party pipelines and other facilities that provide receipt and delivery options to and from our transmission and storage system. For example, our transmission and storage system interconnects with the following interstate pipelines: Texas Eastern, Dominion Transmission, Columbia Gas Transmission, Tennessee Gas Pipeline Company, Rockies Express Pipeline LLC, National Fuel Gas Supply Corporation and ET Rover Pipeline, LLC, as well as multiple distribution companies. Similarly, our gathering systems have multiple delivery interconnects to multiple interstate pipelines. In the event that our

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access to such systems is impaired, the amount of natural gas that our gathering systems can gather and transport would be adversely affected, which could reduce revenues from our gathering activities as well as transmission and storage activities. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. If these or any other pipeline connections or facilities were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to operate efficiently and continue shipping natural gas to end markets could be restricted. Any temporary or permanent interruption at any key pipeline interconnect or facility could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Certain of the services we provide on our transmission and storage system are subject to long-term, fixed-price “negotiated rate” contracts that are subject to limited or no adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts, we could be unable to achieve the expected investment return under such contracts, and/or our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders could be adversely affected.
It is possible that costs to perform services under “negotiated rate” contracts will exceed the negotiated rates we have agreed to provide to our customers. If this occurs, it could decrease the cash flow realized by our systems and, therefore, could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. Under FERC policy, a regulated service provider and a customer may mutually agree to a “negotiated rate,” and that contract must be filed with and accepted by the FERC. As of December 31, 2020, approximately 97% of the contracted firm transmission capacity on our system was subscribed under such “negotiated rate’’ contracts. Unless the parties to these “negotiated rate” contracts agree otherwise, the contracts generally may not be adjusted to account for increased costs that could be caused by inflation or other factors relating to the specific facilities being used to perform the services.
We have entered into joint ventures, and may in the future enter into additional or modify existing joint ventures, that might restrict our operational and corporate flexibility and divert our management’s time and our resources. In addition, it may be difficult or impossible for us to cause these joint ventures to take actions that we believe would be in our or the joint venture’s best interests and these joint ventures are subject to many of the same operational risks to which we are subject.
We have entered into joint ventures to construct the MVP and MVP Southgate projects and a joint venture relating to Eureka Midstream and may in the future enter into additional joint venture arrangements with third parties. Joint venture arrangements may restrict our operational and corporate flexibility. Joint venture arrangements and dynamics can also divert management and operating resources in a manner that is disproportionate to our ownership percentage in such ventures. Because we do not control all of the decisions of the MVP Joint Venture or the joint venture relating to Eureka Midstream, it may be difficult or impossible for us to cause these joint ventures to take actions that we believe would be in our or the joint venture’s best interests. For example, we cannot unilaterally cause the distribution of cash by the MVP Joint Venture or Eureka Midstream. Moreover, joint venture arrangements involve various risks and uncertainties, such as committing that we fund operating and/or capital expenditures, the timing and amount of which we may not control, and our joint venture partners may not act in a manner that we believe would be in our or the joint venture’s best interests or satisfy their financial obligations to the joint venture. In addition, the operations of the MVP Joint Venture, Eureka Midstream and any joint ventures we may enter into in the future are subject to many of the same operational risks to which we are subject.
Acquisitions that we may make could reduce, rather than increase, our results of operations and liquidity, and adversely affect our ability to pay dividends to our shareholders.
Any acquisition involves potential risks, including, among other things:
mistaken assumptions about volumes, revenues and costs, including synergies and potential growth;
an inability to secure adequate customer commitments to use the acquired systems or facilities;
an inability to integrate successfully the assets or businesses we acquire;
the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;
the diversion of management’s and employees’ attention from other business concerns in a manner that is disproportionate to our ownership percentage in such acquired assets or entities; and
unforeseen difficulties operating in new geographic areas, with new joint venture partners or new business lines.

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If risks such as the above are realized, or if an acquisition fails to be accretive to our cash generated from operations on a per share basis, it could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
If we or our subsidiaries are unable to obtain needed capital or financing on satisfactory terms, our ability to execute our business strategy and pay dividends to our shareholders may be diminished. Additionally, financing transactions may increase our financial leverage or could cause dilution to our shareholders.
In order to expand and maintain our asset base and complete announced expansion projects, including the MVP and MVP Southgate projects, we will need to continue to make significant capital expenditures and capital contributions. If we do not make sufficient or effective capital expenditures and capital contributions, we will be unable to expand or maintain our business operations, which impacts our ability to pay dividends to our shareholders.
In order to fund our capital expenditures and capital contributions, we may use cash from our operations, incur borrowings under our subsidiaries’ credit facilities or through debt capital market transactions, enter into our own credit arrangements or sell additional shares of our equity or a portion of our assets. Using cash from operations will reduce the cash we have available to pay dividends to our shareholders. Our and our subsidiaries’ ability to obtain bank financing or to access the capital markets for debt offerings, or our ability to access the capital markets for future equity offerings, may be limited by, among other things, our and our subsidiaries’ financial condition at the time of any such financing or offering, our and our subsidiaries’ credit ratings, as applicable, the covenants in our subsidiaries’ debt agreements, the rights and preferences governing the Equitrans Midstream Preferred Shares, general economic conditions, including related to the COVID-19 outbreak, market conditions in our industry, changes in law (including tax laws), and other contingencies and uncertainties that are beyond our control. Additionally, market forces are affecting (and are expected to continue to affect) the availability of capital to energy industry participants. For example, activists concerned about the potential effects of climate change continue to direct their attention towards, among other things, sources of funding for fossil fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investments in energy-related activities. Further, such institutions are increasingly allocating funds to those industries and companies perceived as having better growth opportunities and/or stronger ESG metrics and practices. Such market forces may adversely affect our ability to obtain financing in the future or achieve increases in our stock price.
As of February 22, 2021, EQM and EQT had sub-investment grade credit ratings at each of Moody’s, S&P and Fitch. See “A further downgrade of EQM’s credit ratings, including in connection with the MVP project or customer credit ratings changes, including EQT’s, which are determined by independent third parties, could impact our liquidity, access to capital, and costs of doing business. Global financial markets and economic conditions have been, and continue to be, volatile, especially for companies involved in the oil and gas industry. Furthermore, as a result of concerns about the stability of financial markets generally, the solvency of counterparties specifically and general market trends favoring funding non-fossil fuel industries and companies (or fossil fuel industry companies with stronger ESG metrics and practices), the cost of obtaining money from the bank markets generally has increased as many lenders and institutional investors have increased rates, enacted tighter lending standards, refused to refinance existing debt at maturity or at all or on terms similar to the borrower’s current debt, and reduced, or in some cases, ceased to provide funding to borrowers, particularly those in the fossil fuel industry. The repricing of credit risk, concern regarding funding fossil fuel companies given climate change, and the relatively weak economic conditions in the oil and gas industry, compounded by the global economic downturn caused by the COVID-19 outbreak, have made, and will likely continue to make, it difficult for some entities to obtain funding on favorable terms or at all. As a result, even if we or our subsidiaries are successful in obtaining funds for capital expenditures and capital contributions through debt or equity financings, as applicable, the terms thereof could limit our ability to pay dividends to our shareholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage thereby limiting our ability to further borrow, and issuing additional equity may result in significant common shareholder dilution and increase the aggregate amount of cash required to maintain the then-current dividend rates, which could materially decrease our ability to pay dividends at the then-current dividend rates. If funding is not available to us or our subsidiaries when needed, or is available only on unfavorable terms, we may be unable to execute our business plans, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which (or actions taken to attempt to address any such funding issue) could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
We are subject to numerous hazards and operational risks.
Our business operations are subject to the inherent hazards and risks normally incidental to the gathering, transmission and storage of natural gas and performance of water services. These operating risks include, but are not limited to:

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damage to pipelines, facilities, equipment, environmental controls and surrounding properties caused by hurricanes, earthquakes, tornadoes, abnormal amounts of rainfall, floods, fires, droughts, landslides and other natural disasters and acts of sabotage, vandalism and terrorism;
inadvertent damage from construction, vehicles, and farm and utility equipment;
uncontrolled releases of natural gas and other hydrocarbons;
uncontrolled releases of fresh or produced water;
leaks, migrations or losses of natural gas as a result of the malfunction of equipment or facilities and, with respect to storage assets, as a result of undefined boundaries, geologic anomalies, natural pressure migration and wellbore migration;
ruptures, fires and explosions;
pipeline freeze offs due to cold weather; and
other hazards that could also result in personal injury and loss of life, pollution to the environment and suspension of operations.
These risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations, regulatory investigations and penalties and substantial losses to us. The location of certain segments of our systems in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from these risks. Despite any precautions taken, an event such as those described above could cause considerable harm to people, property or the environment and could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on segments of our systems. Potential customer impacts arising from service interruptions on segments of our systems could include, but are not limited to, limitations on our ability to satisfy customer contractual requirements, obligations to provide reservation charge credits to customers in times of constrained capacity and solicitation of our existing customers by third parties for potential new projects that would compete directly with our existing services. Such circumstances could adversely impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Negative public perception regarding us, MVP, MVP Southgate, other of our expansion projects, the midstream industry, and/or the natural gas industry in general have had and could continue to have an adverse effect on our operations and business, and negative public perception may increase the likelihood of governmental initiatives aimed at the natural gas industry.
Negative public perception regarding us, the MVP, MVP Southgate, other of our expansion projects, other industry participants and their projects and actions, the midstream industry and/or the natural gas industry in general resulting from, among other things, climate change, oil spills, the explosion of natural gas transmission and gathering lines and other facilities, erosion and sedimentation issues, unpopular expansion projects, and general concerns raised by advocacy groups about hydraulic fracturing and pipeline projects (as well as specific concerns raised by such groups in respect of particular pipeline projects), has led to, and may in the future lead to, increased regulatory scrutiny, which may, in turn, lead to new local, state and federal safety and environmental laws, regulations, guidelines, enforcement interpretations and/or adverse judicial rulings or regulatory actions. See “Item 3. Legal Proceedings.” These actions have caused, and may continue to cause, operational delays or restrictions, increased construction and operating costs, penalties under construction contracts, additional regulatory burdens and increased litigation. As discussed under “The regulatory approval process for the construction of new midstream assets is very challenging, and decisions by regulatory and judicial authorities in pending or potential proceedings could impact our or the MVP Joint Venture's ability to obtain or maintain in effect all approvals and authorizations necessary to complete certain projects on the targeted time frame or at all or our ability to achieve the expected investment returns on the projects,” there are several pending challenges to certain aspects of the MVP project and the MVP Southgate project that must be resolved before the MVP project and the MVP Southgate project, as applicable, can be completed. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we and the MVP Joint Venture need to complete the expansion projects, including the MVP and MVP Southgate projects, and conduct our and its respective operations to be denied, removed, withheld, delayed, stayed or burdened by requirements that restrict our and its respective abilities to profitably conduct business or make it more difficult to obtain the real property interests needed in order to operate

