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or
FOR THE TRANSITION PERIOD FROM ___________ TO __________
COMMISSION FILE NUMBER			001-38629

 

(Exact name of registrant as specified in its charter)

Pennsylvania			83-0516635
(State or other jurisdiction of incorporation or organization)			(IRS Employer Identification No.)

(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 Symbol

Name of each exchange on which registered

Common Stock, no par value

ETRN

New 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.

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. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

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, 2023: $4.1 billion

The number of shares of common stock outstanding (in thousands), as of January 31, 2024: 433,661

The Company's definitive proxy statement relating to the 2024 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, 2023 and is incorporated by reference in Part III to the extent described therein.

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 became effective on March 1, 2022.

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.

Amended EQM Credit Facility – that certain Third Amended and Restated Credit Agreement, dated as of October 31, 2018, among EQM, as borrower, Wells Fargo Bank, National Association, as the administrative agent, swing line lender, and a letter of credit (L/C) issuer, the lenders party thereto from time to time and any other persons party thereto from time to time (as amended by that certain First Amendment to Third Amended and Restated Credit Agreement, dated as of March 30, 2020, by that certain Second Amendment to Third Amended and Restated Credit Agreement, dated April 16, 2021, by that certain Third Amendment to the Third Amended and Restated Credit Agreement, dated as of April 22, 2022, by that certain Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of October 6, 2023, by that certain Fifth Amendment to Third Amended and Restated Credit Agreement, dated as of February 15, 2024, and as may be further amended, restated, amended and restated, supplemented or otherwise modified from time to time). For the avoidance of doubt, any reference to the Amended EQM Credit Facility as of any particular date shall mean the Amended EQM Credit Facility as in effect on such date.

Annual Revenue Commitments (ARC or ARCs) – contractual term in a water services agreement that obligates the customer to pay for a fixed amount of water services annually.

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. EQGP is a wholly owned subsidiary of Equitrans Midstream Corporation.

EQM – EQM Midstream Partners, LP and its subsidiaries. EQM is a wholly owned subsidiary of Equitrans Midstream Corporation.

EQM Merger – On June 17, 2020, pursuant to that certain Agreement and Plan of Merger, dated as of February 26, 2020, by and among the Company, EQM LP LLC (formerly, 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 EQGP Services, LLC (the EQM General Partner), Merger Sub merged with and into EQM, with EQM continuing and surviving as an indirect, wholly owned subsidiary of the Company.

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.

Equitrans Midstream Preferred Shares – the Equitrans Midstream Corporation Series A Perpetual Convertible Preferred Shares, no par value.

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) and ARC (as defined above) 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 or LDCs) – a company 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 formed among the Company and, as applicable, affiliates of each of NextEra Energy, Inc., Consolidated Edison, Inc. (Con Edison), AltaGas Ltd. and RGC Resources, Inc. (RGC) for purposes of the MVP and the MVP Southgate (as defined below) projects.

MVP Southgate – an estimated 31-mile, 30-inch diameter natural gas interstate pipeline with a targeted capacity of 550,000 dekatherms per day that is designed to span from the terminus of the MVP in Pittsylvania County, Virginia to planned new delivery points in Rockingham County, North Carolina.

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, pentane, butane and iso-butane.

play – a proven geological formation that contains commercial amounts of hydrocarbons.

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 2024 annual meeting of shareholders to be filed with the Securities and Exchange Commission.

Rager Mountain natural gas storage field incident – that certain venting of natural gas in 2022 at a storage well (well 2244) at Equitrans, L.P.'s Rager Mountain natural gas storage facility, located in Jackson Township, a remote section of Cambria County, Pennsylvania, which venting was successfully halted on November 19, 2022.

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.

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 the context otherwise requires, a reference to a "Note" herein refers to the accompanying Notes to the consolidated financial statements contained in Part II, "Item 8. Financial Statements and Supplementary Data" of this Annual Report on Form 10-K and all references to "we," "us," "our" and "the Company" refer to Equitrans Midstream Corporation and its subsidiaries.

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 "aim," "anticipate," "approximate," "aspire," "assume," "believe," "budget," "continue," "could," "design," "estimate," "expect," "focused," "forecast," "goal," "guidance," "intend," "may," "objective," "opportunity," "outlook," "plan," "position," "potential," "predict," "project," "pursue," "scheduled," "seek," "should," "strategy," "strive," "target," "view," "will," or "would" 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 "Developments, Market Trends and Competitive Conditions" in Part I, "Item 1. Business" and "Outlook" in Part II, "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 the following and/or statements with respect thereto, as applicable:

•guidance and any changes in such guidance in respect of the Company’s gathering, transmission and storage and water services revenue and volume, including the anticipated effects associated with the EQT Global GGA;

•projected revenue (including from firm reservation fees) and volumes, gathering rates, 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 timing for such project);

•the ultimate gathering MVC fee relief, and timing thereof, provided to EQT under the EQT Global GGA and related agreements, and timing of step ups in MVC thereunder;

•the Company's ability to de-lever and timing and means thereof;

•the ultimate financial, business, reputational and/or operational impacts resulting, directly or indirectly, from the Rager Mountain natural gas storage field incident;

•the weighted average contract life of gathering, transmission and storage contracts;

•infrastructure programs (including the targeted or ultimate timing, cost, capacity and sources of funding with respect to gathering, transmission and storage and water projects);

•the outcome of the Company's Board of Directors' strategic process with respect to the Company;

•the cost to construct or restore right-of-way for, capacity of, shippers for, timing and durability of regulatory approvals and concluding litigation, final design (including project scope, expansions, extensions or refinements and capital related thereto), ability and timing to contract additional capacity on, mitigate emissions from, targeted in-service dates of, and completion (including potential timing of such completion) of current, planned or in-service projects or assets, in each case as applicable;

•the effect of the Fiscal Responsibility Act of 2023 on the MVP Joint Venture's ability to complete the MVP project;

•the ability to construct, complete and place in service the MVP project;

•the targeted timing and cost of completing, the MVP project (and risks related thereto), the realizability of the MVP performance award program, and the degree to which, if at all, the MVP PSU Amendment (as defined in Note 8) fosters the Company completing the MVP project safely and in compliance with environmental standards;

•the targeted total MVP project cost and schedule, including the timing for contractual obligations to commence, and the ability to continue construction, potential receipt of in-service authorization, and the realizability of the perceived benefits of the MVP project;

•finalizing the scope of the MVP Southgate and the ability to permit, construct, complete and place in service the MVP Southgate;

•the targeted total project cost and timing for completing (and ability to complete) MVP Southgate, including the satisfaction, if any, of conditions precedent with respect to the relevant precedent agreements, timing for forecasted capital expenditures related thereto, and the realizability of the perceived benefits of the amended project, design, scope and provisions included in the relevant precedent agreements, and any potential extensions of the terms of the precedent agreements;

•the MVP Joint Venture's ability to execute any additional agreements for firm capacity for the MVP Southgate;

•the realizability of all or any portion of the Henry Hub cash bonus payment under the EQT Global GGA;

•the potential for future bipartisan support for, and the potential timing for, additional federal energy infrastructure permitting reform legislation to be enacted;

•the ultimate terms, partner relationships and structure of the MVP Joint Venture and ownership interests therein;

•the impact of changes in assumptions and estimates relating to the potential completion and full in-service timing of the MVP project (as well as changes in such timing) on, among other things, the fair value of the Henry Hub cash bonus payment provision of the EQT Global GGA, gathering rates, the amount of gathering MVC fee relief and the estimated transaction price allocated to the Company's remaining performance obligations under certain contracts with firm reservation fees and MVCs;

•the Company's ability to identify and complete opportunities to optimize its existing asset base and/or expansion projects in the Company's operating areas and in areas that would provide access to new markets;

•the Company's ability to bring, and targeted timing for bringing, in-service extensions and expansions of its mixed-use water system, and realize benefits therefrom in accordance with its strategy for its water services business segment;

•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;

•the potential for the MVP project, EQM's leverage, customer credit ratings changes, defaults, acquisitions, dispositions and financings to impact EQM's credit ratings and the potential scope of any such impacts;

•the effect and outcome of contractual disputes, litigation and other proceedings, including regulatory investigations and proceedings;

•the potential effects of any consolidation of or effected by upstream gas producers, including acquisitions of midstream assets, whether in or outside of the Appalachian Basin;

•the potential for, timing, amount and effect 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, cash flow profile (and support therefor from certain contract structures) and MVCs, including those associated with the EQT Global GGA, and the potential impacts thereon of the commission and in-service timing (or absence thereof) and cost of the MVP project;

•projected capital contributions and capital and operating expenditures, including the amount and timing of reimbursable capital expenditures, capital budget and sources of funds for capital expenditures;

•the Company's ability to recoup replacement and related costs;

•future dividend amounts, timing and rates;

•statements regarding macroeconomic factors' effects on the Company's business, including future commodity prices, the impact of MVP in-service on commodity prices or natural gas volumes in the Appalachian Basin, and takeaway capacity constraints in the Appalachian Basin;

•beliefs regarding future decisions of customers in respect of production growth, curtailing natural gas production, timing of turning wells in line, rig and completion activity and related impacts on the Company's business, and the effect, if any, on such future decisions should the MVP be brought in-service, as well as the potential for increased volumes to flow to the Company's gathering and transmission system to supply the MVP following in-service;

•the Company's liquidity and financing position and requirements, including sources, availability and sufficiency;

•statements regarding future interest rates and/or reference rates and the potential impacts thereof;

•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;

•the MVP Joint Venture's ability to raise project-level debt, and the anticipated proceeds that the Company expects to receive therefrom;

•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 Company's ability to position itself for a lower carbon economy, achieve, and create value from, its environmental, social and governance (ESG) and sustainability initiatives, targets and aspirations (including targets and aspirations set forth in its climate policy) and respond, and impacts of responding, to increasing stakeholder scrutiny in these areas;

•the effectiveness of the Company's information technology and operational technology systems and practices to detect and defend against evolving cyberattacks on United States critical infrastructure;

•the effects and associated cost of compliance with existing or new government regulations including any quantification of potential impacts of regulatory matters related to climate change on the Company; and

•future tax rates, 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, construction and other risks and uncertainties, many of which are difficult to predict and are beyond the Company's control, including, as it pertains to the MVP project, risks and uncertainties such as the physical construction conditions, including steep slopes and any further unexpected geological impediments, continued crew availability, ability to meet contractor draw down plans, and productivity realizable, project opposition, the receipt of certain time of year and other variances and approvals, if applicable, and weather. 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 Part I, "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. As forward-looking statements involve significant risks and uncertainties, caution should be exercised against placing undue reliance on such statements.

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 and its common stock trades on the New York Stock Exchange under the symbol "ETRN". 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, storage and other facilities that support well completion and produced water handling activities.

As of December 31, 2023, the Company provided a majority of its natural gas gathering, transmission and storage services and water services under long-term contracts that generally include firm reservation fee revenues. For the year ended December 31, 2023, approximately 70% of the Company's operating revenues were generated from firm reservation fee revenues.

Generally, the Company is focused on utilizing contract structures reflecting long-term firm capacity, MVC or ARC commitments which are intended to provide support to its cash flow profile. The percentage of the Company's operating revenues that are generated by firm reservation fees (as well as the Company's revenue generally) may vary year to year depending on various factors, including customer volumes and the rates realizable under the Company's contracts, including the EQT Global GGA (defined below) which provides for periodic gathering MVC fee declines through January 1, 2028 (with the fees then remaining fixed throughout the remaining term). Additionally, as discussed below, in connection with MVP full in-service the EQT Global GGA provides for more significant potential gathering MVC fee declines in certain contract years.

The Company's operations are focused primarily in southwestern Pennsylvania, northern West Virginia and southeastern Ohio, which are prolific resource development areas in the natural gas shale plays known as the Marcellus and Utica Shales. These regions are also the primary operating areas of EQT, the Company's largest customer, which was one of the largest natural gas producers in the United States based on average daily sales volumes as of December 31, 2023. EQT accounted for approximately 61% of the Company's revenues for the year ended December 31, 2023.

EQT Global GGA. On February 26, 2020 (the EQT Global GGA Effective Date), the Company entered into a Gas Gathering and Compression Agreement (as subsequently amended, the EQT Global GGA) with EQT and certain affiliates of 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. The EQT Global GGA is intended to, among other things, incentivize combo and return-to-pad drilling by EQT. 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 and the dedication of a substantial majority of EQT's core acreage in southwestern Pennsylvania and West Virginia. 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 limitations, including geographical in relation to the dedicated area, as well as the distance of such connections to the Company's then-existing gathering system, which have provided and could further provide capital efficiencies to EQM. 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.

Under the EQT Global GGA, the performance obligation is to provide daily MVC capacity and as such the total consideration is allocated proportionally to the daily MVC over the life of the contract. In periods that the gathering MVC revenue billed will exceed the allocated consideration, the excess will be deferred to the contract liability and recognized in revenue when the performance obligation has been satisfied. While the 3.0 Bcf per day MVC capacity became effective on April 1, 2020, additional daily MVC capacity and the associated gathering MVC fees payable by EQT to the Company as set forth in the EQT Global GGA are conditioned upon the full in-service date of the MVP. The performance obligation, the allocation of the total consideration over the life of the contract and the gathering MVC fees payable by EQT under the contract have been in the past, and in the future could be, affected by changes in the timing of the full in-service date of the MVP.

Under the EQT Global GGA, the gathering MVC fee periodically declines through January 1, 2028 (with the fees then remaining fixed throughout the remaining term). Before January 1, 2026, beginning the first day of the quarter in which the full in-service date of the MVP occurs under the EQT Global GGA, the gathering MVC fees payable by EQT to the Company are subject to more significant potential declines for certain contract years as set forth in the EQT Global GGA, which, prior to EQT's exercise of the EQT Cash Option (defined below), provided for estimated aggregate fee relief of up to approximately $270 million in the first twelve-month period, up to approximately $230 million in the second twelve-month period and up to approximately $35 million in the third twelve-month period. Given that the MVP full in-service date did not occur by January 1, 2022, on July 8, 2022, EQT irrevocably elected under the EQT Global GGA to forgo up to approximately $145 million of the potential gathering MVC fee relief in such first twelve-month period and up to approximately $90 million of the potential gathering MVC fee relief in such second twelve-month period in exchange for a cash payment from the Company to EQT in the amount of approximately $195.8 million (the EQT Cash Option). As a result of EQT exercising the EQT Cash Option (and payment by the Company thereof), the maximum aggregate potential fee relief applicable under the EQT Global GGA in such first twelve-month period and such second twelve-month period was reduced to be up to approximately $125 million and depending on the ultimate in-service date of the MVP, up to approximately $140 million, respectively. The gathering MVC fees and potential declines are subject to certain provisions related to inflation adjustment in accordance with the terms of the EQT Global GGA. Additionally, 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.

See also "Our exposure to commodity price risk may increase in the future and NYMEX Henry Hub futures prices affect the fair value, and may affect the realizability, of potential cash payments to us by EQT pursuant to the EQT Global GGA.” included in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K for a discussion of factors affecting the estimated fair value of the derivative asset attributable to the Henry Hub cash bonus payment provision.

The following diagram depicts the Company's organizational and ownership structure as of December 31, 2023:

The following is a map of the Company's gathering, transmission and storage and water services operations as of December 31, 2023. Also included are the MVP and MVP Southgate routes, which projects are discussed under "Developments, Market Trends and Competitive Conditions" in Part I, "Item 1. Business" of this Annual Report on Form 10-K.

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.

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.

The Company's largest customer, EQT, accounted for approximately 61%, 61% and 59% of the Company's total revenues for the years ended December 31, 2023, 2022 and 2021, respectively.

Gathering Customers. For the year ended December 31, 2023, EQT accounted for approximately 59% of Gathering's throughput and approximately 62% of Gathering's revenues. Subject to certain exceptions and limitations, as of December 31, 2023, Gathering (inclusive of acreage dedications to Eureka Midstream Holdings, LLC (Eureka Midstream), a joint venture in which the Company is the operator and has a 60% interest) 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) West Virginia pursuant to agreements with EQT, including the EQT Global GGA, and agreements with certain other third parties, and (iii) Ohio pursuant to agreements with various 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, 2023, the gathering system had total contracted firm reservation capacity (including contracted MVCs) of approximately 7.7 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 or not yet fully in-service for which the Company has executed firm contracts, the gathering system had total contracted firm reservation capacity (including contracted MVCs) of approximately 8.8 Bcf per day (inclusive of Eureka Midstream contracted capacity) as of December 31, 2023, which included contracted firm reservation capacity of approximately 1.9 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 or not yet fully in-service for which the Company has executed firm contracts, the Company's firm gathering contracts had a weighted average remaining term of approximately 13 years as of December 31, 2023.

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 fuel certain of its compressor stations and meet other requirements on the Company's gathering systems.

Transmission Customers. For the year ended December 31, 2023, EQT accounted for approximately 61% of Transmission's throughput and approximately 51% of Transmission's revenues. As of December 31, 2023, 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 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, 2023, the Company had firm capacity subscribed under firm transmission contracts of approximately 5.8 Bcf per day, which includes future capacity expected from expansion projects that are not yet fully constructed or not yet fully in-service for which the Company has executed firm transmission contracts and excludes approximately 2.6 Bcf per day of firm capacity commitments associated with the MVP and MVP Southgate projects. As of December 31, 2023, 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 or not yet fully in-service for which the Company has executed firm contracts, the Company's firm transmission and storage contracts had a weighted average remaining term of approximately 12 years as of December 31, 2023.

Interruptible service contracts include volumetric-based fees, which are charges for the volume of natural gas transported or stored 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 fuel its compressor stations and meet other requirements of the Company's transmission and storage systems.

As of December 31, 2023, approximately 97% of Transmission's contracted firm transmission capacity was subscribed by customers under negotiated rate agreements under its tariff. As of December 31, 2023, Transmission had minimal contracted firm transmission capacity subscribed at discounted rates and recourse rates under its tariff. See also "FERC Regulation" under "Regulatory Environment" below and "Our and the MVP Joint Venture's natural gas gathering, transmission and storage services, as applicable, 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 Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K for additional information.

Water Customers. For the year ended December 31, 2023, 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 will continue 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.

Gathering Assets. As of December 31, 2023, the gathering system, inclusive of Eureka Midstream's gathering system, included approximately 1,220 miles of high-pressure gathering lines, 138 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, 2023, the transmission and storage system included approximately 940 miles of FERC-regulated, interstate pipelines that have interconnect points to seven interstate pipelines and multiple LDCs. As of December 31, 2023, the transmission and storage system was supported by 42 compressor units, with total throughput capacity of approximately 4.4 Bcf per day and compression of approximately 135,000 horsepower, and 18 associated natural gas storage reservoirs, which had a peak withdrawal capacity of approximately 820 MMcf per day and a working gas capacity of approximately 43 Bcf.

Water Assets. As of December 31, 2023, the fresh water systems included approximately 201 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, 2023, the fresh water systems consisted of permanent, buried pipelines, surface pipelines, 17 fresh water impoundment facilities, as well as pumping stations, which support water transportation throughout the systems, and take point facilities and measurement facilities, which support well completion activities. During 2023, the Company completed the majority of the main trunkline pipelines on the mixed water system including a pipeline that connects its two mixed water storage facilities. As of December 31, 2023, the mixed water system included approximately 53 miles of buried pipeline and two water storage facilities with 350,000 barrels of capacity, as well as two interconnects with the Company’s existing Pennsylvania fresh water systems and provides services to producers in southwestern Pennsylvania.

The Company plans to continue to expand its mixed water system in 2024, including the completion of a pipeline to serve a producer in West Virginia and a water pipeline, scheduled to be completed in the first quarter of 2025, to interconnect with the same producer's Pennsylvania mixed water network.

The Company's strategically located and integrated 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 one of the largest natural gas producers in the U.S. based on average daily sales volumes as of December 31, 2023 and EQT's public senior debt had investment grade credit ratings from Standard & Poor's Global Ratings (S&P), Fitch Ratings (Fitch) and Moody's Investors Service (Moody's) as of that date. For the year ended December 31, 2023, approximately 70% of the Company's operating revenues were generated from firm reservation fee revenues. Generally, the Company is focused on utilizing contract structures reflecting long-term firm capacity, MVC or ARC commitments which are intended to provide support to its cash flow profile. The percentage of the Company's operating revenues that are generated by firm reservation fees (as well as the Company's revenues generally) may vary year to year depending on various factors, including customer volumes and the rates realizable under the Company's contracts, including the EQT Global GGA which provides for periodic gathering MVC fee declines through January 1, 2028 (with the fee then remaining fixed throughout the remaining term). Additionally, as discussed above under "Overview of the Company and Operations" in Part 1, "Item 1. Business" of this Annual Report on Form 10-K, in connection with MVP full in-service the EQT Global GGA provides for more significant potential gathering MVC fee declines in certain contract years.

