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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, 2021
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, 2021: $3.4 billion
The number of shares of common stock outstanding (in thousands), as of January 31, 2022: 432,676

DOCUMENTS INCORPORATED BY REFERENCE

The Company's definitive proxy statement relating to the 2022 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, 2021 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

2

EQUITRANS MIDSTREAM CORPORATION
Glossary of Commonly Used Terms, Abbreviations and Measurements
2021 Water Services Agreement – that certain mixed-use water services agreement entered into on October 22, 2021 by the Company and EQT (as defined below), as subsequently amended, which, upon its effectiveness, will replace the Water Services Letter Agreement (as defined below) and certain other existing Pennsylvania water services agreements.
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 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 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 (as 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 is designed to 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 (as defined below) projects.

3

MVP Southgate – a proposed 75-mile interstate pipeline that is contemplated to extend from the MVP at Pittsylvania County, Virginia to new delivery points in Rockingham and Alamance Counties, North Carolina. The project is subject to ongoing discussions between the MVP Joint Venture and the project shipper, Dominion Energy North Carolina, as discussed in "MVP Southgate Project" under "Developments, Market Trends and Competitive Conditions" in "Item 1. Business" of this Annual Report on Form 10-K.
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 (as 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 2022 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.
Scope 1 emissions – direct greenhouse gas emissions from owned or controlled sources.
Scope 2 emissions – indirect greenhouse gas emissions from the generation of purchased energy.
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.
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 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, which letter agreement will be replaced by the 2021 Water Services Agreement.
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."


4

AbbreviationsMeasurements
ARO – asset retirement obligations
Btu = one British thermal unit
ASC – Accounting Standards Codification
BBtu = billion British thermal units
ASU – Accounting Standards Update
Bcf   = billion cubic feet
CERCLA – Comprehensive Environmental Response, Compensation and Liability Act
Mcf = thousand cubic feet
DOT – United States Department of Transportation
MMBtu = million British thermal units
EPA – United States Environmental Protection Agency
MMcf  = million cubic feet
FASB Financial Accounting Standards Board
MMgal = million gallons
FERC – United States Federal Energy Regulatory Commission
GAAP – United States Generally Accepted Accounting Principles
GHG – greenhouse gas
HCA – high consequence area
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

5

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, 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, leverage, 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, and timing thereof, 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 to construct or restore right-of-way for, capacity, shippers for, timing of regulatory approvals and concluding litigation, final design (including expansions, extensions or refinements and capital related thereto), ability to contract additional capacity on, mitigate emissions from and complete, 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 payment provision of the EQT Global GGA and the estimated transaction price allocated to the Company's remaining performance obligations under certain contracts with firm reservation fees and MVCs;
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 and mixed water handling services and realize expansion opportunities;
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, accretion and other benefits associated with transactions, including through increased scale;
any credit rating impacts associated with the MVP project, customer credit ratings changes, defaults, acquisitions, dispositions and financings and any changes in EQM's credit ratings;
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;

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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 (as defined herein);
the effects of seasonality;
expected cash flows and MVCs, including those associated with the EQT Global GGA, and the potential impacts thereon of the commission timing and cost of the MVP project;
the ability to achieve, and time for achieving, Hammerhead pipeline full commercial in-service;
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;
future decisions of customers in respect of curtailing natural gas production, 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 and to timely extend and obtain modifications in terms under such agreements;
expectations regarding natural gas 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 and other commercial 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, commodity prices, access to capital and costs which may be incurred as a result of, and potential need for compliance with, governmental (including state or local) regulations or orders which may be enacted and upheld with respect to testing and/or vaccination for COVID-19;
the Company's ability to achieve, and create value from, its environmental, social and governance (ESG) and sustainability targets (including targets set forth in its climate policy) and the Company's ability to respond to increasing stakeholder scrutiny in these areas;
the effectiveness of the Company's information technology systems and practices to defend against evolving cyberattacks on United States critical infrastructure;
the effects of government regulation including any quantification of potential impacts of regulatory matters related to climate change on the Company; 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.
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.

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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 (as 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).
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 5.3% of Equitrans Midstream's outstanding shares of common stock held by EQT as of December 31, 2021, 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 Convertible Preferred Units (EQM Series A Preferred Units) representing limited partner interests in EQM for a cash purchase

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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 (as defined in Note 3) 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 (as 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 through December 2031 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 full in-service date occurs through 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 to begin the first day of the quarter in which the full in-service date of the MVP occurs, which provide for estimated aggregate fee relief of approximately $270 million in the first twelve-month period, approximately $230 million in the second twelve-month period and approximately $35 million in the third twelve-month period. Further, the EQT Global GGA provides for a fee credit to the gathering rate for certain gathered volumes that also receive separate transmission services under certain transmission contracts. In addition, given that the MVP full in-service date did not occur by January 1, 2022, EQT has an option, exercisable through December 31, 2022, to forgo approximately $145 million of the gathering fee relief in such first twelve-month period and approximately $90 million of the gathering fee relief in such second twelve-month period 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.
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

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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 and 2021 Water Services Agreement. On February 26, 2020, the Company entered into a letter agreement with EQT relating to the provision of water services in Pennsylvania (such letter agreement, the Water Services Letter Agreement). Subject to the effect of the 2021 Water Services Agreement (as defined below), the Water Services Letter Agreement would have been effective as of the first day of the first month following the MVP full in-service date and would have expired on the fifth anniversary of such date. During each year of the Water Services Letter Agreement, EQT had agreed to pay the Company a minimum $60 million per year annual revenue commitment (ARC) for volumetric water services provided in Pennsylvania, all in accordance with existing water service agreements and new water service agreements entered into between the parties pursuant to the Water Services Letter Agreement (or the related agreements).

On October 22, 2021, the Company and EQT entered into a new 10-year, mixed-use water services agreement covering operations within a dedicated area in southwestern Pennsylvania (as subsequently amended, the 2021 Water Services Agreement). The 2021 Water Services Agreement, which, upon its effectiveness, replaces the Water Services Letter Agreement and certain other existing Pennsylvania water services agreements, will become effective with the commencement of water delivery service to a certain EQT well pad (anticipated in the first quarter of 2022). Pursuant to the 2021 Water Services Agreement, EQT has agreed to pay the Company a minimum ARC for water services equal to $40 million in each of the first five years of the 10-year contract term and equal to $35 million per year for the remaining five years of the contract term.
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 (as defined in Note 11) 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, 2021:
etrn-20211231_g1.jpg

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Overview of Operations
The Company provides midstream services to its customers in Pennsylvania, West Virginia and Ohio 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 network, which primarily consists of water pipelines and other facilities that support well completion and produced water handling activities.
As of December 31, 2021, the Company provided a majority of its natural gas gathering, transmission and storage services under long-term contracts that generally include firm reservation fees. The Company maintains a stable cash flow profile, with approximately 64% of the Company's operating revenues for the year ended December 31, 2021 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 of 3.0 Bcf per day that became effective on April 1, 2020 and gradually steps up to 4.0 Bcf per day through December 2031 following the full in-service date of the MVP. These contract structures enhance the stability of the Company's cash flows and limit its exposure to customer volume variability.
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, which was the largest natural gas producer in the United States based on average daily sales volumes as of December 31, 2021 and the Company's largest customer as of December 31, 2021. EQT accounted for approximately 59% of the Company's revenues for the year ended December 31, 2021.


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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, 2021. Also included are MVP and MVP Southgate routes, which projects are discussed in "Strategy" under "Developments, Market Trends and Competitive Conditions" in "Item 1. Business."
etrn-20211231_g2.jpg

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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,
 202120202019
Gathering operating revenues66 %67 %71 %
Transmission operating revenues30 %26 %24 %
Water operating revenues%%%
The Company's largest customer, EQT, accounted for approximately 59%, 64% and 69% of the Company's total revenues for the years ended December 31, 2021, 2020 and 2019, respectively.
Gathering Customers. For the year ended December 31, 2021, EQT accounted for approximately 59% of Gathering's revenues. Subject to certain exceptions and limitations, as of December 31, 2021, Gathering (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 265-mile gathering header pipeline system in Ohio and West Virginia that services both dry Utica and wet Marcellus Shale production) had significant acreage dedications through which the Company has the right to elect to gather all natural gas produced from wells under dedicated areas in (i) Pennsylvania pursuant to agreements with EQT, including the EQT Global GGA, and agreements with certain other third parties, (ii) Ohio pursuant to agreements with EQT and other third parties, and (iii) 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 often 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, 2021, 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 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 8.1 Bcf per day (inclusive of Eureka Midstream contracted capacity) as of December 31, 2021, which included contracted firm reservation capacity of approximately 1.8 Bcf per day associated with the Company's high-pressure header pipelines. 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. 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 14 years as of December 31, 2021.
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. To the extent that capacity reserved by customers with firm service contracts is not fully used or excess capacity exists, the gathering system can allocate capacity to interruptible services.
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 certain of its compressor stations and meet other requirements on the Company's gathering systems.
Transmission Customers. For the year ended December 31, 2021, EQT accounted for approximately 62% of Transmission's throughput and approximately 53% of Transmission's revenues. As of December 31, 2021, 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 dedicated areas 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

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access to 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 often 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. As of December 31, 2021, the Company had firm capacity subscribed under firm transmission contracts of approximately 5.6 Bcf per day, which includes future capacity expected from expansion projects that are not yet fully constructed for which the Company has executed firm transmission contracts and excludes 2.3 Bcf per day of firm capacity commitments associated with the MVP and MVP Southgate projects. As of December 31, 2021, the Company had firm storage capacity of approximately 29.8 Bcf subscribed under firm storage contracts. 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 13 years as of December 31, 2021.
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. 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 but retains a percentage of gas receipts to recover natural gas used to power its compressor stations and meet other requirements of the Company's transmission and storage systems.
As of December 31, 2021, 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, 2021, 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 in or additional regulatory measures adopted by such authorities, and related litigation, 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, 2021, EQT accounted for approximately 96% 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 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. Upon commencement of the 2021 Water Services Agreement, the majority of the Company's water service revenues will be subject to an ARC with EQT.
See also "Water Services Letter Agreement" and "2021 Water Services Agreement" above for additional information on the Company's Water customers.
The Company's Assets
Gathering Assets. As of December 31, 2021, the gathering system, inclusive of Eureka Midstream's gathering system, included approximately 1,170 miles of high-pressure gathering lines and 133 compressor units with compression of approximately 491,000 horsepower and multiple interconnect points with the Company's transmission and storage system and to other interstate pipelines.
Transmission and Storage Assets. As of December 31, 2021, 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 of December 31, 2021, the transmission and storage system was supported by 43 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 850 MMcf per day and a working gas capacity of approximately 43 Bcf.

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Water Assets. As of December 31, 2021, the fresh water systems included approximately 200 miles of pipeline that deliver fresh water from local municipal water authorities, the Monongahela River, the Ohio River, local reservoirs and several regional waterways. In addition, as of December 31, 2021, the water system assets included 23 fresh water impoundment facilities.
During 2021, the Company began construction of a mixed water system in Greene County, Pennsylvania. The system has a targeted full in-service date of summer 2022 and is primarily supported by the 2021 Water Services Agreement. The mixed water system is designed to include 71 miles of buried water pipeline, two water storage facilities with 350,000 barrels of capacity and two interconnects with the Company’s existing Pennsylvania fresh water systems and will provide services to producers in southwestern Pennsylvania. As of December 31, 2021, the Company’s mixed water system included approximately eight miles of buried pipeline.
Developments, Market Trends and Competitive Conditions
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, 2021. The Company maintains a stable cash flow profile, with approximately 64% of its operating revenues for the year ended December 31, 2021 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 of 3.0 Bcf per day that became effective on April 1, 2020 and gradually steps up to 4.0 Bcf per day through December 2031 following the full in-service date of the MVP. This contract structure enhances the stability of the Company's cash flows and limits its exposure to customer volume variability.
Strategy. The Company's principal strategy is to achieve greater scale and scope, enhance the durability of its financial strength and to continue to work to position itself for a lower carbon economy, which strategy the Company expects will drive future growth and investment. The Company is implementing its strategy by continuing to leverage its existing assets, execute on its growth projects (including through potential expansion and extension opportunities), periodically evaluate strategically-aligned inorganic growth opportunities (whether within its existing footprint or to extend the Company's reach into the southeast United States to become closer to key demand markets, such as the Gulf of Mexico LNG export market), and focus on ESG and sustainability-oriented initiatives. Additionally, the Company is also continuing to focus on 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 expects that the MVP project (should it be placed in-service), together with the Hammerhead pipeline and Equitrans, L.P. Expansion Project (EEP), will primarily drive the Company's organic growth, 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, 2021, the Company owned an approximate 46.8% 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 is designed to 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.
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