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relevant assets or complete planned growth projects, which could result in revenue loss or a reduction in our and the MVP Joint Venture’s customer bases.
Additionally, there have been initiatives at the federal and state levels aimed at the natural gas industry, including those to restrict the use of hydraulic fracturing. Adoption of legislation or regulations placing restrictions on hydraulic fracturing activities or other limitations with respect to the natural gas industry could materially adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.
We are not fully insured against all risks inherent in our business, including environmental accidents that might occur as well as many cyber events. In addition, we do not maintain business interruption insurance of the types and in amounts necessary to cover all possible risks of loss, like project delays caused by pandemics, governmental action or inaction. The occurrence of any operating risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
We currently maintain excess liability insurance that covers our and our affiliates’ legal and contractual liabilities arising out of bodily injury, personal injury or property damage, including resulting loss of use, to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability but excludes: release of pollutants subsequent to their disposal; release of substances arising from the combustion of fuels that result in acidic deposition; and testing, monitoring, clean-up, containment, treatment or removal of pollutants from property owned, occupied by, rented to, used by or in the care, custody or control of us and our affiliates. We also maintain coverage for us and our affiliates for physical damage to assets and resulting business interruption, including damage caused by terrorist acts.
Most of our insurance is subject to deductibles or self-insured retentions. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations, business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. We may not be able to maintain or obtain insurance of the types and in the amounts we desire at reasonable rates, and we may elect to self-insure a portion of our asset portfolio. The insurance coverage we have obtained or may obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses. In addition, for pre-Distribution losses, we share insurance coverage with EQT, and we will remain responsible for payment of any deductible or self-insured amounts under those insurance policies. To the extent we experience a pre-Distribution loss that would be covered under EQT’s insurance policies, our ability to collect under those policies may be reduced to the extent EQT erodes the limits under those policies.
Terrorist or cyber security attacks or threats thereof aimed at our pipelines or facilities or surrounding areas and new laws and regulations governing data privacy could adversely affect us.
Our business has become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications, to operate our assets, and the maintenance of our financial and other records has long been dependent upon such technologies. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Deliberate attacks on, or unintentional events affecting, our systems or infrastructure, the systems or infrastructure of third parties or the cloud could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in delivery of natural gas and NGLs, difficulty in completing and settling transactions, challenges in maintaining our books and records, communication interruptions, environmental damage, personal injury, property damage and other operational disruptions, as well as damage to our reputation, financial condition and cash flows. Further, as cyber incidents continue to evolve, we may be required to expend additional resources beyond those currently budgeted to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. In addition, new U.S. laws and regulations governing data privacy and the unauthorized disclosure of personal information may potentially elevate our compliance costs. Any failure by us to comply with these laws and regulations, including as a result of a cyber incident, could result in significant penalties and liability to us. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur significant liabilities and penalties as a result.
Significant portions of our pipeline systems have been in service for several decades. There could be unknown events or conditions, or increased maintenance or repair expenses and downtime, associated with our pipelines that could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Significant portions of our transmission and storage system and FERC-regulated gathering system have been in service for several decades. The age and condition of these systems could result in adverse events, or increased maintenance or repair expenditures, and downtime associated with increased maintenance and repair activities, which could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of our

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systems could adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Our exposure to direct commodity price risk may increase in the future.
For the years ended December 31, 2020, 2019 and 2018, approximately 66%, 58% and 54%, respectively, of our revenues were generated from firm reservation fees. Although our goal is to execute long-term firm reservation fee and MVC contracts with new or existing customers in the future, our efforts to obtain such contractual terms may not be successful. As of December 31, 2020, most of our water service agreements are volumetric in nature and therefore are more sensitive to fluctuations in commodity prices and downturns in hydraulic fracturing by our customers in the future. In addition, we may acquire or develop additional midstream assets in the future that do not provide services primarily based on capacity reservation charges or other fixed fee arrangements and therefore have a greater exposure to fluctuations in commodity price risk than our current operations. Exposure to the volatility of natural gas prices, including regional basis differentials with regard to natural gas prices, as a result of our contracts could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Additionally, the EQT Global GGA provides for potential cash bonus payments payable by EQT to us during the period beginning on the first day of the calendar quarter in which the MVP in-service date occurs through the earlier of the twelfth calendar quarter from that point or the calendar quarter ending December 31, 2024 (the Henry Hub cash bonus payment provision). The fair value of the Henry Hub cash bonus payment provision is largely determined by estimates of the NYMEX Henry Hub natural gas forward price curve, and payments are conditioned upon the quarterly average of certain Henry Hub natural gas prices exceeding certain price thresholds. Based on the Henry Hub natural gas forward strip prices as of February 19, 2021 and the terms of the Henry Hub cash bonus payment provision, delays in the in-service date for the MVP project, including beyond the most recent targeted full in-service of late 2021, may decrease the estimated fair value of the derivative asset attributable to the Henry Hub cash bonus payment provision. Such changes in estimated fair value, if any, would be recognized in other income on our statements of consolidated comprehensive income and could have an adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations and future development.
We do not own all of the land on which our pipelines, storage systems and facilities have been constructed, and we are therefore subject to the possibility of more onerous terms, and/or increased costs or delays, to retain necessary land use if we do not have valid rights-of-way or easements, if such rights-of-way or easements lapse or terminate or if our facilities are not properly located within the boundaries of such rights-of-way or easements. Although many of these rights are perpetual in nature, we occasionally obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. If we were to be unsuccessful in negotiating or renegotiating rights-of-way or easements, we might have to institute condemnation proceedings on our FERC-regulated assets or relocate our facilities for non-regulated assets. It is possible that the U.S. Congress may amend Section 7 of the NGA to require that condemnation authority not be exercised and construction may not begin until a FERC certificate order has been reviewed on rehearing. A loss of rights-of-way or easements or a relocation could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. Additionally, even when we own an interest in the land on which our pipelines, storage systems and facilities have been constructed, agreements with correlative rights owners may require that we relocate pipelines and facilities or shut in storage systems and facilities to facilitate the development of the correlative rights owners’ estate, or pay the correlative rights owners the lost value of their estate if they are not willing to accommodate development.
A further downgrade of EQM’s credit ratings, including in connection with the MVP project or customer credit ratings changes, including EQT’s, which are determined by independent third parties, could impact our liquidity, access to capital, and costs of doing business.
As of February 22, 2021, EQM’s credit ratings were Ba3 with a negative outlook, BB- with a stable outlook and BB with a negative outlook from Moody’s, S&P and Fitch, respectively. EQM’s credit ratings have fluctuated (and may further fluctuate) depending on, among other things, EQM’s leverage, uncertainty around the full in-service date of the MVP project and EQT's credit profile.
EQM’s credit ratings are subject to further revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating. We cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a credit rating agency if, in its judgment, circumstances so warrant, including in connection with the MVP project or the creditworthiness of EQM’s customers, including EQT. Credit rating agencies perform an independent analysis when assigning credit ratings. This analysis includes a number of criteria such as business composition, market and operational risks, as well as various financial tests. Credit rating agencies

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continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are subject to revision or withdrawal at any time by the ratings agencies.
If any credit rating agency further downgrades or withdraws EQM’s ratings, including for reasons relating to the MVP project (such as future delays in the targeted full in-service date of the MVP project or increases in such project’s costs), EQM’s leverage or credit ratings of our customers (including EQT), our access to the capital markets could become more challenging, borrowing costs will likely increase, EQM may be required to provide additional credit assurances (the amount of which may be substantial), including the Cash Option Letter of Credit, in support of commercial agreements such as joint venture agreements and the potential pool of investors and funding sources may decrease.
In order to be considered investment grade, EQM must be rated Baa3 or higher by Moody’s, BBB- or higher by S&P and BBB- or higher by Fitch. EQM’s non-investment grade credit ratings have resulted in greater borrowing costs, including under the Amended EQM Credit Facility, and increased collateral requirements, including under the MVP Joint Venture’s limited liability company agreement, than if EQM’s credit ratings were investment grade.
In addition to causing, among other impacts, higher borrowing costs, any further downgrade could also require additional or more restrictive covenants on future indebtedness that impose operating and financial restrictions on our subsidiaries, certain of our subsidiaries to guarantee such debt and certain other debt, and certain of our subsidiaries to provide collateral to secure such debt.
Any increase in our financing costs or additional or more restrictive covenants resulting from a credit rating downgrade could adversely affect our ability to finance future operations. If a credit rating downgrade and/or a resultant collateral requirement were to occur at a time when we are experiencing significant working capital requirements or otherwise lack liquidity, our business, results of operations, liquidity and ability to pay dividends to our shareholders could be adversely affected.
The loss or disengagement of key personnel could adversely affect our ability to execute our strategic, operational and financial plans.
Our operations are dependent upon key management, technical and professional personnel, and one or more of these individuals could leave our employment. The unexpected loss of the services and skills of one or more of these individuals could have a detrimental effect on us. In addition, the success of our operations will depend, in part, on our ability to identify, attract, develop and retain experienced personnel. There is increased competition for experienced technical and other professionals, primarily in the corporate services functions, which could increase the costs associated with identifying, attracting and retaining such personnel. Additionally, a lack of employee engagement could lead to increased employee burnout, loss of productivity, increased propensity for errors, increased employee turnover, increased absenteeism, increased safety incidents and decreased customer satisfaction, which may in turn negatively impact our results of operations and financial condition. If we cannot identify, attract, develop, retain and engage key management, technical and professional personnel, along with other qualified employees, to support the various functions of our business, our ability to compete could be harmed.
Changes in the method of determining the London Interbank Offered Rate (LIBOR), or the replacement of the LIBOR with an alternative reference rate, may adversely affect interest expense related to outstanding debt.
Amounts drawn under our subsidiaries’ respective credit facilities may bear interest at rates based on U.S. dollar LIBOR (USD LIBOR). On July 27, 2017, the Financial Conduct Authority in the United Kingdom announced that it would phase out LIBOR as a benchmark by the end of 2021. On November 30, 2020, ICE Benchmark Administration (IBA), the administrator of LIBOR, announced plans to consult on ceasing publication of USD LIBOR on December 31, 2021 for only the one-week and two-month USD LIBOR tenors, and on June 30, 2023 for all other LIBOR currency-tenor pairs. U.S. regulators, including the U.S. Federal Reserve, published a concurrent statement supporting the IBA’s plans but also urging banks to phase out LIBOR as soon as practicable. On December 4, 2020, the IBA published its consultation on the potential cessation of LIBOR, consistent with its earlier announcement. In light of these recent announcements, the future of USD LIBOR at this time is uncertain and any changes in the methods by which USD LIBOR is determined or regulatory activity related to USD LIBOR’s phase-out could cause USD LIBOR to perform differently than in the past or cease to exist. The Amended EQM Credit Facility provides for mechanisms to amend the facility to reflect the establishment of an alternative rate of interest upon the occurrence of certain events related to the phase-out of LIBOR, while the Eureka Credit Facility requires USD LIBOR based loans to be converted to base rate borrowings.
In June 2017, the Federal Reserve Bank of New York’s Alternative Reference Rates Committee announced the Secured Overnight Financing Rate (SOFR) as its recommended alternative to USD LIBOR. However, the composition and characteristics of SOFR are not the same as those of USD LIBOR, and there can be no assurance that SOFR will perform in the same way as LIBOR would have at any time.