The Company's standalone strategy reflects its continued pursuit of organic growth projects, including completing and placing in service the MVP, focusing on identifying opportunities to use its existing assets to deepen and grow its customer relationships at optimized levels of capital spending and taking into account the Company’s leverage, and continuing to prudently invest resources in its sustainability-oriented initiatives. The Company’s strategy also reflects its continued focus on achieving a strong balance sheet, and given the Company’s size, operating footprint and other factors considering inorganic opportunities, such as to extend the Company’s operations into the southeast United States and new, key demand markets, such as the Gulf of Mexico LNG export market.

The Company expects that the MVP, together with the Hammerhead pipeline and Equitrans, L.P. Expansion Project (EEP), will primarily drive the Company's near-term organic growth, as discussed in further detail below. In particular, the Company believes that the MVP, among other benefits, will allow for greater natural gas production in the southwestern Appalachian Basin (and/or result in increased volumes flowing to the Company's gathering and transmission system given the Company's belief in the system's current unique positioning to provide the supply path to MVP). In addition, the Company continues to focus on de-levering its balance sheet (which the Company views as a critical strategic objective), including in connection with the MVP.

•Mountain Valley Pipeline. The MVP is being constructed by a joint venture among the Company and affiliates of each of NextEra Energy, Inc. (NEE), Consolidated Edison, Inc. (Con Edison), AltaGas Ltd. and RGC Resources, Inc. (RGC). As of December 31, 2023, the Company owned an approximate 48.4% 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, which will provide access to the growing southeast demand markets once it is placed in-service. 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 for the MVP. In the first quarter of 2018, the MVP Joint Venture received limited notice to proceed with certain construction activities from the FERC and commenced construction. However, the MVP project was repeatedly, significantly delayed and subject to cost increases because of legal and regulatory setbacks, particularly in respect of litigation in the U.S. Court of Appeals for the Fourth Circuit (Fourth Circuit).

Notwithstanding such prior setbacks, the MVP Joint Venture continued to engage in pursuing the authorizations necessary to complete the MVP project, including on February 28, 2023, the U.S. Department of the Interior’s Fish and Wildlife Service (FWS) issuing a new Biological Opinion and Incidental Take Statement (2023 BiOp) for the MVP project and in May 2023, the U.S. Forest Service and Bureau of Land Management issuing authorizations related to MVP’s segment in the Jefferson National Forest (JNF).

On June 3, 2023, the President of the United States signed into law the Fiscal Responsibility Act of 2023 that, among other things, ratified and approved all permits and authorizations necessary for the construction and initial operation of the MVP, directed the applicable federal officials and agencies to maintain such authorizations, required the Secretary of the Army to issue not later than June 24, 2023 all permits or verifications necessary to complete construction of the MVP and allow for the MVP’s operation and maintenance, and divested courts of jurisdiction to review agency actions on approvals necessary for MVP construction and initial operation.

Thereafter, certain necessary authorizations were issued to the MVP Joint Venture, and the FERC authorized the MVP Joint Venture to resume all construction activities in all MVP project locations. After the Fourth Circuit issued a stay halting MVP project construction in the JNF and a stay of the 2023 BiOp, the U.S. Supreme Court vacated the stays on July 27, 2023. The MVP Joint Venture recommenced forward construction activity in August 2023.

Since then, the MVP Joint Venture has made substantial progress on completing the MVP. As of February 15, 2024, the MVP Joint Venture, among other things, has completed:

•approximately 300 miles of pipeline installed (less than 4 miles remaining to install);

•415 crossings (13 remaining);

•the hydrotesting of approximately 180 miles (approximately 125 miles remain to be tested, inclusive of interconnect piping);

•the purging and packing of the pipeline through to the second compressor station (total of approximately 77 miles);

•the commissioning of two of three MVP compressor stations; and

•restoration of a substantial portion of the pipeline right of way, with the remaining approximately 112 miles of pipeline restoration to occur following MVP in-service.

Forward progress slowed at the end of 2023 through early 2024 as a result of unforeseen challenging construction conditions, combined with unexpected and substantially adverse winter weather conditions throughout much of January 2024. As a result, the MVP Joint Venture retained a higher than planned contractor headcount through January into February to maintain the right of way and address weather-induced issues and also to be in a position to improve forward progress as soon as conditions became more favorable. While productivity has since improved at the end of January and into February 2024, the combined effect of these unforeseen challenges significantly slowed the previously anticipated pace of construction and adversely affected project cost. As a result, the Company is targeting MVP project completion and commissioning in the second quarter of 2024, at a total estimated project cost ranging from approximately $7.57 billion to approximately $7.63 billion (excluding allowance for funds used during construction (AFUDC)).

Based on such targeted completion timing and following in-service authorization from the FERC, the Company expects that MVP and MVP-related firm capacity contractual obligations would commence on June 1, 2024 (with certain MVC step ups and more significant gathering MVC fee declines under the EQT Global GGA commencing April 1, 2024).

As the MVP Joint Venture continues to diligently work towards responsibly completing the MVP project, it will

continue to prioritize the safety of its workforce, communities, and assets, and the project's compliance with applicable

environmental standards and regulations.

The targeted completion timing and cost, and accordingly the commencement of MVP and MVP-related firm capacity contractual obligations are subject to many factors, including the physical construction conditions, weather and productivity, many of which are beyond the Company's control.

Further adverse developments however, whatever the cause, affecting the MVP project could further increase project

costs and/or further delay completion or in-service of the project, and adversely affect the Company, including its

leverage levels and potential liquidity. See also "Expanding our business by constructing new midstream

legal uncertainties that are beyond our control." included in Part I, "Item 1A. Risk Factors" of this Annual Report on

Form 10-K. See also Part II, "Item 3. Legal Proceedings" of this Annual Report on Form 10-K.

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). On May 4, 2023, RGC exercised an option for the Company to fund RGC's portion of future capital contributions with respect to the MVP project, which funding the Company commenced in June 2023 and will continue through the full in-service date of the MVP. The Company and NEE are obligated, and RGC, prior to the exercise of its option described above had opted, to fund the shortfall in Con Edison's capital contributions on a pro rata basis. Following RGC's exercise of its option, the Company is also funding RGC's portion of Con Edison's shortfall. Such funding by the Company in respect of the Con Edison shortfall and RGC's portion of capital contributions has and will correspondingly increase the Company's interests in the MVP project and decrease Con Edison's and RGC's respective interest, as applicable, in the MVP project. If the project were to be completed in the second quarter of 2024 and at a total project cost ranging from approximately $7.57 billion to approximately $7.63 billion (excluding AFUDC), the Company expects its equity ownership in the MVP project would progressively increase from approximately 48.4% to approximately 49.0%.

Through December 31, 2023, the Company had funded approximately $3.4 billion to the MVP Joint Venture for the MVP project. If the MVP project were to be completed in the second quarter of 2024 at a total project cost ranging from approximately $7.57 billion to approximately $7.63 billion (excluding AFUDC), the Company expects it would make total capital contributions to the MVP Joint Venture in 2024 of approximately $540 million to $575 million primarily related to forward construction, and expects that it would incur a total of approximately $4.0 billion over the project's construction, inclusive of approximately $245 million in excess of the Company's ownership interest.

•Wellhead Gathering Expansion Projects and Hammerhead Pipeline. During the year ended December 31, 2023, the Company invested approximately $267.7 million in gathering projects (inclusive of capital expenditures related to the noncontrolling interest in Eureka Midstream). For 2024, the Company expects to invest approximately $225 million to $275 million in gathering projects (inclusive of expected capital expenditures of approximately $15 million related to the noncontrolling interest in Eureka Midstream). The primary projects include infrastructure expansion and optimization in 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 Company has seen and expects that it will continue to see the benefits of return-to-pad drilling and system integrations in 2024, and estimates gathering capital expenditures required to maintain flat gathered volumes in a given year would be between approximately $200 million and $250 million for 2024.

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 Eastern Gas Transmission, is supported by a 20-year term, 1.2 Bcf per day, firm capacity commitment from EQT, and cost approximately $540 million. The Company expects Hammerhead pipeline full commercial in-service to commence in conjunction with full MVP in-service and is focused on obtaining additional firm capacity commitments and/or additional interruptible volumes for the pipeline. During the fourth quarter of 2023, the Company provided firm and interruptible volumes from the Company's Hammerhead Gathering agreement with EQT and expects to continue the interruptible volumes up to the full commercial in-service date of the Hammerhead pipeline when firm commitments will commence.

The Company also has an agreement with a producer customer to install approximately 32,000 horsepower booster compression to existing facilities. The project is backed by a long-term firm commitment and is expected to be in-service in the first quarter of 2024. The majority of spend on the project was incurred in 2023.

•Transmission Projects. During the year ended December 31, 2023, the Company invested approximately $84.2 million in transmission projects. For 2024, the Company expects to invest approximately $75 million to $85 million in transmission projects, including approximately $40 million to complete the Company's Ohio Valley Connector expansion project (OVCX). The Company expects 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 primarily 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. On January 20, 2023, the FERC issued the Final Environmental Impact Statement for the project. On June 15, 2023, the FERC issued the Certificate of Public Convenience and Necessity for OVCX. On July 31, 2023, the FERC issued the Notice to Proceed and the Company commenced construction during the third quarter of 2023. The Company expects to invest a total of approximately $160 million in the project and is targeting the incremental capacity to be placed in-service during the second quarter of 2024. The OVCX project, as well as the Company's successful open season in 2023 for the available transmission capacity that was subject of the one-time transmission customer's contract buyout during the first quarter of 2023, is consistent with the Company's ongoing efforts to optimize existing assets and achieve capital efficiency.

The Company's EEP project 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, Eastern Gas Transmission and Columbia Gas Transmission. In connection with MVP full in-service, firm transportation agreements for 550 MMcf per day of capacity will commence under 20-year terms.

•MVP Southgate Project. In December 2023, the MVP Joint Venture announced an amended MVP Southgate project in lieu of the original project. The amended project would extend approximately 31 miles from the terminus of the MVP in Pittsylvania County, Virginia to planned new delivery points in Rockingham County, North Carolina using 30-inch diameter pipe. The MVP Southgate project, which was announced in April 2018, previously contemplated an approximate 75-mile interstate pipeline that was approved by the FERC to extend from the MVP at Pittsylvania County, Virginia to new delivery points in Rockingham and Alamance Counties, North Carolina. 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, 2023. The amended MVP Southgate is estimated to cost a total of approximately $370 million, excluding AFUDC and certain costs incurred for purposes of the original project. The Company expects to fund its proportionate share through capital contributions made to the MVP Joint Venture.

The MVP Joint Venture has entered into precedent agreements with each of Public Service Company of North Carolina, Inc. (PSNC), and Duke Energy Carolinas, LLC (Duke), which precedent agreements contemplate the amended project (in lieu of the original project). In contrast to the original, lengthier project, which traversed 155 water crossings and required an additional compressor station (the permit application for which was denied by the Virginia State Air Pollution Control Board in 2021), the amended project would include substantially fewer water crossings (all of which would be evaluated for boring) and would not require a new compressor station. The new precedent agreements, among other things, collectively provide for 550,000 Dth per day of firm capacity commitments (whereas the original project was supported by a 300,000 Dth per day firm capacity commitment with PSNC, which has been superseded by the new precedent agreement with PSNC), are each for 20-year terms (subject to two potential five-year extensions), and describe certain conditions precedent to the parties’ respective obligations regarding MVP Southgate (including, among others, that both precedent agreements remain in full force and effect). Given the court-related construction stops experienced on MVP, the new precedent agreements also incorporate certain spending and termination protections which may be exercised in certain circumstances in accordance with the terms of the precedent agreements, including in connection with a delay, stay or vacatur of certain governmental authorizations. The MVP Joint Venture recently completed an open season for the MVP Southgate project and expects to finalize the project scope in the coming months. The targeted completion timing for the project is June 2028, with the majority of the capital spend expected to occur in 2027.

The FERC previously conditioned its authorization on MVP Southgate being built and made available for service by June 18, 2023. On June 15, 2023, the MVP Joint Venture filed a request with the FERC for an extension of time to June 18, 2026, to complete MVP Southgate, which the FERC granted on December 19, 2023. Project opponents filed a request for rehearing of the FERC's December 19, 2023 order. On February 20, 2024, the FERC denied the rehearing request. The MVP Joint Venture is evaluating the permitting and regulatory roadmap for the project, including requesting an updated completion due date.

•Water Operations. During the year ended December 31, 2023, the Company invested approximately $45.7 million in its water infrastructure, primarily to continue to construct the initial mixed-use water system buildout. The Company placed portions of the initial mixed-use water system in service during 2022 and its second above ground water storage facility into service in July 2023, which brings its total water storage capacity to 350,000 barrels. During 2023, the Company completed the majority of the main trunkline pipelines on the mixed water system, including a pipeline that connects its two mixed water storage facilities. In May 2023, the Company executed an agreement with a producer customer to provide mixed-use water delivery service. The 10-year agreement is backed by a minimum volume commitment. For 2024, the Company expects to invest approximately $25 million to $35 million in its water operations, primarily related to the continued construction of its mixed-use water system buildout.

See "Sustainability and Corporate Responsibility" in Part II, "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations" of this Annual Report on Form 10-K for a discussion of the Company's continued focus on sustainability matters which the Company believes will help to distinctively position the Company and create value.

Competitive Conditions. 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. Natural gas producers that develop their own gas gathering systems or acquire such systems may also compete with the Company depending on the location of such systems relative to the Company's assets and existing agreements.

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, certain 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 (including by technological advancement, legislation or government subsidies, as well as traditional supply and demand dynamics) 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.

See also “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.” included in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K.

FERC Regulation. The Company's interstate natural gas transmission and storage operations are regulated by the FERC under the Natural Gas Act of 1938, as amended (NGA), the Natural Gas Policy Act of 1978, as amended (NGPA), and the regulations, rules and policies promulgated under those and other statutes. 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;

•certification and construction of new interstate transmission and storage facilities;

•abandonment of interstate transmission and storage services and facilities;

•maintenance of accounts and records;

•relationships between pipelines and certain affiliates;

•terms and conditions of services and service contracts with customers;

•depreciation and amortization policies;

•acquisitions and dispositions of interstate transmission and storage facilities; and

•initiation and discontinuation of interstate transmission and storage services.

The FERC regulates the rates and charges for transmission and storage in interstate commerce. Unless market-based rates have been approved by the FERC, the maximum applicable recourse rates and terms and conditions for service are set forth in the pipeline's FERC-approved tariff. Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of providing service, including the recovery of a return on the pipeline's actual and prudent historical investment costs. Key determinants in the ratemaking process include the depreciated capital costs of the facilities, the costs of providing service, the allowed rate of return and income tax allowance, as well as volume throughput and contractual capacity commitment assumptions.

Interstate pipelines may not charge rates or impose terms and conditions of service that, upon review by the FERC, are found to be unjust or unreasonable, unduly discriminatory or preferential. Rate design and the allocation of costs also can affect a pipeline's profitability. While the ratemaking process establishes the maximum rate that can be charged, interstate pipelines such as the Company's transmission and storage system are permitted to discount their firm and interruptible rates without further FERC authorization down to a specified minimum level, provided they do not unduly discriminate. In addition, pipelines are allowed to negotiate different rates with their customers, under certain circumstances. Changes to rates or terms and conditions of service, and contracts can be proposed by a pipeline company under Section 4 of the NGA, or the existing interstate transmission and storage rates, terms and conditions of service and/or 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, 2023, 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. Prior to commencing construction of new or existing interstate transmission and storage facilities, an interstate pipeline must obtain (except in certain circumstances, such as where the activity is permitted under the FERC’s regulations or is authorized under the operator’s existing blanket certificate issued by the FERC) a certificate authorizing the construction, or file to amend its existing certificate, from the FERC.

On April 19, 2018, the FERC issued a Notice of Inquiry (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. On February 18, 2022, the FERC issued an interim GHG policy. On March 24, 2022, the FERC issued an order suspending the effectiveness of the Updated Certificate Policy Statement and the interim GHG policy and has taken no further action to date.

In 2024, there is a possibility that the U.S. Congress could 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. 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.

The FERC’s assessment of greenhouse gas emissions in the NEPA review of pipeline certificate projects remains a divided issue among the Commissioners. In 2023, the FERC reached a compromise position among Acting Chairman Phillips and Commissioners Danly and Christie whereby the FERC will disclose the social cost of GHG calculations for informational purposes, but does not characterize the significance of the projects’ greenhouse gas emissions. This compromise position continued in the FERC’s 2023 Order on Remand in Rio Grande LNG, LLC in response to a U.S. Court of Appeals for the District of Columbia (D.C. Circuit) directive that the FERC address arguments regarding whether the social cost of carbon protocol is a generally accepted analytical tool for assessing the significance of greenhouse gas impacts. Commissioner Allison Clements has continued to file dissenting opinions opposing the Commission’s approach. The D.C. Circuit could decide several pending appeals in 2024 regarding the FERC’s treatment of greenhouse gas emissions in natural gas pipeline certificate reviews.

The FERC had four commissioners in 2023. However, Commissioner James Danly left the FERC at the end of 2023. On February 9, 2024, President Biden named Willie Phillips Chairman of the FERC. Commissioner Allison Clements’s term expires on June 30, 2024, and she has indicated that she will not seek another term, leaving the possibility that the FERC could be without a quorum of three members in 2024. If Congress does not confirm Commissioner Clements's replacement prior to expiration of her term, Commissioner Clements may remain in her position until the end of the current the U.S. Congress in January 2025. As of the filing of this Annual Report on Form 10-K, President Biden has not yet nominated new commissioners.

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 submitted an application to the FERC requesting authorization to abandon its low-pressure gathering facilities and services. On June 17, 2022 and December 16, 2022, the FERC issued orders authorizing Equitrans, L.P. to abandon these low-pressure gathering facilities, subject to certain conditions. In 2023, Equitrans, L.P. completed the abandonments of the remaining low-pressure gathering facilities and no longer maintains rates and terms of service in its tariff for unbundled gathering services performed on gathering facilities in connection with its transmission service.

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.

Safety and Maintenance. The Company's interstate natural gas pipeline system and natural gas storage assets are subject to regulation by the PHMSA. The PHMSA has established safety requirements pertaining to the design, installation, testing, construction, operation and maintenance of gas pipeline and storage facilities, including requirements that pipeline and storage operators develop a written qualification program for individuals performing covered tasks on pipeline facilities and implement pipeline and storage well 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 and storage facilities 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 and storage management activities, the Company may incur significant additional expenses if anomalous pipeline or storage conditions are discovered or more stringent safety requirements are implemented. For example, in April 2016, the 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, along with certain storage facilities (the Mega Rule). The PHMSA intended the Mega Rule to 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 I of the Mega Rule was promulgated on October 1, 2019, with an effective date of July 1, 2020 (see discussion below). Part II was promulgated on November 15, 2021, with an effective date of May 16, 2022 (see discussion below). Finally, Part III of the Mega Rule was promulgated on August 24, 2022, with an effective date of May 24, 2023 (see discussion below).

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 the PHMSA's statutory mandate under prior legislation through 2019. In addition, the 2016 Pipeline Safety Act empowered the 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 the PHMSA to develop new safety standards for natural gas storage facilities by June 2018.

Pursuant to those provisions of the 2016 Pipeline Safety Act, the PHMSA issued a final rule effective December 2, 2019 that expanded the agency's authority to impose emergency restrictions, prohibitions and safety measures and issued a final rule effective March 13, 2020 that strengthened the rules related to underground natural gas storage facilities, including well integrity, wellbore tubing and casing integrity

Following the October 2016 Interim Final Rule, the PHMSA also published five 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 I); 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 II); and "Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments" (also known as the Mega Rule Part III); and “Pipeline Safety: Requirement of Valve Installation and Minimum Rupture Detection Standards” (the valve rule). The Enhanced Emergency Order Procedures rule, which became effective on December 2, 2019, implements an existing statutory authorization for the 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. Mega Rule Part I, 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 (MAOP), 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 (ILI), 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 the PHMSA of proposed alternative approaches to achieving the objectives of the minimum safety standards. Mega Rule Part II, which was finalized on November 15, 2021 and went 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 (with the first annual reports submitted in Spring 2023), and creates new safety requirements that vary based on pipeline diameter and potential consequences of a failure. Mega Rule Part III, which was finalized on August 24, 2022, went into effect on May 24, 2023. The rule requires operators of certain transmission pipelines to assess their integrity management practices, and comply with enhanced corrosion control and mitigation timelines. It also establishes new requirements for pipeline inspections following an extreme weather event or natural disaster, and provides enhanced guidance for pipeline repairs. The valve rule requires the installation of remote operated rupture mitigation valves on new or entirely replaced transmission and storage lines when valves are installed to meet valve spacing requirements. In addition the valve rule includes requirements for operator actions to be taken when notified of a potential rupture that include notifying emergency response agencies and closing valves within a specified timeframe. In 2023, the Company did not incur material compliance costs in connection with complying with the PHMSA rules applicable to the Company. However, as discussed below, the Company does expect certain compliance costs to increase in the near future, and the Company continues to assess the impact of compliance with these rules which could materially impact its future costs of operations and revenue from operations. For example, Mega Rule Part I requires MAOP reconfirmation of certain previously untested transmission pipeline segments, which are commonly referred to as ‘‘grandfathered’’ pipelines. The Company’s grandfathered pipeline MAOP reconfirmation efforts, which the Company has initiated, may result in unanticipated testing and/or replacement costs. When reconfirming MAOP on certain of the Company’s grandfathered pipeline segments the Company may be required to remove portions of pipelines for testing, shut in certain pipelines, and/or may face significant operational or technical challenges when performing either a pressure test or an ILI examination, which could result in substantial costs related thereto, or to repairs, remediation, or replacing existing pipelines, and/or other mitigating actions that may be determined to be necessary as a result of the tests, as well as lost cash flows resulting from shutting down the Company's pipelines during the pendency of any such actions, which could be material to capital expenditures, earnings and the Company's competitive position. Additionally, ensuring complete compliance with the applicable Mega Rule compliance deadlines may cause the Company to incur significant additional expenses if anomalous pipeline conditions are discovered.