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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 requested an Individual Permit from the Army Corps to effect approximately 300 water crossings utilizing open cut techniques (the Army Corps Individual Permit) and (ii) an application to amend the Certificate that seeks FERC authority to utilize alternative trenchless construction methods to effect approximately 120 water crossings. Related to seeking the Army Corps Individual Permit, on March 4, 2021, the MVP Joint Venture submitted applications to each of the West Virginia Department of Environmental Protection (WVDEP) and the Virginia Department of Environmental Quality (VADEQ) seeking Section 401 water quality certification approvals or waivers (such approvals or waivers, the State 401 Approvals), which State 401 Approvals were each received in December 2021. In early June 2021, the FERC issued a notice of schedule for the MVP Joint Venture's Certificate amendment application and the FERC issued an Environmental Assessment in mid-August 2021. As discussed in Part I, "Item 3. Legal Proceedings" of this Annual Report on Form 10-K, on January 25, 2022, the MVP Joint Venture's authorizations related to the Jefferson National Forest (JNF) received from the Bureau of Land Management (BLM) and the U.S. Forest Service (USFS) were vacated and remanded on specific issues by the U.S. Court of Appeals for the Fourth Circuit (Fourth Circuit). As also discussed in Part I, "Item 3. Legal Proceedings" of this Annual Report on Form 10-K, on February 2, 2022, the Fourth Circuit vacated and remanded on specific issues 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. The MVP Joint Venture continues to review these recent decisions and evaluate the possible paths forward, which include working with the relevant federal agencies and consideration of potential legal appeals. As a result, the Company is not able to provide an update as to the in-service timing and overall cost for the project, except that the Company is no longer targeting a summer 2022 in-service date.
In addition to timely receiving, and subsequently maintaining, new authorizations in respect of the JNF, and a Biological Opinion and Incidental Take Statement, the MVP Joint Venture must, in order to complete the project, among other things, timely receive (i) the Army Corps Individual Permit (as well as timely receive, if necessary, certain other state-level approvals), and (ii) authorization from the FERC to amend the Certificate to utilize alternative trenchless construction methods for certain stream and wetland crossings, as well as any necessary extensions from FERC to complete the MVP project. The MVP Joint Venture also must (i) continue to have available the orders previously issued by the FERC, which are the subject of ongoing litigation, modifying its prior stop work orders and extending the MVP Joint Venture’s prescribed time to complete the MVP project; and (ii) 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 in the JNF. In each case, any such foregoing or other authorizations must remain in effect notwithstanding any pending or future challenge thereto. For further information regarding litigation and regulatory related delays affecting the completion of the MVP project, see Part I, "Item 3. Legal Proceedings" of this Annual Report on Form 10-K. See also "The regulatory approval process for the construction of new midstream assets is very challenging, has significantly increased costs and delayed targeted in-service dates, and decisions by regulatory and judicial authorities in pending or potential proceedings are likely to 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" for additional discussion.
On November 4, 2019, Con Edison exercised an option to cap its investment in the construction of 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, depending on the project's total cost, the Company's equity ownership in the MVP project will progressively increase to a percentage in excess of approximately 46.8%.
Through December 31, 2021, the Company had funded approximately $2.5 billion of its then-estimated total capital contributions. During the year ended December 31, 2021, the Company made approximately $284 million of capital contributions to the MVP Joint Venture for the MVP project. For 2022, the Company expects to make total capital contributions of approximately $175 million to $225 million related to work completed in late 2021 and ongoing right-of-way maintenance.
Wellhead Gathering Expansion Projects and Hammerhead Pipeline. During the year ended December 31, 2021, the Company invested approximately $224 million in gathering projects (inclusive of capital expenditures related to the noncontrolling interest in Eureka Midstream). For 2022, the Company expects to invest approximately $270 million to

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$320 million in gathering projects (inclusive of expected capital expenditures of approximately $20 million 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.
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. For more information, including regarding full commercial in-service status for the Hammerhead pipeline, see "Outlook" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
Transmission Projects and Equitrans Expansion Project. During the year ended December 31, 2021, the Company invested approximately $26 million in transmission projects, including the EEP. The EEP is designed to provide north-to-south capacity on the mainline Equitrans, L.P. 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.

For 2022, the Company expects to invest approximately $45 million in transmission projects, inclusive of capital expenditures expected for 2022 associated with the Company's Ohio Valley Connector expansion project (OVCX). OVCX will increase deliverability on the Company's existing Ohio Valley Connector pipeline (OVC) by approximately 350 MMcf per day, create new receipt and delivery transportation paths, and enhance long-term reliability. The project is supported by new long-term firm capacity commitments of 330 MMcf per day, as well as an extension of approximately 1.0 Bcf per day of existing contracted mainline capacity for EQT. OVCX is designed to meet growing demand in key markets in the mid-continent and gulf coast through existing interconnects with long-haul pipelines in Clarington, Ohio. The targeted in-service date for the incremental OVC capacity is the third quarter of 2023. The Company expects to invest approximately $160 million, which includes approximately $130 million for new compression. The project is consistent with the Company's ongoing efforts to optimize existing assets and achieve capital efficiency.

MVP Southgate Project. In April 2018, the MVP Joint Venture announced the MVP Southgate project, which is a proposed 75-mile interstate pipeline that is contemplated to 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, and, as currently designed, reflects potential expansion capabilities that could provide up to 900 MMcf per day of total capacity. The Company is expected to operate the MVP Southgate project and owned a 47.2% interest in the MVP Southgate project as of December 31, 2021.

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, the North Carolina Department of Environmental Quality (NCDEQ) 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. On March 11, 2021, the Fourth Circuit, pursuant to an appeal filed by the MVP Joint Venture, vacated the NCDEQ's denial and remanded the matter to the NCDEQ for additional review. On April 29, 2021, the NCDEQ reissued its denial of the MVP Southgate project's application for a Clean Water Act Section 401 Individual Water Quality Certification and Jordan Lake Riparian Buffer Authorization. On December 3, 2021, the Virginia State Air Pollution Control Board denied the permit for the MVP Southgate project’s Lambert compressor station, which decision the MVP Joint Venture has appealed (and such appeal is pending). See the discussion of litigation and regulatory related delays affecting the completion of the MVP Southgate project set forth in Part I, "Item 3. Legal Proceedings" of this Annual Report on Form 10-K.

Given the continually evolving regulatory and legal environment for greenfield pipeline construction projects, as well as factors specific to the MVP and MVP Southgate projects, including the December 2021 compressor station state air permit denial, the MVP Joint Venture is evaluating the MVP Southgate project, including engaging in discussions with Dominion Energy North Carolina regarding options with respect to the MVP Southgate project, including potentially

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refining the project’s design and timing in lieu of pursuing the project as originally contemplated. Dominion Energy North Carolina’s obligations under the precedent agreement in support of the original project are subject to certain conditions, including that the MVP Joint Venture complete construction of the project facilities by June 1, 2022, which deadline is subject to extension by virtue of previously declared events of force majeure. The Company is unable to predict the results of the discussions between the MVP Joint Venture and Dominion Energy North Carolina, including any potential modifications to the project, or ultimate undertaking or completion of the project.

The MVP Southgate project, as originally designed, was estimated to cost a total of approximately $450 million to $500 million, a portion of which the Company expected to fund. During the year ended December 31, 2021, the Company made approximately $4 million of capital contributions to the MVP Joint Venture for the MVP Southgate project. For 2022, the Company expects to make capital contributions of approximately $5 million to the MVP Joint Venture for the MVP Southgate project.
Water Operations. During the year ended December 31, 2021, the Company invested approximately $35 million in its water infrastructure. For 2022, the Company expects to invest approximately $50 million in the operations of its water infrastructure in Pennsylvania, primarily for the construction of the mixed water system.

See "Sustainability and Corporate Responsibility" in "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of the Company's continued focus on ESG and sustainability matters which the Company believes will distinctively position the Company and create value.
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 operations in multiple natural gas producing basins, 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.
Key competition for water services includes 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, governmental clean energy policies, 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 are elevated 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 of 1938 (NGA), the Natural Gas Policy Act of 1978 (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;

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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.
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, 2021, 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.

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On April 19, 2018, the FERC issued a Notice of Inquiry (2018 Notice of Inquiry) 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. On February 18, 2021, the FERC issued another Notice of Inquiry in the same proceeding that modified and expanded the inquiry and renewed its request for public comment (together with the 2018 Notice of Inquiry, the Certificate Policy Statement NOI). The formal comment period closed May 26, 2021. On February 18, 2022, the FERC issued an Updated Certificate Policy Statement. The Company is evaluating the Updated Certificate Policy Statement, but at this time, it is not possible to predict the impact that the Updated Certificate Policy will have on the Company, if any.
In 2021, Congress did not pass legislation revising the NGA or other statutes that may impact the Company's existing facilities and operations or the ability to construct new facilities, though that remains a possibility in 2022. 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 affecting the ability of companies to exercise eminent domain; and (iii) amending Section 19(b) of the NGA to provide the FERC additional time to act on requests for rehearing.
Party control at the FERC changed in 2021, and the FERC reestablished its full complement of five commissioners. In 2021, FERC issued Order Nos. 871-B and -C (amending FERC regulations to prohibit the issuance of authorizations to proceed with construction while certain requests for rehearing are pending), demonstrated that it will consider climate change impacts in individual certificate proceedings, and incorporated enhanced environmental justice review in pipeline certificate orders. On February 18, 2022, the FERC issued an interim GHG policy. The Company is evaluating the interim GHG policy, but at this time, it is not possible to predict the impact that the interim GHG policy, or any future changes to that policy, will have on the Company, if any.
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, 2021, 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 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 (see discussion below). Part three of the Mega Rule was finalized on November 15, 2021, with an effective date of May 16, 2022 (see discussion below). Part two of the Mega Rule will now be the final portion

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addressed by a future rulemaking activity which remains under development, and no expected date for finalization has been released by PHMSA.

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. 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 three final rules on pipeline safety applicable to the Company: "Enhanced Emergency Order Procedures;" "Safety of Gas Transmission Pipelines: Maximum Allowable Operating Pressure Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments" (also known as the Mega Rule Part 1); and "Safety of Gas Gathering Pipelines: Extension of Reporting Requirements, Regulation of Large, High-Pressure Lines, and Other Related Amendments" (also known as the Mega Rule Part 3). 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. The Safety of Gas Gathering Pipelines rule, which was finalized on November 15, 2021 and will go into effect on May 16, 2022, extends existing design, operational and maintenance, and reporting requirements to onshore natural gas gathering pipelines in rural areas. The rule requires operators of onshore gas gathering pipelines to report incidents and file annual reports, and creates new safety requirements that vary based on pipeline diameter and potential consequences of a failure. In 2021, the Company did not incur material compliance costs in connection with complying with the PHMSA rules applicable to the Company, and does not currently expect these rules to materially impact its future costs of operations and revenue from operations. However, the Company will continue to assess the impact of compliance with 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 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

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added costs or delays to 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," which reauthorized the federal pipeline safety program that expired in 2019. 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 that operators be able to locate and categorize all leaks that are hazardous to human safety, the environment, or that can become hazardous. The Company has not incurred and does not anticipate incurring material capital expenditures in connection with complying with the PIPES Act.

Cybersecurity. The U.S. government has continued to issue public warnings that indicate that energy assets might be specific targets of cyberattacks and, in May and July 2021, the U.S. Department of Homeland Security's Transportation Safety Administration (the TSA) issued security directives (as well as subsequent revisions thereto) applicable to certain midstream companies requiring such companies to comply with mandatory reporting measures and undertake a number of specific cybersecurity enhancements for both information technology (IT) and operational technology (OT) systems. The Company continues to work with the TSA to ensure compliance with the security directives and is implementing the requirements of those security directives, as needed. While such implementation is utilizing significant internal resources, implementation as of the filing date of this Annual Report on Form 10-K has not materially adversely affected the Company's business and operations.

The regulatory environment surrounding cybersecurity continues to evolve in ways that are frequently difficult to predict. We have been required and may further be required to expend additional resources as a result of current or new laws, regulations, directives or other requirements, or changes in the interpretation or enforcement practices thereof, related to cybersecurity, which could result in material compliance costs. Any failure to remain in compliance with laws or regulations governing cybersecurity, including TSA security directives, may result in penalties, fines, enforcement actions, or mandated changes in our practices, which may have a material adverse effect on our business and operations.

For further information, see also "Cyberattacks aimed at us or third parties, as well as any noncompliance by us with applicable laws and regulations governing cybersecurity and/or data privacy, could materially adversely affect us." under "Item 1A. Risk Factors."

OSHA Regulation. On September 9, 2021, President Biden announced a proposed new rule requiring that all employers with at least 100 employees require that their employees be fully vaccinated or require unvaccinated workers to produce a negative test result at least once a week. On November 4, 2021, the U.S. Department of Labor’s Occupational Safety and Health Administration (OSHA) issued an Emergency Temporary Standard (ETS) to carry out this mandate.

On January 13, 2022, the U.S. Supreme Court granted an application to stay the ETS pending disposition of petitions for review in the U.S. Court of Appeals for the Sixth Circuit. Effective January 26, 2022, OSHA withdrew the ETS as an enforceable emergency temporary standard, but did not withdraw the ETS as a proposed rule.

Should the ETS, or similar state or local requirement, take effect in the future, the Company expects it would be subject to such regulation concerning COVID-19 vaccination or testing. In that case, the Company may be required to implement a requirement that many or most employees get vaccinated, subject to limited exceptions, or be tested, resulting in additional costs to the Company. At this time, it is not possible to predict the impact that a vaccine or testing requirement would have on the Company or its workforce. Any such mandate may result in increased costs, operational disruptions or employee attrition, which could materially and adversely affect the Company’s business and results of operations.

OSHA has also implemented a National Emphasis Program in July 2021 that focuses on COVID-19. This program channels the agency’s resources toward inspections of employers with congregate work settings, to ensure they maintain safety protocols designed to limit the spread of the coronavirus (e.g., masking, social distancing). This program is not likely to impact the Company’s remote workers, but could result in increased inspections and fines at the Company’s congregate work settings.

OSHA is also focusing on hazards posed to workers by extreme heat. The Biden Administration has indicated that it considers heat-related illnesses to be a growing hazard because of climate change, has identified this area of policy as a priority for the Administration because of its disproportionate impact on communities of color. To combat this hazard, on September 1, 2021, OSHA implemented an enforcement initiative prioritizing inspections of work activities when the heat index exceeds 80 degrees Fahrenheit. OSHA is also developing a National Emphasis Program for heat inspections and, on October 27, 2021,

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OSHA issued an Advanced Notice of Proposed Rulemaking on heat injury and illness prevention in outdoor and indoor work settings. This notice signals OSHA’s intent to issue a rule requiring employers to take certain precautions to avoid heat-related illnesses amongst their employees. As with OSHA’s COVID-19 enforcement initiatives, these programs will not likely impact the Company’s remote employees, but could result in increased inspections and fines at the Company’s outdoor worksites.

Employee Health and Safety. As noted above, the Company is subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act 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.
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 the Company's 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 the cost of 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 it is generally expected that 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, the Biden Administration has announced that it will be reviewing the National Ambient Air Quality Standards (NAAQS) for ozone and may make these standards more stringent. This could result in the areas in which the Company operates being designated 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. The EPA did not make the ozone NAAQS more stringent when it reviewed them in 2020, but the Biden Administration has indicated that it will reconsider that decision. In addition, in November 2021, the EPA issued a proposed rule that would make more stringent the volatile organic compound (VOC) and methane emissions limits on certain new and modified equipment in the oil and gas source category, including certain types of compressors and pneumatic pumps. The proposed rule would also extend these requirements to existing sources for the first time. Some states are also enacting methane reduction programs. For example, Pennsylvania has a methane reduction framework for the oil and gas industry that will result in an existing source VOC regulation with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines.