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We have not yet pursued any technical amendments or other contractual alternatives to address this matter. We are evaluating the potential impact of the cessation of USD LIBOR; however, we are not able to predict whether USD LIBOR will cease to be available or cease to be used, when such cessation may occur, whether SOFR or any other rate will become a widely accepted replacement for LIBOR, or the terms on which we may be able to renegotiate our credit facilities and the eventual impact of such developments on our interest expense. In addition, the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. Uncertainty as to the nature of such potential phase-out and alternative reference rates or disruption in the financial markets could have a material adverse impact on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Legal and Regulatory Risk
Our natural gas gathering, transmission and storage services are subject to extensive regulation by federal, state and local regulatory authorities. Changes in or additional regulatory measures adopted by such authorities could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends.
Our interstate natural gas transmission and storage operations are regulated by the FERC under the NGA and the NGPA and the regulations, rules and policies promulgated under those and other statutes. Certain portions of our gathering operations are also currently regulated by the FERC in connection with our interstate transmission operations. Our FERC-regulated operations are pursuant to tariffs approved by the FERC that establish rates (other than market-based rate authority), cost recovery mechanisms and terms and conditions of service to our customers. The FERC’s authority extends to a variety of matters relevant to our operations. For additional information, see “Regulatory Environment—FERC Regulation” and “Regulatory Environment—FERC Regulation of Gathering Rates and Terms of Service” under “Item 1. Business.”
Pursuant to the NGA, existing interstate transmission and storage rates, terms and conditions of service, and contracts may be challenged by complaint and are subject to prospective change by the FERC. Additionally, rate increases, changes to terms and conditions of service and contracts proposed by a regulated interstate pipeline may be protested and such actions can be delayed and may ultimately be rejected by the FERC. We currently hold authority from the FERC to charge and collect (i) “recourse rates,” which are the maximum rates an interstate pipeline may charge for its services under its tariff, (ii) “discount rates,” which are rates below the “recourse rates” and above a minimum level, (iii) “negotiated rates,” which involve rates above or below the “recourse rates,” provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement, and (iv) market-based rates for some of our storage services from which we derive a small portion of our revenues. As of December 31, 2020, approximately 97% of our contracted firm transmission capacity was subscribed by customers under negotiated rate agreements under our tariff, rather than recourse, discount or market-based rate contracts. There can be no guarantee that we will be allowed to continue to operate under such rate structures for the remainder of those assets’ operating lives. Customers, the FERC or other interested stakeholders, such as state regulatory agencies, may challenge our rates offered to customers or the terms and conditions of service included in our tariffs. We do not have an agreement in place that would prohibit customers, including EQT or its affiliates, from challenging our tariffs. Any successful challenge against rates charged for our transmission and storage services could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Any changes to the FERC’s policies regarding the natural gas industry may have an impact on us, including the FERC’s approach to pro-competitive policies as it considers matters such as interstate pipeline rates and rules and policies that may affect rights of access to natural gas transmission capacity and transmission and storage facilities. The change in party control at FERC and in Congress in 2021 may lead to changes in the NGA or FERC regulations or policies that may impact our operations and affect our ability to construct new facilities.
A significant construction project generally requires review by multiple governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any agency’s delay in the issuance of, or refusal to issue, authorizations or permits for one or more of these projects may mean that we will not be able to pursue these projects or that they will be constructed in a manner or with capital requirements that we did not anticipate. Such delays, refusals or resulting modifications to projects could materially and negatively impact the revenues and costs expected from these projects or cause us to abandon planned projects.
Failure to comply with applicable provisions of the NGA, the NGPA, federal pipeline safety laws and certain other laws, as well as with the regulations, rules, orders, restrictions and conditions associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties. For example, the FERC is authorized to impose civil penalties of up to approximately $1 million (adjusted periodically for inflation) per violation, per day for violations of the NGA, the NGPA or the rules, regulations, restrictions, conditions and orders promulgated under those statutes.

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In addition, future federal, state or local legislation or regulations under which we will operate our natural gas gathering, transmission and storage businesses may have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
We are subject to stringent environmental laws and regulations, including in respect of climate change, that may expose us to significant costs and liabilities, and events caused by climate change could affect our operations.
Our operations are regulated extensively at the federal, state and local levels. Laws, regulations and other legal requirements have increased the cost to plan, design, install, operate and abandon gathering, transmission and water systems and pipelines, as well as storage systems. Legal requirements relating to the environment, health and safety govern discharges of substances into the air, water and ground; the management and disposal of hazardous substances and wastes; the clean-up of contaminated sites; groundwater quality and availability; plant and wildlife protection; locations available for pipeline construction; environmental impact studies and assessments in connection with permitting; restoration of properties after construction or operations are completed; pipeline safety (including replacement requirements); and work practices related to employee health and safety. Compliance with the laws, regulations and other legal requirements applicable to our business, including delays in obtaining (or challenges maintaining) permits or other government approvals, may increase our cost of doing business, result in delays or restrictions in the performance of operations due to the need to pursue alternative construction methods or obtain additional or more detailed permits or other governmental approvals or even cause us to abandon an existing project or not to pursue a new project. For example, the FWS continues to receive hundreds of petitions to consider listing of additional species as endangered or threatened and is being regularly sued or threatened with lawsuits to address these petitions. Some of these legal actions have resulted in, and may in the future result in, listing of species located in areas in which we operate. Such designations of previously unprotected species as being endangered or threatened, or the designation of previously unprotected areas as a critical habitat for such species, can result in increased costs, construction delays, restrictions in our operations or abandonment of projects. Listing of aquatic species could potentially affect water supplies or delay related infrastructure development. As discussed under “The regulatory approval process for the construction of new midstream assets is very challenging, and decisions by regulatory and judicial authorities in pending or potential proceedings could impact our or the MVP Joint Venture's ability to obtain or maintain in effect all approvals and authorizations necessary to complete certain projects on the targeted time frame or at all or our ability to achieve the expected investment returns on the projects,” there are several pending challenges to certain aspects of the MVP project and the MVP Southgate project that must be resolved before the MVP project and the MVP Southgate project, as applicable, can be completed, including those litigation and regulatory-related delays discussed in “Item 3. Legal Proceedings.” In addition, lack of compliance with laws, regulations or other legal requirements could subject us to claims for personal injuries, property damage and other damages. Our failure to comply with the laws, regulations and other legal requirements applicable to our business, even if as a result of factors beyond our control, could result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties and damages.
The EPA regulates GHG emissions from new and modified facilities that are potential major sources of criteria pollutants under the Clean Air Act’s Prevention of Significant Deterioration and Title V programs and has adopted regulations that require, among other things, preconstruction and operating permits for certain large stationary sources and the monitoring and reporting of GHGs from certain onshore oil and natural gas production sources on an annual basis. Laws, regulations and other legal requirements are constantly changing, and implementation of compliant processes in response to such changes could be costly and time consuming. For additional information on laws, regulations and other legal requirements applicable to us, see “Regulatory Environment—Environmental Matters” under “Item 1. Business.” Compliance with these or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business. In addition to periodic changes to air, water and waste laws, as well as anticipated EPA initiatives to impose climate change-based air regulations on industry, which we expect to increase under the Biden Administration, the U.S. Congress and various states have been evaluating and/or implemented climate-related legislation and other regulatory initiatives that would further restrict emissions of GHGs, including methane (a primary component of natural gas) and carbon dioxide (a byproduct of burning natural gas). Several states are also pursuing similar measures to regulate emissions of GHGs from new and existing sources. Many states and regions have adopted GHG initiatives and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities. For example, ten northeastern states and Virginia participate in the Regional Greenhouse Gas Initiative agreement (RGGI) aimed at reducing carbon dioxide emissions from power plants. RGGI imposes a cap on emissions of carbon dioxide on all fossil-fuel fired electric generating facilities that are 25 MW or larger and allows for trades of carbon dioxide emissions in the participating states. Pennsylvania has taken steps to join RGGI. It is likely that these regional efforts will continue. If implemented, GHG restrictions may result in additional compliance obligations with respect to, or taxes on the release, capture and use of, GHGs that could have an adverse effect on our business, financial condition, results of operations, liquidity or ability to pay dividends to our shareholders. Further, initiatives such as RGGI may adversely affect demand for natural gas and accordingly our producer customers, which could