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 U.S. DOT regulations adopted under authority granted to the PHMSA, it could be subject to penalties and fines. The PHMSA has the statutory authority to impose civil penalties for pipeline safety violations up to a maximum of approximately $266,000 per day for each violation and approximately $2.6 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, unforeseen maintenance capital expenditures in the future for its regulatory compliance initiatives. Additionally, the adoption of new laws and regulations, such as the Mega Rule discussed above, could result in significant 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 the U.S. Congress believed additional oversight, research, or regulations was needed. The PIPES Act includes new mandates for the 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. The 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. In May and July 2021, the U.S. Department of Homeland Security's Transportation Safety Administration (the TSA) issued security directives 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. In both 2022 and 2023, the TSA released updated versions of the security directives, with the most recent versions requiring, among other things, the assessment of the effectiveness of our security measures. 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, as of the filing of this Annual Report on Form 10-K, implementation of, and ongoing compliance with, our cybersecurity implementation program (CIP) and security directives have not materially adversely affected the Company's business and operations.

On November 30, 2022, the TSA issued an advanced notice of proposed rulemaking seeking comment on how to strengthen cybersecurity and resiliency in, among other areas, the pipeline sector. The comment period ended in February 2023. As of the filing of this Annual Report on Form 10-K, it is not clear if or when the TSA will issue a notice of proposed rulemaking. Should any regulations be promulgated, the Company will likely be covered by them, but it is not possible as of the filing of this Annual Report on Form 10-K to predict the ultimate impact such regulations may have on the Company's business or operations.

In March 2022, President Biden signed into law the Cyber Incident Reporting for Critical Infrastructure Act of 2022 (CIRCIA). CIRCIA directs the U.S. Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) to promulgate regulations requiring certain entities to report to CISA certain cyber incidents. The Company expects that it will be subject to such regulations after they are promulgated and continues to monitor regulatory developments to ensure future compliance and assess the impact the compliance with these rules on its future costs of operations. As of the filing of this Annual Report on Form 10-K, it is not possible to predict the ultimate impact such regulations may have on the Company’s business or 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. Additionally, we may become subject to multiple incident reporting requirements and other cybersecurity obligations that could overlap or conflict with each other, resulting an increased risk of non-compliance or in different responses to the same incident. Any failure to remain in compliance with laws or regulations governing cybersecurity, including the requirements contained in the Company’s CIP, 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 those third parties on which we rely, as well as any noncompliance by us or such third parties with applicable laws and regulations governing cybersecurity and/or data privacy, could materially adversely affect us.” under Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K.

OSHA Regulation. U.S. Department of Labor’s Occupational Safety and Health Administration (OSHA) is 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. To combat this hazard, on September 1, 2021, the OSHA implemented an enforcement initiative prioritizing inspections of work activities when the heat index exceeds 80 degrees Fahrenheit. The OSHA further stepped-up enforcement in this area, announcing a National Emphasis Program for Outdoor and Indoor Heat-Related Hazards on April 8, 2022. In addition, the OSHA continues to make progress towards a formal national heat stress standard. In 2021, the OSHA issued an Advanced Notice of Proposed Rulemaking on heat injury and illness prevention in outdoor and indoor work settings and on August 24, 2023, the OSHA released options for a regulatory framework to address heat stress in the workplace. 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 U.S. Environmental Protection Agency (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.

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 anticipates as of the filing of this Annual Report on Form 10-K. 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 announced that it will be commencing a review of these NAAQS. In addition, in December 2023, the EPA issued a final rule that makes 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 final rule also extends 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.

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.

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. The Company 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 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 expenditures could also be required in areas that are nonattainment for the ozone NAAQS depending on the design of the relevant state’s implementation plan to meet the air quality standards. The EPA did not make the ozone NAAQS more stringent when it reviewed them in 2020, and although the Biden Administration initially indicated that it would reconsider that decision, the EPA announced in August 2023 that it would cease its reconsideration and begin an entirely new review of the ozone NAAQS that would need to be completed by 2025 under the federal Clean Air Act. As of the filing of this Annual Report on Form 10-K, it is not clear when the EPA will issue a notice of proposed rulemaking. If the ozone NAAQS are made more stringent, this could result in additional nonattainment areas being designated, which could in turn result in the Company being required to install additional pollution control equipment. Moreover, with regard to the 2015 ozone NAAQS, the EPA released a final rule in May 2023 called the Good Neighbor Plan that imposes a federal implementation plan in 23 states to address air pollution from those states that is contributing to downwind nonattainment of the 2015 ozone NAAQS in other states. The final rule establishes limitations on emissions of nitrogen oxides for certain industrial stationary sources in 23 states, including states in which the Company operates. The rule has been stayed in 12 states including West Virginia by seven different federal courts of appeals because the underlying disapproval of those states’ state implementation plans has been found likely to have been unlawful. The Good Neighbor Plan remains in effect in the remaining 11 states including Ohio, Pennsylvania and Virginia. The final Good Neighbor Plan has been challenged in various courts of appeals, including the D.C. Circuit. The D.C. Circuit denied a motion to stay the rule in September 2023, and some of the parties filed emergency stay applications with the U.S. Supreme Court in October 2023. The U.S. Supreme Court has scheduled oral argument on the emergency stay applications for February 21, 2024. As of the filing of this Annual Report on Form 10-K, it is not clear how the U.S. Supreme Court will rule on the emergency stay application or how the other courts of appeals will rule on the challenges to the underlying disapproval of some states' implementation plans and on the Good Neighbor Plan itself. If the Good Neighbor Plan withstands these judicial challenges and remains in place in states in which the Company operates, the Company will be required to install additional pollution control equipment on certain of its assets, but the Company does not anticipate that compliance with the Good Neighbor Plan will have a material effect on the Company’s capital expenditures, earnings and competitive position.

In August 2023, an EPA issued final rule removing the “emergency” affirmative defense provision from the EPA’s Title V permit program regulations became effective. The EPA removed this provision from the permitting program because the agency found that these provisions conflicted with its current interpretation of the enforcement structure of the Clean Air Act. The EPA has directed states with similar emergency affirmative defense provisions in their Title V permitting programs to revise permits contains those provisions during permit renewals. The final rule has been challenged in the D.C. Circuit, but, as of the filing of this Annual Report on Form 10-K, is in abeyance awaiting a decision in a separate D.C. Circuit case involving a different EPA rule that may have relevance to the challenge to the emergency defense rule. Although the EPA has stated that it “may” use its “case-by-case” enforcement discretion to determine whether to initiate enforcement as appropriate, this rule removes the automatic defense the Company could claim in an emergency situation and may make it more difficult to avoid liability for Title V permit violations.

On February 7, 2024, the EPA released a final rule revising the NAAQS for fine particulate matter (PM2.5). In the final rule, the EPA lowered the level of the annual NAAQS from 12.0 µg/m3 to 9.0 µg/m3. The new annual NAAQS could result in additional nonattainment areas being designated in areas in which the Company operates, which would result in new construction being more difficult in these areas. It would also result in states having to develop new state implementation plans setting forth the measures the state intends to take to attain the new annual standard, and it is possible that these new state implementation plans could require air pollution control devices to be installed on existing compression stations. The rule will take effect 60 days after it is published in the Federal Register, which had not occurred as of the filing of this Annual Report. It is not possible as of the filing date of this Annual Report on Form 10-K to predict the ultimate impact the revised annual PM2.5 NAAQS may have on the Company’s business or operations.

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 an aspiration of becoming net zero for scope 1 and 2 carbon emissions by 2050. The Company’s climate policy includes two interim emission reduction goals: (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 are 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.

As discussed further below, the construction of interstate natural gas transportation pipelines pursuant to the NGA requires authorization from the FERC, and FERC actions are subject to review under NEPA. NEPA requires federal agencies, such as the FERC, to evaluate major federal actions having the potential to significantly affect the environment. On January 9, 2023, the White House Council on Environmental Quality published new interim guidance entitled “National Environmental Policy Act Guidance on Consideration of Greenhouse Gas Emissions and Climate Change.” Generally, the interim guidance calls for increased scrutiny of the GHG effects of proposed federal action, including requiring agencies to quantify the proposed action’s GHG emissions and relevant climate impacts. The interim guidance and increased review of the GHG impacts of federal action has the potential to significantly delay or limit, and significantly increase the cost of, development of midstream infrastructure. The EPA announced its Climate Enforcement and Compliance Strategy in September 2023, which directs all enforcement and compliance programs in the EPA to address climate change, wherever appropriate, in every matter within their jurisdiction. The Compliance Strategy also directs the EPA to prioritize enforcement and compliance actions to mitigate climate change and to include climate adaptation and resilience requirements whenever appropriate.

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.

Since May 2016, the EPA has regulated methane and VOCs from the oil and gas sector through its new source performance standard program under the Clean Air Act. These initial rules (Subpart OOOOa) impose methane and VOC emissions limits on certain types of new and modified compressors and pneumatic pumps. In December 2023, the EPA issued a final rule, which as of the filing of this Annual Report on Form 10-K has not yet been published in the Federal Register, that does three things: (i) modifies Subpart OOOOa to, among other things, increase fugitive emissions monitoring frequency; (ii) promulgates a new Subpart OOOOb that imposes more stringent requirements on new and modified oil and gas sources that commence construction or modification on or after December 6, 2022; and (iii) promulgates an emissions guideline (a new Subpart OOOOc) that provides direction to the states to regulate VOC and methane emissions from existing sources in the sector for the first time. The Subpart OOOOc directs states to regulate existing sources in largely the same manner in which new and modified sources are regulated under Subpart OOOOb. It is expected that some parties may challenge the final rule once it is published in the Federal Register. It is also expected that some parties may file petitions for reconsideration asking the EPA to reexamine certain parts of the final rule. If those challenges are filed and the rule withstands judicial review, or if the EPA decides against any changes to the final rule in response to petitions for reconsideration, the Company will be required to incur certain capital expenditures 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, the Pennsylvania Environmental Quality Board has promulgated regulations that require conventional oil and natural gas sources of volatile organic compounds and methane to meet reasonably available control technology standards to control these emissions, which could result in significant costs that could adversely affect the Company’s business.

In August 2022, the Inflation Reduction Act (IRA) was enacted. Among other provisions, the IRA includes a methane fee that is imposed on certain types of facilities, including certain ones owned and/or operated by the Company. The IRA exempts from the methane fee those facilities that are subject to the EPA’s final methane rule (Subparts OOOOb and OOOOc discussed above), provided that the rule results in emission reductions that are at least equivalent to those that would be achieved under the November 2021 proposed rule (which is the case for new and modified sources and will be the case for existing sources unless a state is able to justify a lesser standard based on the Clean Air Act’s “remaining useful life and other factors” provision). The EPA published a proposed rule in the Federal Register in January 2024. The proposed rule makes clear that the EPA does not think the exemption for existing sources that are subject to Subpart OOOOc would be available until state plans implementing OOOOc are approved and in effect in all states with sources subject to Subpart OOOOc. If the EPA finalizes this interpretation of the IRA’s exemption, the methane fee could have a material effect on the Company until all states have finalized and had their plans approved by the EPA. Under the IRA, the Company could be liable for methane emissions from applicable facilities that are above 25,000 metric tons of carbon dioxide equivalent. These fees are written into the IRA and are: (1) $900 per ton for any tons over the threshold that are reported for calendar year 2024; (2) $1,200 per ton for any tons over the threshold that are reported for calendar year 2025; and (3) $1,500 per ton for any tons over the threshold that are reported for calendar year 2026 and each year thereafter. Even once all the states have approved state plans to implement Subpart OOOOc, it is possible that the Company could have operations in a state that implements less stringent emissions standards than the final Subpart OOOOc emissions guideline, in which case the exemption would not be available for applicable facilities in that state.

The IRA also directed the EPA to amend Subpart W of the Greenhouse Gas Reporting Rule (which governs GHG emissions by the oil and gas sector). The EPA issued a proposed rule amending Subpart W in August 2023. Depending on how the Subpart OOOOc of the EPA’s final rule and the Subpart W of the Greenhouse Gas Reporting Rule are finalized, there is a potential for significant impacts on calculation of the Company’s IRA methane fee.

In May 2023, the EPA proposed revised new source performance standards and an emissions guideline for certain new, modified, reconstructed, and existing natural gas-fired electric generating units. If finalized, this rule could have an impact on the demand for natural gas from the U.S. power sector, which could have an adverse effect on the demand for the Company’s business. State programs regulating GHG emissions from power plants, such as the Regional Greenhouse Gas Initiative (RGGI), can also have the effect on the Company of reducing demand for natural gas by power plants. RGGI was found, however, to be unconstitutional in Pennsylvania in November 2023, but this decision is being appealed. Virginia also withdrew from the RGGI program effective January 1, 2024, but as of the filing of this Annual Report on Form 10-K, the decision has not yet been challenged in court.

California enacted two climate-related disclosure laws called the Climate Corporate Data Accountability Act (CCDAA) and the Climate-Related Financial Risk Act (CRFRA) on October 7, 2023. These laws may apply to the Company if we are considered to be “doing business in California” under the CCDAA and the CRFRA. Under the CCDAA, we may be required to quantify and disclose certain GHG emissions data in accordance with the GHG Protocol, a standard developed by the World Resources Institute and the World Business Council for Sustainable Development beginning in 2026 (with the reporting of 2025 emissions data). These reports must be independently audited by a third-party assurance provider. The CRFRA may require us to prepare and submit a biennial report in accord with the framework of the Final Report and Recommendations of the Task Force on Climate-related Financial Disclosures disclosing the company’s climate-related financial risk, and the measures it has adopted to reduce and adapt to climate-related financial risk, with the first report due on January 1, 2026. These financial risk reports must be made available to the public on our website by the applicable compliance dates. There are annual fees associated with both the CCDAA and the CRFRA as well. The CCDAA and the CRFRA may cause us to incur additional (and potentially accelerate) compliance and reporting costs, certain of which could be material, including related to monitoring, collecting, analyzing and reporting new metrics and implementing systems and procuring additional necessary attestation. As of the filing of this Annual Report on Form 10-K, the California Air Resources Board has not yet issued proposed regulations to implement these two climate disclosure laws. Similarly, on March 21, 2022, the SEC released proposed rule changes that would require new climate-related disclosure in SEC filings, including certain climate-related metrics and GHG emissions. The SEC proposal, which as of the filing of this Annual Report on Form 10-K has not been finalized, would also require disclosure of our certain GHG emissions, further increasing our compliance and reporting costs. Such costs may adversely affect our future business, financial condition, results of operations, and liquidity.

The U.S. Congress, along with federal and state agencies, has also considered other 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 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 uncertain as of the filing of this Annual Report on Form 10-K. 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 the financing of non-fossil fuel businesses and prompting the pursuit of emissions reductions, lower-carbon technologies, and alternative forms of energy), as well as 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 Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K.

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 federal and 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 U.S. Army Corps of Engineers (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, the 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 U.S. Supreme Court decisions through that date. On December 30, 2022, the EPA and the Army Corps announced the final revised rule, which took effect on March 20, 2023. On May 25, 2023, the U.S. Supreme Court issued its ruling in Sackett v. EPA, U.S. Supreme Court Docket No. 21-454, holding that portions of the existing rules defining “waters of the United States” were invalid, and announcing a new definition of “waters.” On August 29, 2023, the EPA and the Army Corps issued a revised final rule designed to conform their regulations to the Sackett decision (the Conforming Rule), and the Conforming Rule took effect immediately upon its publication on September 8, 2023. However, the Conforming Rule itself does not define certain language from the U.S. Supreme Court’s ruling, and could be expanded or face additional legal challenges in the future. To the extent that any future rules expand the scope of the Clean Water Act's jurisdiction, or to the extent individual states choose to define their jurisdiction to include, and impose requirements on, waters previously regulated by the federal agencies, the Company could face increased costs and delays with respect to obtaining permits for activities in jurisdictional and non-jurisdictional waters, including wetlands.

The Sackett decision may also have effects on the implementation of Water Quality Certifications (WQC) under Section 401 of the Clean Water Act. Section 401 requires that any activity that may result in a discharge to waters of the United States must first receive a Section 401 WQC before a federal agency may issue a permit for that activity. A WQC is typically issued by the state where the discharge originates, or by the EPA itself in areas where a state or tribe does not have authority. In 2020, the EPA finalized a series of changes to the Clean Water Act regulations governing the WQC process, largely curtailing states’ and tribes’ authority over WQCs. On September 27, 2023, the EPA published a final rule that restores states’ and tribes’ authority to review requests for WQCs and imposes additional requirements on the WQC process. The final rule took effect on November 27, 2023, but has been challenged by states and regulated entities in ongoing litigation enjoin its enforcement. If certain elements of the final rule remain in effect, such as expanding the scope of WQCs to non-water quality impacts and changing the allowed time for review by states and tribes, or if states or tribes attach non-water-quality conditions to issuance of WQCs, the Company could face increased costs and delays with respect to obtaining permits for pipeline crossings and other activities in jurisdictional and non-jurisdictional waters.

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.

Nationwide Permits (NWPs) are issued by the Army Corps under the Clean Water Act and the Rivers and Harbors Act of 1899 and act as a type of general permit to minimize delays and paperwork for certain activities and discharges in federal jurisdictional waters and wetlands. NWPs are typically reviewed and reissued (or modified) every five years. One such permit, NWP 12, authorizes certain “Oil or Natural Gas Pipeline Activities” and was most recently modified and reissued in January 2021. On March 28, 2022, reportedly at the request of the Biden Administration, the Army Corps initiated an early review of NWP 12 to determine whether any future actions may be appropriate to modify NWP 12 prior to its expiration in 2026. The Army Corps solicited public and stakeholder comments through public meetings held in May 2022, but has not provided any additional updates on the status of its review. To the extent future revisions to NWP 12 or litigation relating to such revisions modify its provisions with respect to oil and natural gas pipeline activities, the Company could face increased costs and delays with respect to obtaining permits for activities in jurisdictional waters, including wetlands.

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 of 1978, as amended (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. Those rules have been challenged in courts, although initial efforts to enjoin enforcement of the rule were unsuccessful. On January 20, 2020, President Biden issued an Executive Order requiring a review of certain federal regulations, and in response the Council on Environmental Quality initiated a two-phase process to review NEPA regulations.

Phase 1 of that process resulted in new regulations taking effect in May 2022, partially reverting NEPA regulations to rules that were in effect at the end of the Obama administration. On July 31, 2023, the Council on Environmental Quality published proposed Phase 2 revisions to NEPA regulations, including revisions to bring the regulations into compliance with changes made to NEPA by the Fiscal Responsibility Act of 2023, to increase substantive obligations placed on federal agencies in NEPA process, require consideration of climate change consequences, and require consideration of environmental justice, among other changes. The comment period for the proposed Phase 2 rules ended on September 29, 2023; a final rule is expected to follow.

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. The federal designation of previously unprotected species as being endangered or threatened, or the federal 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 or presumed to exist. For example, on September 14, 2022, the U.S. Fish and Wildlife Service (FWS) proposed to list the Tricolored Bat (Perimyotis subflavus) as an endangered species; the Tricolored Bat is located in 39 states including North Carolina, Ohio, Pennsylvania, Virginia, and West Virginia. As of the filing of this Annual Report on Form 10-K, the FWS has not finalized that proposal, but an endangered species listing of the Tricolored Bat could limit development activities, particularly tree clearing, in areas where the bat is known or presumed to be present, including areas where we operate. 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 U.S. Department of Interior narrowed the ESA regulations and their applicability. These regulations have been challenged in the courts. In August 2022, the U.S. Department of the Interior rescinded certain aspects of the 2020 changes to the ESA regulations. On June 22, 2023, the FWS also proposed further revisions to three sets of ESA regulations, all intended to reverse rules issued in 2019; those proposed rules remain pending. Some or all of these rules could be subject to additional rulemaking or litigation to revise or rescind the rules currently in effect as of the filing of this Annual Report on Form 10-K.