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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 continuously attempts to anticipate future regulatory requirements that might be imposed and works 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.
Additionally, on January 20, 2021, President Biden signed an executive order on "Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis," under which 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 Biden Administration order. Regulatory actions resulting from this review could adversely affect the Company’s business and results of operations, 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 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

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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. Future 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. The Company has announced a goal of becoming net zero for carbon by 2050. The Company’s climate policy includes two interim emission reduction targets: (i) a 50 percent reduction of its Scope 1 and Scope 2 methane emissions by 2030; and (ii) a 50 percent reduction of its total Scope 1 and Scope 2 greenhouse gas (GHG) emissions by 2040.

Legislative and regulatory measures to address climate change and 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. A district court issued an injunction halting the leasing pause, but the Biden Administration is appealing that decision. Under the executive order, the Interior Department issued a report in November 2021 in response to this executive order that recommends increasing the 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 regulates methane and VOCs from the oil and gas sector through its new source performance standard program under the Clean Air Act. In May 2016, the EPA finalized rules (Subpart OOOOa) that impose methane and VOC emissions limits on certain types of new and modified compressors and pneumatic pumps. 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 final rule (known as the Policy Rule) that "corrected" the regulations by removing the transmission and storage segments from the source category subject to the rule and removing the methane emissions limits from the rule. Congress revoked the Policy Rule through the Congressional Review Act, and President Biden signed this into law in June 2021. The Congressional Review Act action has the effect as though the Policy Rule never existed. The revocation of the Policy Rule did not affect Equitrans Midstream because the Company never stopped complying with the Subpart OOOOa methane and VOC emissions limits. In November 2021, the EPA issued a proposed rule that proposes to do three things: (i) modify Subpart OOOOa to, among other things, increase fugitive emissions monitoring frequency; (ii) promulgate a new Subpart OOOOb that would impose more stringent requirements on new and modified oil and gas sources; and (iii) promulgate an emissions guideline (a new Subpart OOOOc) that would provide direction to the states to regulate VOC and methane emissions from existing sources in the sector for the first time. The proposed Subpart OOOOc would largely regulate existing sources in the same manner in which new and modified sources are regulated. If the proposed rule is finalized, the Company will be required to incur certain capital expenditures in the future for air pollution control equipment, increased fugitive emissions monitoring, and other requirements that could result in significant costs and could adversely affect the Company's business.

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. The United States participated in the United Nations Conference on Climate Change in Glasgow, Scotland in November 2021 and was one of the countries entering into a Global Methane Pledge. One of the key pieces of the U.S. Methane Emissions Reduction Action Plan that was announced is the EPA’s proposed methane rules for the oil and gas sector. In April 2021, the United States announced its commitment to reduce its greenhouse gas emissions by 50 to 52 percent from 2005 levels by 2030. Depending on how this reduction is to be 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 imposes a carbon tax on carbon emissions or that restricts those emissions could increase the Company's cost of environmental compliance through the Company's incurrence of increased non-income taxes or by requiring

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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 Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.

See also "Our business is subject to climate change-related transitional risks (including evolving climate-focused regulation and climate change-driven trends, emphasizing financing non-fossil fuel businesses and prompting pursuit of emissions reductions, lower-carbon technologies and alternative forms of energy) and physical risks that could significantly increase our operating expenses and capital costs, adversely affect our customers' development plans, and reduce demand for our products and services." under "Item 1A. Risk Factors" in this Annual Report on Form 10-K for the year ended December 31, 2021.

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), however, 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. On December 7, 2021, EPA and the Army Corps published a proposed rule that would reinstate the pre-2015 definition of waters of the United States, updated to reflect recent Supreme Court decisions. 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

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endangered or threatened, or the designation of previously unprotected areas as a critical habitat for such species, has caused and could in the future cause the Company to incur additional costs, resulted in and could in the future 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.

Environmental Justice. The federal government has made advancing environmental justice a priority and has announced a number of new initiatives in the area. Some of those initiatives could have impacts on the business of oil and gas companies, although the ultimate form of the federal government’s approach to these issues is unknown and the impact to the oil and gas industry remains uncertain. The Biden Administration announced a renewed commitment to environmental justice in its day one executive order on climate change and the environment and followed up that action with an executive order establishing new environmental justice advisory committees tasked with helping the government devise new environmental justice policies. Since that time, the White House Environmental Justice Advisory Committee has released recommendations that include new spending priorities, development of environmental justice impact assessment techniques, and legal enforcement recommendations. The Department of Justice and the EPA Office of Enforcement and Compliance Assurance have issued policy statements indicating that both agencies will seek to enhance prosecution of environmental justice crimes and to seek out ways to address environmental justice through the legal system. EPA has also issued a number of statements indicating that it will attempt to address environmental justice issues more substantially through its policy making. It is unclear how these new policies will be implemented, and Equitrans Midstream will continue to monitor new developments and assess whether and how they may affect the Company.

States are also in the process of reexamining environmental justice law and policy. Pennsylvania’s governor signed an executive order in October 2021 creating an Office of Environmental Justice within the Pennsylvania Department of Environmental Protection. It is tasked with revising Pennsylvania’s environmental justice policies and examining ways to advance environmental justice issues. In Virginia, the legislature enacted the Environmental Justice Act of 2020, which requires state agencies to examine the environmental justice impacts of their actions and creates a council to recommend new environmental justice policies. Ohio and West Virginia appear to be monitoring developments at the EPA. Many of the key issues before the states appear to be focused on enhancing public participation in permitting and other project development-related decisions. State agencies also appear to be considering new approaches to environmental justice in permitting decisions, potentially denying permits or other authorizations on environmental justice grounds. Equitrans Midstream will continue to monitor state legal and regulatory developments in this area and respond as appropriate.

The majority of environmental justice litigation matters appear to be focused on whether state or federal agencies with permitting or other decision-making responsibility have adequately considered environmental justice issues during the decision-making process. Many advocacy organizations purport to raise environmental justice issues in connection with permitting legal challenges. Equitrans Midstream will continue to monitor these litigation-related developments.

Equitrans Midstream has a number of policies in place that address environmental justice issues. One of the Company’s pillars of sustainability is stakeholder engagement, including engagement with the communities where Equitrans Midstream operates. In 2021, Equitrans Midstream published its Stakeholder Engagement and Community Investment Policy, which emphasizes early and consistent community engagement throughout project development and operation, and it specifically prioritizes environmental justice and environmental stewardship. The Company has also adopted a Human Rights Policy committing the Company to safeguarding dignity and respect for all people throughout the Company’s value chain, including through community engagement and the prevention of discrimination.

Equitrans Midstream is in the process of developing a comprehensive environmental justice policy. The Company will continue that work, mindful of new developments at the federal, state, and local levels.
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 and in a changing economic landscape focused on long-term, sustainable operations, the

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Company seeks to employ a team of highly accomplished people who are dedicated to the Company’s success and to foster an engaging workplace environment that provides for competitive pay and benefits, attractive career development opportunities, and a collaborative, respectful culture.
As of December 31, 2021, the Company had 766 employees. During 2021, the Company's overall turnover was just over 5% (with approximately 4.5% being voluntary turnover) of the total employee population.
Company Culture. The Company’s five core values of Safety, Integrity, Collaboration, Transparency, and Excellence shape its culture and identity and provide the framework for employee conduct and the Company’s relationships with its stakeholders.
The Company continues to utilize a cross-functional Culture Champions Group which solicits employee feedback on ways to further enhance corporate culture. In 2021, the Company completed its second anonymous culture survey and is in the process of assessing the results and determining key actions to implement in 2022.
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 continuing to identify and mitigate safety risks. The Health, Safety, Security and Environmental Committee of the Company's Board of Directors (Board) provides oversight for the Company's safety initiatives. The Company tracks numerous safety-related metrics to evaluate its safety performance and has incorporated safety metrics into the Company's annual incentive plan.
Diversity and Inclusion. The Company believes that diversity of thought and perspective and a team-based approach are essential to its continued success and is committed, through its Inclusion Program and other initiatives, to continuing to build a diverse, inclusive, respectful, and safe workplace. During 2021, the Company hosted, and more than 700 employees attended, eight guest speaking sessions on inclusion topics; became a Certified Age-Friendly Employer through the Age-Friendly Institute and a Corporate Champion of the Wounded Warrior Project; signed the CEO Pledge through the CEO Action for Diversity and Inclusion Coalition to publicly acknowledge the importance of diversity and inclusion; led a Pronouns Matter Campaign to encourage employees to select their preferred pronouns; provided a platform for employees to review inclusion-related content on a bi-monthly basis; facilitated Unconscious Bias training for all employees; and published an Inclusion Scorecard to capture relevant employee demographics for discussion with leadership and for all employees to review.
The Company also partners with several diverse organizations to broaden and extend its recruitment efforts, including HBCUConnect.com (Historically Black Colleges and Universities Connect), DiversityJobs.com, and RetirementJobs.com.
Total Rewards. The Company believes its employees are critical to its success and its total rewards and benefits are structured to attract and retain a talented and engaged workforce. These benefits include comprehensive health insurance for full- and part-time employees; a robust wellness program; annual flu immunizations and paid time off for COVID-19 vaccinations; access to an Employee Assistance Program; tuition reimbursement; adoption assistance and paid new parent leave; paid time off for holidays, vacation, bereavement, jury duty, military and volunteer time; paid short- and long-term disability, life insurance, and business travel insurance; medical spending accounts for eligible retirees; competitive base salaries and an annual incentive plan and long-term incentive opportunities; and a robust retirement plan with generous company matching and non-elective contributions. In addition, the Company offers flexible work arrangements based on job duties, which the Company believes will increasingly enable it to compete for talent on a broad geographic basis.
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 management personnel. The Company provides leadership training to multiple levels of Company leaders and managers, as well as customized, executive-level assessment and development programs for senior leaders. Employees at all levels within the Company are encouraged to participate in relevant developmental opportunities through Company partnerships with external learning organizations and all employees are encouraged to complete an annual development plan.
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 2021 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 or our website is not incorporated into this Annual Report on Form 10-K.
Availability of Reports

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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 therefore are subject to the business and liquidity risks of EQT, and any 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 regulatory approval process for the construction of new midstream assets is very challenging and has significantly impacted, and in the future could impact, our and the MVP Joint Venture's ability to obtain or maintain all approvals necessary to complete certain projects on time or at all. If we do not complete expansion projects and/or identify and complete inorganic growth opportunities, our future growth may be limited.
Reviews of our goodwill, intangible and other long-lived assets and equity method investment in the MVP Joint Venture have resulted in and could result in significant impairment charges.
Cyberattacks aimed at us or third parties, as well as any noncompliance by us with applicable laws and regulations governing cybersecurity and/or data privacy, could materially adversely affect us.
Increasing scrutiny and changing stakeholder expectations for ESG matters and sustainability practices may adversely affect us.
Our business is subject to climate change-related transitional risks and physical risks that could significantly increase our operating expenses and capital costs, adversely affect our customers’ development plans, and reduce demand for our products and services.
We face and will continue to face opposition to and negative public perception regarding the development of our expansion projects and the operation of our pipelines and facilities from various groups.
Our subsidiaries' significant indebtedness, and any future indebtedness, as well as the restrictions under our subsidiaries' debt agreements, could adversely affect us.
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, could impact our liquidity, access to capital, and costs of doing business.
Increased competition from other companies that provide gathering, transmission and storage, and water services, or from alternative fuel or energy 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.
The ongoing outbreak of COVID-19 and its variant strains (or any future pandemic) could harm our business, results of operations and financial condition.
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. We do not exercise control over our joint venture partners, 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.

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Expanding our business by constructing new midstream assets subjects us to risk, and we do not insure against all potential losses and could be seriously harmed by unexpected liabilities.
Significant portions of our pipeline systems have been in service for several decades, and we are subject to numerous hazards and operational risks. We do not own all of the land on which our assets are located, which could disrupt our operations and future development.
The loss or disengagement of key personnel could adversely affect our ability to execute our plans.
Our exposure to direct commodity price risk may increase in the future.
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
For the 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. If the IRS were to treat EQM as a corporation or if EQM becomes subject to additional amounts of entity-level taxation, it would reduce the amount of cash we have available to pay dividends to our shareholders.
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 has fluctuated and may further 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.
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 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. Therefore, we are subject to the business and liquidity risks of EQT, and any 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 water services. EQT accounted for approximately 59% of our revenues for the year ended December 31, 2021. 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 commodity prices, primarily natural gas and natural gas liquids (NGLs);
natural gas price volatility or a sustained period of low commodity prices, and EQT’s utilization of financial hedges, which may have an adverse effect on, as applicable, EQT’s drilling operations, revenue, profitability, future rate of growth, creditworthiness and liquidity;
decisions of EQT’s management in respect of curtailing natural gas production, choke management, timing of turning wells in line, and rig and completion activity;
a 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 to fund EQT’s operations and 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 additional 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;
the loss of key personnel and/or the effectiveness of their replacements;

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EQT’s ability to achieve its ESG and sustainability targets; and
risks associated with cybersecurity, environmental activists and other threats.
EQT may reduce its capital spending in the future based on various factors, including corporate capital allocation strategies, regional takeaway constraints, 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, as disclosed on December 13, 2021, EQT’s corporate capital allocation strategy continues to focus on capital efficiency, reducing indebtedness to achieve investment grade metrics, returning capital to its shareholders and free cash flow generation as opposed to volume growth. A reduction in the capacity subscribed or volumes transported or gathered on our systems by EQT (or sustained 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.
As discussed under the heading "Decreases in production of natural gas in our areas of operation, whether as a result of producer corporate capital allocation strategies, lower regional natural gas prices, regional takeaway constraints, and/or other factors, have adversely affected, and in the future could adversely affect, our business and operating results and reduce our cash available to pay cash dividends to our shareholders." in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K, there are a number of factors that could cause EQT and other producers to elect to reduce or maintain then-current levels of drilling activity or curtail production. 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 actual results differ from those assumptions, as has occurred in respect of, for example, the targeted full in-service date for the MVP, our ability to fully achieve the benefits we believed associated with the EQT Global GGA at the time of its execution, as well as our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders, may be adversely affected. Further, if EQT's volumetric 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 in connection with the full 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.
Decreases in production of natural gas in our areas of operation, whether as a result of producer corporate capital allocation strategies, lower regional natural gas prices, regional takeaway constraints, and/or other factors, have adversely affected, and in the future could adversely affect, our business and operating results and reduce our cash available to pay cash dividends to our shareholders.
Our business is dependent on continued natural gas production and the availability and development of reserves in our areas of operation and the production and development plans of our customers are impacted by various factors, including prices for natural gas and NGLs, which fluctuate, corporate capital allocation strategies, and regional takeaway constraints.
Prices for natural gas and NGLs, including regional basis differentials, have previously adversely affected, and may in the future adversely affect, the timing of development of additional reserves and production that is accessible by our pipeline and storage assets, which also negatively affects our water services business, and the creditworthiness of our customers. Lower natural gas prices, particularly in the Appalachian region, have in the past caused, and may in the future cause, certain producers, including certain of our customers, to determine to reduce or hold generally steady their rig count (and thereby delay or not increase production), delay turning wells in line, temporarily shut in portions of their production or otherwise take actions to slow production growth and/or reduce production, which when effected by our producer customers reduces the demand for, and usage of, our services. For instance, temporary production curtailments effected in 2020 by EQT and certain other of our customers resulted in a decrease in our volumetric-based fee revenues for portions of 2020. An extended period of low natural gas prices and/or instability in natural gas prices in future periods, especially in the Appalachian region, or other factors could cause EQT or other producers to take similar actions in the future, which could have a significant negative effect on the demand for our services, and therefore our results of operations.