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have an adverse effect on our business, financial condition, results of operations, liquidity or ability to pay dividends to our shareholders.
There is a risk that we may incur costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of wastes and potential emissions and discharges related to our operations. Private parties, including the owners of the properties through which our gathering system or our transmission and storage system pass and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to require remediation of contamination or enforce compliance with environmental requirements as well as to seek damages for personal injury or property damage. In addition, changes in environmental law that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our business, financial condition, results of operations, liquidity or ability to pay dividends to our shareholders. We may not be able to recover all or any of these costs from insurance.
Furthermore, climate change is expected to result in storms, floods and other climatic events of increasing severity and/or frequency which may, depending on the location and severity of such events, have a material adverse effect on our business, financial condition, results of operations, liquidity or ability to pay dividends to our shareholders.
We may incur significant costs and liabilities as a result of increasingly stringent pipeline safety regulation, including pipeline integrity management program testing and related repairs.
The DOT, acting through PHMSA, has adopted regulations requiring pipeline operators to develop integrity management programs for transmission pipelines located where a leak or rupture could harm high population areas, unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area. The regulations require operators, including us, to:
perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could impact a high population area;
maintain processes for data collection, integration and analysis;
repair and remediate pipelines as necessary; and
implement preventive and mitigating actions.
Changes to pipeline safety laws and regulations that result in more stringent or costly safety standards could have a material adverse effect on us. For more information on the laws, regulations and risks applicable to us, see “Regulatory Environment—Pipeline Safety and Maintenance” under “Item 1. Business.”
The adoption of legislation relating to hydraulic fracturing and the enactment of new or increased severance taxes and impact fees on natural gas production could cause our current and potential customers to reduce the number of wells they drill in the Marcellus and Utica Shales or curtail production of existing wells. If reductions are significant for those or other reasons, the reductions would have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Our assets are primarily located in the Marcellus Shale fairway in southwestern Pennsylvania and northern West Virginia and the Utica Shale fairway in southeastern Ohio, and a substantial majority of the production that we receive from customers is produced from wells completed using hydraulic fracturing. Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells, particularly in unconventional resource plays like the Marcellus and Utica Shales. Hydraulic fracturing is typically regulated by state oil and gas commissions and similar agencies, but several federal agencies have asserted regulatory authority over aspects of the process, including the EPA, which finalized effluent limit guidelines allowing zero discharge of waste water from shale gas extraction operations to a publicly owned treatment plant in 2016 in addition to existing limits on direct discharges. Additionally, in response to increased public concern regarding the alleged potential impacts of hydraulic fracturing, the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels.
The U.S. Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing, while a growing number of states, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. Some states, such as Pennsylvania, have imposed fees on the drilling of new unconventional oil and gas wells. Some states have elected, and other states could elect, to prohibit hydraulic fracturing altogether. Also, certain

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local governments have adopted, and others may adopt, ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Further, several federal governmental agencies are conducting reviews and studies on the environmental aspects of hydraulic fracturing, including the EPA. For example, in December 2016, the EPA issued its final report on a study it had conducted over several years regarding the effects of hydraulic fracturing on drinking water sources. The final report, contrary to several previously published draft reports issued by the EPA, found instances in which impacts to drinking water may occur. However, the report also noted significant data gaps that prevented the EPA from determining the extent or severity of these impacts. The results of such reviews or studies could spur initiatives to further regulate hydraulic fracturing.
State and federal regulatory agencies recently have focused on a possible connection between hydraulic fracturing-related activities and the increased occurrence of seismic activity (induced seismicity). In a few instances, operators of injection disposal wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado, Ohio, Oklahoma and Texas, have modified their regulations to account for induced seismicity. While Pennsylvania is not one of the states where such regulation has been enacted, regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. These developments could result in additional regulation and restrictions on the use of injection disposal wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on our customers.
The adoption of new laws, regulations or ordinances at the federal, state or local levels imposing more stringent restrictions on hydraulic fracturing could make it more difficult for our customers to complete natural gas wells, increase customers’ costs of compliance and doing business, and otherwise adversely affect the hydraulic fracturing services they perform, which could negatively impact demand for our gathering, transmission and storage, or water services.
Furthermore, the tax laws, rules and regulations that affect our customers are subject to change. For example, Pennsylvania’s governor has previously proposed legislation to impose a state severance tax on the extraction of natural resources, including natural gas produced from the Marcellus and Utica Shale formations, either in replacement of or in addition to the existing state impact fee. Pennsylvania’s legislature has not thus far advanced any of the governor’s severance tax proposals; however, severance tax legislation may continue to be proposed in future legislative sessions. Any such tax increase or change could adversely impact the earnings, cash flows and financial position of our customers and cause them to reduce their drilling in the areas in which we operate, which could negatively impact demand on our gathering, transmission and storage, and water services.
Risks Related to an Investment in Us
For taxable years prior to January 1, 2021, the tax treatment of EQM depended on its status as a partnership for U.S. federal income tax purposes, as well as it not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat EQM as a corporation or if EQM becomes subject to additional amounts of entity-level taxation for state or foreign tax purposes for any open taxable year prior to January 1, 2021, it would reduce the amount of cash we have available to pay dividends to our shareholders.
Prior to the EQM Merger, EQM was a publicly traded partnership and the anticipated after-tax economic benefit of an investment in our shares depended largely on EQM being treated as a partnership for federal income tax purposes, which requires that 90% or more of EQM’s gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Code. As a result of the EQM Merger, the requirements under Section 7704 of the Code are no longer applicable to EQM for taxable years beginning after December 31, 2020.
Despite the fact that EQM is a limited partnership under Delaware law and has not elected to be treated as a corporation for federal income tax purposes, it is possible, under certain circumstances, that the IRS could determine on audit for taxable years prior to January 1, 2021 for EQM to be treated as a corporation for federal income tax purposes. For example, EQM would be treated as a corporation if the IRS determined that less than 90% of EQM’s gross income for any taxable year consisted of qualifying income within the meaning of Section 7704 of the Code.
If EQM was treated as a corporation for federal income tax purposes for any taxable year prior to January 1, 2021, EQM would pay federal income tax on its taxable income at the corporate tax rate applicable to the relevant tax year and would likely pay state income taxes at varying rates. Distributions to us after the Separation Date would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to us. Treatment of EQM as a corporation could result in a material reduction in the anticipated cash flow in the year of the payment to the IRS, potentially causing, among other things, a substantial reduction in the value of our shares.


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If the IRS makes audit adjustments to EQM’s income tax returns for tax years beginning after 2017, the IRS (and some states) may assess and collect any resulting taxes (including any applicable penalties and interest) directly from EQM, in which case we may be required, and potentially former unitholders would be required, to reimburse EQM for such payment or, if EQM is required to bear such payment, our cash available to pay dividends to our shareholders might be substantially reduced.
Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to EQM’s income tax return for tax years beginning after 2017, the IRS (and some states) may assess and collect any resulting taxes (including any applicable interest and penalties) directly from EQM. EQM will have a limited ability to shift any such tax liability to its general partner and unitholders, including us, in accordance with their interests in EQM during the year under audit, but there can be no assurance that EQM will be able to do so under all circumstances, or that EQM will be able to effect corresponding shifts in state income or similar tax liability resulting from the IRS adjustment in states in which EQM does business in the year under audit or in the adjustment year. As a result of the EQM Merger, we own all of the EQM common units. If EQM makes payments of taxes, penalties and interest resulting from audit adjustments with respect to tax periods beginning in 2017 and before 2021, we may be and potentially former unitholders may be required to reimburse it for such payment or, if EQM is required to bear such payments, our cash available to pay dividends to our shareholders might be substantially reduced.
In the event the IRS makes an audit adjustment to EQM’s income tax returns and EQM does not or cannot shift the liability to its unitholders in accordance with their interests in EQM during the year under audit, EQM will generally have the ability to request that the IRS reduce the determined underpayment by reducing the suspended passive loss carryovers of EQM’s unitholders (without any compensation from EQM to such unitholders), to the extent such underpayment is attributable to a net decrease in passive activity losses allocable to certain partners. Such reduction, if approved by the IRS, will be binding on any affected unitholders.
Our stock price may fluctuate significantly.
The market price of our common stock may further decline or fluctuate significantly due to a number of factors, some of which may be beyond our control, including:
any further delays to the MVP full in-service date or further MVP cost increases (or the market’s perception that such delays or increases will occur);
actual or anticipated fluctuations in our operating results;
additional declines, or flat or slow growth, in the production of natural gas by our customers, including EQT, in our areas of operation;
declining operating revenues derived from our core business;
any further delays in the MVP Southgate in-service date or MVP Southgate cost increases;
inability to complete growth projects;
the gain or loss of significant customers;
additions or departures of key personnel;
the operating and stock price performance of companies that investors deem comparable to us;
changes in the regulatory and legal environment under which we operate;
the rate of adoption of renewable and alternative energy as an alternative to natural gas;
the recovery to pre-2020 levels or increased growth in the production of associated natural gas in other formations such as the Permian Basin and the supply of such gas to our end-use markets;
market conditions in the oil-and-gas industry and domestic and worldwide economy as a whole;
changes in commodity prices and the effect of commodity prices on our business, including future decisions of customers in respect of curtailing (or subsequently bringing back online) natural gas production, choke management, timing of turning wells in line, rig and completion activity and related impacts on our business;
changes in recommendations by securities analysts;