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 amount of impacts remain uncertain. The Biden Administration announced a renewed commitment to environmental justice in a day one executive order, Executive Order 13990: Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis, and followed up that action with Executive Order 14008: Tackling the Climate Crisis at Home and Abroad, which further solidified the administration’s commitment to addressing climate change and advancing environmental justice. Further, in April 2023, the Biden Administration issued Executive Order 14096: Revitalizing Our Nation’s Commitment to Environmental Justice for All, which reinforced the administration’s whole-of-government approach to advancing environmental justice. Since the beginning of the Biden Administration, numerous federal agencies have announced initiatives to prioritize environmental justice as they fulfill their missions.

On May 5, 2022, the U.S. Department of Justice (DOJ) launched a comprehensive environmental justice enforcement strategy designed to guide the DOJ’s work and ensure use of all available tools to promote environmental justice. The strategy provides a roadmap for using DOJ’s civil and criminal enforcement authorities to advance environmental justice through prioritizing enforcement of environmental and civil rights violations in overburdened communities. On the same day, DOJ also launched the Office of Environmental Justice, which has the mission of protecting overburdened and underserved communities from the harm caused by environmental crimes, pollution and climate change. The office serves as a central hub for implementing DOJ’s comprehensive environmental justice enforcement strategy and engages with all department entities to carry out this task.

Further, on September 24, 2022, the EPA launched the Office of Environmental Justice and External Civil Rights. In addition to providing resources and technical assistance on civil rights and environmental justice, the Office of Environmental Justice and External Civil Rights enforces federal civil rights laws, including Title VI of the Civil Rights Act of 1964, which prohibits discrimination by federal funding recipients.

In addition, the FERC has increased its focus on environmental justice issues in its processes and analyses. For example, in March 2023, the FERC convened the Roundtable on Environmental Justice and Equity in Infrastructure Permitting as part of its two-year Equity Action Plan to promote equity and remove barriers that underserved communities, including environmental justice communities, face in the context of the FERC’s processes and policies in five focus areas.

Equitrans Midstream is aware of these changes regarding environmental justice-related policy and enforcement and is in the process of assessing whether and how they may affect the Company. Equitrans Midstream will continue to monitor new developments and actions taken by each of these offices.

States are also in the process of reexamining environmental justice law and policy. Pennsylvania’s then governor signed Executive Order 2021-07 in October 2021. The executive order permanently created an Office of Environmental Justice within the Pennsylvania Department of Environmental Protection, formally established the existent Environmental Justice Advisory Board, and created an Environmental Justice Interagency Council. In September 2023, the Pennsylvania Department of Environmental Protection’s interim final Environmental Justice Policy became effective after an extensive public comment period. The interim final policy was subject to a public comment period that ended November 30, 2023, indicating the policy may be amended further. The prior policy had been in effect since 2004. Under the interim final policy, applications for certain Pennsylvania Department of Environmental Protection permits in environmental justice areas would be subject to specified enhanced public participation requirements, and the agency would prioritize inspections and enforcement in environmental justice areas. 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. In May 2023, the Virginia Department of Environmental Quality released for public comment draft guidance entitled Environmental Justice in the Permitting Process, which provides guidance to agency personnel on a permit evaluation process for permitting actions in environmental justice communities. Finalization of the guidance document remains pending. The West Virginia Department of Environmental Protection released draft Public Engagement Guidelines, which set forth guidance for agency public engagement efforts, for public comment in September 2023. The guidelines are pending finalization. Ohio appears to be monitoring developments at the EPA and other federal agencies. 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. The Company will continue to monitor state legal and regulatory developments in this area and respond as appropriate.

The majority of environmental justice litigation matters appear 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. These kinds of litigation, even if unsuccessful, present risks to the underlying project’s timeline and budget. Equitrans Midstream will continue to monitor these litigation-related developments.

Equitrans Midstream takes environmental justice issues seriously and is committed to supporting the communities in which the Company operates. In July 2022, the Company published its Environmental Justice Policy that reaffirms our commitment to providing reliable energy infrastructure in a safe and responsible manner while treating all people fairly. Additionally, one of the Company’s pillars of sustainability is stakeholder engagement, including engagement with the communities where Equitrans Midstream operates. For example, Equitrans Midstream has adopted a 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.

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.

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 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, 2023, the Company had 773 employees. During 2023, the Company's overall turnover was 6% (with more than 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.

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, Sustainability and Environmental Committee of the 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 the Company is committed, through its Inclusion Program and other initiatives, to continuing to build a diverse, inclusive, respectful, and safe workplace. During 2023, the Company hosted, and more than 300 employees attended, five educational sessions on inclusion topics, including a training on disability awareness and cognitive bias; implemented an automated resume redaction process for initial resume reviews during recruitment; promoted and obtained more than 50% employee participation in an Equitrans DEI Badge program whereby employees completed inclusion-focused courses to earn one of three badge levels (advocate, ambassador, and champion) to display in their email signatures and on LinkedIn; continued the annual mentor program for high potential underrepresented employees based on a successful pilot program in 2022; and continued to publish 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, RecruitMilitary.com and GettingHired.com (representing individuals with disabilities).

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; 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 recognizes is enabling 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 Human Capital and Compensation Committee of the Board reviews and discusses with management the human capital management matters relevant to the Company’s work force, including talent attraction and retention. The Company provides technical, behavioral, and leadership training to multiple levels of Company individual contributors, managers, and leaders, as well as customized, executive-level assessment, development, and coaching 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.

Culture and Inclusion Council. The Company continues to utilize a cross-functional Culture and Inclusion Council (CIC) which solicits employee feedback on ways to further enhance corporate culture. In 2023, as part of its One Team philosophy, the Company emphasized internal relationships and connectedness in a hybrid person-centric work environment. The CIC hosted four regionally based networking opportunities for employees in Pennsylvania, Texas, and Florida; six Coffee Talks, which are virtual informational sessions on various Company or wellbeing topics; and seven Lunch with Leaders opportunities in which members of the leadership team take small groups of employees to lunch. The Company also continued to promote a flexible work environment for all employees, regardless of how or from where they work. This includes flexible temporary schedules when family or personal matters arise, and various permanent work schedule options based on the nature of the job and an employee’s personal preference. We encourage all employees, both field and non-field workers, to utilize flexibility opportunities as needed. As part of its person-centric work environment, the Company believes that nurturing relationships, supporting employees’ individual needs, and connecting with one another helps to foster a One Team environment to further drive efficiency and promote a stronger corporate culture long-term.

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 2023 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.

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.

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" in Part II of this Annual Report on Form 10-K. Note that additional risks not presently known to us or that are currently considered immaterial as of the filing of this Annual Report on Form 10-K 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.

The following is a summary of the most significant risks relating to our business activities that we have identified. If any of these risks actually occur, our business could be materially adversely affected. For a more complete understanding of our material risk factors, this summary should be read in conjunction with the detailed description of our risk factors which follows this section.

•We generate a substantial majority of our revenues from EQT and therefore are subject to the business and liquidity risks of EQT, and any decrease in EQT's drilling or completion activity or a greater focus of such activity on acreage not dedicated to us could adversely affect us.

•Expanding our business by constructing new midstream assets subjects us to risk.

•The regulatory approval process, including judicial review, for the construction of new transmission 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 in a timely manner or at all or our ability to achieve the expected investment returns on the projects. If we do not complete organic growth projects, realize revenue generating volume growth on our systems, and/or identify and complete inorganic growth opportunities, our future growth may be limited. Further, there is no assurance as to the outcome of our Board of Directors' ongoing strategic process with respect to the Company.

•Decreases or a lack of growth in production of natural gas in our areas of operation, and the lack of diversification of our assets, products and geographic locations, could further adversely affect us.

•Impairments of our assets, including property, plant, and equipment, intangible assets, goodwill and our equity method investment in the MVP Joint Venture, previously have reduced, and if incurred in the future could reduce, our earnings.

•Cyberattacks aimed at us and/or third parties on which we rely, as well as any noncompliance by us or our third parties with applicable laws and regulations governing cybersecurity and/or data privacy, could materially adversely affect us.

•Our subsidiaries' significant indebtedness, and any future indebtedness, as well as the restrictions under our subsidiaries' debt agreements, could adversely affect us.

•We or our joint ventures may be unable to obtain financing on satisfactory terms and financing transactions may increase our financial leverage or cause dilution to our shareholders. A further downgrade of EQM’s credit ratings could impact our liquidity, access to capital, and costs of doing business.

•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 projects and the operation of our pipelines and facilities from various groups.

•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, and we have in the past been and may become subject to disagreements with counterparties on the interpretation of existing or future contractual terms.

•Third-party pipelines and other facilities interconnected to our pipelines and facilities may become unavailable to transport or process natural gas, or may not accept deliveries of natural gas from us or our joint ventures.

•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 ventures or joint venture partners, and it may be difficult or impossible for us to cause these joint ventures or partners to take actions that we believe would be in our or the joint venture’s best interests.

•Strategic transactions could reduce, rather than increase, our results of operations and liquidity, and adversely affect our ability to pay dividends to our shareholders.

•We have incurred and expect to continue to incur costs and expenses resulting from or arising out of the Rager Mountain natural gas storage field incident in November 2022, including potentially additional regulatory penalties.

•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, regulatory compliance obligations 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 commodity price risk may increase in the future.

•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 as a result of performance of our pipeline integrity management programs and compliance with increasingly stringent safety regulations.

•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 our shareholders’ 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 present a number of risks to current and future holders of our common stock.

•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.

Historically, we have provided EQT a substantial percentage of its natural gas gathering, transmission and water services. EQT accounted for approximately 61% of our revenues for the year ended December 31, 2023. We expect to continue to derive a substantial majority of our revenues from EQT for the foreseeable future.

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 (or the amount of its production which flows to our systems), 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:

•decisions of EQT’s management to reduce, slow or maintain at relatively flat levels EQT’s natural gas production or to prioritize production away from our assets or obligations to build, which such decisions have been and may in the future be influenced by corporate capital allocation strategies, regional takeaway constraints, commodity prices, and/or other factors (as applicable); such decisions have in certain instances in the past directly and adversely impacted demand for our services and aspects of our business, including, in combination with MVP project delays, the value potentially realizable under certain of our contracts, and future such decisions could (including, without limitation, as gathering fee declines take effect under the EQT Global GGA) directly and adversely impact us and our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders;

•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;

•prevailing and projected commodity prices, primarily natural gas and natural gas liquids (NGLs), including their effect on EQT’s hedge positions;

•natural gas price volatility or periods of low commodity prices, which may have an adverse effect on EQT’s drilling operations, revenue, profitability, future rate of growth, creditworthiness and liquidity;

•the proximity, capacity, cost and availability of gathering and transportation facilities, and other factors that result in differentials to benchmark prices;

•the costs of producing natural gas, including the availability and costs of drilling rigs and crews and other equipment;

•geologic and reservoir risks and considerations;

•risks associated with the operation of EQT’s wells and facilities, including potential environmental liabilities;

•EQT’s ability to identify future exploration, development and production opportunities and midstream alternatives;

•uncertainties inherent in projecting future rates of production, levels of reserves, and demand for natural gas, NGLs and oil;

•EQT’s execution of its strategic plan and additional strategic transactions, if any;

•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, and changes in tax laws, and negative public perception, whether as a result of stakeholder focus on ESG and sustainability matters or otherwise, regarding EQT’s operations;

•the loss or disengagement of key personnel and/or the effectiveness of their replacements;

•EQT’s ability to achieve its ESG and sustainability targets; and

•risks associated with cybersecurity, environmental activists and other threats.

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. A substantial 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 or a lack of growth in production of natural gas in our areas of operation, whether as a result of regional takeaway constraints, producer corporate capital allocation strategies, lower regional natural gas prices, natural well decline, 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, or maintenance levels of production could adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

Our growth strategy includes organic optimization of our existing assets and greenfield growth projects. The development and construction by us or our joint ventures of pipeline and water infrastructure and storage facilities and the optimization of such assets involve numerous construction, business, economic, competitive, regulatory, judicial, environmental, political and legal uncertainties that are beyond our control, require the expenditure of significant amounts of capital and expose us to risks. Those risks include, but are not limited to: (i) physical construction conditions, such as topographical, or unknown or unanticipated geological, conditions and impediments; (ii) construction site access logistics; (iii) crew availability and productivity and ability to adhere to construction workforce drawdown plans; (iv) adverse weather conditions; (v) project opposition, including delays caused by landowners, advocacy groups or activists opposed to our projects and/or the natural gas industry through lawsuits or intervention in regulatory proceedings; (vi) environmental protocols and evolving regulatory or legal requirements and related impacts therefrom, including additional costs of compliance; (vii) the application of time of year or other regulatory restrictions affecting construction, (viii) failure to meet customer contractual requirements; (ix) environmental hazards; (x) vandalism; (xi) the lack of available skilled labor, equipment and materials (or escalating costs in respect thereof, including as a result of inflation); (xii) issues regarding availability of or access to connecting infrastructure; and (xiii) 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, including by reason of judicial hostility or activism). Risks inherent in the construction of these types of projects, such as unanticipated geological conditions, challenging terrain in certain of our construction areas and severe or continuous adverse weather conditions, have adversely affected, and in the future could adversely affect, project timing, completion and cost, as well as increase the risk of loss of human life, personal injuries, significant damage to property or environmental pollution. Most notably, certain of these risks have been realized in the construction of the MVP project, including construction-related risks and adverse weather conditions, and such risks or other risks may be realized in the future which may further adversely affect the timing and/or cost of the MVP project.

Given such risks and uncertainties, our projects or those of our joint ventures may not be completed on schedule, within budgeted cost or at all. As a further example, public participation, including by pipeline infrastructure opponents, in the review and permitting process of projects, through litigation or otherwise, has previously introduced, and in the future can introduce, uncertainty and adversely affect project timing, completion and cost. See also “The regulatory approval process for the construction of new transmission assets is very challenging, and, as demonstrated with the MVP pipeline, has resulted in significantly increased costs and delayed targeted in-service dates, and decisions by regulatory and/or judicial authorities in pending or potential proceedings relevant to the development of midstream assets, particularly any litigation instituted in the Fourth Circuit, such as regarding the MVP Southgate project and/or expansions or extensions of the MVP, are likely to impact our or the MVP Joint Venture's ability to obtain or maintain in effect all approvals and authorizations, including as may be necessary to complete certain projects in a timely manner 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 or challenges in project permitting processes related to such issues, including proposed construction and location of infrastructure associated with fossil fuels, poses an increased risk and may lead to increased litigation, legislative and regulatory initiatives and review at federal, state, tribal and local levels of government or permitting delays that can prevent or delay the construction of such infrastructure and realization of associated revenues.

Additionally, construction expenditures on projects generally 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, including as a result of taxes which could potentially be calculated based on excess expenditures, inclusive of maintenance, incurred during extended court-driven construction delays. Furthermore, we may construct facilities to capture anticipated future growth in production and/or demand in a region in which such growth does not materialize or is delayed beyond our expectations. 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.

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, and opposition to, 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 or the MVP Joint Venture’s projects, including any expansion of the MVP project and the MVP Southgate project or other extensions, 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 was repeatedly the case with the construction of the MVP project, particularly in respect of litigation in the Fourth Circuit. Significant delays in the regulatory approval process for projects, as well as stays and losses of critical authorizations and permits, should they be experienced, have the potential to significantly increase costs, delay targeted in-service dates and/or affect operations for projects (among other adverse effects), as has happened with the MVP and the originally contemplated MVP Southgate projects and could occur in the future in the case of authorizations required for our or the MVP Joint Venture’s current or future projects, including in respect of developing expansions or extensions, such as expansion of the MVP project and the MVP Southgate project.

Any such adverse developments and uncertainties could adversely affect our ability, and/or, as applicable, 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 cause impairments, including, as has occurred in the past, to our equity investment in the MVP Joint Venture.

We have experienced and may further experience increased opposition with respect to our and the MVP Joint Venture’s projects from activists in the form of lawsuits, intervention in regulatory proceedings and otherwise, which in the past resulted in adverse impacts to our business, financial condition, results of operations and liquidity. In particular, opponents were successful in past challenges with respect to the MVP project and two challenges with respect to MVP project authorizations remains outstanding as of the filing of this Annual Report on Form 10-K (see Part I, “Item 3. Legal Proceedings — Challenges to FERC Certificate, D.C. Circuit” of this Annual Report on Form 10-K). Opposition is ongoing regarding the MVP Southgate project and is expected for future projects, including any expansions of the MVP. If ongoing or future challenges were successful, it could result in significant, adverse impacts to our business, financial condition, results of operations and liquidity. Such opposition has made it increasingly difficult to complete projects and place them in service and, following any in-service, may also affect operations or affect extensions and/or expansions of projects. Further, such opposition and/or adverse court rulings and regulatory determinations may have the effect of increasing the timeframe on necessary agency action to address actual or perceived concerns in prior adverse court rulings, or may have the effect of increasing the risk that at a future point joint venture partners may elect not to continue to pursue or fund a project, which could, 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 or partners 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 risks to which we are subject.” in Part I, "Item 1A.

Risk Factors" of this Annual Report on Form 10-K. Challenges to our projects have adversely affected and 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.

Decreases or a lack of growth in production of natural gas in our areas of operation, whether as a result of regional takeaway constraints, producer corporate capital allocation strategies, lower regional natural gas prices, natural well decline, 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. Periods of higher natural gas prices have not caused our largest customers to materially increase their production forecasts. At various times our customers have previously announced, and may in the future announce, lower, flat or modest increases to production forecasts based on various factors, which could include (and have in the past included) regional takeaway capacity limitations (including without limitation the lack of completion of MVP), natural gas prices, access to capital, investor expectations regarding free cash flow, a desire to reduce or refinance leverage or other factors. See, for example, “We generate a substantial majority of our revenues from EQT. 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) or a shift in such activity away from our assets 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, regional takeaway constraints, corporate capital allocation strategies or lower regional natural gas prices have caused and 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 limit our ability to grow, reduce throughput on our systems and adversely impact our business, including our ability to pay dividends to our shareholders.

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 take actions to slow production growth and/or maintain or reduce production, which when effected by our producer customers reduces the demand for, and usage of, our services. For instance, temporary production curtailments have previously resulted in a decrease in our volumetric-based fee revenues. 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 curtail production in the future, which could have a significant negative effect on the demand for our services, our volumetric-based fee revenue, and therefore our results of operations.

Maintaining or increasing the contracted capacity or the volume of natural gas not subject to MVCs 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 anticipated based upon publicly available data provided by our producer customers, 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.

GAAP requires us to test certain assets for impairment on either an annual basis or when events or circumstances occur which indicate that the carrying value of such assets might be impaired. The outcome of such testing previously has resulted in, and in the future could result in, impairments of our assets, including our property, plant, and equipment, intangible assets, goodwill and/or our equity method investment in the MVP Joint Venture. If we determine that an impairment has occurred, we would be required to take a noncash charge to earnings, which, if significant, could have a material adverse effect on our results of operations and financial position. See Note 2 to the consolidated financial statements for a discussion of impairments previously recognized.

Further, the accounting estimates related to impairments are susceptible to change, including estimating fair value which requires considerable judgment. For goodwill, management’s estimate of a reporting unit’s future financial results is sensitive to changes in assumptions, such as changes in stock prices, weighted-average cost of capital, terminal growth rates and industry multiples. Similarly, cash flow estimates utilized for purposes of evaluating long-lived assets and equity method investments (such as in the MVP Joint Venture) require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating costs, timing of operations, and other factors. 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 its equity method investment, that such investment has suffered other-than-temporary declines in value under ASC 323, Investments: Equity Method Investments and Joint Ventures (ASC 323)). When a quantitative assessment is performed, we use estimates and assumptions in estimating our reporting units', our long-lived assets' and our equity method investment's fair values that we believe are reasonable and appropriate at that time; however assumptions and estimates are inherently subject to significant business, economic, competitive and other risks that could materially affect the calculated fair values and the resulting conclusions regarding impairments, which could materially affect our results of operations and financial position.

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. Our business also involves collection, uses and other processing of personally identifiable information of our employees, contractors, land agreement counterparties, and other related parties by the Company and/or our third-party business partners. 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, data breaches and cyberattacks (including through third parties with which we do business), which could significantly impair our ability to conduct our business. Additionally, if our major customers or suppliers experience deliberate attacks on, or unintentional events affecting their digital technologies, it may reduce their ability to utilize our, or provide, services, which could have a material adverse impact on our operations and business. Energy industry participants, including midstream companies, have been the victims of high-profile 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. The TSA has issued a series of security directives applicable to certain midstream companies, including us, requiring such companies to comply with mandatory reporting measures and undertake a number of specific cybersecurity enhancements for both IT and OT systems. In addition to the TSA security directives, there are multiple regulatory rulemaking processes, and contemplated legislation that may result in new regulations or requirements applicable to us. For additional information regarding cybersecurity matters applicable to us, including our TSA-approved CIP and laws and regulations such as the TSA security directives, see "Regulatory Environment" and "Cybersecurity" under Part I, “Item 1. Business” of this Annual Report on Form 10-K. 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. With the proliferation of regulations, we may become subject to overlapping or conflicting regulatory requirements. 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.