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Additionally, although natural gas prices have increased from 2020 lows as of the filing date of this Annual Report on Form 10-K, higher natural gas prices have not caused our largest customers to increase their production forecasts and, even if natural gas prices remain elevated, our customers may announce in the future lower, flat or modest increases to production forecasts based on various factors, which could include regional takeaway capacity limitations, access to capital, investor expectations regarding free cash flow, a desire to reduce or refinance leverage or other factors. See, for example, “We depend on EQT for a substantial majority of our revenues. Therefore, we are subject to the business and liquidity risks of EQT, and any decrease in EQT’s drilling or completion activity (or significant production curtailments) could adversely affect our business and operating results.” in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K. Such decisions by our customers affect production levels and, accordingly, demand for our services and therefore our results of operations. Additionally, lower regional natural gas prices (including regionally), corporate capital allocation strategies or regional takeaway constraints could cause producers to determine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them. Further reduction, or continued lack of growth, in the natural gas volumes supplied by our producer customers could result in reduced throughput on our systems and adversely impact our business, including our ability to 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. For example, 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 naturally declines over time. EQT and other producers may not develop the acreage they have dedicated to us for a variety of reasons, including, among other things, the availability and cost of capital, corporate capital allocation policies, producers’ focus on generating free cash flow and/or de-levering, prevailing and projected energy prices, hedging strategies and environmental or other governmental regulations. Our ability to obtain non-dedicated sources of natural gas is affected by 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.
In addition, the amount of natural gas reserves underlying wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. 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, 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, has significantly increased costs and delayed targeted in-service dates, and decisions by regulatory and judicial authorities in pending or potential proceedings are likely to 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 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 gathering, transmission and storage systems, as applicable. The approval process for certain projects has become increasingly slower and more difficult, due in part to federal, state and local concerns related to exploration and production, transmission and gathering activities and associated environmental impacts, 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 activists requesting that issued approvals and authorizations be stayed and vacated.
Accordingly, authorizations needed for our 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, as has been the case with certain authorizations in the past, including, most recently, in January and February 2022 with respect to certain approvals for the MVP project that the Fourth Circuit vacated.

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In addition, significant delays in the regulatory approval process for projects, as well as stays and losses of critical authorizations and permits, including for the MVP and MVP Southgate projects, have significantly increased costs and delayed the targeted in-service dates for the projects, and further delays may cause similar adverse effects. Significant delays, such as that caused by the vacatur in January and February 2022 of certain approvals for the MVP project by the Fourth Circuit, 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 expected investment returns, adversely affect our willingness or ability and/or that of our joint venture partners to continue to pursue projects, and/or further cause other-than-temporary declines in value to the Company's equity investment in the MVP Joint Venture. 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), as described in more detail in “Item 3. Legal Proceedings” and "Strategy" under "Developments, Market Trends and Competitive Conditions" in “Item 1. Business.”
There is no guarantee that the MVP Joint Venture will ultimately (or timely) receive all necessary authorizations or that such authorizations will be maintained in effect following challenge, or even after projects are placed in service. 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 then-targeted time frame for placing projects in service, prior to placing projects in service, or enable the MVP Joint Venture to meet the then-targeted project costs.
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 MVP project and which have resulted in significant, adverse decisions in respect of project authorizations. Such opposition has made it increasingly difficult to complete the project and place it in service within the then-targeted time frame or at all and, following any in-service, may also affect the ability to continue operating or effect extensions and/or expansions of the project. Further, such opposition and/or adverse court rulings and regulatory determinations may have the effect of increasing that risk that at a future point joint venture partners may elect not to continue to pursue or fund the project, which would, absent additional project sponsors, significantly imperil the ability to complete the project. See "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, we exercise no control over joint venture partners 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 interest and these joint ventures are subject to many of the same operational risks to which we are subject." in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K. We also expect that other projects, such as the MVP Southgate, may be subject to similar heightened opposition. These and other challenges to our 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.
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 to begin the first day of the quarter in which the full in-service date of the MVP occurs, which provide for estimated aggregate fee relief of approximately $270 million in the first twelve-month period, approximately $230 million in the second twelve-month period and approximately $35 million in the third twelve-month period. In addition, given that the MVP full in-service date did not occur by January 1, 2022, EQT has an option, exercisable through December 31, 2022, to forgo approximately $145 million of the gathering fee relief in such first twelve-month period and approximately $90 million of the gathering fee relief in such second twelve-month period in exchange for the EQT Cash Option. Among the benefits to us pursuant to the EQT Global GGA, EQT is subject to an initial annual MVC of 3.0 Bcf per day that became effective on April 1, 2020, which annual MVC gradually steps up to 4.0 Bcf per day through December 2031 following the full in-service date of the MVP. Delays in the MVP full in-service date affect our ability to achieve 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 and equity method investment in the MVP Joint Venture have resulted in significant impairment charges, and reviews of our goodwill, intangible and other long-lived assets and equity method investment in the MVP Joint Venture could result in future significant impairment charges.
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

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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 to goodwill 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, the application of contractual terms providing for fee credit as necessary, 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. The reporting unit to which goodwill is recorded as of December 31, 2021 is the EQM Opco reporting unit (as defined and discussed in Note 4). 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 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 and 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 if 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, 2021, we had approximately $486.7 million of goodwill (all associated with the EQM Opco reporting unit) and $9.7 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, intangible asset, and property, plant and equipment 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 further suffered an other-than-temporary decline, we would also 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.
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.
Cyberattacks aimed at us or third parties, as well as any noncompliance by us with applicable laws and regulations governing cybersecurity and/or data privacy, could materially adversely affect us.

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We have become increasingly dependent upon digital technologies, including information systems, infrastructure, and cloud applications, to conduct our business, and the maintenance of our financial and other records has long been dependent upon such technologies. We depend on both our own systems, networks, and technology as well as the systems, networks and technology of our vendors, customers and other business partners. Our increasing reliance on digital technologies puts us at greater risk for system failures, disruptions, incidents, and cyberattacks, which could significantly impair our ability to conduct our business. For instance, energy industry participants, including midstream companies, have been the victims of ransomware attacks, and we expect to continue to be targeted by cyberattacks as a critical infrastructure company.
The U.S. government has continued to issue public warnings that indicate that energy assets might be specific targets of cyberattacks, and in May and July 2021, the TSA issued security directives (and subsequent amendments/revisions thereto) applicable to certain midstream companies requiring such companies to comply with mandatory reporting measures and undertake a number of specific cybersecurity enhancements for both IT and OT systems. We have been required and may further be required to expend additional resources as a result of current or new laws, regulations, directives or other requirements related to critical infrastructure cybersecurity. Any failure to remain in compliance with laws or regulations governing cybersecurity, including the TSA security directives, may result in penalties, fines, enforcement actions, or mandated changes in our practices, which may have a material adverse effect on our business and operations.
While we and our third-party service providers commit resources to the design, implementation and monitoring of our IT and OT systems, there is no guarantee that our cybersecurity measures will provide absolute security. Despite these measures, we may not be able to anticipate, detect or prevent all cyberattacks or incidents, particularly because the methodologies used by attackers change frequently or may not be recognized until launched, and because attackers are increasingly using tactics, techniques, and procedures designed to circumvent controls and avoid detection. As a result, our IT and OT systems (or those of third parties) that are designed to protect against cyber risks may not prevent or detect all cyberattacks or incidents, and deliberate attacks on, or unintentional events or incidents affecting, our systems or infrastructure or the systems or infrastructure of third parties could, depending on the extent or duration of the event, materially adversely affect us, including by leading to corruption, misappropriation or loss of our proprietary and sensitive data, delays (which could be significant) in the performance of services for our customers, difficulty in completing and settling transactions, challenges in maintaining our books and records, communication interruptions, environmental damage, regulatory scrutiny, personal injury or death, property damage and other operational disruptions, as well as damage to our reputation, financial condition and cash flows and potential legal claims and liabilities. Like other companies in the natural gas industry, we have identified and expect to continue to identify cyberattacks and incidents on our systems, but none of the cyberattacks and incidents we have identified to date has had a material impact on our business or operations.
Further, as cyberattacks continue to evolve and increase in sophistication and volume, we have expended, and expect to continue to expend, additional resources relating to cybersecurity, including, as applicable, to continue to modify or enhance our preventive, protective, and response measures and/or to investigate and remediate potential vulnerabilities to or consequences of cyberattacks and incidents. There can be no assurance that any preventive, protective, response, or remedial measures will address or mitigate all threats that arise.
The regulatory landscape with regard to data privacy continues to develop. New laws and regulations governing data privacy, as well as any unauthorized disclosure of personal information, may potentially increase our compliance costs. Any failure by us, a company that we acquire, or one of our technology service providers, to comply with these laws and regulations, where applicable, could adversely affect us, including by resulting in reputational harm, penalties, regulatory scrutiny, liabilities, legal claims and/or mandated changes in our business practices.
Increasing scrutiny and changing stakeholder expectations in respect of ESG and sustainability practices may adversely impact our business and our stock price and expose us to new or additional risks.
Companies across all industries are facing increasing scrutiny from stakeholders related to their ESG and sustainability practices. Investor advocacy groups, proxy advisory firms, certain institutional investors and lenders, investment funds and other influential investors and rating agencies are also increasingly focused on ESG and sustainability practices and matters and on the implications and social cost of their investments and loans. Stakeholders’ increased focus and activism related to ESG and sustainability matters may potentially adversely affect our business, financial condition, results of operations, and liquidity, as well as our stock price, and expose us to new or additional risks, including as described below.
Increased focus on ESG and sustainability matters, particularly with respect to climate change and related demand for renewable and alternative energy, may, among other things, hinder our access to capital given our fossil fuel-based operations and/or adversely affect demand for our services. See “Our business is subject to climate change-related transitional risks (including evolving climate-focused regulation and climate change-driven trends emphasizing financing non-fossil fuel businesses and prompting pursuit of emissions reductions, lower-carbon technologies and alternative forms of energy) and

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physical risks that could significantly increase our operating expenses and capital costs, adversely affect our customers’ development plans, and reduce demand for our products and services.” and “Increased competition from other companies that provide gathering, transmission and storage, and water services, or from alternative fuel or energy sources, could negatively impact demand for our services, which could adversely affect our financial results.” under "Item 1A. Risk Factors" in this Annual Report on Form 10-K for the year ended December 31, 2021. Additionally, pipeline infrastructure companies and projects, such as our MVP project, face increased legal scrutiny and risk, including litigation risk and enhanced and lengthier regulatory reviews by federal, state and/or environmental regulators, due to an increased focus on climate change and/or environmental justice policies and the fossil fuel industry.
We recognize that our shareholders, employees, customers, regulators, and other stakeholders expect us to continue to focus on long-term sustainable performance, including by addressing significant, relevant ESG factors, further working to prioritize sustainable energy practices, reducing our carbon footprint and promoting sustainability. We have incurred and expect to continue to incur costs and capital expenditures in doing so, and certain of such future costs and capital expenditures could be material. Further, if we do not adapt to or comply with investor or other stakeholder expectations and standards (or meet sustainability targets that we set), which are evolving, or if we are perceived not to have responded appropriately or quickly enough to growing concern for ESG and sustainability issues even if our actions are regulatorily and legally compliant, our business could suffer, including from reputational damage (and negative public perception regarding us or our industry may lead to additional regulatory scrutiny or other adverse developments). Additionally, activist shareholders may submit proposals to promote an ESG-related position. Responding to proxy contests and other actions by activist shareholders can be costly and time-consuming, disrupting our operations, causing reputational harm, and diverting the attention of our Board and senior management from the pursuit of business strategies.
In addition, as we continue to focus on long-term sustainable performance and address ESG factors, and as disclosure standards continue to evolve, including as a result of potential regulatory initiatives, we have expanded and expect to further expand our public disclosures in these areas. Such disclosures may reflect aspirational goals, targets, cost estimates and other expectations and assumptions, including over long timelines, which aspirational goals, targets, cost estimates, and other expectations and assumptions are necessarily uncertain and may not be realized. Failure to realize (or timely achieve progress on) such aspirational goals, targets, cost estimates, and other expectations or assumptions may adversely impact us. Further, a multitude of organizations that provide information to investors have developed ratings processes for evaluating companies on their approach to ESG and sustainability matters. Such ratings and reports are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings, or perceptions of us or our industry as a result of such ratings or our ESG and sustainability practices, may lead to increased negative investor and other stakeholder sentiment toward us or our customers, and to the allocation of investment capital to other industries and companies, which could negatively affect our stock price and access to and costs of capital.
The occurrence of any of the foregoing may adversely affect our business, financial condition, results of operations, liquidity and/or our stock price.
Our business is subject to climate change-related transitional risks (including evolving climate-focused regulation and climate change-driven trends emphasizing financing non-fossil fuel businesses and prompting pursuit of emissions reductions, lower-carbon technologies and alternative forms of energy) and physical risks that could significantly increase our operating expenses and capital costs, adversely affect our customers’ development plans, and reduce demand for our products and services.
Combating the effects of climate change continues to attract considerable attention in the United States and internationally, including from regulators, legislators, companies in a variety of industries, financial market participants and other stakeholders. Numerous proposals have been made and will likely continue to be made to monitor and limit existing emissions of GHGs, as well as to restrict or eliminate future emissions. Accordingly, our business and operations, and those of our producer customers, are subject to executive, regulatory, political, litigation, and financial risks associated with natural gas and the emission of GHGs.
While no comprehensive climate change legislation has been enacted at the federal level in the United States as of the filing of this Annual Report on Form 10-K for the year ended December 31, 2021, President Biden has made addressing climate change a priority of his administration, including by issuing in January 2021 an executive order recommitting the United States to the United-Nations-sponsored “Paris Agreement” (an international agreement for nations to limit GHG emissions) and announcing in April 2021 that the United States will target a 50-52% reduction in economy-wide GHG emissions by 2030 relative to 2005 levels. Accordingly, future federal GHG regulations of the oil and gas industry and legislation relating to climate change are likely. Moreover, federal regulators have taken (or announced that they plan to take or are contemplating) actions related to GHG regulations that have or may have a significant influence on our operations, including the EPA’s November 2021 proposed rule to regulate methane emissions from oil and natural gas sources and the FERC's ongoing evaluation of how to