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news reports relating to trends, concerns and other issues in the energy, gas and water industries;
new technology used, or services offered, by competitors;
perceptions in the marketplace regarding us, our competitors, our customers (and our relationships with our customers) and our industry, including the ongoing trend of investors allocating funds to those industries and companies perceived as having better growth opportunities and/or stronger ESG metrics and practices;
significant acquisitions or business combinations, strategic partnerships, joint ventures or other strategic transactions or capital commitments by or involving us or our competitors;
effects of any consolidation of or effected by upstream gas producers, whether in or outside of the Appalachian Basin;
failure to identify or integrate acquisitions or realize anticipated benefits from acquisitions, business combinations, strategic partnerships, joint ventures or other strategic transactions;
changes in our customers’, including EQT’s, respective credit ratings and access to capital;
defaults, if any, of our customers, including EQT;
additional investments from third parties;
our consolidated leverage level, the ability of our subsidiaries (some of which are not wholly owned) to service debt under, and comply with the covenants contained in, their respective credit agreements, and our ability to, and the pace at which we may, de-lever;
the impact on us of the COVID-19 pandemic, including, among other things, effects on demand for natural gas and our services, levels of production of associated gas from basins such as the Permian Basin, commodity prices and access to capital;
the effect and outcome of litigation and other proceedings, including regulatory proceedings;
dividend amounts, timing and rates;
effects of conversion, if at all, of the Equitrans Midstream Preferred Shares; and
issuance of additional shares of our common stock.
General market fluctuations, industry factors and general economic and political conditions and events, such as economic slowdowns or recessions, have caused and could also continue to cause our stock price to decrease regardless of operating results.
Certain of the above described factors have contributed to a general decline in our stock price from a per share closing price of $20.89 on November 13, 2018 (the initial date shares of our common stock began regular way trading on the NYSE) to $7.33 on February 22, 2021. A reduced stock price affects, among other things, our cost of capital and could affect our ability to execute on future strategic transactions, as well as increase opportunities for investor activism or unsolicited third-party activity affecting us.
Our stock price may be adversely affected by transactions in our common stock by significant shareholders, including EQT.
We expect that EQT will ultimately dispose of its ownership interest in us, representing approximately 5.8% of our outstanding common stock as of December 31, 2020, when it deems appropriate consistent with the business reasons for the retention of such common stock, but in no event later than five years after the Distribution. EQT management has indicated that EQT’s position in our common stock may be utilized to support EQT’s goal to further de-lever. There can be no assurance regarding the method by which EQT will dispose of its interest in us, as we expect EQT to seek to maximize overall value to its shareholders, or the actual timing of any such disposal.
Additionally, any disposition by EQT, or any other significant shareholder, of our common stock in the public market, or the perception that such dispositions could occur, could adversely affect prevailing market prices for our common stock.
EQT may alternatively decide for any reason not to consummate a disposition of our common stock and instead retain a significant ownership interest in us for a period of time (not exceeding five years). Any delay by EQT in completing the disposition of its ownership interest in us could have an adverse effect on the market price for our common stock, which could affect investor confidence in us.

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We cannot guarantee the timing, amount or payment of dividends on our common stock, and we may further reduce the amount of the cash dividend that we pay on our common stock or may not pay any cash dividends at all to our shareholders. Our ability to declare and pay cash dividends to our shareholders, if any, in the future will depend on various factors, many of which are beyond our control.
We are not required to declare and pay dividends to our common shareholders, and our Board may decide to reduce the amount of the cash dividend that we pay on our common stock or may decide not to declare any dividends in the future. Although we have in the past paid regular cash dividends, any payment of future dividends will be at the sole discretion of our Board and will depend upon many factors, including the financial condition, earnings, liquidity and capital requirements of our operating subsidiaries, covenants associated with certain debt obligations, legal requirements, our leverage, regulatory constraints and other factors deemed relevant by our Board. We are also not entitled to pay any dividends on any junior securities, including any shares of our common stock, prior to paying the quarterly dividends payable to the holders of Equitrans Midstream Preferred Shares, including any previously accrued and unpaid dividends.
Your percentage of ownership in us may be diluted in the future.
In the future we may issue common stock or other equity to raise cash for our projects, operations, acquisitions or other purposes and may also acquire interests in other companies or assets by using one or more of cash, debt and/or our equity.
Any of these events may dilute your ownership interests in us, reduce our earnings per common share and have an adverse effect on the price of our common stock. The issuance of these new shares and the sale of additional shares from time to time could have the effect of depressing the market value for our common stock. The increase in the number of shares of our common stock outstanding or the issuance of other equity of us, and any resulting dilution, may cause holders to sell shares of our common stock or may create the perception that such sales may occur, either of which may adversely affect the market for, and the market value of, our common stock.
Your percentage ownership in us may also be diluted because of equity awards that we grant to our directors, officers and employees or otherwise as a result of equity issuances for acquisitions or capital market transactions. Our Management Development and Compensation Committee and our Board have authority to grant share-based awards to our employees under our employee benefit plans. Such awards will have a dilutive effect on our earnings per common share, which could adversely affect the market price of our common stock. From time to time, we will issue share-based awards to our employees under our employee benefits plans.
In addition, our Amended and Restated Articles of Incorporation authorize us to issue, without the approval of our shareholders, one or more classes or series of preferred stock that have such designations, powers, preferences and relative, participating, optional and other special rights, including preferences over our common stock respecting dividends and distributions, as our Board generally may determine. The terms of one or more classes or series of preferred stock could dilute the voting power or reduce the value of our common stock. Similarly, the repurchase or redemption rights or liquidation preferences we could assign to holders of preferred stock could affect the residual value of our common stock.
As more fully described under “As part of the EQM Merger and the related Restructuring, we issued Equitrans Midstream Preferred Shares in exchange for a portion of the then-outstanding EQM Series A Preferred Units, which Equitrans Midstream Preferred Shares by virtue of their terms and preferences present a number of risks to current and future holders of our common stock”, at the effective time of the EQM Merger, we created and issued the Equitrans Midstream Preferred Shares in exchange for a portion of the then-outstanding EQM Series A Preferred Units. Upon the occurrence of certain events or the passage of time, the Equitrans Midstream Preferred Shares may be converted by the holder or us, as applicable, initially on a one-for-one basis in the case of certain conversions by holders, subject to certain anti-dilution adjustments and an adjustment for any dividends that have accrued but not been paid when due and partial period dividends. If we or a holder of the Equitrans Midstream Preferred Shares convert Equitrans Midstream Preferred Shares into common stock, the conversion will have a dilutive effect on our earnings per share of common stock, which could adversely affect the market price of our common stock.
Anti-takeover provisions contained in our Amended and Restated Articles of Incorporation and Second Amended and Restated Bylaws, as well as provisions of Pennsylvania law, could impair an attempt to acquire us.
Our Amended and Restated Articles of Incorporation and Second Amended and Restated Bylaws contain provisions that could have the effect of rendering more difficult or discouraging an acquisition of us deemed undesirable by our Board. These include provisions:
requiring the vote of the holders of not less than 80% of the combined voting power of the then-outstanding shares of capital stock for the approval of certain transactions;

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requiring the vote of the holders of not less than 80% of the combined voting power of the then-outstanding shares of capital stock to amend our articles of incorporation and bylaws, under certain circumstances;
authorizing blank check preferred stock, which we could issue with voting, liquidation, dividend and other rights superior to those of our common stock;
limiting the liability of, and providing indemnification to, our directors and officers;
specifying that our shareholders may take action only at a duly called annual or special meeting of shareholders and otherwise in accordance with our bylaws and prohibiting our shareholders from calling special meetings;
requiring advance notice of proposals by our shareholders for business to be conducted at shareholder meetings and for nominations of candidates for election to our Board; and
controlling the procedures for conduct of our Board and shareholder meetings and election, appointment and removal of our directors.
These provisions, alone or together, could deter or delay hostile takeovers, proxy contests and changes in control or management of us. As a Pennsylvania corporation, we are also subject to provisions of Pennsylvania law, including certain provisions of Chapter 25 of the Pennsylvania Business Corporation Law (PBCL), which, among other things, requires enhanced shareholder approval for certain transactions between us and a shareholder who is a party to the transaction or is treated differently from other shareholders and also prevents persons who become the beneficial owner of shares representing 20% or more of our voting power from engaging in certain business combinations without approval of our Board, and in some cases preventing consummation of the transaction for at least five years.
Any provision of our Amended and Restated Articles of Incorporation or Second Amended and Restated Bylaws or Pennsylvania law that has the effect of delaying or deterring a change in control of us could limit the opportunity for our shareholders to receive a premium for their shares of our common stock and also could affect the price that some investors are willing to pay for our common stock.
On May 1, 2020, our Board announced, upon recommendation from the Corporate Governance Committee, that it will propose at the 2021 annual meeting of shareholders, and recommend that the shareholders approve, amendments to our Amended and Restated Articles of Incorporation and Second Amended and Restated Bylaws to eliminate the supermajority voting requirements described above. These amendments are subject to the approval of the record holders of our common stock and Equitrans Midstream Preferred Shares at the time of our annual meeting, and as such, we cannot guarantee that our shareholders will vote to eliminate the supermajority voting requirements.
Our Second Amended and Restated Bylaws designate the state and federal courts sitting in the judicial district of the Commonwealth of Pennsylvania, County of Allegheny, as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders, which could discourage lawsuits against us and our directors and officers.
Our Second Amended and Restated Bylaws provide that, unless our Board otherwise determines, the state and federal courts sitting in the judicial district of the Commonwealth of Pennsylvania, County of Allegheny, will be the sole and exclusive forum for any derivative action or proceeding brought on behalf of us, any action asserting a claim of breach of a fiduciary duty owed by any director or officer or other employee of ours to us or our shareholders, any action asserting a claim against us or any director or officer or other employee of us arising pursuant to any provision of the PBCL or our Amended and Restated Articles of Incorporation or Second Amended and Restated Bylaws or any action asserting a claim against us or any director or officer or other employee of ours governed by the internal affairs doctrine. The choice of forum provision set forth in our Second Amended and Restated Bylaws does not apply to actions arising under the Securities Act or the Exchange Act.
When applicable, this exclusive forum provision may limit the ability of our shareholders to bring a claim in a judicial forum that such shareholders find favorable for disputes with us or our directors or officers, which may discourage such lawsuits against us and our directors and officers. Alternatively, if a court outside of Pennsylvania were to find this exclusive forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings described above, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, results of operations and financial condition.