We rely on IT systems, some of which are managed by third parties that we do not control, that may also be, and may have been, susceptible to cyber threats and cyber-related risks described in this risk factor. While we and third parties that provide services to us commit resources to the design, implementation and monitoring of our IT and OT systems, there is no guarantee that our or such third parties’ 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. Attacks may originate from outside or inside parties, hackers, criminal organizations, or other threat actors, including nation states. As artificial intelligence (“AI”) capabilities improve and gain widespread use, we may experience cyberattacks created using AI or incidents related to the use of AI, which may be difficult to detect and mitigate against.

Deliberate attacks on, or unintentional events or incidents affecting, our IT and OT 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. Additionally, we have received notification from third party service providers of certain such matters on their systems. None of the cyberattacks and incidents we have identified, or been notified of, to the filing of this Annual Report on Form 10-K 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 rapidly develop in foreign, federal and state jurisdictions. Compliance with new laws and regulations governing data privacy, as well as any unauthorized disclosure of personal information, is becoming increasingly complex and may potentially increase our compliance costs. Any failure by us, a company that we acquire, or one of those third parties on which we rely, to comply with these laws and regulations, where applicable, could adversely affect us, including by resulting in reputational harm, penalties, regulatory investigations scrutiny, liabilities, legal claims and/or mandated changes in our business practices.

Our subsidiaries have significant amounts of debt outstanding under the Amended EQM Credit Facility, the 2021 Eureka Credit Facility (as such terms are defined in Note 9) and the senior unsecured notes issued by EQM. See Note 9 to the consolidated financial statements for a discussion of the Amended EQM Credit Facility, the 2021 Eureka Credit Facility and the senior unsecured notes issued by EQM and see Note 15 to the consolidated financial statements for a discussion of the Fifth Amendment to the Amended EQM Credit Facility. 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.

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 could not exceed 5.85 to 1.00 for the quarter ended December 31, 2023, 6.00 to 1.00 for the quarter ending March 31, 2024, 6.25 to 1.00 for the quarter ending June 30, 2024, 5.85 to 1.00 for the quarter ending September 30, 2024, and 5.50 to 1.00 for quarters thereafter, with the then-applicable ratio being tested as of the end of each fiscal quarter. 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.

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 (as defined in the applicable credit facility). Events beyond the control of EQM and Eureka (including changes in general economic and business conditions) and with respect to EQM, certain delays in the full in-service of the MVP project (absent mitigating actions by management), may affect the ability of EQM and Eureka to, as applicable, meet and comply with their respective financial obligations and covenants.

The provisions of the debt agreements may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of these 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.

Our subsidiaries’ levels of debt could have important consequences to us, including that 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. Further, we view de-levering our business as a critical strategic objective given that leverage levels affect the manner in which we may pursue strategic and organic initiatives, our ability to respond to market and competitive pressures, and the competition for investment capital. Our ability to de-lever and the pace thereof will depend on our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors (including particularly bringing the MVP in-service), as well as the MVP Joint Venture’s ability to execute on project-level financing, 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 (for example, the Amended EQM Credit Facility has been amended to increase the Consolidated Leverage Ratio in the past), including providing guarantees, pledging assets as collateral, reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity or debt capital. We may not be able to timely effect any of these actions on satisfactory terms or at all. Further, if our operating results are not sufficient to enable de-levering or affect the pace of de-levering, or if MVP project-level financing is not realized, the manner in which we may pursue strategic and organic initiatives, address market and competitive pressures, and compete for investment capital may be adversely affected, absent additional actions to de-lever, which may not be available to us 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 cause our subsidiaries’ respective access to the capital markets to become more challenging. 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 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 the financing of non-fossil fuel businesses and prompting the pursuit of emissions reductions, lower-carbon technologies, and alternative forms of energy), as well as 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.

In order to fund our capital expenditures and capital contributions so to grow and maintain our asset base and complete expansion projects, including the MVP project, any expansion of the MVP project and the MVP Southgate project, as well as to fund 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 new 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 subsidiaries’ or our joint ventures’ ability to 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 and as applicable, our subsidiaries’ or our joint ventures’ financial condition at the time of any such financing or offering, our subsidiaries’ or our joint ventures’ credit ratings, as applicable, the covenants in our subsidiaries’ or our joint ventures’ 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 the financing of non-fossil fuel businesses and prompting the pursuit of emissions reductions, lower-carbon technologies, and alternative forms of energy), as well as 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, our subsidiaries, or our joint ventures 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, our subsidiaries or joint ventures 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. For example, our strategic plans reflect the potential to incur debt at the MVP Joint Venture following MVP in-service so to enhance our ability to de-lever and pace thereof. The MVP Joint Venture’s ability to incur debt is subject to many of the same factors and considerations, as applied to the MVP Joint Venture, as are described for us and our subsidiaries in this risk factor, as well as joint venture considerations described under “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 or partners 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 risks to which we are subject.” in Part I, “Item 1A. Risk Factors” of this Annual Report on Form 10-K, and there is no assurance that debt at the MVP Joint Venture level, or related impacts or benefits, will be realized.

As of February 20, 2024, EQM’s credit ratings were Ba3 with a stable outlook, BB- with a negative outlook and BB on Rating Watch Positive 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, in-service timing and total project cost 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, EQM's leverage 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, 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 affecting the MVP project or increases in such project’s targeted costs), EQM’s leverage or credit ratings of our customers, 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) 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 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 and limit our operating flexibility. 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.

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. Increased focus related to ESG and sustainability matters may 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 the financing of non-fossil fuel businesses and prompting the pursuit of emissions reductions, lower-carbon technologies, and alternative forms of energy), as well as 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. Additionally, due to an increased focus on climate change and/or environmental justice policies, particularly as it relates to the fossil fuel industry, pipeline infrastructure companies and projects, as was the case with the MVP project, face increased legal scrutiny and execution risk, including related to litigation and enhanced and lengthier regulatory reviews by federal, state and/or environmental regulators.

We recognize that our shareholders, employees, customers, regulators, and other stakeholders expect us to continue to focus and report 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, including because of increasing regulatory demands, which may not be consistent in their requirements. For example, California enacted two climate related disclosure laws called the Climate Corporate Data Accountability Act (“CCDAA”) and the Climate-Related Financial Risk Act (“CRFRA”) on October 7, 2023. Further, on March 21, 2022, the SEC released proposed rule changes that would require new climate-related disclosure in SEC filings. For additional information regarding the SEC’s climate related disclosures rule, the CCDAA and the CRFRA, please see “Regulatory Environment — Climate Change” under Part I, "Item 1. Business" of this Annual Report on Form 10-K. The CCDAA and the CRFRA would, and the SEC’s climate related disclosures rule if adopted as proposed would, cause us to incur additional (and potentially accelerate) compliance and reporting costs, certain of which could be material, including related to monitoring, collecting, analyzing and reporting new metrics and implementing systems and procuring necessary attestations, as applicable.

Such costs, or costs or impacts associated with any failures to comply with such or any similar laws, may adversely affect our future business, financial condition, results of operations, and liquidity.

Further, if we do not adapt to or comply with investor or other stakeholder expectations and standards, which are evolving, or if we are perceived not to have responded appropriately or quickly enough to growing concern for ESG and sustainability issues, 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). We have disclosed aspirational goals, targets, potential financial impacts and other expectations and assumptions related to reducing our carbon footprint and promoting sustainability that are necessarily uncertain due to, among other things, long implementation timelines, and thus 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. Our disclosures regarding aspirational goals, targets, cost estimates, and other expectations or assumptions, as applicable, could receive increased scrutiny by shareholders or regulators which may adversely impact us, including as a result of unforeseen events which may affect us.

Additionally, activist shareholders may submit proposals to promote or oppose an ESG-related position. Responding to such proposals, 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. 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. Favorable or 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.

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. Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing risks and governmental actions that could have an adverse impact on our operations in the United States. Numerous proposals and regulations have been made and will continue to be made to monitor and limit existing GHG emissions, as well as to restrict or eliminate future emissions. Accordingly, our business and operations, and those in our value chain, including our producer customers, are subject to executive, regulatory, political, litigation, and financial risks associated with natural gas and the emission of GHGs.

At the federal level, the United States has taken steps to address climate change through legislative action, executive actions, and regulatory initiatives pursuant to existing statutes, such as the Clean Air Act. The EPA released in December 2023 its final rule, which has not yet been published in the Federal Register as of the filing of this Annual Report on Form 10-K, regulating methane emissions from the oil and gas sector under the Clean Air Act. The Inflation Reduction Act of 2022 amended the Clean Air Act to require a “methane fee” for specific facilities that exceed GHG emission and/or methane intensity thresholds beginning in 2024. These new Clean Air Act regulations, as well as any other future laws or regulations that legislators or federal agencies may adopt, could have an adverse impact on our operations and results thereof. State and regional efforts could establish requirements in states in which our assets, employees or customers are located regardless of federal action.

States where our, the MVP Joint Venture’s or our customers’ assets are located have entered or sought to enter into the Regional Greenhouse Gas Initiative (RGGI), which is a consortium of certain Northeastern and Mid-Atlantic states that set declining limits on CO2 emissions from fossil fuel fired power plants. Initiatives such as RGGI, if enforceable in our areas of operation, may result in increased uncertainty regarding demand for natural gas used in the generation of electricity, including in our operating markets. Beyond regional and state efforts, nationally, demand for natural gas used in the generation of electricity could also be affected by federal action, such as the EPA’s proposed rulemaking to regulate GHG emissions from new and existing fossil fuel fired power plants.

There remains considerable uncertainty surrounding the timing, scope and potential impact of future state, national and international action 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 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 interpreted or reinterpreted, and this may occur during the permitting and construction phases of our projects, and may result in increased costs and delays. Generally, development and implementation of processes to comply with changing legal requirements are likely to be costly and time consuming. Laws, regulations and legal requirements designed to reduce GHG emissions also may: (i) 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; (ii) reduce the number of attractive business opportunities available to us and discourage investments in our securities; (iii) impose additional and costly compliance obligations such as new emission control requirements, taxes, fees or other costs on the release of GHGs, cause longer permitting timelines, require that we purchase allowances for emissions, expose us to regulatory penalties or affect our reputation; and (iv) adversely affect production of or demand for natural gas (such as by increasing the cost of producing natural gas, increasing the cost of producing electricity with natural gas, or prompting consumers to use renewable fuels).

If any of the foregoing events were to occur, it may 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 which is inherently uncertain.

Litigation risks relating to climate change continue to increase. Parties have brought suit against certain large 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 damages. Parties have also alleged that these companies have been aware of the adverse effects of climate change for some time but misled their investors and consumers by failing to adequately disclose those impacts. While we are not currently party to any such litigation as of the filing of this Annual Report on Form 10-K, we, joint ventures in which we participate, or third parties with which we do business could be named in future actions given that our or their 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, and are likely to cite in the future, our and/or the MVP Joint Venture's direct and/or indirect GHG emissions as a specific concern during comment periods for regulatory permit reviews.

Market forces driven by concern for climate change are also 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 (as we have experienced with respect to the Amended EQM Credit Facility (as defined in Note 9), and in the future could experience). 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. 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, the concern surrounding climate change is increasing demand for lower-carbon technologies and alternate forms of energy in the marketplace, which is driving innovation and investment in products that compete with natural gas. Continued momentum to develop and drive down the cost of competitive energy alternatives 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 located in the Appalachian Basin, which is a rain-susceptible region and given its geography there is inherent risk associated with landslides which could increase with climate change. Further, climate-induced rainfall events and severe storms above and beyond historical estimates, magnitudes, and frequency could exceed the pre-designed environmental controls in place on our construction projects, and/or cause pipeline slips or other 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 or temporarily interrupt our operations. We may not be able to pass on resultant financial impacts 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 environmental controls, 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 and financial condition.

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.

For additional information on GHG laws, regulations and other legal requirements applicable to us, see “Regulatory Environment — Environmental Matters” under “Item 1. Business” in Part I of this Annual Report on Form 10-K.

Negative public perception regarding us, the MVP, MVP Southgate, other of our or the MVP Joint Venture’s extension or expansion projects and/or our industry, resulting from, among other things, concerns raised by advocacy groups regarding 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; hydraulic fracturing, environmental justice concerns; as well as general and specific concerns relating to our operations or pipeline and expansion projects, has led to, and may in the future lead to, increased regulatory scrutiny, and/or new local, state, and federal safety and environmental laws, regulations, guidelines, enforcement interpretations and/or adverse judicial rulings or regulatory actions.

These actions have caused, and may continue to cause, operational delays or restrictions, increased construction and operating costs, penalties under construction contracts, additional regulatory burdens, and increased litigation. 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 extension or expansion projects, including the MVP Southgate project and any expansion of the MVP, 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 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.

Furthermore, the 2024 election cycle will impact public policy initiatives at the federal and state level. In addition to the U.S. presidential election, all 435 seats in the U.S. House of Representatives and 34 U.S. Senate seats are subject to election. With the exception of Virginia, all of the states in our, or the MVP Joint Venture’s, operating area have elections that will determine control of state legislatures, including a gubernatorial election in North Carolina. The results of these elections will have a significant effect on the legislative and regulatory landscape for the natural gas industry. Additionally, there have been and continue to be certain initiatives at the federal, state and local levels aimed at the natural gas industry, including those to restrict the use of hydraulic fracturing as discussed in more detail in “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 connected to our assets. If reductions are significant for those or other reasons, the reductions could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.” in Part I, “Item 1A. Risk Factors” of this Annual Report on Form 10-K. 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.

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, and as of December 31, 2023 dry natural gas comprised approximately 86% of our product portfolio.

Due to our lack of diversification in assets, products and geographic location and the challenging environment for completing transmission 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 or production determinations, decreases in demand for natural gas from the Appalachian Basin, takeaway capacity constraints from the Appalachian Basin (including as may remain long term notwithstanding any completion of MVP and limit our producer customers’ future ability to grow production volumes to then-existing pipeline capacity and consequently affect natural gas prices adversely within the Appalachian Basin) or increases in supply of natural gas from other natural gas or oil producing basins (such as associated gas production from the Permian Basin) 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, products and locations.

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 Part II, “Item 7A. Quantitative and Qualitative Disclosure About Market Risk” of this Annual Report on Form 10-K. 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 or any other party and our credit policies cannot completely eliminate credit risk. Pursuant to certain agreements with EQT, 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, however, there can be no assurance that EQT will maintain sufficient credit ratings or such rating thresholds are protective against all credit risk in the case of EQT.

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. Periods of low commodity prices have previously 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 ability to grow organically depends primarily upon our ability to complete organic growth projects, such as the MVP project (and related extensions or expansions thereof), leverage our existing asset base to benefit our existing customer relationships and attract new customers, and realize increasing commitments and/or volume growth that generate revenue from customers. As gathering fee declines take effect under the EQT Global GGA, the failure to grow organically, including particularly the failure to achieve increasing commitments and/or volume growth that generate revenue, could adversely affect our cash flows and potentially our business. See, for example, “We generate a substantial majority of our revenues from EQT. 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) or a shift in such activity away from our assets could adversely affect our business and operating results.” in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K. Factors which may adversely affect our ability to grow organically include, among other things, any inability to:

•identify attractive organic growth projects;

•obtain and/or maintain necessary rights-of-way, real-estate rights or permits or other government approvals, including approvals by regulatory agencies;

•successfully integrate the infrastructure we build with our existing systems;

•obtain and/or maintain sources of fresh or produced water;

•generate sufficient cash from our operations and/or raise financing on economically acceptable terms for projects;

•realize assumptions about volumes, revenues, costs, producer turn-in-lines and in-service timing, as well as potential growth; or

•secure or maintain adequate customer commitments, including to use newly expanded facilities.

Additionally, we face and expect to continue to face staunch and protracted opposition to the development of expansion and extension projects (such as has been case with the MVP and MVP Southgate projects) and operation of our pipelines and facilities from environmental groups, certain 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 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 or extension projects, and/or revenues generated, or expected to be generated, by our operations or that causes us to make significant expenditures associated with delayed construction completion or 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. Our Board of Directors has been engaged in a process with third parties that have expressed interest in strategic transactions involving the Company. The board has engaged outside advisors and the process is ongoing. There is no assurance that such process will result in the execution, approval or completion of any specific transaction or outcome. See also “Strategic transactions that we enter into 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.

On November 6, 2022, we became aware of natural gas venting from a storage well (well 2244) at Equitrans, L.P.’s Rager Mountain natural gas storage facility, located in Cambria County, Pennsylvania, which venting was halted on November 19, 2022 (the Rager Mountain natural gas storage field incident). During and continuing since the occurrence of the incident, we have incurred costs and expenses relating to or arising out of the incident, including in connection with a root cause analysis of the incident, which was conducted by an independent, third-party company with expertise in reservoir management and well and corrosion engineering and which was submitted to the PHMSA in August 2023.

Although in October 2023, following authorization from the PHMSA of our injection plan for the Rager Mountain facility, we returned the Rager Mountain facility, other than well 2244 and two additional wells, to injection operations, as discussed in Part I, “Item 3. Legal Proceedings” of this Annual Report on Form 10-K, the PADEP, the PHMSA and other investigators are continuing to conduct civil and criminal investigations of the incident and we and our subsidiary Equitrans L.P., as applicable, are cooperating in such investigations. There can be no assurance as of the filing of this Annual Report on Form 10-K as to the outcome of any investigation or pending or future proceeding with respect to the Rager Mountain natural gas storage field incident, nor can there be any assurance regarding the scope of potential (or ultimately actual) financial or other impacts or sanctions to the Company as a result of such incident. Certain of the statutory provisions cited by the PADEP in certain notices of violation relating to the incident provide for a maximum penalty of up to $25,000 per day of violation, and if penalties are pursued and ultimately imposed related to the Rager Mountain natural gas storage field incident, the penalties are expected to result in monetary sanctions in excess of $300,000.

See also “We do not insure against all potential losses and could be seriously harmed by unexpected liabilities or the inability of our insurers to satisfy our claims.” in Part I, “Item 1A. Risk Factors.”, and see also Note 14 to the consolidated financial statements, Part I, “Item 3. Legal Proceedings” and Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report on Form 10-K for further information regarding the Rager Mountain natural gas storage field incident.

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:

•aging infrastructure and mechanical or structural problems;

•security risks, including cybersecurity;

•pollution and other environmental risks;

•operator error;

•failure of equipment, facilities or new technology;

•damage to pipelines, wells and storage assets, facilities, equipment, environmental controls and surrounding properties, and pipeline blockages or other operational interruptions, caused or exacerbated by natural phenomena, weather conditions, 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, or other hazardous materials;

•leaks, migrations or losses of natural gas as a result of issues regarding pipeline and/or storage equipment or facilities and, including with respect to storage assets, as a result of undefined boundaries, geologic anomalies, limitations in then-applied industry-standard testing methodologies, operational practices (including as a result of regulatory requirements), natural pressure migration and wellbore migration or other factors relevant to such storage assets;

•ruptures, fires, leaks and explosions; 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 or other sanctions 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, particularly if the event is not fully covered by insurance. See also “We do not insure against all potential losses and could be seriously harmed by unexpected liabilities or the inability of our insurers to satisfy our claims.” and “We have incurred and expect to continue to incur costs and expenses as a result of or arising in relation to the Rager Mountain natural gas storage field incident in November 2022, which has included and may include potential additional regulatory penalties or other sanctions, which could, depending on their scope and timing, materially adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.” in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K. 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. Customer impacts arising from service interruptions on segments of our systems and/or our assets have included and/or may include, without limitation and as applicable, curtailments, limitations on our ability to satisfy customer contractual requirements, obligations to provide reservation charge credits to customers 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 and, as has been the case in certain instances in the past, negatively impact our business, financial condition, results of operations, liquidity and/or ability to pay dividends to our shareholders.

Our ability to renew or replace existing contracts or add new contracts at rates sufficient to maintain or grow 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, certain of our customers, including EQT, have developed or acquired their own gathering and water infrastructure, and may acquire or develop gathering, transmission or storage and/or water infrastructure in the future, which could have a negative impact on the demand for our services depending on the location of such systems relative to our assets and our producer customers’ drilling plans, commodity prices, existing contracts and other factors.

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 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, the availability of renewable and alternative energy is growing, and it continues to become more cost competitive with fossil fuels, including natural gas. Continued increases, whether driven by legislation, regulation or consumer preferences, in the availability and demand for renewable and alternative energy at the expense of natural gas (or increases in the demand for other sources of energy relative to natural gas based on price and other factors) could adversely affect our producer customers and lead to a reduction in demand for our natural gas gathering, transmission and storage, and water services.