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treat GHGs for purposes of its environmental and certificate reviews. For additional information on GHG laws, regulations and other legal requirements applicable to us, see "Regulatory Environment" and "Environmental Matters" under "Item 1. Business."
The U.S. Congress, regulatory bodies and various states also have been evaluating and/or have implemented climate-related legislation and other regulatory initiatives that would further restrict emissions of GHGs, including the establishment of market-based cap-and-trade or carbon pricing programs or imposition of fees or taxes based on the emission of GHGs by certain facilities. For example, certain Northeastern and Mid-Atlantic states in which we and/or the MVP Joint Venture operate, participate, and others are considering participating, in the Regional Greenhouse Gas Initiative agreement (RGGI) aimed at reducing carbon dioxide emissions from power plants, which could in turn lead to increased uncertainty with regard to demand for natural gas used in the generation of electricity.
Pennsylvania, which is home to our headquarters and many of our assets, approved Environmental Quality Board Final Rulemaking #7-599: CO2 Budget Trading Program (“RGGI Rules”) on September 1, 2021. This rulemaking would establish a cap on carbon dioxide emissions from fossil fuel plants and would authorize Pennsylvania to participate in RGGI. The RGGI Rules will not become effective until they are published by Pennsylvania’s Legislative Reference Bureau (“LRB”). Under Pennsylvania’s Regulatory Review Act, the LRB must provide the General Assembly time to review and reject the rulemaking before publishing the final rules. The Pennsylvania Senate and House passed concurrent resolutions disapproving the implementation of the RGGI Rules. However the Pennsylvania Governor vetoed those resolutions on January 10, 2022, leaving the Pennsylvania General Assembly with the opportunity to override that veto. The ongoing legislative review process means that the final RGGI Rules may not be promulgated until the second quarter of 2022, at the earliest. Additionally, it is anticipated that the RGGI Rules, if promulgated, will face legal challenges, which cast further uncertainty over the timing and implementation of the RGGI Rules.
Beyond Pennsylvania, it is likely that such regional and state efforts will continue and may establish additional requirements in states in which our assets are located regardless of federal action. For example, with respect to the footprints of MVP and MVP Southgate projects, North Carolina is considering rulemaking to join RGGI and Virginia currently is a member of RGGI. Virginia's recently elected governor, however, has issued an executive order calling on the state to begin the process of withdrawing from RGGI and rescinding its RGGI regulations. GHG restrictions, if implemented, may result in additional compliance obligations or taxes, and initiatives such as RGGI may adversely affect demand for natural gas and, therefore, negatively impact our producer customers, and in turn, the demand for our services. Any of these outcomes could have an adverse effect on our business, financial condition, results of operations, liquidity or ability to pay dividends to our shareholders.
There remains considerable uncertainty surrounding the timing, scope and potential impact of future action in the United States and internationally with respect to GHG emissions, including methane in particular. Although we continue to monitor legislative, regulatory and judicial developments in this area to assess potential impacts on our operations and otherwise take efforts and invest funds proactively to limit and reduce GHG emissions from our facilities, we cannot predict precisely what form future laws, regulations and legal requirements relating to climate change might take. Nor can we predict the stringency of any such requirements, when they might become effective or their exact effect on us. Further, laws, regulations and other legal requirements relating to climate change are constantly changing or being reinterpreted, and this may occur during the permitting and construction phases of our projects (which may last several years), as has been the case with our MVP and MVP Southgate projects. Generally, development and implementation of processes to comply with changing legal requirements is likely to be costly and time consuming. Further, compliance or noncompliance with existing or new climate change-focused regulations or other initiatives could adversely impact us by, among other things, imposing additional compliance obligations such as new emission control requirements, taxing the release of GHGs, causing longer permitting timelines, requiring that we purchase allowances for emissions, exposing us to regulatory penalties or affecting our reputation. Future laws, regulations and legal requirements designed to reduce GHG emissions also could make some of our activities, or those of our customers, uneconomic or less economically advantageous to maintain or operate, which may affect the estimated fair values of underlying assets and results of operations. Further, such future legislation and/or regulation may reduce the number of attractive business opportunities available to us. Additionally, climate change-focused regulations may adversely affect production of or demand for natural gas (such as by increasing the cost of producing natural gas or prompting consumers to use renewable fuels), which could have an adverse effect on our business, financial condition, results of operations, liquidity or ability to pay dividends to our shareholders. Although future laws, regulations and legal requirements relating to climate change could have a material impact on our industry and us, attempts at quantification are based on speculation of what may occur in the future. For example, based on several bills proposing the establishment of a carbon tax or carbon pricing that have been drafted across various jurisdictions, our preliminary estimate in 2021 of the potential increase in our operating cost upon the enactment of a carbon tax or carbon pricing ranged from approximately $2 million to approximately $96 million reflecting an assumed cost of carbon range and our estimated metric tons of carbon dioxide equivalent Scope 1 and 2 emissions for 2020. However, these and any

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other estimates we may make taking into account potential future laws, regulation or legal requirements are necessarily uncertain.
Litigation risks relating to climate change also are increasing. Parties have brought suit against the largest oil and natural gas exploration and production companies, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change effects, such as rising sea levels, and therefore are responsible for resultant roadway and infrastructure damages. Parties have also alleged that these companies have been aware of the adverse effects of climate change for some time but defrauded their investors and consumers by failing to adequately disclose those impacts. While we are not currently party to any such litigation, we or our customers could be named in future actions given that our business involves natural gas. Further, climate change-related factors may prompt governmental investigations or adversely affect the regulatory approval process for the construction and operation of midstream assets as, for example, opposition parties have cited our GHG operational emissions as a specific concern during comment periods for regulatory permit reviews.
Market forces driven by concern for climate change are affecting (and are expected to continue to affect) the availability and cost of capital to companies in the fossil fuel sector. For example, climate change activists 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 adding more burdensome terms to or altogether eliminating their investments in, or lending with respect to, fossil fuel energy-related activities and companies. 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. Certain financial institutions, including some that are lenders under the Amended EQM Credit Facility (as defined in Note 11), have voluntarily adopted policies that have the effect of reducing the funding provided to the fossil fuel sector, and there is also a risk that financial institutions will in the future be required to adopt such policies. These market forces may adversely affect our ability to obtain financing in the future (and thus our pursuit of initiatives, such as growth projects) or achieve increases in our stock price, and these forces may also adversely affect our customers, which could result in, among other things, increased counterparty risk and/or decreased demand for our services. Further, demand for and development of lower carbon technologies and renewable and alternative energy is increasing as a result of concern regarding climate change, which may adversely affect demand for natural gas and accordingly our producer customers.
In addition to such transitional risks, climate change also may create physical risks to our business. Climate impacts, such as increasing temperatures, changing weather patterns, and more frequent or intense floods and storms, can pose serious challenges for our facilities, supply chains, employees, contractors, current and potential customers, and the communities in which we operate. In particular, our operations are primarily focused in the Appalachian Basin, which is a rain-susceptible region. Severe and repeated rainfall events above and beyond historical estimates and magnitudes because of climate change could cause damage to our physical assets, especially facilities located in low-lying areas near streams and riverbanks and pipelines situated in landslide-prone and rain susceptible regions, which may adversely affect our operations. We may not be able to pass on resultant higher costs to our customers or recover all costs related to mitigating these physical risks or repairing damage due to such events. Further, our ability to mitigate the adverse impacts of these events depends in part on the resilience of our facilities and the effectiveness of planning for disaster preparedness and response and business continuity, which plans may not fully encompass every potential climate-driven eventuality. Additionally, changing climate patterns could impact the demand for energy in the regions we currently and plan to serve. For example, extreme warm weather in the winter months may lead to decreased natural gas usage, which may affect our results of operations.
One or more of any such developments could have an adverse effect on our business, financial condition, results of operations, liquidity or 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 or produced water spills, gas and other hydrocarbon leaks, the explosion or location of natural gas transmission and gathering lines and other facilities, erosion and sedimentation issues, unpopular expansion projects, environmental justice concerns, and general concerns raised by activists about hydraulic fracturing and pipeline projects (as well as specific concerns raised 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 the sections captioned "Regulatory Environment" and "Environmental Matters" under "Item 1. Business" as well as “Item 3. Legal Proceedings.” These actions have caused, and may continue to cause, operational delays or restrictions, increased construction and operating

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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, has significantly increased costs and delayed targeted in-service dates, and decisions by regulatory and judicial authorities in pending or potential proceedings are likely to 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 affect the MVP project and the MVP Southgate project, as applicable. 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 further cause the permits we and the MVP Joint Venture need to complete the expansion projects, including the MVP and MVP Southgate projects, and to 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 relevant assets or complete planned growth projects, which could, among other adverse effects, affect project completion or subsequent operation, 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, state and local levels aimed at the natural gas industry, including those to restrict the use of hydraulic fracturing. Adoption of legislation or regulations (which may be prompted by negative public perception) 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.
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.
Our subsidiaries have significant amounts of debt outstanding under the Amended EQM Credit Facility, the 2021 Eureka Credit Facility (as defined in Note 11) and the senior unsecured notes issued by EQM. 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’s, 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 2021 Eureka Credit Facility. The Amended EQM Credit Facility contains certain negative covenants, that, among other things, establish for EQM a maximum Consolidated Leverage Ratio (as defined in the Amended EQM Credit Facility) that varies over the course of the term ranging from not more than 5.95 to 1.00 to not more than 5.00 to 1.00, with the then-applicable ratio being tested as of the end of each fiscal quarter (which in limited circumstances may be increased for certain measurement periods following the consummation of certain acquisitions). Under the 2021 Eureka Credit Facility, Eureka is required to maintain a Consolidated Leverage Ratio (as defined in the 2021 Eureka Credit Facility) of not more than 4.75 to 1.00 (or not more than 5.25 to 1.00 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 2021 Eureka Credit Facility) for the four fiscal quarters then ending to Consolidated Interest Charges (as defined in the 2021 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 2021 Eureka Credit Facility each contain certain events of default, including the occurrence of a change of control.
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

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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 and the 2021 Eureka Credit Facility each contain a cross default provision that applies to a default related to any other indebtedness the applicable borrower may have with an aggregate principal amount in excess of $25 million as to EQM, and $10 million as to Eureka.
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 seeking modifications to the terms of our debt agreements, 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 timely 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, repayment of existing indebtedness, 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 increase our capital costs or adversely affect our operating flexibility or ability to raise capital in the future. See "A further downgrade of EQM's credit ratings, including in connection with the MVP project or customer credit rating changes, which are determined by independent third parties, could impact our liquidity, access to capital, and costs of doing business." in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K.
Additionally, our ability to obtain financing in the future may be adversely affected by market forces driven by concern for climate change. See “Our business is subject to climate change-related transitional risks (including evolving climate-focused regulation and climate change-driven trends emphasizing financing non-fossil fuel businesses and prompting pursuit of emissions reductions, lower-carbon technologies and alternative forms of energy) and physical risks that could significantly increase our operating expenses and capital costs, adversely affect our customers’ development plans, and reduce demand for our products and services.” in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K.
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 grow and maintain our asset base and complete 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 grow 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, as well as potential strategic transactions, if any, 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

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obtain or maintain 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, the status of the MVP project, general economic conditions, 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 and cost of capital to companies in the fossil fuel sector. See “Our business is subject to climate change-related transitional risks (including evolving climate-focused regulation and climate change-driven trends emphasizing financing non-fossil fuel businesses and prompting pursuit of emissions reductions, lower-carbon technologies and alternative forms of energy) and physical risks that could significantly increase our operating expenses and capital costs, adversely affect our customers’ development plans, and reduce demand for our products and services.” in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K.
Even if we or our subsidiaries are successful in obtaining funds through debt or equity financings, as applicable, the terms thereof could limit our ability to pay dividends to our shareholders and otherwise adversely affect us, such as by requiring additional or more restrictive covenants that impose operating and financial restrictions or, in the case of debt, requiring that collateral be posted to secure such debt. 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.
A further downgrade of EQM’s credit ratings, including in connection with the MVP project or customer credit ratings changes, which are determined by independent third parties, could impact our liquidity, access to capital, and costs of doing business.
As of February 23, 2022, 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 the credit profile of our customers.
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. 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, operational risks, various financial tests, ESG matters, as well as analysis of various financial metrics. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time.
If any credit rating agency further downgrades or withdraws EQM’s ratings, including for reasons relating to the MVP project (such as for delays in the targeted full in-service date of the MVP project or increases in such project’s targeted costs), EQM’s leverage or credit ratings of our customers, our and our subsidiaries’ respective access to the capital markets could become more challenging, borrowing costs will likely increase, our operating flexibility may be adversely affected, EQM may be required to provide additional credit assurance (the amount of which may be substantial), including the Cash Option Letter of Credit (as discussed in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations"), 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 and/or more restrictive terms associated with modifications to existing debt instruments, any further downgrade could also require additional or more restrictive covenants on future