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We may experience difficulties with implementation and operation of our new enterprise resource planning software solution.
We are in the process of implementing a new enterprise resource planning (ERP) system. We are committing significant resources to implementation activities and the system software. Our ERP system is critical to our financial reporting and ability to establish effective controls and execute critical business processes. The transition to our new ERP system may be disruptive to our business if the ERP system, which is being done in phases, does not work as planned or if we experience issues relating to the implementation. Such disruptions could impact our ability to provide important information to our management, send invoices and track payments, fulfill contractual obligations, accurately maintain books and records, provide accurate, timely and reliable reports on our financial and operating results or otherwise operate our business. In addition, we may experience periodic or prolonged disruption of our financial functions arising out of the implementation and conversion, general use of the system, other periodic upgrades or updates, or other external factors that are outside of our control. Additionally, if the system does not operate as intended, the effectiveness of our internal control over financial reporting could be adversely affected or ability to assess it adequately could be delayed. This ERP system and our other information technology systems may be vulnerable to data breaches, cyber-attacks or fraud.
As part of the EQM Merger and the related Restructuring, we issued Equitrans Midstream Preferred Shares in exchange for a portion of the then-outstanding EQM Series A Preferred Units, which Equitrans Midstream Preferred Shares by virtue of their terms and preferences present a number of risks to current and future holders of our common stock.
At the effective time of the EQM Merger, we created and issued the Equitrans Midstream Preferred Shares in exchange for a portion of the then-outstanding EQM Series A Preferred Units. The creation and issuance of the Equitrans Midstream Preferred Shares present a number of risks to current and future holders of our common stock, including a preference in favor of holders of Equitrans Midstream Preferred Shares in the payment of dividends on our common stock, the risk of dilution occurring as a result of the conversion of the Equitrans Midstream Preferred Shares into our common stock and the ability of the holders of the Equitrans Midstream Preferred Shares to vote with the holders of our common stock on most matters, as well as the risk that the holders of the Equitrans Midstream Preferred Shares will have certain other class voting rights with respect to any amendment to our organizational documents that would be adverse (other than in a de minimis manner) to any of the rights, preferences or privileges of the Equitrans Midstream Preferred Shares.
Pursuant to the terms of the Restructuring Agreement, in connection with the closing of the Restructuring, we entered into a registration rights agreement with certain holders of the Equitrans Midstream Preferred Shares pursuant to which, among other things, we gave the Investors certain rights to require us to file and maintain one or more registration statements with respect to the resale of the Equitrans Midstream Preferred Shares and the shares of our common stock that are issuable upon conversion of the Equitrans Midstream Preferred Shares, and which, upon request by certain Investors party to the Registration Rights Agreement, will require us to initiate underwritten offerings for the Equitrans Midstream Preferred Shares and the shares of our common stock that are issuable upon conversion of the Equitrans Midstream Preferred Shares and use our best efforts to cause the Equitrans Midstream Preferred Shares to be listed on the securities exchange on which the shares of our common stock are then listed. See Note 2 to the consolidated financial statements for further information on the Equitrans Midstream Preferred Shares.
Risks Related to the Separation
If the Separation and Distribution, together with certain related transactions, does not continue to qualify as a transaction that is generally tax-free for U.S. federal income tax purposes, we, EQT, and our respective shareholders could be subject to significant tax liabilities and, in certain circumstances, we could be required to indemnify EQT for material taxes and other related amounts pursuant to indemnification obligations under the tax matters agreement.
It was a condition to the Distribution that (i) a private letter ruling from the IRS regarding the qualification of the Distribution, together with certain related transactions, as a transaction that is generally tax-free for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code and certain other U.S. federal income tax matters relating to the Separation and Distribution shall not have been revoked or modified in any material respect and (ii) EQT received an opinion of counsel with respect to certain tax matters relating to the qualification of the Distribution, together with certain related transactions, as a transaction described in Sections 355 and 368(a)(1)(D) of the Code. The IRS private letter ruling is based upon and relies on, and the opinion of counsel is based upon and relies on, among other things, various facts and assumptions, as well as certain representations, statements and undertakings of EQT and us, including those relating to the past and future conduct of EQT and us. If any of these representations, statements or undertakings is, or becomes, inaccurate or incomplete, or if any representations or covenants contained in any of the Separation-related agreements and documents or in any documents relating to any IRS private letter ruling or opinion of counsel are breached, such IRS private letter ruling and/or opinion of counsel may be invalid and the conclusions reached therein could be jeopardized.

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Notwithstanding receipt of the IRS private letter ruling and opinion of counsel, the IRS could determine that the Distribution and/or certain related transactions should be treated as taxable transactions for U.S. federal income tax purposes if it determines that any of the representations, assumptions or undertakings upon which such IRS private letter ruling or the opinion of counsel was based are false or have been violated. In addition, the IRS private letter ruling does not address all of the issues that are relevant to determining whether the Distribution, together with certain related transactions, continues to qualify as a transaction that is generally tax-free for U.S. federal income tax purposes, and the opinion of counsel represented the judgment of such counsel and is not binding on the IRS or any court and the IRS or a court may disagree with the conclusions in any opinion of counsel. Accordingly, notwithstanding receipt of an IRS private letter ruling or opinion of counsel, there can be no assurance that the IRS will not assert that the Distribution and/or certain related transactions do not qualify for the intended tax treatment or that a court would not sustain such a challenge. In the event the IRS were to prevail with such challenge we, EQT, and our respective shareholders could be subject to material U.S. federal income tax liability.
Even if the Distribution otherwise qualifies as generally tax-free for U.S. federal income tax purposes under Section 355 and Section 368(a)(1)(D) of the Code, it would result in a material U.S. federal income tax liability to EQT (but not to its shareholders) under Section 355(e) of the Code if one or more persons acquire, directly or indirectly, a 50-percent or greater interest (measured by either vote or value) in EQT’s stock or in the stock of us as part of a plan or series of related transactions that includes the Distribution, and we may be required to indemnify EQT for any such liability under the tax matters agreement entered into by EQT and us in connection with the Distribution. The process for determining whether an acquisition is part of a plan under these rules is complex, inherently factual in nature and subject to a comprehensive analysis of the facts and circumstances of the particular case. Notwithstanding the IRS private letter ruling and opinion of counsel described above, a sufficient change in ownership of EQT or our common stock may occur which could result in a material tax liability to EQT.
Under the tax matters agreement that EQT entered into with us, we may be required to indemnify EQT against any additional taxes and related amounts resulting from (i) an acquisition of all or a portion of our equity securities or assets, whether by merger or otherwise (and regardless of whether we participated in or otherwise facilitated the acquisition), (ii) other actions or failures to act by us or (iii) any of our representations, covenants or undertakings contained in any of the Separation-related agreements and documents or in any documents relating to the IRS private letter ruling or the opinion of counsel being incorrect or violated. Any such indemnity obligations could be material. For a more detailed discussion, see Note 8 to the consolidated financial statements.
If the IRS were to successfully assert that the EQM Merger or Share Purchases resulted in the Distribution and/or certain related transactions being treated as taxable transactions to EQT for U.S. federal income tax purposes, we may be required to indemnify EQT for such taxes and related amounts.
Certain contingent liabilities allocated to us following the Separation may mature, resulting in material adverse impacts to our business.
There are several significant areas where the liabilities of EQT may become our obligations. For example, under the Code and the related rules and regulations, each corporation that was a member of the EQT consolidated U.S. federal income tax return group during a taxable period or portion of a taxable period ending on or before the effective date of the Distribution is jointly and severally liable for the U.S. federal income tax liability of the EQT consolidated U.S. federal income tax return group for that taxable period. Consequently, if EQT is unable to pay the consolidated U.S. federal income tax liability for a pre-Separation period, we could be required to pay the amount of such tax, which could be substantial and in excess of the amount allocated to us under the tax matters agreement. For a discussion of the tax matters agreement, see Note 8 to the consolidated financial statements. Other provisions of federal law establish similar liability for other matters, including laws governing tax-qualified pension plans, as well as other contingent liabilities.
We or EQT may fail to perform under various transaction agreements that were executed as part of the Separation.
In connection with the Separation, we and EQT entered into a Separation and Distribution Agreement as well as various other agreements, including a tax matters agreement, an employee matters agreement and a shareholder and registration rights agreement with respect to EQT’s continuing ownership of our common stock. The Separation and Distribution Agreement, the tax matters agreement and the employee matters agreement determined the allocation of assets and liabilities between the companies following the Separation for those respective areas and include indemnification related to liabilities and obligations. If EQT is unable or unwilling to satisfy its obligations under these agreements, including its indemnification obligations, our business, results of operations and financial condition could be materially and adversely affected. For a description of these agreements with EQT, see Note 8 to the consolidated financial statements.


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Certain members of our management and directors may hold stock in both EQT and us, and as a result may face actual or potential conflicts of interest.
Although none of our management or directors serve at both EQT and the Company, certain of our management and directors may own both shares of common stock in EQT (EQT common stock) and our common stock. This ownership overlap could create, or appear to create, potential conflicts of interest when our management and directors and EQT management and directors face decisions that could have different implications for us and EQT. For example, potential conflicts of interest could arise in connection with the resolution of any dispute between us and EQT. For more information, see “Item 13. Certain Relationships and Related Party Transactions and Director Independence” found in our Proxy Statement.
Potential indemnification liabilities to EQT pursuant to agreements relating to the Separation and Distribution could materially and adversely affect us.
The Separation and Distribution Agreement with EQT provides for, among other things, provisions governing the relationship between us and EQT with respect to and resulting from the Separation. For a description of the Separation and Distribution Agreement, see Note 8 to the consolidated financial statements. Among other things, the Separation and Distribution Agreement provides for indemnification obligations designed to make us financially responsible for substantially all liabilities that may exist relating to our business activities, whether incurred prior to or after the Separation, as well as those obligations of EQT assumed by us pursuant to the Separation and Distribution Agreement. If we are required to indemnify EQT under the circumstances set forth in the Separation and Distribution Agreement, we may be subject to substantial liabilities. See also the discussion of potential indemnification obligations under “If the Separation and Distribution, together with certain related transactions, does not continue to qualify as a transaction that is generally tax-free for U.S. federal income tax purposes, we, EQT, and our respective shareholders could be subject to significant tax liabilities and, in certain circumstances, we could be required to indemnify EQT for material taxes and other related amounts pursuant to indemnification obligations under the tax matters agreement.
Item 1B.    Unresolved Staff Comments
None.
Item 2.        Properties
The Company leases its corporate headquarters office in Canonsburg, Pennsylvania.
The Company's real property falls into two categories: (i) parcels that it owns in fee and (ii) parcels in which its interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the Company's operations. Certain lands on which the Company's pipelines and facilities are located are owned by the Company in fee title, and the Company believes that it has satisfactory title to these lands. The remainder of the lands on which the Company's pipelines and facilities are located are held pursuant to surface leases or easements between the Company, as lessee or grantee, and the respective fee owners of the lands, as lessors or grantors. The Company has held, leased or owned many of these lands for many years without any material challenge known to the Company relating to the title to the land upon which the assets are located, and the Company believes that it has satisfactory leasehold estates, easement interests or fee ownership to such lands. The Company believes that it has satisfactory title to all of its material leases, easements, rights-of-way, permits and licenses, and the Company has no knowledge of any material challenge to its title to such assets or their underlying fee title.
As discussed under, “We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations and future development," included in "Item 1A. Risk Factors," there are, however, certain lands within the Company's storage pools as to which it may not currently have vested real property rights, some of which are subject to ongoing acquisition negotiations or inverse condemnation proceedings. In accordance with Equitrans, L.P.'s FERC certificates, the geological formations within which its permitted storage facilities are located cannot be used by third parties in any way that would detrimentally affect its storage operations, and the Company has the power of eminent domain with respect to the acquisition of necessary real property rights to use such storage facilities. Certain property owners have initiated legal proceedings against the Company and its affiliates for trespass, inverse condemnation and other claims related to these matters, and there is no assurance that other property owners will not initiate similar legal proceedings against the Company and its affiliates prior to final resolution.
See "Item 1. Business" for a discussion of the properties and their related business segments and map of the Company's operations.