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.

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.

One of our exposures to market risk occurs at the time our existing contracts expire and are subject to renegotiation and renewal. As these contracts expire, we may have to negotiate extensions or renewals with existing customers or enter into new contracts with existing customers or other customers. We may be unable to do so on favorable commercial terms, if at all. Further, we also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. The extension or renewal of existing contracts and entry into new contracts depends on a number of factors beyond our control, including, but not limited to: (i) the level of existing and new competition to provide services to our markets; (ii) macroeconomic factors affecting natural gas economics for our current and potential customers; (iii) the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets; (iv) the extent to which the customers in our markets are willing to contract on a long-term basis or require capacity on our systems; (v) customers’ existing and future downstream commitments; and (vi) 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 certain of our services, see “Regulatory Environment — FERC Regulation” under Part I, “Item 1. Business” of this Annual Report on Form 10-K. Additionally, disagreements may arise with contractual counterparties on the interpretation of contractual provisions, as had been the case with EQT with the Hammerhead gathering contract, including during the negotiation, for example, of contract amendments required to be entered into upon the occurrence of specified events.

Any failure to extend or replace a significant portion of our existing contracts or to extend or replace our significant contracts, or extending or replacing contracts at unfavorable or lower rates or with lower or no associated firm reservation fee revenues, or other disadvantageous terms relative to the prior contract structure, or disagreements or disputes on the interpretation of existing or future contractual terms, 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 increase our customer-subscribed capacity and throughput and resulting revenue is subject to numerous factors beyond our control, including competition from producers’ existing contractual obligations to competitors, the location of our assets relative to those of competitors for existing or potential producer customers (or such producer customers’ own midstream assets), takeaway capacity constraints out of the Appalachian Basin, commodity prices, producers’ optionality in utilizing our (relative to third-party) systems to fill downstream commitments, 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 and capacity constraints, as well as commodity prices, may, as has occurred in the past, adversely affect the degree to which natural gas production occurs in the Appalachian Basin, and relatedly the degree to which our systems are utilized.

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.

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 and the MVP Joint Venture’s (once MVP is placed in-service) transmission, and our storage, system interconnects, as applicable, with the following third-party interstate pipelines: Transcontinental Gas Pipe Line Company, LLC (Transco), East Tennessee Natural Gas, Texas Eastern, Eastern Gas 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 or the MVP Joint Venture's access to such systems is impaired (or any third party refuses to accept our or any of the MVP Joint Venture's deliveries), our or the MVP Joint Venture's operations could be adversely affected, resulting in adverse economic impact to us or the MVP Joint Venture. We have been affected by certain such circumstances in the past, which for example has reduced revenues from our gathering activities.

Because we do not own these third-party pipelines or facilities, their continuing operation and access requirements are 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 (or, with MVP in-service, the MVP Joint Venture’s) ability to operate efficiently and ship 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 adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

It is possible that costs to perform services under “negotiated rate” contracts could exceed the negotiated rates we have agreed to with 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, 2023, 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, GHG emission cost (such as carbon taxes, fees, or assessments) or other factors relating to the specific facilities being used to perform the services.

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, including in respect of any expansion of the MVP. 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 our joint ventures or joint venture partners, it may be difficult or impossible for us to cause these joint ventures or partners 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, and would in the case of the MVP project, significantly adversely affect the ability to complete the project. In addition, the MVP Joint Venture, Eureka Midstream and any joint ventures we may enter into in the future are subject to many of the same risks to which we are subject.

We have, and may in the future, engage in acquisitions, dispositions, and other strategic transactions. These transactions involve risks that have impacted and may in the future impact our ability to realize a benefit from the transaction, including, among other potential risks (and as applicable): (i) an inability to obtain necessary regulatory and third-party approvals; (ii) the timing of and conditions imposed upon us by regulators in connection with such approvals; (iii) failure to realize assumptions about volumes, revenues, capital expenditures and costs, including synergies and potential growth; (iv) an inability to secure or maintain adequate customer commitments to use the acquired systems or facilities; (v) an inability to successfully integrate the assets or businesses we acquire; (vi) 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; (vii) 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 (viii) unforeseen difficulties operating a larger organization or in new geographic areas, with new joint venture partners or new business lines.

If risks such as the above are realized, or if a strategic transaction 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 are not fully insured against all risks inherent in our business, including certain environmental accidents that might occur as well as many cyber events. We do not maintain insurance in the type to cover all possible risks of loss, including “wild well” coverage or certain damage caused by cyberattacks. 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, certain environmental incidents, 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.

In addition to requiring in many instances that we are named as additional insureds on policies maintained by vendors such as construction contractors, as of the filing of this Annual Report on Form 10-K we 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, in limited circumstances, 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 have elected and may elect in the future 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.

Furthermore, any insurance company that provides coverage to us may experience negative developments that could impair its ability to pay any of our claims. As a result, we could be exposed to greater losses than anticipated and may have to obtain replacement insurance, if available, at a greater cost.

Significant portions of our transmission and storage system have been in service for several decades. The age and condition of these systems has contributed to, and could result in, adverse events, or increased maintenance or repair expenditures, and downtime associated with increased maintenance and repair activities, as applicable. 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. See also, “We may incur significant costs and liabilities as a result of performance of our pipeline and storage integrity management programs and compliance with increasingly stringent safety regulation.” in Part I, “Item 1A. Risk Factors” of this Annual Report on Form 10-K.

Our operations are dependent upon key management, technical and professional personnel, and one or more of these individuals could leave our employment or become unavailable due to, among other things, pandemics or epidemics, natural disaster, war, act of terrorism, sustained illness or injury. 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 continues to be increased competition for experienced technical and other professionals, 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.

Our exposure to commodity price risk may increase in the future and NYMEX Henry Hub futures prices affect the fair value, and may affect the realizability, of potential cash payments to us by EQT pursuant to the EQT Global GGA.

For the years ended December 31, 2023, 2022 and 2021, approximately 70%, 71% and 64%, respectively, of our operating revenues were generated from firm reservation fee revenues. Consequently, cash flows generated from such revenues generally had limited exposure to commodity price risks. However, cash flows that are not derived from firm reservation fees, such as those derived from our volumetric-based services, do create a level of exposure to commodity price risk in that producer customers may adjust their plans as a result of changes in the commodity price environment. Although our goal is to continue to seek to contractually minimize our exposure to commodity price risk in the future by executing long-term firm reservation fee, MVC and ARC contracts with new or existing customers, 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, MVCs, ARCs or other fixed fee arrangements and therefore may have a greater exposure to fluctuations in customer volume variability driven by commodity price risk. Our existing and future exposure, primarily through volumetric-based services, to the volatility of natural gas prices, including regional basis differentials with regard to natural gas prices, and any significant increase to such exposure 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 derivative asset attributable to the Henry Hub cash bonus payment provision is largely determined by estimates of the NYMEX Henry Hub natural gas forward price curve and probability-weighted assumptions regarding MVP full in-service timing, and payments are conditioned upon the quarterly average of certain Henry Hub natural gas prices exceeding certain price thresholds. The NYMEX Henry Hub future price of natural gas is a widely used benchmark for the price of natural gas in the United States. Based on the Henry Hub natural gas forward strip prices as of February 16, 2024 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 adverse change or simply commodity prices on their own could ultimately result in further decreases to such estimated fair value, including to zero. Such changes in estimated fair value, if any, would be recognized in other income (expense), net, on our statements of consolidated comprehensive income. Depending on the future NYMEX Henry Hub prices, payments under the Henry Hub cash bonus payment provision may not be triggered even if MVP were to be placed in-service (and, even if prices are sufficient to meet necessary thresholds, payments will not be triggered if the MVP is not placed in-service in or before the quarter ending December 31, 2024), which 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, 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 attempting (or by virtue of the need to attempt) to acquire or to maintain use rights to land. See “Item 2. Properties” in Part I of this Annual Report on Form 10-K for additional information. Although many of these rights are perpetual in nature, we occasionally obtain the rights to construct and operate our pipelines and other facilities on land owned by third parties and governmental agencies for a specific period of time or in a manner in which certain facts could give rise to the presumption of the abandonment of the pipeline or other facilities. 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, the potential for which may have a negative effect on the timing and/or terms of FERC action on a project’s certification application and/or the timing of any authorized activities, 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. It is also possible that a court may limit, modify or remove an operator’s ability to utilize condemnation under Section 7 of the NGA. A loss of rights-of-way, lease or easements or a relocation of our non-regulated assets 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.

Our and the MVP Joint Venture’s interstate natural gas transmission and storage operations, as applicable, are regulated by the FERC under the NGA and the NGPA and the regulations, rules and policies promulgated under those and other statutes. Our and the MVP Joint Venture’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 our customers. The FERC’s authority extends to a variety of matters relevant to our operations. For additional information, see “Regulatory Environment — FERC Regulation” under “Item 1. Business” in Part I of this Annual Report on Form 10-K.

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.

As of the filing of this Annual Report on Form 10-K, we and the MVP Joint Venture 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, 2023, 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 or the MVP Joint Venture 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 or the MVP Joint Venture’s rates offered to customers or the terms and conditions of service included in our tariffs. Neither we nor the MVP Joint Venture have an agreement in place that would prohibit customers, including EQT or its affiliates, from challenging our or the MVP Joint Venture’s rates or tariffs. Any successful challenge against rates charged for our or the MVP Joint Venture’s transmission and storage services, as applicable, 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 U.S. Congress may continue to evaluate changes in the NGA or new or modified FERC regulations or policies that may impact our or the MVP Joint Venture’s operations and affect our or the MVP Joint Venture’s ability to construct new facilities and the timing and cost of such new facilities, as well as the rates charged to our or the MVP Joint Venture’s customers and the services provided.

Our and the MVP Joint Venture’s significant construction projects generally require 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 (as has been the case with our MVP project). Such delays, refusals, losses of permits, or resulting modifications to projects, certain of which we have experienced with respect to the MVP project and the originally contemplated MVP Southgate project, could materially and negatively impact the revenues and costs expected from these projects or cause us or our joint venture partners to abandon planned projects.

Failure to comply with applicable provisions of the NGA, the NGPA, federal pipeline safety laws and certain other laws, as well as with the regulations, rules, orders, restrictions and conditions associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties. For example, the FERC is authorized to impose civil penalties of up to approximately $1.5 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 or the MVP Joint Venture will operate may have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

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” in Part I of this Annual Report on Form 10-K. Laws, regulations and other legal requirements applicable to our business, including relating to environmental protection, health and safety, cybersecurity, as well 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 increased costs, 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, see Part I, “Item IA.

Risk Factors” of this Annual Report on Form 10-K under “We have incurred and expect to continue to incur costs and expenses as a result of or arising in relation to the Rager Mountain natural gas storage field incident in November 2022, which has included and may include potential additional regulatory penalties or other sanctions, which could, depending on their scope and timing, materially adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.” and Part I, “Item 3. Legal Proceedings” of this Annual Report on Form 10-K. In addition, noncompliance with applicable laws, regulations or other legal requirements, including required permits and other approvals, has subjected and 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, release, irrespective of fault, from one of our pipelines or storage systems, has subjected and could subject us, as applicable, 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 needed to bring certain facilities that were acquired into compliance have been expensive. In the future, steps to bring other acquired facilities 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, 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” in Part I of this Annual Report on Form 10-K, 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. Our projects and the MVP Joint Venture’s projects 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 and state agencies have increased their focus on, and resources devoted to, environmental justice and certain agencies, including EPA and DOJ, have sought out opportunities to address environmental justice issues through federal and state 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 the financing of non-fossil fuel businesses and prompting the pursuit of emissions reductions, lower-carbon technologies, and alternative forms of energy), as well as 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.

The DOT, acting through PHMSA, and certain state agencies certificated by PHMSA, have adopted regulations requiring pipeline operators to develop an integrity management program for transmission pipelines located where a leak or rupture could impact high population sensitive areas (also known as High Consequence Areas or HCAs) and newly defined Moderate Consequence Areas (MCAs), and an integrity management program for storage wells, unless the operator effectively demonstrates by a prescriptive risk assessment that these operational assets have mitigated risks that could affect these predefined areas, as applicable. The regulations require operators, including us, to perform ongoing assessments of pipeline and storage integrity; identify and characterize applicable threats to pipeline segments and storage wells that could impact population sensitive areas; confirm maximum allowable operating pressures; maintain and improve processes for data collection, integration and analysis; repair and remediate facilities as necessary; and implement preventive and mitigating actions.

In addition to population sensitive areas, PHMSA has recently adopted regulations extending existing design, operational and maintenance, and reporting requirements to onshore gathering pipelines in rural areas. Finally, new PHMSA regulations require operators of certain transmission pipelines to assess their integrity management and maintenance practices, comply with enhanced corrosion control and mitigation timelines, and follow new requirements for pipeline inspections following an extreme weather event or natural disaster.

The cost and financial impact of compliance will vary and depend on factors such as the number and extent of maintenance determined to be necessary as a result of the application of our integrity management programs, and such costs and financial impact could have a material adverse effect on us. Further, our pipeline and storage integrity management programs depend in part on inspection tools and methodologies developed, maintained, enhanced and applied, and certain testing conducted, by certain third parties, many of which are widely utilized within the natural gas industry. Advances in these tools and methodologies could identify potential and/or additional integrity issues for our assets. Consequently, we may incur additional costs and expenses to remediate those newly identified or potential issues, and we may not have the ability to timely comply with applicable laws and regulations. Additionally, pipeline and storage safety laws and regulations are subject to change and failures to comply with pipeline and storage safety laws and regulations, including changes in such laws and regulations or interpretations thereof 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, including risks associated with compliance with the Mega Rule, see “Regulatory Environment — Safety and Maintenance” under “Item 1. Business” in Part I of this Annual Report on Form 10-K.

We may, and joint ventures of which we are the operator could, as is the case with the MVP Joint Venture, become subject to consent orders and agreements relating to integrity matters. On October 3, 2023, PHMSA issued a consent order incorporating the terms of a consent agreement entered into by PHMSA and the Company as the operator of the MVP project (the MVP Consent Agreement). The MVP Consent Agreement resolves the Notice of Proposed Safety Order (NOPSO) that PHMSA issued to the Company on August 11, 2023, for the MVP project, without admission or denial of any of the allegations in the NOPSO. The MVP Consent Agreement outlines the steps being taken by the MVP Joint Venture to responsibly complete construction, including, among other things, enhancing MVP’s existing coating, remediation and inspection processes, mandating or accelerating certain previously planned MVP inline inspections, accelerating the regulatory timeline for conducting cathodic protection surveys, and implementing additional measures to assess cathodic protection following MVP full in-service. The MVP Joint Venture has been conducting surveys and analyses and submitting reports to PHMSA in compliance with the requirements of the consent agreement. Failure to comply with the terms of the MVP Consent Agreement could have adverse effects on our business, including, in the case of the MVP Consent Agreement, adverse effects regarding MVP project completion.

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.

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. In addition, there are regulations existing and proposed at the federal and state level that could indirectly limit or affect hydraulic fracturing. 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, including the EPA, as well as certain states, have conducted reviews and studies on the environmental aspects of hydraulic fracturing. The results of such reviews or studies have and could further spur initiatives to further regulate hydraulic fracturing.

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, in Pennsylvania legislation was proposed 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 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.

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.

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 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.

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, including the MVP project, some of which may be beyond our control. General market fluctuations, industry factors, such as climate change-related physical and transitional risks, and general economic and political conditions and events, such as economic slowdowns or recessions, as well as factors specific to our business (including the status of and cost to construct the MVP project and perceptions regarding our growth opportunities), have, as applicable, 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, de-levering, 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. A reduced stock price affects, among other things, our cost of capital and could affect our ability to execute future strategic transactions, as well as increases opportunities for investor activism or unsolicited third-party activity affecting us.

We are not required to declare and pay dividends to our common shareholders. 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. Our Board may also 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 Pennsylvania Business Corporation Law (PBCL), 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 also may not 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.

Our shareholders’ percentage of ownership in us may be diluted because of equity issuances for acquisitions, capital market transactions or otherwise, including, without limitation, equity awards that we may grant to our directors, officers, and employees. Our Human Capital and Compensation Committee and our Board have authority to grant share-based awards to our employees under employee benefit plans and, from time to time, we issue 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. Equity issuances may have a dilutive effect on our earnings per share, which could adversely affect the market for and the market price of our stock, and have a dilutive effect on our shareholders’ ownership interests in us.

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.” in Part I, “Item 1A. Risk Factors” of this Annual Report on Form 10-K, 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.

Our Second Amended and Restated Articles of Incorporation and Fifth 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 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, Fifth 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 Fifth 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 and Fifth 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 Fifth Amended and Restated Bylaws does not apply to actions arising under the Securities Act or the Exchange Act.

When applicable, this exclusive forum provision may limit the ability of our shareholders to bring a claim in a judicial forum that such shareholders find favorable for disputes with us or our directors or officers, which may discourage such lawsuits against us and our directors and officers. Alternatively, if a court outside of Pennsylvania were to find this exclusive forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings described above, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, results of operations and financial condition.

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. In July 2023, pursuant to this Registration Rights Agreement, we filed a registration statement with the SEC to register up to 30,018,446 Equitrans Midstream Preferred Shares and up to 30,018,446 shares of our common stock that are issuable upon conversion of the Equitrans Midstream Preferred Shares held by such certain investors party to the Registration Rights 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.

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 certain share purchases from EQT in 2020 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.

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 (EQT Tax 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 Tax 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.

The agreement that effected the Separation (the Separation and Distribution Agreement) 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.” in Part I, “Item 1A. Risk Factors” of this Annual Report on Form 10-K. Further, 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.

None.

Due to the critical nature of our business to the U.S. economy and national energy security and the continuous threat of cyberattacks, we regard cybersecurity as a top tier enterprise risk. Cybersecurity is integrated into our enterprise risk management program, which includes quarterly technology and cybersecurity risk assessments. We use the results of the technology and cybersecurity risk assessments for risk-based decision making to determine actions and priorities for our cybersecurity program. The technology and cybersecurity risk assessment process includes an objective, risk-ranking process; documented mitigation activities; and action plans for those risks requiring additional mitigation. These activities consider safety implications, operational disruptions, and business and financial impacts. As part of the cybersecurity program, we regularly obtain threat intelligence from various sources, which sources originate from private, commercial, and independent entities. In addition, our IT leadership routinely conducts risk quantification, simulations, and assessment exercises. We regularly engage with relevant government agencies to report and share certain security information enabling us to benchmark our capabilities, establish appropriate program targets, and adapt to emerging cybersecurity issues.

To manage our cybersecurity risk, we practice cyber hygiene through, among other measures, identity and access management, vulnerability and patch management, and asset management programs. We also segment our informational and operational technologies, and leverage network micro-segmentation and combine this practice with zero-trust security concepts. Operationally, we continuously monitor for cyber intrusions and augment our internal resources and capabilities with third-party service providers. Multiple security technologies are employed to protect our systems, applications, and data, including next generation firewalls, multi-factor authentication and access controls, and endpoint detection and response solutions.

We have integrated our cloud-hosted services with our security operations center and have implemented measures aimed at securing our remote workforce. We measure our cybersecurity practices against the National Institute of Standards and Technology Cybersecurity Framework, relevant industry standards, and government regulations. We routinely engage independent third-party security firms to exercise and assess our cybersecurity capabilities.

Our information technology governance, including cybersecurity, is documented through written policies, procedures, guidelines, and standard operating procedures. All of our employees are required to undergo quarterly cybersecurity training. This training includes cybersecurity policies, cyber threats, and incorporating best practices into daily routines. Contractors and vendors that have access to our data, devices, or services are required to complete cybersecurity training prior to receiving access. Employees, vendors, and contractors with access to our operational technology network are required to undergo additional training specific to operational technology interactions. We maintain a Supplier Code of Conduct that is provided to our providers of materials and services during the onboarding process and that conveys our expectations regarding use and access requirements when using our technology resources.

We also manage cybersecurity risk through incident response strategies. We employ a fault-tolerant, highly available architecture and network segmentation as part of our containment strategy. We do not solely rely on architecture to ensure continuity and containment, and we employ additional technologies including, but not limited to, automated account disabling, automated device quarantining, network segment-isolation scripts, and cyber kill chain runbooks. We have implemented an Enterprise Data Backup Policy, which includes, among other activities, offsite backups, intra-day recovery points, and routine restoration of critical data. We use infrastructure-as-code to enable recovery of virtualized environments and employ data replication across multiple operating regions. We routinely exercise our recovery capabilities. Our Cybersecurity Incident Response Plan establishes a framework to manage the life cycle of a cyber event. Additionally, our Enterprise Crisis Management Plan provides a structure to assemble an enterprise crisis team in the event of a potential cyber related crisis. The crisis response team, including our Chief Information Officer (CIO), is responsible for managing the channels of communication pursuant to our Crisis Management Plan. This notification includes the notification or reporting of any significant cyber incidents to executive management. We periodically conduct cyber incident drills that include, as applicable, members of our Board of Directors, executives, certain business stakeholders, and legal and security partners, as necessary.