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indebtedness that impose operating and financial restrictions on us or 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 resulting from a credit rating downgrade, and/or more restrictive covenants or the pledging of security, 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 lack of diversification of our assets and geographic locations could adversely affect us.
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 and continuing challenges to completing expansion projects such as the MVP and MVP Southgate, 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 from the Appalachian Basin or increases in supply of natural gas (such as if associated gas production were to continue to recover and return to or exceed pre-COVID-19 pandemic levels) 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.
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 adequately assess 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 23, 2022, EQT’s public debt had sub-investment grade credit ratings of BB+ with a positive outlook at S&P, Ba1 with a stable outlook at Moody’s, and BB+ with a stable outlook at Fitch. Periods of natural gas price declines and sustained periods of low natural gas and NGL prices, previously have had, and could in the future have, an adverse effect on the creditworthiness of our customers, including their ability to pay firm reservation fees under long-term contracts. For example, the low commodity price environment in 2019 and 2020 negatively impacted natural gas producers causing some producers significant economic stress including, in certain cases, to file for bankruptcy protection or to seek renegotiated contracts. 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 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. To the extent one or more of our counterparties is in financial distress or commences bankruptcy proceedings, contracts with these counterparties may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code (Bankruptcy Code). Nonpayment and/or nonperformance by our counterparties 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.
Our future growth may be limited if we do not complete expansion projects and/or identify and complete suitable acquisitions and other strategic transactions and realize anticipated benefits therefrom, 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, such as the MVP and MVP Southgate projects (and related expansions 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;

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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;
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 staunch opposition to the development of expansion projects (such as the MVP project) and operation of our pipelines and facilities from environmental groups, landowners, local, regional and national groups opposed to the natural gas industry and/or fossil fuels generally, 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 (or continues to delay or interrupt) 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.
We also periodically evaluate inorganic growth opportunities, including additional interests in existing joint ventures. There is no guarantee that we will be able to identify, compete for and/or complete, suitable strategic transactions, or, in the case of any such strategic transaction, achieve synergies or other potential benefits. See also “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.” in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K.
Failure to achieve growth 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.
Our growth strategy includes organic and greenfield growth projects. The development and construction of pipeline infrastructure and storage facilities and the optimization of such assets involve numerous regulatory, environmental, political and legal uncertainties that are beyond our control, and require the expenditure of significant amounts of capital and expose us to risks. Those risks include the failure to meet customer contractual requirements; delays caused by landowners; delays caused by advocacy groups or activists opposed to the natural gas industry through lawsuits or intervention in regulatory proceedings; environmental hazards; vandalism; adverse weather conditions; the performance of third-party contractors; delays caused by evolving regulatory or legal requirements; the lack of available skilled labor, equipment and materials (or escalating costs in respect thereof) 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, within budgeted cost, or, in the case of the MVP Joint Venture may continue to be delayed and exceed the budgeted cost, or at all. For example, public participation, including by pipeline infrastructure opponents, in the review and permitting process of projects, through litigation or otherwise, can introduce uncertainty and adversely affect project timing, completion and cost. See also “The regulatory approval process for the construction of new midstream assets is very challenging, has significantly increased costs and delayed targeted in-service dates, and decisions by regulatory and judicial authorities in pending or potential proceedings are likely to 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.” in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K. Further, civil protests regarding environmental justice and social issues, including proposed construction and location of infrastructure associated with fossil fuels, may lead to increased litigation, legislative and regulatory initiatives and review at federal, state, tribal and local levels of government that could prevent or delay the construction of such infrastructure and realization of associated revenues.
Additionally, construction expenditures on projects may occur over an extended period, yet we will not receive revenues from, or realize any material increases in cash flow as a result of, the relevant project until it is placed into service. Moreover, our cash flow from a project may be delayed or may not meet our expectations. Furthermore, we may construct facilities to capture

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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. Such issues in respect of the construction of midstream assets could adversely affect 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, some of which we have experienced and/or could experience in the future, include but are not limited to:
damage to pipelines, facilities, equipment, environmental controls and surrounding properties caused by hurricanes, earthquakes, tornadoes, abnormal amounts of rainfall, floods and flash flooding, 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 or of fresh, mixed 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.
Any such events, certain of which we have experienced, and any of which we may experience in the future, could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment or interruption, which could be significant, of our operations, regulatory investigations and penalties and substantial losses to us and could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. 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. Accidents or other operating risks have resulted, and in the future could result, in loss of service available to our customers. Potential customer impacts arising from service interruptions on segments of our systems 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 retain customers, as well as potentially negatively impact 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 or energy sources, could negatively impact 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, including if 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 continue to have the effect of increasing the natural gas transmission and storage options for our 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

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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 and development of renewable and alternative energy is increasing as a result of concern regarding climate change. Further, renewable and alternative energy continues to become more cost competitive with fossil fuels, including natural gas, and is growing more widely available. Continued increases, whether driven by regulation or consumer preferences, 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 adversely affect our producer customers and lead to a reduction in demand for our 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, including from renewable and alternative energy, 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 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 14 years and 13 years, respectively, as of December 31, 2021. The extension or replacement of existing contracts depends on a number of factors beyond our control, including, but not limited to, 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 and us. For more information related to contracting practices applicable to us see “Regulatory Environment – FERC Regulation” under “Item 1. Business.”
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.
The ongoing outbreak of COVID-19 and its variant strains (or any future pandemic) could harm our business, results of operations and financial condition.
Disruptions caused by pandemics, epidemics or disease outbreaks, such as COVID-19 and variants thereof, could materially affect the domestic and global economy, the natural gas industry, and/or us. The COVID-19 pandemic is ongoing and there is considerable uncertainty regarding the extent to which COVID-19 and variant strains will continue to spread and the effects of such continued spread.
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, and/or us; however, our business, results of operations and financial condition could be negatively affected in numerous ways, including, without limitation, that:
demand for natural gas could be adversely affected, as was the case in 2020, which could negatively affect prices and forward prices for natural gas and our customers, including their development plans and, consequently, lead to curtailments or otherwise decrease demand for our services or heighten our exposure to customer risk;
our operations, or those of our customers or suppliers, may be disrupted or become less efficient if a significant number of employees or contractors are unavailable due to illness;
we, our customers and suppliers may be adversely affected due to the continued constraints on global supply chains resulting from the outbreak and may be adversely affected if the outbreak causes further or long delays in access to or

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increases to cost of inventory, equipment or other items necessary to our, our customers’ or our suppliers’ respective businesses;
legal and regulatory processes relevant to our operations 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, 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).
Further, we could be affected by governmental mandates and responses to the pandemic. See “The loss or disengagement of key personnel could adversely affect our ability to execute our strategic, operational and financial plans.” in this Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K.
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 continue to 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 or escalating circulation of new strains of the virus (including those with potential immune evasion or escape mutations), 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 and mandates.
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 and where shippers require it. To the extent that we lack available capacity on our systems for volumes, or we cannot economically increase capacity, 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 which could require volumetric exposure or potentially direct commodity exposure, and we may not be willing to agree to such other forms of contractual arrangements.
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 access to such systems is impaired, the amount of natural gas that our gathering systems can gather and transport previously has been, and in the future would be, adversely affected, which has in the past reduced and could, as applicable, 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, as has occurred in the past. Any temporary or permanent interruption at any key pipeline interconnect or facility could have a material

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adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
A substantial majority 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 could 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, 2021, 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, we exercise no control over joint venture partners 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 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. 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, may elect not to support further pursuit of projects, and/or may not satisfy their financial obligations to the joint venture. The loss of joint venture partner support in further pursuing or funding a project may significantly adversely affect the ability to complete the project. 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. For example, we may not be able to obtain financing at, or in respect of, a joint venture, which could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
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 completed acquisition involves potential risks, including, among other things:
failure to realize assumptions about volumes, revenues, capital expenditures and costs, including synergies and potential growth;
an inability to secure or maintain adequate customer commitments to use the acquired systems or facilities;
an inability to successfully integrate the assets or businesses we acquire;
we could be required to contribute additional capital to support acquired businesses or assets, and we may assume liabilities that were not disclosed to us, for which we are not indemnified or insured or for which our indemnity or insurance is inadequate;
the diversion of management’s and employees’ attention from other business concerns in a manner that is disproportionate to the relative size and impact of, or ownership percentage in, such acquired assets or entities; and
unforeseen difficulties operating a larger organization or 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 over the long term 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.
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 certain 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, cyberattacks, governmental action or inaction. The occurrence of any 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 certain damage caused by cyberattacks.
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.
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. Any such adverse events or any significant increase in maintenance and repair expenditures or downtime, or related loss of revenue, due to the age or condition of our systems could adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
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 depends, 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.
On November 4, 2021, OSHA issued the ETS to carry out President Biden’s executive order requiring all employers with at least 100 employees to ensure that their employees are fully vaccinated or require unvaccinated workers to produce a negative test result at least once a week. On January 13, 2022, the U.S. Supreme Court granted an application to stay the ETS pending disposition of the applicants' petitions for review in the U.S. Court of Appeals for the Sixth Circuit. Effective January 26, 2022, OSHA withdrew the ETS as an enforceable emergency temporary standard, but did not withdraw the ETS as a proposed rule.

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Should the ETS, or a similar state or local requirement, take effect in the future, the Company expects it would be subject to such regulation concerning COVID-19 vaccination or testing. In that case, the Company may be required to implement a requirement that many or most employees get vaccinated, subject to limited exceptions, or be tested. Such a mandate may result in increased costs, operational disruptions or employee attrition for the Company, which could be material. If we lose employees, it may be difficult in the current competitive labor market to find replacement employees, and this could have an adverse effect on future operations, revenues and costs, which could be material. Accordingly, implementation of and complying with the ETS or a similar state or local requirement could have a material adverse effect on our business and results of operations.
Our exposure to direct commodity price risk may increase in the future.
For the years ended December 31, 2021, 2020 and 2019, approximately 64%, 66% and 58%, respectively, of our operating 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. 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 may have a greater exposure to fluctuations in customer volume variability driven by commodity price risk than our current operations. Significantly greater 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 full in-service date occurs through 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 18, 2022 and the terms of the Henry Hub cash bonus payment provision, any adverse change in assumptions regarding the MVP project may further decrease the estimated fair value of the derivative asset attributable to the Henry Hub cash bonus payment provision, and such decrease may be substantial. Such changes in estimated fair value, if any, would be recognized in other (expense) income, net, 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 have been, and in the future could be, subject to more onerous terms, and/or increased costs or delays, in retaining 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. As has been the case in the past, 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. The FERC has announced a policy that would presumptively stay the effectiveness of certain future construction certificates, which may limit when we are able to exercise condemnation authority. It is possible that the U.S. Congress may amend Section 7 of the NGA to codify the FERC's presumptive stay or otherwise limit, modify, or remove the ability to utilize condemnation. 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 have caused us to, and in the future 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.
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, and related litigation, could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends.

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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 that may be 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, 2021, 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 rates or 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 FERC and Congress may continue to evaluate changes in the NGA or new or modified FERC regulations or policies that may impact our operations and affect our ability to construct new facilities and the timing and cost of such new facilities, as well as the rates we charge our customers and the services we provide.
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, issuance of such authorizations or permits with unanticipated conditions, or the loss of a previously-issued authorization or permit, 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. For example, see “Developments, Market Trends and Competitive Conditions” under “Item 1. Business.” and “Item 3. Legal Proceedings.” for a discussion of certain such regulatory matters relevant to the MVP and the MVP Southgate 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 $1.3 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.
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 and other laws and regulations that expose us to significant costs and liabilities that could exceed our expectations and affect our business. The current laws and regulations affecting our business are subject to change and in the future we may be subject to additional or revised laws, regulations and legal requirements, that could adversely impact our business.
Our operations are regulated extensively at the federal, state and local levels. For additional information on laws, regulations and other legal requirements applicable to us, see “Regulatory Environment” under “Item 1. Business.” Laws, regulations and other legal requirements applicable to our business, including relating to the environmental protection, health and safety, as well

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as climate change, have, among other things, increased, and in the future could continue to increase, our cost of compliance and doing business, including costs related to planning, designing, permitting, constructing, installing, operating, updating and/or abandoning gathering, transmission and water systems and pipelines, as well as storage systems. The need to comply with such laws, regulations and other legal requirements, and incidents of noncompliance, whether by us or third parties with whom we engage, has adversely affected and will likely continue to adversely affect our business, such as by, among other things and as applicable, resulting in costly delays, operating restrictions and diversion of management time and resources in evaluating the ability to pursue projects, such as when new or additional permits or alternative construction methods are required. For example, as discussed under “The regulatory approval process for the construction of new midstream assets is very challenging, has significantly increased costs and delayed targeted in-service dates, and decisions by regulatory and judicial authorities in pending or potential proceedings are likely to 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 applications for and/or challenges to certain aspects of the MVP project and the MVP Southgate project that affect the MVP project and the MVP Southgate project, as applicable, including those litigation and regulatory-related delays discussed in “Item 3. Legal Proceedings.” In addition, noncompliance with applicable laws, regulations or other legal requirements, including required permits and other approvals, could subject us to, among other things, claims for personal injuries, property damage and other damages and, even if as a result of factors beyond our control and irrespective of our fault, could result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties and damages that could materially and negatively affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. The risk of our incurring environmental costs and liabilities in connection with our operations is significant given our handling of natural gas, produced water and other hydrocarbons, as well as air emissions related to our operations. Risk is also present as a result of historical industry operations and waste disposal practices, and our handling of waste. These matters are subject to stringent and complex federal, state and local laws and regulations governing environmental protection and could affect our business in many ways. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. We may not be able to recover all or any of these costs from insurance. Further, we are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities that are acquired into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.
Laws, regulations and other legal requirements applicable to our business also are constantly changing, and implementation of compliant processes in response to such changes could be costly and time consuming. As an example, the FWS receives hundreds of petitions to consider listing of additional species as endangered or threatened and is regularly sued or threatened with lawsuits to address these petitions. Some of these legal actions have resulted, and may in the future result, in the listing of species located in our operating areas. 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 has adversely affected and may in the future adversely affect our assets or projects. Additionally, as discussed under “Regulatory Environment” in “Item 1. Business”, federal and state governments and agencies, including states where we operate, have made advancing environmental justice a priority. A significant number of current environmental justice initiatives focus on enhancing public participation in permitting and other project development-related decisions. We have been, and in the future may be, the target of objections to permits before state and federal agencies and related litigation brought by individuals or advocacy organizations that are purporting to raise environmental justice issues. In addition, various federal agencies, including EPA and DOJ, have announced plans to seek out opportunities to address environmental justice issues through federal enforcement actions. Revised or additional laws, regulations or legal requirements (or interpretations thereof) that result in increased compliance costs, litigation or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, or affect our customers’ production and operations, could have a material adverse effect on our business, financial position, results of operations, liquidity and ability to pay dividends to our shareholders.
For information related to risks associated with laws and regulations concerning climate change, see “Our business is subject to climate change-related transitional risks (including evolving climate-focused regulation and climate change-driven trends emphasizing financing non-fossil fuel businesses and prompting pursuit of emissions reductions, lower-carbon technologies and alternative forms of energy) and physical risks that could significantly increase our operating expenses and capital costs, adversely affect our customers’ development plans, and reduce demand for our products and services.