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Item 3.        Legal Proceedings
In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against the Company and its subsidiaries. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company accrues legal and other direct costs related to loss contingencies when incurred. The Company establishes reserves whenever it believes it to be appropriate for pending matters. Furthermore, after consultation with counsel and considering available insurance, the Company believes that the ultimate outcome of any matter currently pending against it or any of its consolidated subsidiaries will not materially affect its business, financial condition, results of operations, liquidity or ability to pay dividends to its shareholders.
Hammerhead Pipeline Dispute
See “Hammerhead Pipeline” under “Outlook” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information.
Environmental Proceedings
Pratt Storage Field. On October 31, 2018, a gas explosion occurred in Morgan Township, Greene County, Pennsylvania (the Incident). Following the explosion, the Pennsylvania Department of Environmental Protection (the PADEP), the Pennsylvania Public Utilities Commission and the PHMSA began investigating the Incident. In January 2020, the PADEP notified the Company that it was required to submit an investigation report pursuant to the state’s gas migration regulations due to the Incident's proximity to the Company's Pratt Storage Field assets. The Company, while disputing the applicability of the regulations, submitted a report to the PADEP in March 2020. In September 2020, the PADEP responded to the Company’s investigation report with a request for additional information. The Company responded to the September 2020 request, but cannot predict whether any action will ultimately be brought by the PADEP or what the outcome of such an action would be. If a penalty is imposed, it could result in monetary sanctions in excess of $300,000. However, the Company does not believe that the penalty, if imposed, will have a material impact on the financial condition, results of operations or liquidity of the Company.
PADEP Consent Agreement I/M/O Swarts Storage Field – Stipulated Penalty Assessment. On September 2, 2020, the PADEP notified the Company that it was assessing a stipulated penalty in the amount of $490,000 due to the alleged failure of the Company to submit information required pursuant to an October 29, 2019 Consent Order and Agreement. The Company disputed the PADEP’s claim and sought initial dispute resolution proceedings based on the Company’s position that it had submitted the information multiple times since October 2019. On September 29, 2020, the PADEP notified the Company that it was no longer pursuing penalties arising from the alleged violation referenced in the September 2, 2020 letter, but it did not officially withdraw the stipulated penalty. Despite the PADEP’s notification that it was no longer pursuing the stipulated penalty, as a result of the PADEP not officially withdrawing the stipulated penalty, the PADEP could pursue the stipulated penalty in the future. If penalties are pursued and ultimately imposed, these penalties could result in monetary sanctions in excess of $300,000. However, the Company does not believe that the penalties, if imposed, would have a material impact on the financial condition, results of operations or liquidity of the Company.
PADEP Notice of Violations, Beta System. During the fourth quarter of 2020, the Company received several notices of violation (NOV) from the PADEP related to the Company’s Beta gathering system. The NOVs include (i) a lack of permanent stabilization on two repaired slip areas, (ii) five current slip areas in need of repair that have not been repaired due to the PADEP’s ongoing review of the slip repair plans, and (iii) an unpermitted disturbance that occurred during construction in 2017. The Company also voluntarily notified the PADEP of other unpermitted, disturbed areas on the Beta gathering system. The Company is continuing negotiations with the PADEP. The Company expects that this matter could result in monetary penalties in excess of $300,000, but does not believe that if imposed the penalties will have a material impact on the financial condition, results of operations or liquidity of the Company.
MVP Matters
The MVP Joint Venture is currently defending certain agency actions and judicial challenges to the MVP that must be resolved before the project can be completed, including the following:
Sierra Club, et al. v. U.S. Army Corps of Eng'rs (Huntington District) Fourth Circuit Court of Appeals (Fourth Circuit), Case No. 20-2039 and Sierra Club, et al. v. U.S. Army Corps of Eng'rs (Norfolk District), Fourth Circuit Court of Appeals, Case No. 20-2042. In February 2018, the Sierra Club filed a lawsuit in the Fourth Circuit against the Army Corps in Sierra Club, et al. v. U.S. Army Corps of Engineers, et al., consolidated under Case No. 18-1173. The lawsuit challenged the verification by the Huntington District of the Army Corps that Nationwide Permit 12, which generally authorizes discharges of dredge or fill material into waters of the United States and the construction of pipelines across such waters under Section 404 of the Clean Water Act, could be utilized in the Huntington District

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(which covers all but the northernmost area of West Virginia) for the MVP project. The crux of Sierra Club's position was that the MVP Joint Venture, pursuant to its FERC license, planned to use a certain methodology (dry open cut creek crossing methodology) to construct the pipeline across streams in West Virginia that would take considerably longer than the 72 hours allowed for such activities pursuant to the terms of West Virginia's Clean Water Act Section 401 certification for Nationwide Permit 12. A three-judge panel of the Fourth Circuit agreed with the Sierra Club and on October 2, 2018, issued a preliminary order stopping the construction in West Virginia of that portion of the pipeline that is subject to Nationwide Permit 12. In August 2018, the West Virginia Department of Environmental Protection (WVDEP) initiated an administrative process to revise its 401 Water Quality Certification for the Army Corps Nationwide Permits and requested public comment to, among other things, specifically revise the 72-hour limit for stream crossings noted as problematic by the Fourth Circuit as well as other conditions (the WVDEP 401 Rulemaking Proceedings). Pending the resolution of the West WVDEP 401 Rulemaking Proceedings, the Army Corps' Pittsburgh District and Norfolk District (each of which had also verified use of Nationwide Permit 12 by the MVP Joint Venture) suspended their verifications that allowed the MVP Joint Venture to use Nationwide Permit 12 for stream and wetlands crossings in northern West Virginia and Virginia, respectively. On April 24, 2019, the WVDEP submitted a modification to its 401 Water Quality Certification developed in the WVDEP 401 Rulemaking Proceedings to the EPA for approval, which approval was received in August 2019. The Army Corps approved the WVDEP's modification on January 24, 2020, and the MVP Joint Venture submitted a new permit application to the Army Corps on January 28, 2020. On September 25, 2020, the Huntington and Pittsburgh districts approved MVP Joint Venture’s Nationwide Permit 12 and the Norfolk district lifted its suspension of the MVP Joint Venture's Nationwide Permit 12. On September 28, 2020, Appalachian Mountain Advocates, on behalf of Sierra Club and certain other petitioners, filed a petition for review of the Huntington and Norfolk permits. On October 5, 2020, Appalachian Mountain Advocates requested from the Fourth Circuit an administrative stay of the Army Corps' verifications to the MVP Joint Venture's Nationwide Permit 12. On November 9, 2020, the Court entered an order granting the motion to stay the verifications and issued a written opinion on December 1, 2020 on the issuance of the stay. While the case was scheduled to be fully briefed and argued by March 31, 2021, on February 19, 2021, the MVP Joint Venture, as part of its initiated broader strategy to obtain authorization for stream and wetland crossings discussed above under "Developments, Market Trends and Competitive Conditions" under "Item 1. Business" requested that the Army Corps' Huntington, Pittsburgh, and Norfolk Districts administratively revoke the previously-issued Nationwide Permit 12 verifications for the project. After receiving confirmation from the Army Corps, the MVP Joint Venture accordingly will seek dismissal of the existing litigation challenging those verifications as moot.
Jefferson National Forest Crossing and Associated Authorizations. In a different Fourth Circuit appeal, Sierra Club, et al. v. U.S. Forest Service, et al., consolidated under Case No. 17-2399, Fourth Circuit Court of Appeals, filed in December 2017, the Sierra Club challenged a BLM decision to grant a right-of-way to the MVP Joint Venture and a USFS decision to amend its management plan to accommodate the MVP, both of which affect the MVP's approximate 3.5-mile segment in the Jefferson National Forest (JNF) in Virginia. On July 27, 2018, agreeing in part with the Sierra Club, the Fourth Circuit vacated the BLM and USFS decisions, finding fault with the BLM's analysis of the practicality of alternate routes and the USFS' analysis of erosion and sedimentation effects. The USFS published a draft Supplemental Environmental Impact Statement (SEIS) to the 2017 FERC Final Environmental Impact Statement for MVP in the Federal Register on September 25, 2020 with a public comment period that closed on November 9, 2020. On December 11, 2020, the USFS published a Final Supplemental Environmental Impact Statement that addressed the issues raised in the prior proceedings and evaluated the most recent sedimentation analysis submitted to the agency consistent with the findings presented in MVP’s Biological Opinion and Incidental Take Statement issued by the FWS on September 4, 2020. See Appalachian Voices, et al. v. U.S. Dep’t of Interior below for additional information. On January 11, 2021, the MVP Joint Venture received final approval of the Record of Decision from the USFS and the BLM on January 15, 2021 issued the required right-of-way permit for the MVP’s 3.5-mile segment in the JNF in Virginia (the JNF Right-of-Way). Sierra Club, et al. subsequently filed a petition with the Fourth Circuit to reverse the USFS approval of the Record of Decision and BLM’s grant of the JNF Right-of-Way in Sierra Club, et. V. U.S. Bureau of Land Management, Case No. 21-108, Fourth Circuit Court of Appeals.
On August 3, 2018, citing the court's vacatur and remand in Sierra Club, et al. v. U.S. Forest Service, et al., consolidated under Case No. 17-2399, the FERC issued a stop work order for the entire pipeline pending the agency actions on remand. The FERC modified its stop work order on August 29, 2018 to allow work to continue on all but approximately 25 miles of the project (the Exclusion Zone). On October 10, 2018, the Fourth Circuit granted a petition for rehearing filed by the MVP Joint Venture for the limited purpose of clarifying that the July 27, 2018 order did not vacate the portion of the BLM's Record of Decision authorizing a right-of-way and temporary use permit for the MVP to cross the Weston and Gauley Bridge Turnpike Trail in Braxton County, West Virginia. On October 15, 2018, the MVP Joint Venture filed with the FERC a request to further modify the August 3, 2018 stop work order to allow the MVP Joint Venture to complete the bore and install the pipeline under the Weston and Gauley Bridge Turnpike