While we and third parties that provide services to us commit resources to the design, implementation and monitoring of our digital systems, there is no guarantee that our or our third parties’ cybersecurity measures will provide absolute security. Like other companies in the natural gas industry, we have identified and expect to continue to identify cyberattacks and incidents on our systems. Additionally, we have received notification from third-party service providers of certain such matters on their systems. None of the cyberattacks and incidents we have identified, or been notified of, to the filing of this Annual Report on Form 10-K has had a material impact on our business strategy, results of operations or financial condition. For more information regarding the risks associated with cybersecurity that may impact our business strategy, results of operations, or financial condition, see “Cyberattacks aimed at us or those third parties on which we rely, as well as any noncompliance by us or such third parties with applicable laws and regulations governing cybersecurity and/or data privacy, could materially adversely affect us.” included in Part I, “Item 1A. Risk Factors” of this Annual Report on Form 10-K.

Given the importance to us of our cybersecurity program, in April 2022, our Board elected to exercise direct oversight of cybersecurity matters, rather than acting through its committees. The Board, as well as separately our executive management, receives, and has the opportunity to ask questions and raise discussion points regarding, management reports from the CIO and Senior Director of Cybersecurity and Network Operations on cybersecurity matters, as needed and no less than quarterly throughout the year, which reports include items such as cybersecurity updates, cybersecurity operational results, and audit findings. In addition, the Board and executive management receives and reviews the results of our cybersecurity risk and capabilities assessment on an annual basis.

The cybersecurity program is managed by our CIO and our Senior Director of Cybersecurity and Network Operations and reviewed and monitored by executive management, with oversight from the Board. Our CIO has significant expertise and more than 30 years of experience in information technology and cybersecurity including cloud technologies and reports to our Executive Vice President & Chief Legal Officer. Our Senior Director of Cybersecurity and Network Operations has more than two decades of experience in the fields of information technology and cybersecurity and holds cybersecurity certifications, including the Certified Information Systems Security Professional, Certified Cloud Security Professional, and GIAC Information Security Professional certifications. The CIO and Senior Director of Cybersecurity and Network Operations meet regularly with each other and members of their team to discuss cybersecurity threats, capabilities and program strategy. We have built in incident workflows that automatically provide notifications and escalate cybersecurity incidents. During an incident, the CIO acts as the incident commander and the Senior Director of Cybersecurity and Network Operations acts as operations section chief, working together to provider supervision over incident response.

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 in all material respects. Other 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 in all material respects. The Company believes that it has satisfactory title to all of its material leases, easements, rights-of-way, permits and licenses in all material respects, and the Company has no knowledge of any material challenge to its title to such assets or their underlying fee title.

There are, however, certain lands within the Company's storage pools and where the Company's pipelines and other facilities are located as to which it may not currently have vested real property rights as of the filing of this Annual Report on Form 10-K, 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 "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 Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K.

See Part I, "Item 1. Business" of this Annual Report on Form 10-K for a discussion of the Company's business segments relevant to its property holdings and map of the Company's operations.

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 October 2019, 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 May 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. Over the next months the Company provided many responses to the PADEP’s continuing information requests. The PADEP issued a final report and closed its investigation and the Company does not expect further inquiry from the PADEP on this matter. On October 23, 2023, the Company received permission from the FERC to plug and abandon the well in the Pratt Storage Field that is the subject of the PADEP’s investigation of the Company. Additionally, the Company is continuing to defend in a civil litigation related to the Incident.

On October 30, 2023, the Company received a criminal complaint from the State Attorney General’s Office charging the Company with violations of the Clean Streams Law (the Pratt Complaint). In response to the Pratt Complaint, the Company intends to fully assert its rights and defenses to the claims raised. The Pratt Complaint carries the possibility of a monetary sanction, that if imposed could result in a fine in excess of $300,000.

The Pratt Complaint could also cause reputational or other adverse impacts.

Rager Mountain Storage Field. On November 6, 2022, the Company became aware of natural gas venting from one of the storage wells, well 2244, at Equitrans, L.P.’s Rager Mountain natural gas storage facility (Rager Mountain facility), located in Jackson Township, a remote section of Cambria County, Pennsylvania, which venting was halted on November 19, 2022. The PADEP, the PHMSA and other investigators are continuing to conduct civil and criminal investigations of the incident and the Company is cooperating in such investigations. On December 7, 2022, the Company and its subsidiary Equitrans, L.P. each separately received an order from the PADEP alleging, in connection with earth disturbance activities undertaken to halt the venting of natural gas from well 2244, (i) in the case of the order received by the Company, violations of Pennsylvania’s Clean Streams Law and requiring certain remedial actions and (ii) in the case of the order received by Equitrans, L.P., violations of Pennsylvania’s 2012 Oil and Gas Act, Clean Streams Law and Solid Waste Management Act and requiring certain remedial actions. On December 8, 2022, the PADEP submitted a compliance order to Equitrans, L.P. relating to certain alleged violations of law in respect of wells at the Rager Mountain natural gas storage field and the venting of natural gas, including from well 2244. The December 8, 2022 order also prohibited Equitrans, L.P. from injecting natural gas into the storage wells at the Rager Mountain facility. The Company and Equitrans, L.P. disputed aspects of the applicable orders, and on January 5, 2023, the Company and Equitrans, L.P., as applicable, appealed each of the orders to the Commonwealth of Pennsylvania Environmental Hearing Board. Additionally, the Company and Equitrans, L.P., as applicable, have received, and may continue to receive, notices of violation (NOVs) related to the incident which allege violations of various Pennsylvania statutes and regulations. The Company has been engaged in discussions with the PADEP to address the outstanding NOVs. Equitrans, L.P. and the PADEP entered into a Stipulation of Settlement on April 12, 2023 that, among other things, resulted in the PADEP rescinding its December 8, 2022 order and Equitrans, L.P. withdrawing its appeal of such order. Equitrans, L.P.’s and the Company's appeals of the December 7, 2022 orders remain pending and negotiations regarding a potential consent order with respect to certain NOVs remain ongoing. On October 5, 2023, Equitrans, L.P. received an NOV from the PADEP’s Bureau of Air Quality for the release of uncontrolled hydrocarbons to the atmosphere during the Rager Mountain natural gas storage field incident, and expects to finalize a consent order and civil penalty related the NOV in the first quarter of 2024.

On December 29, 2022, the PHMSA issued the Company a Notice of Proposed Safety Order that included proposed remedial requirements related to the Rager Mountain natural gas storage field incident, including, but not limited to, completing a root cause analysis. The Company addressed certain proposals in advance of an order from the agency. These efforts included conducting testing, evaluating other wells at the Rager field and hiring a third-party specialist firm to undertake a root cause analysis, and subsequently on May 26, 2023, the PHMSA issued a consent order to the Company incorporating the terms of a consent agreement between the parties, which, among other things, required the completion of a root cause analysis and a remedial work plan, and specified that the Company may not resume injection operations at the Rager Mountain facility until authorized by the PHMSA. As discussed in “Transmission Results of Operation” in Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of this Annual Report on Form 10-K, in August 2023, the Company submitted a root cause analysis to the PHMSA in accordance with the consent order and later submitted a remedial work plan and, following completion of all actions in its remedial work plan, an injection plan to the PHMSA seeking authority to resume injections at Rager Mountain using all wells except three, which remain disconnected. On October 2, 2023, the PHMSA approved the Company’s injection plan. The Company began injections at Rager Mountain on October 5, 2023, subject to certain pressure restrictions and other requirements specified in the consent agreement between the PHMSA and the Company. On November 16, 2023, the PHMSA issued a letter to the Company approving the Company’s request to remove all pressure restrictions at the Rager Mountain facility. The Company plans to continue working with the PHMSA, pursuant to the consent order, regarding the remaining three wells.

If additional penalties are pursued and ultimately imposed related to the Rager Mountain natural gas storage field incident, the penalties, individually and/or in the aggregate, are expected to result in monetary sanctions in excess of $300,000. While the Company does not believe that penalties, if imposed, will have a material adverse impact on the Company's financial condition, results of operations or liquidity, there can be no assurance as of the filing of this Annual Report on Form 10-K regarding the scope of potential (or ultimately actual) financial or other impacts to the Company as a result of the Rager Mountain natural gas storage field incident.

There remain certain legal and regulatory matters relevant to the MVP project, the outcome of which could have adverse effects with respect to the project and consequently the Company, including matters pending with the U.S. Court of Appeals for the District of Columbia (D.C. Circuit) described below:

•Challenges to FERC Certificate, D.C. 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 D.C. Circuit issued an order rejecting multiple consolidated petitions seeking direct review of the FERC order under the Natural Gas Act of 1938, as amended (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 D.C. 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 D.C. Circuit entered an order holding this appeal in abeyance pending rulings on the appeals from the ACP and MVP FERC proceedings. The ACP petitioners on November 16, 2022, filed a joint motion for voluntary dismissal of all petitions for review pertaining to ACP, except for the Bold Alliance proceeding. The court granted the motion on November 17, 2022. On January 5, 2023, the D.C. Circuit entered an order holding the Bold Alliance proceeding in abeyance pending further order of the court and requiring the parties to file motions to govern future proceedings within 60 days of the U.S. Supreme Court disposition of the petition for writ of certiorari in Bohon et al. v. FERC et al., discussed below. On June 26, 2023, the court entered an order continuing the abeyance of Bold Alliance until 30 days after the disposition of Case No. 20-5203, discussed below.

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 the 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 D.C. Circuit in Case No. 20-5203. On November 30, 2020, appellants asked the D.C. Circuit to overturn the decision of the lower court. The D.C. 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. On June 21, 2022, the D.C. Circuit upheld the lower court’s decision to dismiss the lawsuit. On September 15, 2022, the petitioners filed a petition for writ of certiorari with the U.S. Supreme Court. The FERC and the MVP Joint Venture filed responses to the petition in November 2022. On April 24, 2023, the U.S. Supreme Court granted the petition for certiorari, vacated the judgment, and remanded the case to the D.C. Circuit for further consideration in light of the U.S. Supreme Court's April 14, 2023 opinion in Axon Enterprises, Inc. v. FTC. The D.C. Circuit subsequently issued an order authorizing, among other things, the parties to address in their supplemental briefing the implications of Section 324 of the Fiscal Responsibility Act of 2023 in addition to Axon. On October 24, 2023, the D.C. Circuit denied a stay motion filed by the petitioners. The parties filed their respective supplemental briefs on November 13, 2023. On November 26, 2023, the petitioners filed in the U.S. Supreme Court an “emergency” motion for an injunction requesting a judicial injunction on, or access to, the petitioners’ three properties pending resolution of their underlying claims in the Bohon matter. On December 5, 2023, Chief Justice John Roberts denied the application, without calling for a response from the MVP Joint Venture or the federal government. On February 13, 2024, the D.C. Circuit affirmed and reinstated its June 21, 2022 judgment upholding the lower court's decision to dismiss the lawsuit. If appealed to the U.S. Supreme Court and the appeal were successful on its merits, or if the Bold Alliance appeal 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 ensure, and cause a delay or further delay in the full in-service date for the MVP project (and consequent impacts related to such delay), or otherwise have adverse effects.

Mr. Karam has served as Executive Chairman of Equitrans Midstream since January 1, 2024, and previously served as Chief Executive Officer of Equitrans Midstream from September 2018 through December 31, 2023, a Director on the Board since November 2018 and Chairman of the Board since July 2019. Mr. Karam also served as President of Equitrans Midstream from September 2018 to July 2019. 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 Equitrans Midstream's acquisition of 100% of the limited partner interests in EQGP in January 2019 (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 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 has served as President and Chief Executive Officer of Equitrans Midstream since January 1, 2024 and previously served as President and Chief Operating Officer of Equitrans Midstream from July 2019 through December 31, 2023. The Board appointed Ms. Charletta as a Director in April 2022. She previously served as Executive Vice President and Chief Operating Officer of Equitrans Midstream since 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. Ms. Charletta also has served as a director of the Southern Gas Association, a natural gas trade association, since November 2022.

Mr. Oliver has served as Executive Vice President and Chief Financial Officer of Equitrans Midstream since January 1, 2024, having previously served as Senior Vice President and Chief Financial Officer of Equitrans Midstream from September 2018 through December 31, 2023. 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. Macken has served as Executive Vice President, Pipeline Operations and Project Execution of Equitrans Midstream since January 1, 2024, having previously served as Equitrans Midstream's Senior Vice President of Gas Systems Planning and Engineering from September 2018 through December 31, 2023. Mr. Macken joined EQT in 2008 as manager of gas systems planning and engineering and was promoted to director of gas systems planning in 2010 and vice president of gas systems planning in 2014, a position he held until the Separation.

Mr. Moore has served as Executive Vice President and Chief Legal Officer of Equitrans Midstream since January 1, 2024, having previously served as Senior Vice President and General Counsel of Equitrans Midstream from April 2019 through December 31, 2023.

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. Tetlow has served as Senior Vice President, Commercial Services of Equitrans Midstream since January 1, 2024, having previously served as Vice President, Corporate Development and Investor Relations from November 2018 through December 31, 2023. Mr. Tetlow joined EQT in 2008 as a business specialist in the treasury department and held various management positions with increased responsibility. Mr. Tetlow was promoted to manager of corporate treasury in 2011 and became investor relations manager in 2012 and investor relations director in 2015, a position he held until 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.

Equitrans Midstream common stock trades on the NYSE under the symbol "ETRN".

As of January 31, 2024, there were 1,626 shareholders of record of Equitrans Midstream common stock.

On January 23, 2024, the Board declared cash dividends for the fourth quarter of 2023 of $0.15 per common share and $0.4873 per Equitrans Midstream Preferred Share, which dividends were paid on February 14, 2024 to shareholders of record at the close of business on February 6, 2024.

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 Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K, 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.

See Part III, “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” of this Annual Report on Form 10-K for information relating to the Company’s equity compensation plans.

The Company did not have any sales of unregistered securities registered under Section 12 of the Exchange Act during the three months ended December 31, 2023.

The following table sets forth the Company's repurchases of equity securities registered under Section 12 of the Exchange Act that occurred during the three months ended December 31, 2023.

(a) Reflects shares withheld by the Company to pay taxes upon vesting of restricted stock.

The graph below compares the cumulative five-year 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 and each index beginning on December 31, 2018, and relative performance is tracked through December 31, 2023.

Net income (loss) attributable to Equitrans Midstream common shareholders was $386.7 million, $0.89 per diluted share, in 2023 compared to $(327.9) million, ($0.76) per diluted share, in 2022. The increase resulted primarily from an impairment of the Company's equity method investment in the MVP Joint Venture incurred during the year ended December 31, 2022, higher equity income, higher operating revenues, a loss on extinguishment of debt incurred during the year ended December 31, 2022 and higher income tax benefit, partially offset by higher operating expenses and higher net interest expense. See Note 2 to the consolidated financial statements for a discussion of the impairment of the Company's equity method investment in the MVP Joint Venture.

As part of implementing the Company's succession plan, on January 1, 2024, Mr. Thomas F. Karam stepped down as Chief Executive Officer of the Company and Diana M. Charletta, the former President and Chief Operating Officer, became President and Chief Executive Officer.

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 embraces working to conduct 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 it will continue to prudently allocate capital resources to ESG and sustainability initiatives in the future, which may include at increasing levels, which the Company believes will benefit the sustainability of the Company's business and help to 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 and negative sentiment with respect to natural gas, including natural gas infrastructure, from certain actors. Further, the Company believes that continued natural gas production and infrastructure growth are directly supportive of the United States' energy security, as evidenced by the historic inclusion of provisions mandating the completion of the MVP project in the Fiscal Responsibility Act of 2023. The Company also acknowledges the reality and risks of climate change as a critical current issue and, as an energy infrastructure company, recognizes the ongoing developments and risks surrounding climate change. As a result, the Company is focused on long-term sustainable performance, such as continuing to proactively pursue climate change mitigation aspirations while also balancing the need to deliver reliable, safe, and affordable natural gas energy in the United States now and in the future.

The Company is focused on executing on sustainability initiatives while further integrating sustainability-focused risks and opportunities into the Company’s strategic and capital spending decision processes. In 2023, the Company focused primarily on developing the appropriate strategy and building the requisite programs and plans for achieving its GHG reduction goals. In January 2023, the Company announced its status as a founding member of the newly formed Appalachian Methane Initiative (AMI), a coalition of regional natural gas operators committed to further enhancing methane monitoring throughout the Appalachia Basin and facilitating additional methane emissions reduction in the region. Additionally, the Company’s GHG Committee developed a portfolio of 2024 capital projects that includes avoiding or eliminating methane emissions from both certain fixed and event-based sources. Further, the Company finalized its GHG Management program, providing the roadmap and accounting protocols for pursuing achievement of and reporting on progress towards its aspirational emissions targets. Additionally, aspects of the Company's compensation structure reflect sustainability-oriented goals and developments. For example, the Human Capital and Compensation Committee of the Board determined to include the completion of certain scenario analyses under the Task Force on Climate-Related Financial Disclosures framework, and the development of a related publishable report, as a metric in the Company’s 2023 short-term incentive compensation program applicable to all employees, including executives.

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. Costs and expenses associated with sustainability and ESG matters 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 the financing of non-fossil fuel businesses and prompting the pursuit of emissions reductions, lower-carbon technologies, and alternative forms of energy), as well as 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” and “Regulatory Environment” in Part I, “Item 1. Business” of this Annual Report on Form 10-K, the Company recognizes the evolving landscape of international accords and federal, state and local laws and regulations regarding GHG emissions or climate change initiatives. The Company also recognizes, as discussed in "Increasing scrutiny and changing stakeholder expectations and disclosures in respect of ESG and sustainability practices may adversely impact our business and our stock price and impose additional costs or expose us to new or additional risks." in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K, the changing expectations from a variety of stakeholders relating to ESG and sustainability practices. 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 prudently invest capital in furtherance of its goal of long-term sustainable operations and recognizes that responsive adaptation efforts are likely to be costly and time consuming.

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 certain unallocated corporate expenses and transaction costs, as applicable. Net interest expense, loss on extinguishment of debt, components of other income (expense), net, and income tax expense (benefit) are managed on a consolidated basis. The Company has presented each segment's operating income (loss), other income (expense), net, equity income, impairment of equity method investment and various operational measures, as applicable, in the following sections. Management believes that the presentation of this information is useful to management and investors regarding the financial condition, results of operations and trends and uncertainties of its segments. The Company has reconciled each segment's operating income (loss) to the Company's consolidated operating income (loss) and net income (loss) in Note 3 to the consolidated financial statements.

(a)For the years ended December 31, 2023, 2022 and 2021, firm reservation fee revenues included approximately $4.1 million, $20.2 million and $11.3 million, respectively, of MVC unbilled revenues.

(b)For the year ended December 31, 2023, volumetric-based fee revenues included a one-time contract buyout by a customer for approximately $5.0 million. For the years ended December 31, 2023, 2022, and 2021, volumetric-based fee revenues included approximately $4.6 million, $4.2 million and $3.5 million, respectively, of MVC unbilled revenues.

(c)Other income (expense), net, includes the unrealized gain (loss) on derivative instruments associated with the Henry Hub cash bonus payment provision and gain on sale of gathering assets in 2022. See Note 10 to the consolidated financial statements for further information on the Henry Hub cash bonus payment provision.

(d)Includes volumes up to the contractual MVC under agreements structured with MVCs. Volumes in excess of the contractual MVC are reported under volumetric-based services.

(e)Includes approximately $14.3 million, $20.3 million and $14.1 million of capital expenditures related to noncontrolling interest in Eureka Midstream for the years ended December 31, 2023, 2022 and 2021, respectively.

Gathering operating revenues decreased by $20.4 million for the year ended December 31, 2023 compared to the year ended December 31, 2022. Firm reservation fee revenues increased by $10.0 million primarily due to $15.8 million of higher firm reservation fees associated with the EQT Global GGA due to assumption changes impacting the estimated total consideration in the prior year and increased contracted capacity, partially offset by lower average rates on a certain customer MVC. Volumetric-based fee revenues decreased by $30.4 million primarily due to lower gathered volumes resulting from reduced producer activity and lower effective rates, partially offset by a one-time contract buyout by a customer of approximately $5.0 million and $4.7 million associated with firm and interruptible gathered volumes on Hammerhead. The Company expects interruptible volumes from the Company's Hammerhead gathering agreement with EQT to continue up to the full commercial in-service date of the Hammerhead pipeline when firm commitments will commence.