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We may incur significant costs and liabilities as a result of adverse events or 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. PHMSA has also recently adopted regulations extending existing design, operational and maintenance, and reporting requirements to onshore gathering pipelines in rural areas.
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 likely 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 wastewater from shale gas extraction operations to publicly owned treatment plants 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 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. The Biden Administration temporarily banned new leases for oil and gas drilling on federal lands in January 2021, but that ban was subsequently blocked by a federal court. Also, certain 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 have conducted 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. EPA has more recently sought input from states and stakeholders on approaches to management of wastewater produced from oil and gas extraction at onshore facilities, and published a summary of the input it received in May 2020. The results of such reviews or studies could spur initiatives to further regulate hydraulic fracturing.
State and federal regulatory agencies 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.

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The adoption of new laws, regulations, ordinances, or executive actions 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 the 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 such 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 be required to 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.
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 payments or, if EQM is required to bear such payments, such payments could have a material adverse effect on our business, financial position, results of operations, liquidity and ability to pay dividends to our shareholders.
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 after 2017 and before 2021, we and potentially former unitholders may be required to reimburse it for such payment or, if EQM is required to bear such payments, such payments could have a material adverse effect on our business, financial position, results of operations, liquidity and ability to pay dividends to our shareholders.
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

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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 has fluctuated and may fluctuate significantly.
The market price of our common stock has experienced substantial price volatility in the past and may continue to do so due to a number of factors, some of which may be beyond our control. General market fluctuations, industry factors, such as climate change-related transitional risks, and general economic and political conditions and events, such as economic slowdowns or recessions, as well as factors specific to our business, have caused and could also continue to cause our stock price to decrease regardless of operating results. If we fail to meet expectations related to future growth, profitability, cash dividends, strategic transactions or other market expectations, the market price of our common stock may decline significantly. Additionally, 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 5.3% of our outstanding common stock as of December 31, 2021, when it deems appropriate, but in no event later than November 12, 2023. There can be no assurance regarding the method by which EQT will dispose of its interest in or the actual timing of any such disposal.

However, 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. Further, 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.

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.
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 previously has reduced, and in the future may decide to further 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 issue share-based awards to our employees under our employee benefits plans.

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In addition, our Second 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 “The 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.”, 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 Second Amended and Restated Articles of Incorporation and Third Amended and Restated Bylaws, as well as provisions of Pennsylvania law, could impair an attempt to acquire us.
Our Second Amended and Restated Articles of Incorporation and Third 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:
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 and appointment 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 Second Amended and Restated Articles of Incorporation or Third 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.
Our Third 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 Third 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 Second Amended and Restated Articles of Incorporation or Third 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 Third Amended and Restated Bylaws does not apply to actions arising under the Securities Act or the Exchange Act.

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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.
The 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.
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.
We are party to 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.
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.

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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.
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. 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.
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. 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.

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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 contemplated 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.
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.
Arbitration Decision in 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.

Swarts Storage Field. On April 8, 2021, the PADEP notified the Company that it considered certain aspects of the storage field to be out of compliance due to an alleged failure to plug or recondition wells within 2,000 feet of ongoing coal mining activities by CONSOL Energy Inc. and that a number of wells on the property allegedly did not meet current plugging standards. The

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Company disputes these claims and is working with the PADEP and CONSOL Energy Inc. to resolve these issues. Based on the discussion with the PADEP, the Company anticipates a notice of violation (NOV) will be issued. If penalties are pursued and ultimately imposed, the 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 Company's financial condition, results of operations or liquidity.
MVP Matters
The MVP Joint Venture is currently defending certain agency actions and judicial challenges to the MVP, any of which could affect the ability to complete or operate the project, including the following:

Sierra Club, et al. Petitioners v. State Water Control Board, et al. Respondents and Mountain Valley Pipeline, Intervenor, Docket No. 21-2425, Fourth Circuit Court of Appeals (Fourth Circuit). On December 20, 2021, the Virginia Department of Environmental Quality (VADEQ) certified that the MVP project would satisfy Virginia’s water quality standards based on its comprehensive nine-month review of the MVP Joint Venture’s Joint Permit Application (VA 401 Permit). On December 22, 2021, Petitioners filed their petition challenging the VADEQ’s approval of the VA 401 Permit with the Fourth Circuit. On December 22, 2021, the Petitioners filed a request for an administrative stay with the VADEQ which was denied on January 4, 2022. On January 4, 2022, the Petitioners filed a petition with the Fourth Circuit seeking a judicial stay of the VA 401 Permit pending a decision on the merits. On February 11, 2022, Petitioners withdrew the stay petition. If the challenge were successful on its merits, it could result in the MVP Joint Venture's VA 401 Permit being delayed or vacated and/or additional legal proceedings, the outcome of which the Company cannot predict, and cause a delay or further delay in the targeted full in-service date for the MVP project (and consequent impacts related to such delay), or otherwise adverse effects.

Sierra Club, et al. Petitioners v. West Virginia Department of Environmental Protection, et al. Respondents and Mountain Valley Pipeline, Intervenor, Docket No. 22-1008, Fourth Circuit. On December 30, 2021, the West Virginia Department of Environmental Protection (WVDEP) certified that the MVP project would satisfy West Virginia’s water quality standards based on its comprehensive nine-month review of the MVP Joint Venture’s Joint Permit Application (WV 401 Permit). On January 3, 2022, Petitioners filed their petition challenging the WVDEP’s approval of the WV 401 Permit with the Fourth Circuit. On January 4, 2022, the Petitioners filed a request for an administrative stay with the WVDEP which was denied on January 11, 2022. On January 11, 2022, Petitioners filed a petition with the Fourth Circuit seeking a judicial stay of the WV 401 Permit pending a decision on the merits. The stay petition was denied by the Fourth Circuit on February 8, 2022. If the challenge were successful on its merits, it could result in the MVP Joint Venture's WV 401 Permit being delayed or vacated and/or additional legal proceedings, the outcome of which the Company cannot predict, and cause a delay or further delay in the targeted full in-service date for the MVP project (and consequent impacts related to such delay), or otherwise adverse effects.

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, filed in December 2017, the Sierra Club challenged a Bureau of Land Management (BLM) decision to grant a right-of-way to the MVP Joint Venture and a U.S. Forest Service (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 SEIS 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 Department of the Interior's Fish and Wildlife Service (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, on January 15, 2021, the BLM 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). On January 11, 2021, Sierra Club, et al. filed a petition with the Fourth Circuit to reverse the USFS approval of the Record of Decision and, on January 15, 2021, filed a petition with the Fourth Circuit challenging BLM’s grant of the JNF Right-of-Way. See Wild Virginia, et al. v. United States Forest Service, et al., No. 21-1039(L). The Fourth Circuit consolidated the challenges to the Record of Decision and the JNF Right-of-Way and briefing was completed. Oral argument occurred on October 29, 2021. On January 25, 2022, the Fourth Circuit, agreeing in part with the petitioners, vacated and remanded the Record of Decision and the JNF Right-of-Way, finding fault with (i) the USFS’ and BLM’s consideration of certain data from the U.S. Geological Survey and (ii) the USFS’ and BLM’s authorization of the use of conventional bores for stream crossings within the JNF based on a variance issued by the FERC, and, as a result of such issues, (iii) the USFS’ amendments in connection with the Record of Decision to the Jefferson Forest plan. The

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vacatur of the Record of Decision and the JNF Right-of-Way may result in appellate and/or additional agency proceedings (the outcome of which the Company cannot predict) and has caused a delay in the targeted full in-service date for the MVP project (and consequent impacts relating to such delay). The Company cannot predict whether and when any new authorizations will be received from the USFS and BLM and, if received, the result of any challenge to such authorizations.
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 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. 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). Briefing in Sierra Club, et al. v. FERC, Case No. 20-1512 (consolidated with No. 21-1040), D.C. Circuit Court of Appeals was completed in January 2022 and oral argument is scheduled for April 7, 2022. If any of the challenges to the FERC's October 9, 2020 and December 17, 2020 orders are successful, it could result in the FERC's orders being vacated and/or additional agency proceedings (the outcome of which the Company cannot predict) and cause a delay or further delay in the targeted full in-service date for the MVP project (and consequent impacts relating to such delay), or otherwise adverse effects.

Challenges to FERC Certificate, Court of Appeals for 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 NGA 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 the 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 asked the DC Circuit to overturn the decision of the lower court. Oral argument before the DC Circuit was scheduled for March 29, 2021, but the court cancelled and held oral argument in abeyance and directed the parties to file motions to govern future proceedings following a decision by the U.S. Supreme Court in PennEast Pipeline Co. v. New Jersey, Case No. 19-1039, which decision was published on June 29, 2021. Briefing in Bohon et al. v. FERC et al., Case No.

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20-00006 on the significance of the PennEast Pipeline Co. opinion was completed on July 29, 2021. The DC Circuit issued an order on September 15, 2021 denying appellants' motion for summary reversal of the decision of the lower court and supplemental briefing was completed as of October 6, 2021. Oral argument occurred on December 15, 2021 and the parties are awaiting a decision. 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. Briefing in Sierra Club, et al. v. FERC, Case No. 20-1512 (consolidated with No. 21-1040, D.C. Circuit), was completed in January 2022 and oral argument is scheduled for April 7, 2022. 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, and cause a delay or further delay in the targeted full in-service date for the MVP project (and consequent impacts related to such delay), or otherwise adverse effects.

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 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 under "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 was fully briefed as of March 19, 2021. Oral argument occurred on October 29, 2021. On February 2, 2022, the Fourth Circuit vacated and remanded the New BiOp holding, in part, that the FWS did not adequately analyze the environmental context for species at issue. The vacatur of the New BiOp may result in appellate and/or additional agency proceedings (the outcome of which the Company cannot predict) and has caused a delay in the targeted full in-service date for the MVP project (and consequent impacts relating to such delay). The Company cannot predict whether and when a new BiOp will be received from the FWS and, if received, the result of any challenge to such biological opinion.
Other Proceeding Relevant to the MVP Project
FERC Rulemaking on Construction Commencement. The MVP Joint Venture is a party to a FERC rulemaking proceeding that may potentially affect when the MVP Joint Venture is permitted to commence the crossings of streams and wetlands utilizing trenchless construction methods following the FERC’s issuance of its amended Certificate for the MVP project, as described above in "Strategy" under "Developments, Market Trends and Competitive Conditions" in "Item 1. Business." On May 4, 2021, the FERC issued Order No. 871-B. Order No. 871-B and its predecessors relate to an industry-wide rulemaking regarding construction commencement while a rehearing request is pending before the FERC. The MVP Joint Venture filed a request for clarification or rehearing of the certificate amendment aspects of Order No. 871-B with the FERC on June 3, 2021. The FERC issued Order No. 871-C on August 2, 2021. The Company cannot predict the impact of Order No. 871 and its progeny, or the FERC policies discussed in "Regulatory Environment - FERC Regulation" under "Item 1. Business.", on the MVP project, if any.
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 in connection with the project, in addition to working to address matters affecting the MVP, 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