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Trail. On October 24, 2018, the FERC granted the MVP Joint Venture's request to further modify the stop work order and authorize construction. Additionally, on October 9, 2020, the FERC authorized construction to resume project-wide (as it had been stopped by the FERC on October 15, 2019 in relation to a separate matter discussed below), other than with respect to the Exclusion Zone, which requires additional authorization. On December 17, 2020, the FERC again modified the stop work order and authorized construction to resume in 17 miles of the Exclusion Zone. The Company cannot guarantee whether or when the FERC will act in respect of any or all of the remaining portions of the Exclusion Zone (although the MVP Joint Venture anticipates seeking FERC authorization to lift the Exclusion Zone stop work order should water body crossing authorizations be received as discussed above under "Developments, Market Trends and Competitive Condition" under "Item 1. Business"). The FERC's October 9, 2020 and December 17, 2020 actions are the subject of challenges filed by the Sierra Club in Sierra Club, et al. v. FERC, Case No. 20-1512 (consolidated with No. 21-1040), D.C. Circuit Court of Appeals on December 22, 2020 and January 25, 2021, respectively (a stay request filed by the Sierra Club on January 29, 2021 was denied by the Court of Appeals for the D.C. Circuit (DC Circuit) on February 19, 2021). If any of the challenges to the JNF Right-of-Way or FERC's October 9, 2020 and December 17, 2020 orders are successful, it could result in the JNF Right-of-Way or the FERC's orders, as applicable, being vacated and/or additional agency proceedings (the outcome of which the Company cannot predict) and cause a delay in the targeted in-service date for the MVP project (and consequent impacts relating to such delay).
Challenges to FERC Certificate, Court of Appeals for the DC Circuit. Multiple parties have sought judicial review of the FERC's order issuing a certificate of public convenience and necessity to the MVP Joint Venture and/or the exercise by the MVP Joint Venture of eminent domain authority. On February 19, 2019, the DC Circuit issued an order rejecting multiple consolidated petitions seeking direct review of the FERC order under the Natural Gas Act and certain challenges to the exercise by the MVP Joint Venture of eminent domain authority in Appalachian Voices, et al. v. FERC, et al., consolidated under Case No. 17-1271. No petitions for rehearing or petitions for rehearing en banc were filed by the April 5, 2019 deadline. The mandate was issued on April 17, 2019. Another group of parties filed a complaint in the U.S. District Court for the District of Columbia asserting that the FERC's order issuing certificates is unlawful on constitutional and other grounds in Bold Alliance, et al. v. FERC, et al., Case No. 17-1822. The district court plaintiffs sought declaratory relief as well as an injunction preventing the MVP Joint Venture from developing its project or exercising eminent domain authority. In December 2017 and January 2018, the FERC and the MVP Joint Venture, respectively, moved to dismiss the petitions for lack of subject matter jurisdiction. The court granted the motion and dismissed plaintiffs' complaint on September 28, 2018. On October 26, 2018, plaintiffs appealed the decision in Case No. 17-1822 to the DC Circuit in Bold Alliance, et al. v. FERC, et al., Case No. 18-5322. On December 3, 2018, the FERC, as appellee, filed a joint motion with the appellants to hold Case No. 18-5322 in abeyance pending completion of the appeals of the final agency orders related to the MVP certificate in consolidated Case No. 17-1271 and Atlantic Coast Pipeline’s (ACP) certificate. The MVP Joint Venture filed a motion to dismiss the case as to some of the plaintiffs. On February 15, 2019, the DC Circuit entered an order holding this appeal in abeyance pending rulings on the appeals from the ACP and MVP FERC proceedings. Although the members of the ACP project announced the cancellation of that project on July 5, 2020, ACP's proceeding remains pending. Case No. 18-5322 remains in abeyance. Similarly, another group of parties filed a complaint in the U.S. District Court for the District of Columbia in Bohon et al. v. FERC et al., Case No. 20-00006, asserting that the delegation of authority to FERC under the NGA violates the nondelegation doctrine and separation-of-powers principle of the U.S. Constitution. The MVP Joint Venture and FERC filed motions to dismiss which were granted by the court. On July 6, 2020, the landowners filed a notice of appeal to the DC Circuit in Case No. 20-5203. On November 30, 2020, appellants filed their brief, asking the DC Circuit to overturn the decision of the lower court. Oral arguments before the DC Circuit are scheduled for March 29, 2021. Due to the uncertainty regarding the timing of permitting and the outcome of legal challenges facing the MVP project, on August 25, 2020, the MVP Joint Venture filed a request with the FERC for and, on October 9, 2020, the FERC granted, an extension of time to complete the MVP project for an additional two years through October 13, 2022. On December 22, 2020, a challenge to the FERC’s action to grant an extension of time to complete the MVP project was filed in the DC Circuit in Sierra Club, et al. v. FERC, Case No. 20-1512 (consolidated with No. 21-1040, DC Circuit). On January 29, 2021, Sierra Club requested a stay of the FERC’s action to grant the MVP Joint Venture an extension of time to complete the MVP project from the DC Circuit, which stay request was denied by the DC Circuit on February 19, 2021. If any of these challenges were successful, it could result in the MVP Joint Venture's certificate of public convenience and necessity being vacated and/or additional proceedings before the FERC, the outcome of which the Company cannot predict.
Appalachian Voices, et al. v. U.S. Dep’t of Interior, et al., Fourth Circuit Court of Appeals, Case No. 20-2159. In August 2019, Wild Virginia and certain other petitioners filed a petition in the Fourth Circuit in Wild Virginia et al. v. United States Department of the Interior; Case No. 19-1866, to challenge the MVP Joint Venture’s Biological Opinion and Incidental Take Statement issued by FWS which was approved in November 2017 (the Original BiOp). On October 11, 2019, the Fourth Circuit issued an order approving the petitioners’ requested stay of the Original BiOp and

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holding the litigation in abeyance until January 11, 2020. On October 15, 2019, the FERC issued an order requiring the MVP Joint Venture to cease all forward-construction progress. The FERC modified this order on October 9, 2020 and December 17, 2020, which the Sierra Club has appealed to the DC Circuit as discussed above in Jefferson National Forest Crossing and Associated Authorizations. On September 4, 2020, FWS issued the MVP Joint Venture a new Biological Opinion and Incidental Take Statement (the New BiOp) for the MVP project and the Fourth Circuit subsequently dismissed the litigation regarding the Original BiOp. On October 27, 2020, Appalachian Voices et al. filed a petition with the Fourth Circuit challenging the New BiOp and filed a request for an administrative stay of the New BiOp with FWS, which FWS subsequently denied. On November 2, 2020, the petitioners filed a motion to stay the New BiOp with the Fourth Circuit. On November 18, 2020, the Fourth Circuit issued an order denying the requested stay. The matter is scheduled to be fully briefed and argued by June 30, 2021. If this challenge were successful, it could result in the New BiOp being vacated and/or additional proceedings (the outcome of which the Company cannot predict) and cause a delay in the targeted in-service date for the MVP project (and consequent impacts relating to such delay).
Other Proceeding Relevant to the MVP Project
Grand Jury Subpoena. On January 7, 2019, the MVP Joint Venture received a letter from the U.S. Attorney's Office for the Western District of Virginia stating that it and the EPA are investigating potential criminal and/or civil violations of the Clean Water Act and other federal statutes as they relate to the construction of the MVP. The January 7, 2019 letter requested that the MVP Joint Venture and its members, contractors, suppliers and other entities involved in the construction of the MVP preserve documents related to the MVP generated from September 1, 2018 to the present. In a telephone call on February 4, 2019, the U.S. Attorney's Office confirmed that it had opened a criminal investigation. On February 11, 2019, the MVP Joint Venture received a grand jury subpoena from the U.S. Attorney's Office for the Western District of Virginia requesting certain documents related to the MVP from August 1, 2018 to the present. The MVP Joint Venture is complying with the letter and subpoena but cannot predict whether any action will ultimately be brought by the U.S. Attorney's Office or what the outcome of such an action would be. The MVP Joint Venture began a rolling production of documents responsive to the subpoena after the U.S. Attorney’s office narrowed its subpoena inquiry to five farms in Virginia containing twenty streams or wetlands.
MVP Southgate Matters
The MVP Joint Venture is currently challenging or defending certain agency actions and judicial challenges to the MVP Southgate project that must be resolved before the project can be completed, including the following:
Sierra Club et al. v. FERC; Case No. 20-1427, DC Circuit. On June 18, 2020, the FERC issued an order granting a certificate of public convenience and necessity for the MVP Southgate project. However, the FERC, while authorizing the project, directed the Office of Energy Projects not to issue a notice to proceed with construction until necessary federal permits are received for the MVP project and the Director of the Office of Energy Projects lifts the stop-work order and authorizes the MVP Joint Venture to continue constructing the MVP project. Certain opposition parties subsequently requested rehearing of the certificate order. On August 20, 2020, the FERC issued an order denying requests for rehearing of that certificate order, and on September 17, 2020, the FERC issued an order addressing the arguments raised on rehearing. On October 9, 2020, Sierra Club, among other petitioners, filed an appeal of these orders with the DC Circuit. On December 23, 2020, the Court set a revised briefing schedule for the proceeding and the matter is scheduled to be fully briefed by August 2, 2021. If this challenge were successful, it could result in the MVP Southgate project’s certificate of public convenience and necessity being vacated and/or additional proceedings before the FERC, the outcome of which the Company cannot predict.
Mountain Valley Pipeline, LLC v. North Carolina Department of Environmental Quality, No. 20-1971, Fourth Circuit Court of Appeals. On August 11, 2020, North Carolina regulators denied the MVP Southgate project’s application for a Clean Water Act Section 401 Individual Water Quality Certification and Jordan Lake Riparian Buffer Authorization due to uncertainty surrounding the completion of the MVP project, which denial was appealed by the MVP Joint Venture on September 10, 2020. The case was fully briefed and oral arguments occurred on January 26, 2021. The Company cannot guarantee the outcome of such litigation, or whether, should its appeal be successful and its application approved, such approval would be further challenged.
Item 4.        Mine Safety Disclosures
Not applicable.

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Information About Our Executive Officers
NameAgeYear Initially Elected as Executive Officer