Gathering operating expenses increased by $28.3 million for the year ended December 31, 2023 compared to the year ended December 31, 2022. Selling, general and administrative expenses increased by $31.1 million primarily due to higher incentive compensation of $29.2 million, including $12.3 million associated with the MVP PSU Program that included the impact of a cumulative catch-up since the inception of the award. Operating and maintenance expenses decreased by $4.3 million primarily due to lower operating expenses associated with the divestiture of the regulated low pressure gathering assets in June 2023 and lower repairs and maintenance expenses, partially offset by higher personnel costs and higher property taxes. Depreciation expense increased by $1.5 million as a result of additional assets placed in-service.

See "Overview of the Company and Operations" in Part 1, "Item 1. Business" of this Annual Report on Form 10-K for discussions of the EQT Global GGA, and the transactions related thereto, including periodic gathering MVC fee declines and, additionally, discussion that in connection with MVP full in-service the EQT Global GGA provides for more significant potential gathering MVC fees declines in certain contract years. Firm reservation fee revenues under the Company’s Hammerhead gathering agreement with EQT are expected to contribute to an increase in the Company’s firm reservation fee revenues following achievement of the Hammerhead pipeline full commercial in-service in conjunction with full MVP in-service. However, the percentage of the Company's operating revenues that are generated by firm reservation fees may vary year to year depending on various factors, including customer volumes and the rates realizable under the Company’s contracts, including the EQT Global GGA. See also "Commodity Price Risk" in Part II, "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" of this Annual Report on Form 10-K for additional information on factors that could affect the Company's operating revenues. Also, see Note 8 for further discussion on the MVP PSU Program.

(a)For the year ended December 31, 2023, volumetric-based fee revenues included a one-time contract buyout by a customer for approximately $23.8 million.

(b)Firm capacity includes volumes associated with firm capacity contracts including volumes in excess of firm capacity.

(c)Transmission capital expenditures do not include aggregate capital contributions made to the MVP Joint Venture for the MVP and MVP Southgate projects of approximately $689.4 million, $199.6 million and $287.7 million for the years ended December 31, 2023, 2022 and 2021, respectively.

Transmission operating revenues increased by $38.6 million for the year ended December 31, 2023 compared to the year ended December 31, 2022. Firm reservation fee revenues decreased by $9.4 million primarily due to lower contracted capacity payments resulting from the one-time contract buyout that occurred during the first quarter of 2023. Volumetric-based fee revenues increased by $48.0 million primarily as a result of a one-time contract buyout by a customer of approximately $23.8 million and higher volumes in excess of firm capacity contracts.

Operating expenses increased by $41.9 million for the year ended December 31, 2023 compared to the year ended December 31, 2022. Operating and maintenance expense increased $21.8 million primarily due to operational efficiencies associated with operating activities with the Gathering segment for replenishment gas on the regulated low pressure gathering assets which were divested in June 2023, increased personnel costs and expenses associated with the Rager Mountain natural gas storage field incident. Selling, general and administrative expenses increased by $19.7 million resulting primarily from higher incentive compensation of $12 million, including $4.7 million associated with the MVP PSU Program that included the impact of a cumulative catch-up since the inception of the award, an increased reserve for bad debt expense and higher professional fees.

Regarding the Rager Mountain natural gas storage field incident, the root cause analysis, which was conducted by an independent, third-party company with expertise in reservoir management and well and corrosion engineering, was submitted to the PHMSA in August 2023, which root cause analysis indicated that the direct cause of the venting from the relevant Rager Mountain facility storage well (well #2244) was due to corrosion caused by the infiltration of water, oxygen and debris into the well's annulus, and such corrosion resulted in a failure of the well casing. Based on results of an inventory verification test conducted after the venting incident was resolved, the Company’s initial gas loss estimate for well #2244 was approximately 1.29 Bcf. Following completion of the root cause analysis, the cumulative gas loss was determined to be approximately 1.164 Bcf, approximately 1.037 Bcf of which was vented to the atmosphere and roughly 0.127 Bcf was diverted to and contained within formation(s) located at approximately 1,800’ and/or 3,000’ below ground. Post-incident workstreams related to the safe and environmentally responsible operation of the Rager Mountain facility and other storage fields are ongoing.

The Company worked with various third-party experts to identify and address the causes and/or contributors to the November 2022 incident. The damaged casing on well #2244 has been replaced, and the well remains temporarily plugged. The Company intends to seek any necessary approval from PHMSA to perform certain capital activities to remediate well 2244 and ultimately return it to in-service. Additionally, several other Rager wells have undergone top joint casing replacements to address proactively less-aggressive corrosion that was identified. The Company also has performed supplemental evaluations and testing, including updated wireline logging, on all other wells at the Rager Mountain facility. In October 2023, following authorization from PHMSA of the Company's injection plan for the Rager Mountain facility, the Company returned the Rager Mountain facility, other than well #2244 and two additional wells, to injection operations, subject to certain operating pressure restrictions and other requirements specified in the consent agreement between the PHMSA and the Company. On November 16, 2023, the PHMSA issued a letter to the Company approving the Company's request to remove all pressure restrictions at the Rager Mountain facility. For additional information, see Part I, "Item 3. Legal Proceedings", Part I, "Item 1. Business" and "We have incurred and expect to continue to incur costs and expenses as a result of or arising in relation to the Rager Mountain natural gas storage field incident in November 2022, which has included and may include potential additional regulatory penalties or other sanctions, which could, depending on their scope and timing, materially adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders." in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K.

Equity income increased by $175.0 million for the year ended December 31, 2023 compared to the year ended December 31, 2022 due to the increase in the MVP Joint Venture's AFUDC on the MVP project resulting from the resumption of growth construction activities in 2023. Following MVP full in-service, the Company's equity income will be primarily derived from 20-year firm reservation contracts for the MVP project.

Impairments of equity method investment includes the separate impairments of the Company's equity method investment in the MVP Joint Venture. See Note 2 to the consolidated financial statements for further information.

(a)    Includes volumes up to the contractual MVC under agreements structured with MVCs or ARCs, as applicable. Volumes in excess of the contractual MVC are reported under Volumetric-based services.

Water operating revenues increased by $18.0 million for the year ended December 31, 2023 compared to the year ended December 31, 2022. Firm reservation fee revenues increased by $5.3 million primarily as a result of increased revenues due to a full year of ARCs associated with the 2021 Water Services Agreement. Volumetric-based fee revenues increased by $12.7 million primarily due to higher volumes.

Water operating expenses increased by $19.3 million for the year ended December 31, 2023 compared to the year ended December 31, 2022. Selling, general and administrative expense increased by $7.4 million primarily due to a contract asset write-down. Operating and maintenance expense increased by $5.9 million due to higher mixed-use water storage expenses related to storage facilities placed in-service during the year ended December 31, 2023. Depreciation expense increased $6.0 million due to additional assets placed in-service.

The Company’s volumetric-based water services are directly associated with producers’ well completion activities and fresh and produced water needs (which are primarily driven by horizontal lateral lengths and the number of completion stages per well). Therefore, the Water volumetric operating results traditionally fluctuate from year-to-year in response to producers’ well completion activities.

Other income (expense), net, decreased $10.6 million for the year ended December 31, 2023 compared to the year ended December 31, 2022. The decrease was primarily due to a $1.5 million unrealized gain on derivative instruments during the year ended December 31, 2023 as compared to a $9.6 million unrealized gain on derivative instruments during the year ended December 31, 2022, and a $3.7 million gain on the sale of non-core gathering assets during the year ended December 31, 2022, partially offset by higher sublease income. The decrease in unrealized gains on derivative instruments was primarily due to changes in timing and probability-weighted assumptions regarding MVP project completion and changes in NYMEX Henry Hub natural gas futures prices associated with the Henry Hub cash bonus payment provision.

See also "Our exposure to commodity price risk may increase in the future and NYMEX Henry Hub futures prices affect the fair value, and may affect the realizability, of potential cash payments to us by EQT pursuant to the EQT Global GGA." included in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K for a discussion of factors affecting the estimated fair value of the derivative asset attributable to the Henry Hub cash bonus payment provision.

During the year ended December 31, 2022, the Company incurred a loss on extinguishment of debt of approximately $24.9 million related to the 2022 Tender Offers (as defined in Note 9) for Senior Notes and open market repurchase premiums and fees, and write off of the respective unamortized discounts and financing costs associated with the purchase of portions of 2023, 2024 and 2025 Notes in such Tender Offers.

Net interest expense increased by $32.6 million for the year ended December 31, 2023 compared to the year ended December 31, 2022 primarily due to increased interest rates and borrowings under the revolving credit facilities and interest on the 2022 Senior Notes (as defined in Note 9), partially offset by the impact of the 2022 Tender Offers and the redemption of the 2023 Notes effected in June 2023.

See also Note 9 and Note 15 to the consolidated financial statements for a discussion of certain of the Company's outstanding debt.

See Note 12 to the consolidated financial statements for an explanation of the changes in income tax expense and effective tax rate for the year ended December 31, 2023 compared to the year ended December 31, 2022.

Net income attributable to noncontrolling interest decreased $2.7 million for the year ended December 31, 2023 compared to the year ended December 31, 2022 primarily as a result of lower net income on Eureka Midstream.

See "Investing Activities" and "Capital Requirements" under "Capital Resources and Liquidity" for a discussion of capital expenditures and capital contributions.

The Company's strategically located and integrated 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 one of the largest natural gas producers in the U.S. based on average daily sales volumes as of December 31, 2023 and EQT's public senior debt had investment grade credit ratings from Standard & Poor's Global Ratings (S&P), Fitch Ratings (Fitch) and Moody's Investors Service (Moody's) as of that date. For the year ended December 31, 2023, approximately 70% of the Company's operating revenues were generated from firm reservation fee revenues. Generally, the Company is focused on utilizing contract structures reflecting long-term firm capacity, MVC or ARC commitments which are intended to provide support to its cash flow profile. The percentage of the Company's operating revenues that are generated by firm reservation fees (as well as the Company's revenues generally) may vary year to year depending on various factors, including customer volumes and the rates realizable under the Company’s contracts, including the EQT Global GGA which provides for periodic gathering MVC fee declines through January 1, 2028 (with the fee then remaining fixed throughout the remaining term). Additionally, as discussed in "Overview of the Company and Operations" in Part 1, "Item 1. Business", in connection with MVP full in-service the EQT Global GGA provides for more significant potential gathering MVC fee declines in certain contract years.

The Company's standalone strategy reflects its continued pursuit of organic growth projects, including completing and placing in service the MVP, focusing on identifying opportunities to use its existing assets to deepen and grow its customer relationships at optimized levels of capital spending and taking into account the Company’s leverage, and continuing to prudently invest resources in its sustainability-oriented initiatives. The Company’s strategy also reflects its continued focus on achieving a strong balance sheet, and given the Company’s size, operating footprint and other factors considering inorganic opportunities, such as to extend the Company’s operations’ into the southeast United States and new, key demand markets, such as the Gulf of Mexico LNG export market.

As part of its approach to organic growth, the Company is focused on its projects and assets outlined in "Developments, Market Trends and Competitive Conditions" in Part I, "Item 1. Business" of this Annual Report on Form 10-K, many of which are supported by contracts with firm capacity, MVC or ARC commitments.

For discussion of the Company's commercial relationship with EQT and related considerations, including risk factors, see Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K.

For a discussion of capital expenditures, see "Capital Requirements" under "Capital Resources and Liquidity" below.

The Company's liquidity requirements are to finance its operations, its capital expenditures, potential acquisitions and other strategic transactions and capital contributions to joint ventures, including the MVP Joint Venture, to pay cash dividends and distributions, when declared and to satisfy any indebtedness obligations. Additionally, the Company or its affiliates may, at any time and from time to time, seek to retire or purchase outstanding debt through cash purchases and/or exchanges for equity or debt, in open-market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will be upon such terms and at such prices as the Company may determine, and will depend on prevailing market conditions, the Company's other liquidity requirements, contractual restrictions and other factors and the amounts involved may be material. The Company's ability to meet these liquidity requirements depends on the Company's cash flow from operations, the continued ability of the Company to borrow under its subsidiaries' credit facilities and the Company's ability to raise capital in banking and capital markets. We believe that our cash on hand, future cash generated from operations and future cash received from potential distributions from the MVP Joint Venture, together with available borrowing capacity under our subsidiaries' credit facilities and our access to banking and capital markets, will provide adequate resources to fund our short-term and long-term capital, operating and financing needs. However, cash flow, available borrowing capacity and capital raising activities may be affected by prevailing economic conditions in the natural gas industry and other financial and business factors, including factors discussed in Part I, "Item 1A. Risk Factors" of this Annual Report Form 10-K (for example, see “If we, our subsidiaries or our joint ventures 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."), some of which are beyond the Company's control.

The Company's available sources of liquidity include cash from operations, cash on hand, borrowings under its subsidiaries' revolving credit facilities, issuances of additional debt and issuances of additional equity securities. The amount the Company is able to borrow under the Amended EQM Credit Facility is bounded by a maximum consolidated leverage ratio that could not exceed 5.85 to 1.00 for the quarter ended December 31, 2023, 6.00 to 1.00 for the quarter ending March 31, 2024, 6.25 to 1.00 for the quarter ending June 30, 2024, 5.85 to 1.00 for the quarter ending September 30, 2024, and 5.50 to 1.00 for quarters thereafter, with the then-applicable ratio being tested as of the end of each fiscal quarter. As of December 31, 2023, EQM had the ability to borrow approximately $0.4 billion under the Amended EQM Credit Facility. See Note 9 and Note 15 to the consolidated financial statements for further information regarding the Amended EQM Credit Facility. See also "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." included in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K.

See “Security Ratings” below for a discussion of EQM’s credit ratings during 2023. Based on EQM's credit rating levels, EQM has delivered credit support to the MVP Joint Venture in the form of a letter of credit, which is for MVP project, and was in the amount of approximately $104.7 million as of December 31, 2023. The letter of credit with respect to the MVP project is expected to be further reduced as the Company contributes capital to fund MVP Holdco's remaining proportionate share of the construction budget, subject to a minimum-required level to be maintained through in-service of the MVP project. See "A further downgrade of EQM’s credit ratings could impact our liquidity, access to capital, and costs of doing business." included in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K. See Note 7 to the consolidated financial statements for further information on EQM's letters of credit.

The following table is a summary of the cash flows by activity for the years ended December 31, 2023, 2022 and 2021, respectively.

Net cash flows provided by operating activities increased approximately $170.3 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022. The increase was primarily driven by the payment of the EQT Cash

Option during the year ended December 31, 2022 and the timing of other working capital receipts and payments, partially offset by higher interest payments.

Net cash flows used in investing activities increased by $503.0 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022. The increase was primarily due to an increase in capital contributions to the MVP Joint Venture. See “Capital Requirements” below for a discussion of forecasted 2024 capital expenditures and capital contributions to the MVP Joint Venture.

Net cash flows provided by financing activities were $245.0 million for the year ended December 31, 2023 as compared to net cash flows used in financing activities of $345.5 million for the year ended December 31, 2022. For the year ended December 31, 2023, the primary source of financing cash flows were proceeds from borrowings under the revolving credit facilities, while the primary uses of financing cash flows were repayments on borrowings under the revolving credit facilities, the payments of dividends to shareholders, the redemption of the 2023 Notes and distributions paid to noncontrolling interest. For the year ended December 31, 2022, the primary uses of financing cash flows were the purchase of certain tranches of EQM's outstanding long-term indebtedness pursuant to the 2022 Tender Offers and an open market purchase, repayments on borrowings under the revolving credit facilities, and the payments of dividends to shareholders, while the primary source of financing cash flows were the issuance of the 2022 Senior Notes and borrowings under the revolving credit facilities.

The gathering, transmission and storage and water services businesses are capital intensive, requiring significant investment to develop new facilities and to maintain and upgrade existing operations. 

The following represents the Company's material short-term and long-term cash requirements from contractual and other obligations as of December 31, 2023.

(a)Includes approximately $6.4 billion in aggregate principal amount of EQM's senior notes as of December 31, 2023. See Note 9 to the consolidated financial statements for further information.

(b)Credit facility borrowings are classified based on the termination date of the credit facility agreements. As of December 31, 2023, the Company had aggregate credit facility borrowings outstanding of $915 million and $315 million under the Amended EQM Credit Facility and the 2021 Eureka Credit Facility, respectively. See Note 9 and Note 15 to the consolidated financial statements for further information.

(c)Interest payments exclude interest related to the Amended EQM Credit Facility and the 2021 Eureka Credit Facility as the interest rates on the credit facility borrowings are variable.

(d)Excludes purchase obligations of the MVP Joint Venture. Purchase obligations represent agreements to purchase goods or services that are enforceable, legally binding and specify all significant terms, including the approximate timing of the transaction. As of December 31, 2023, the Company's purchase obligations included commitments for capital expenditures, operating expenses and service contracts.

(e)Lease obligations are primarily entered into for various office locations, compression equipment and a water storage facility.

(f)Other liabilities represent accruals for short-term employee compensation and estimated payouts for the Company's various liability award plans as of December 31, 2023. See "Critical Accounting Estimates" below and Note 8 to the consolidated financial statements for discussion of factors that affect the ultimate amount of the payout of the Company's liability award plans.

Contractual and other obligations exclude dividends associated with the Equitrans Midstream Preferred Shares.

Capital expenditures in 2024 are expected to be approximately $325 million to $395 million (including approximately $15 million attributable to the noncontrolling interest in Eureka Midstream). If the MVP project were to be completed in the second quarter of 2024 and at a total project cost ranging from approximately $7.57 billion to approximately $7.63 billion (excluding AFUDC), the Company expects it would make total capital contributions to the MVP Joint Venture in 2024 of approximately $540 million to $575 million primarily related to forward construction of the MVP project. Capital contributions payable to the MVP Joint Venture are accrued upon the issuance of a capital call by the MVP Joint Venture. The Company's short-term and long-term capital investments may vary significantly from period to period based on the available investment opportunities, the timing of the construction of the MVP and other projects, and maintenance needs. The Company expects to fund short-term and long-term capital expenditures and capital contributions primarily through cash on hand, cash generated from operations, available borrowings under its subsidiaries' credit facilities and its access to banking and capital markets.

See Note 9 and Note 15 to the consolidated financial statements for discussion of the Amended EQM Credit Facility and the 2021 Eureka Credit Facility.

The table below sets forth the credit ratings for EQM's debt instruments at December 31, 2023.

On August 29, 2023, Fitch affirmed EQM's credit rating on Rating Watch Positive. EQM's credit ratings are subject to revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating. The Company 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. If any credit rating agency downgrades or withdraws EQM's ratings, including for reasons relating to the MVP project (such as delays affecting the MVP project or increases in such project’s targeted costs), EQM’s leverage or credit ratings of the Company's customers, the Company's access to the capital markets could become more challenging, borrowing costs will likely increase, the Company may, depending on contractual provisions in effect at such time, be required to provide additional credit assurances (the amount of which may be substantial) and the potential pool of investors and funding sources may decrease. In order to be considered investment grade, a company must be rated Baa3 or higher by Moody's, BBB- or higher by S&P, or BBB- or higher by Fitch. All of EQM's credit ratings are considered non-investment grade.

From time to time, 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 the availability, if any, of insurance, the Company believes, although no assurance can be given, that the ultimate outcome of any matter currently pending against it or any of its consolidated subsidiaries as of the filing of this Annual Report on Form 10-K will not materially adversely affect its business, financial condition, results of operations, liquidity or ability to pay dividends to its shareholders.

See Part I, "Item 3. Legal Proceedings" of this Annual Report on Form 10-K for discussion of litigation and regulatory proceedings, including related to the Rager Mountain natural gas storage field incident, and, further relating to that incident, "We have incurred and expect to continue to incur costs and expenses as a result of or arising in relation to the Rager Mountain natural gas storage field incident in November 2022, which has included and may include potential additional regulatory penalties or other sanctions, which could, depending on their scope and timing, materially adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders." under Part I, "Item 1A. Risk Factors," of this Annual Report on Form 10-K.

See Note 14 to the consolidated financial statements for further discussion of the Company's commitments and contingencies.

On February 14, 2024, the Company paid cash dividends for the fourth quarter of 2023 of $0.15 per common share and $0.4873 per Equitrans Midstream Preferred Share to shareholders of record at the close of business on February 6, 2024.

For each quarter ending after March 31, 2024, the holders of the Equitrans Midstream Preferred Shares will receive quarterly dividends at a rate per annum equal to the sum of (i) three-month CME Term SOFR, administered by CME Group Benchmark Administration, Ltd., plus a tenor spread adjustment of 0.26161% per annum as of the relevant determination date in respect of the applicable quarter and (ii) 8.15%; provided that such rate per annum in respect of periods after March 31, 2024 will not be less than 10.50%. As such, the Company expects dividends paid to holders of the Equitrans Midstream Preferred Shares to be higher beginning in the third quarter of 2024.

Recently issued accounting standards relevant to the Company are described in Note 1 to the consolidated financial statements.