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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. The matter has been fully briefed and oral argument was held on January 19, 2022 and the parties are awaiting a decision. 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, and cause a further delay to the MVP Southgate project (and consequent impacts relating to such delay), or otherwise adverse effects.
Mountain Valley Pipeline, LLC v. North Carolina Department of Environmental Quality, No. 20-1971, Fourth Circuit Court of Appeals. On August 11, 2020, the North Carolina Department of Environmental Quality (NCDEQ) denied the MVP Southgate project’s application for a Clean Water Act Section 401 Individual Water Quality Certification and Jordan Lake Riparian Buffer Authorization and such denial was reissued by the NCDEQ on April 29, 2021. See "MVP Southgate Project" under "Developments, Market Trends and Competitive Conditions" in "Item 1. Business" for additional information. The Company is evaluating next steps, including the submission of a new application for a Clean Water Act Section 401 Individual Water Quality Certification and Jordan Lake Riparian Buffer Authorization for the MVP Southgate project, but cannot guarantee whether a new application, if submitted, will ultimately be approved or, if approved, whether conditions may be included as part of such approval or whether the application would then be further challenged.
Mountain Valley Pipeline, LLC v. State Air Pollution Control Board et al., U.S. Court of Appeals for the Fourth Circuit. On December 3, 2021, the Virginia State Air Pollution Control Board (VAPCB) voted 5-2 to deny the air permit for the MVP Southgate project’s Lambert Compressor Station (the Lambert Air Permit). On December 31, 2021, the MVP Joint Venture filed a Petition for Review in the Fourth Circuit to review the VAPCB’s December 3, 2021 denial of the Lambert Air Permit. The Company anticipates that the matter will be fully briefed by April 26, 2022. The Company cannot guarantee whether the MVP Joint Venture’s appeal will be successful and, if it were successful, and if the Lambert Air Permit were issued, that the decision or permit would not be further challenged and what the outcome or impact of any such challenge would be.
Item 4.        Mine Safety Disclosures
Not applicable.
Information About Our Executive Officers
NameAgeYear Initially Elected as Executive OfficerTitle
Thomas F. Karam632018Chief Executive Officer
Diana M. Charletta492018President and Chief Operating Officer
Kirk R. Oliver642018Senior Vice President and Chief Financial Officer
Stephen M. Moore622019Senior Vice President and General Counsel
Brian P. Pietrandrea472019Vice President and Chief Accounting Officer
Mr. Karam was appointed Chief Executive Officer and Chairman of the Board of Equitrans Midstream in July 2019. Prior to that, Mr. Karam served as President and Chief Executive Officer of Equitrans Midstream since September 2018 and a Director since November 2018. Prior to his service at Equitrans Midstream, he served as senior vice president, EQT and president, midstream from August 2018, serving in those capacities until the Separation. Mr. Karam served as chief executive officer and chairman of the EQM General Partner from July 2019 until the EQM Merger in June 2020, chairman, president and chief executive officer, from October 2018 to July 2019, and as president, chief executive officer and director, from August 2018 to October 2018. Additionally, he served as chairman, president and chief executive officer of the general partner of EQGP from October 2018 through the consummation of the EQGP Buyout, as well as president, chief executive officer and director from August 2018 to October 2018. Mr. Karam served on EQT’s board of directors from November 2017 until the Separation. Mr. Karam is the founder and served as chairman of Karbon Partners, LLC, which invests in, owns, constructs, and operates midstream energy assets, from April 2017 to August 2018. Mr. Karam previously served as the founder, chairman and chief executive officer of the general partner of PennTex Midstream Partners, LP (PennTex), a publicly traded master limited partnership with operations in North Louisiana and the Permian Basin from 2014 until its sale to Energy Transfer Partners in 2016. Preceding PennTex, he was the founder, chairman and chief executive officer of Laser Midstream Partners, LLC, one of

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the first independent natural gas gathering systems in the northeast Marcellus Shale, from 2010 until 2012 when it was acquired by Williams Partners.
Ms. Charletta was appointed President and Chief Operating Officer of Equitrans Midstream in July 2019. She was appointed Executive Vice President and Chief Operating Officer of Equitrans Midstream in September 2018. She also served as executive vice president, chief operating officer and a director of the EQM General Partner from October 2018 through July 2019, when she was promoted to president and chief operating officer. She served as president, chief operating officer and director of the EQM General Partner through the EQM Merger. Ms. Charletta served as the executive vice president, chief operating officer and as a director of EQGP's general partner from October 2018 through the consummation of the EQGP Buyout. Ms. Charletta joined EQT in 2002 as a senior pipeline engineer and from that time held various management positions with increasing responsibility. She assumed the role of senior vice president of midstream operations of a subsidiary of EQT in December 2013 and was promoted to senior vice president of midstream engineering and construction in July 2017, a position she held until the Separation.
Mr. Oliver was appointed Senior Vice President and Chief Financial Officer of Equitrans Midstream in September 2018. He also served as senior vice president, chief financial officer and a director of the EQM General Partner from October 2018 through the EQM Merger. Mr. Oliver served as the senior vice president, chief financial officer and as a director of the general partner of EQGP from October 2018 through the EQGP Buyout. Prior to joining Equitrans Midstream, he was chief financial officer for UGI Corporation, which distributes, stores, transports and markets energy products and related services, from October 2012 through May 2018.
Mr. Moore was appointed Senior Vice President and General Counsel of Equitrans Midstream in April 2019. Prior to joining Equitrans Midstream, Mr. Moore was general counsel of PennTex Midstream Partners, LP, a publicly traded master limited partnership, from 2014 through 2017. From March 2018 to April 2019, Mr. Moore served as special projects counsel to UGI Corporation.
Mr. Pietrandrea was appointed as Vice President and Chief Accounting Officer of Equitrans Midstream in August 2019. He also served as vice president and chief accounting officer of the EQM General Partner from August 2019 through the EQM Merger. Mr. Pietrandrea also served as controller of certain subsidiaries of Equitrans Midstream effective upon the Separation until his promotion in August 2019. Prior to joining Equitrans Midstream, Mr. Pietrandrea served in various roles of increasing responsibility at a subsidiary of EQT, including director, partnership accounting and reporting, from October 2013 through February 2017, controller, from March 2017 through February 2018, and vice president and controller from March 2018 through the Separation.
All executive officers have executed agreements with the Company and serve at the pleasure of the Board. Officers are elected annually to serve during the ensuing year or until their successors are elected and qualified, or until their death, resignation or removal.
PART II
Item 5.        Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Equitrans Midstream common stock trades on the NYSE under the symbol "ETRN".
As of January 31, 2022, there were 1,827 shareholders of record of Equitrans Midstream common stock.
On January 24, 2022, the Board declared cash dividends for the fourth quarter of 2021 of $0.15 per common share and $0.4873 per Equitrans Midstream Preferred Share, which dividends were paid on February 14, 2022 to shareholders of record at the close of business on February 3, 2022.
As discussed under "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.” included in "Item 1A. Risk Factors," the amount and timing of dividends is subject to the discretion of the Board and depends upon business conditions, including, but not limited to, the financial condition, results of operations, liquidity and capital requirements of the Company's operating subsidiaries, covenants associated with certain debt obligations, legal requirements and strategic direction and other factors deemed relevant by the Board. The Board has the discretion to change the dividend at any time for any reason.

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Securities Authorized for Issuance under Equity Compensation Plans
See “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information relating to the Company’s equity compensation plans.
Recent Sales of Unregistered Securities
See Notes 1 and 2 to the consolidated financial statements for a description of the Restructuring Agreement and Restructuring.
Market Repurchases
The Company did not have any repurchases of equity securities registered under Section 12 of the Exchange Act during the three months ended December 31, 2021.
Stock Performance Graph
The graph below compares the cumulative thirty-seven month total return provided to shareholders on Equitrans Midstream's common stock relative to the cumulative total returns of (i) the S&P 500 index and (ii) the Alerian US Midstream Energy Index. An investment of $100 (with reinvestment of all dividends) is assumed to have been made in Equitrans Midstream common stock on November 13, 2018, and with respect to each index, October 31, 2018, and relative performance is tracked through December 31, 2021.
etrn-20211231_g3.jpg
 11/13/201812/31/201812/31/201912/31/202012/31/2021
Equitrans Midstream Corporation$100.00 $95.84 $71.75 $47.88 $66.20 
S&P 500100.00 92.82 122.05 144.51 185.99 
Alerian U.S. Midstream Energy100.00 89.60 103.54 77.70 112.67 
Item 6.        Reserved
Item 7.        Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of financial condition and results of operations should be read in conjunction with “Item 1. Business,” “Item 1A. Risk Factors,” and the consolidated financial statements, and the notes thereto, included in "Item 8. Financial Statements and Supplementary Data" of this Annual Report on Form 10-K for the year ended December 31, 2021.
The information covered in this section provides a comparison of material changes in the Company's results of operations and financial condition for fiscal year 2021 and fiscal year 2020. For the discussion of fiscal year 2020 relative to fiscal year 2019, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of the Company's Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on February 23, 2021.

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Executive Overview
Net loss attributable to Equitrans Midstream common shareholders was $1,439.0 million ($(3.32) per diluted share) in 2021 compared to net income attributable to Equitrans Midstream common shareholders of $364.4 million ($1.06 per diluted share) in 2020. The decrease resulted primarily from an impairment of the Company's equity method investment in the MVP Joint Venture, lower equity income from the Company's investment in the MVP Joint Venture, lower operating revenues on Gathering (primarily due to impacts of the EQT Global GGA) and Water, higher net interest expense, higher other expense and additional loss on extinguishment of debt charges, partially offset by lower income tax expense, lower net income attributable to noncontrolling interest and transaction costs recorded during 2020. See Note 4 and Note 6 to the consolidated financial statements for a discussion of the impairment of the Company's equity method investment in the MVP Joint Venture and deferred revenues under the EQT Global GGA, respectively.

COVID-19 Update

While the COVID-19 pandemic is continuing, the outbreak has had, and continues to have, a minimal direct impact on the Company’s overall operations. The Company continues to actively manage its response to the COVID-19 pandemic in collaboration with relevant parties and, given that the situation surrounding COVID-19 remains fluid, a number of Company-wide measures undertaken in response to COVID-19 remain in effect to continue to promote the safety and health of field and office-based employees and contractors.

On November 4, 2021, the U.S. Department of Labor's Occupational Safety and Health Administration (OSHA) issued an Emergency Temporary Standard (ETS) to carry out President Biden’s executive order requiring all employers with at least 100 employees to ensure that their employees are fully vaccinated or require unvaccinated workers to produce a negative test result at least once a week. On January 13, 2022, the U.S. Supreme Court granted an application to stay the ETS pending disposition of the applicants' petitions for review in the U.S. Court of Appeals for the Sixth Circuit. Effective January 26, 2022, OSHA withdrew the ETS as an enforceable emergency temporary standard, but did not withdraw the ETS as a proposed rule. Should the ETS, or a similar state or local requirement, take effect in the future, the Company expects it would be subject to such regulation concerning COVID-19 vaccination or testing. In that case, the Company may be required to implement a requirement that many or most employees get vaccinated, subject to limited exceptions, or be tested, resulting in additional costs to the Company. At this time, it is not possible to predict the impact that a vaccine or testing requirement would have on the Company or its workforce. Any such mandate may result in increased costs, operational disruptions or employee attrition for the Company. See “The loss or disengagement of key personnel could adversely affect our ability to execute our strategic, operational and financial plans.” under "Item 1A. Risk Factors" in this Annual Report on Form 10-K for the year ended December 31, 2021.

Notwithstanding the outbreak’s minimal direct impact to date on the Company’s overall operations, the Company acknowledges that the COVID-19 pandemic is still ongoing and therefore the Company cannot predict that the pandemic, or further developments regarding variants of COVID-19 or other governmental action, will not have any impact in the future on the Company's business, results of operations or financial position. For further information regarding the potential impact of COVID-19 on the Company, see "The ongoing outbreak of COVID-19 and its variant strains (or any future pandemic) could harm our business, results of operations and financial condition." under "Item 1A. Risk Factors" and "Item 1. Business" in this Annual Report on Form 10-K for the year ended December 31, 2021.

Sustainability and Corporate Responsibility

The Company recognizes that the long-term interests of shareholders are served by managing ESG matters important to the Company’s stakeholders and working to be resilient and appropriately positioned in any environment, including a lower-carbon economy. The Company has, throughout its corporate history, embraced conducting business in a socially responsible and ethical manner by respecting all stakeholders, and is focused on identifying and executing on ESG and sustainability initiatives while further integrating corporate responsibility and ESG concerns into its business strategy and decision-making throughout the organization. The Company also is committed to continuing to operate with integrity, accountability and transparency. As a result, the Company anticipates that its allocation of capital resources to ESG and sustainability initiatives will increase in the future, which the Company believes will distinctively position the Company and create value.

The Company believes that natural gas will remain a significant component of the global and national energy complex and will play a vital role in the transformation to a lower-carbon economy, notwithstanding increased demand for alternative energy sources. However, the Company acknowledges the reality and risks of climate change as one of the most critical current issues. As an energy infrastructure company, the Company recognizes the ongoing developments and risks surrounding climate change, as well as corresponding potential opportunities, and that it must continue to focus on long-term sustainable performance, including working to minimize impacts to the environment and society, such as by aggressively pursuing its

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climate change mitigation targets while also balancing the immediate and increasing need to deliver reliable, safe, and affordable natural gas energy in the United States now and in the future.

The Company is focused on incorporating sustainability-focused risks and opportunities into the Company’s strategic and capital spending decision processes. For example, among other initiatives, in 2021 the Company made investments to replace certain high-bleed pneumatic devices with low-bleed pneumatic devices and replace certain gas-driven pneumatics with instrument air systems so as to reduce pneumatic methane emissions relative to 2019 levels in support of its publicized climate policy and methane reduction targets. The Company expects to continue to pursue strategic sustainability initiatives as appropriate, including with respect to climate change, and to incur costs and capital expenditures to do so, and certain of such future costs and capital expenditures could be material.

As discussed in “Our business is subject to climate change-related transitional risks (including evolving climate-focused regulation and climate change-driven trends emphasizing financing non-fossil fuel businesses and prompting pursuit of emissions reductions, lower-carbon technologies and alternative forms of energy) and physical risks that could significantly increase our operating expenses and capital costs, adversely affect our customers’ development plans, and reduce demand for our products and services.” in “Item 1A. Risk Factors” and “Regulatory Environment” in “Item 1. Business”, the Company recognizes the evolving landscape of international accords and federal, state and local laws and regulations regarding GHG emissions or climate change initiatives. Changing market conditions, competition from lower emitting fuels, new laws and regulatory requirements, as well as unanticipated or inconsistent application of existing laws and regulations by administrative agencies, make it difficult to predict the long-term business impact of GHG emission and climate change initiatives on the Company’s liquidity, capital resources, results of operations and financial condition. However, the Company is taking steps to adjust its approach to capital investment given regulatory change and recognizes that responsive adaptation efforts are likely to be costly and time consuming.
Business Segment Results
Operating segments are revenue-producing components of an enterprise for which separate financial information is produced internally and is subject to evaluation by the chief operating decision maker in deciding how to allocate resources. Headquarters costs consist primarily of transaction costs and other unallocated corporate expenses. Net interest expense, components of other (expense) income, net, and income tax (benefit) expense are managed on a consolidated basis. The Company has presented each segment's operating income (loss), unrealized (loss) gain on derivative instruments, equity income, impairment of equity method investment and various operational measures in the following sections. Management believes that the presentation of this