Unless the context otherwise requires, a reference to a "Note" herein refers to the accompanying Notes to Consolidated Financial Statementsthe consolidated financial statements contained in Part II, "Item 8. Financial Statements and Supplementary Data."

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," "could,"expect," "would,"focused," "forecast," "goal," "guidance," "intend," "may," "objective," "opportunity," "outlook," "plan," "position," "potential," "predict," "project," "pursue," "scheduled," "seek," "should," "strategy," "strive," "target," "view," "will," "may," "forecast," "approximate," "expect," "project," "intend," "plan," "believe," "target"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 "Strategy" under "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:including the following and/or statements with respect thereto, as applicable:

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 asand 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 resultmajority of the Separation (as defined below).

price2023, approximately 70% of $48.77 per EQM Series A Preferred Unit, resulting in total gross proceedsthe 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 approximately $1.2 billion. The net proceeds from the Private Placement were used in partCompany's operating revenues that are generated by firm reservation fees (as well as the Company's revenue generally) may vary year to fund the purchase price in the Bolt-on Acquisition (as defined in Note 3) and to pay certain fees and expenses related to the Bolt-on Acquisition,year depending on various factors, including customer volumes and the remainder was usedrates realizable under the Company's contracts, including the EQT Global GGA (defined below) which provides for general partnership purposes. The Private Placement closed concurrently withperiodic gathering MVC fee declines through January 1, 2028 (with the closing offees then remaining fixed throughout the Bolt-on Acquisition on April 10, 2019. See Note 2 to the consolidated financial statements for further information on the EQM Series A Preferred Units, none of which remain outstanding, and Note 3 to the consolidated financial statement for further information on the Bolt-on Acquisition.

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 “Series A Change of Control” (as definedlargest natural gas producers in the Fourth Amended and Restated AgreementUnited States based on average daily sales volumes as of Limited Partnership of EQM (as amended, the Former EQM Partnership Agreement)) that occurred upon the closingDecember 31, 2023. EQT accounted for approximately 61% of the EQM Merger (collectively,Company's revenues for the Restructuring and, the closing of the Restructuring, the Restructuring Closing). See Note 2 to the consolidated financial statements for further information on the Restructuring Agreement and the Restructuring.year ended December 31, 2023.

TheUnder 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 subject to potential reductions for certainconditioned upon the full in-service date of the MVP. The performance obligation, the allocation of the total consideration over the life of the contract years as set forthand 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, conditioned to beginthe 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, provideprior 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. Further,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. In addition, given that the MVP full in-service date did not occur by January 1, 2022, EQT has an option, exercisable through December 31, 2022, to forgo approximately $145 million of the gathering fee relief in such first twelve-month period and approximately $90 million of the gathering fee relief in such second twelve-month period in exchange for a cash payment from the Company to EQT in the amount of approximately $196 million (the EQT Cash Option). See Note 6 to the consolidated financial statements for further information on the EQT Global GGA.

The following diagram depicts the Company's organizational and ownership structure as of December 31, 2021:2023:

The following is a map of the Company's gathering, transmission and storage and water services operations as of December 31, 2021.2023. Also included are the MVP and MVP Southgate routes, which projects are discussed in "Strategy" under "Developments, Market Trends and Competitive Conditions" in Part I, "Item 1. Business."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. For discussion of the composition of the three segments, see Notes 1 and 5 to the consolidated financial statements.

The Company's three business segments correspond to the Company's three primary assets: the gathering system, transmission and storage system and water service system. The following table summarizes the composition of the Company's operating revenues by business segment.

The Company's largest customer, EQT, accounted for approximately 59%61%, 64%61% and 69%59% of the Company's total revenues for the years ended December 31, 2021, 20202023, 2022 and 2019,2021, respectively.

The Company provides gathering services in two manners: firm service and interruptible service. Firm service contracts are typically long-term and often include firm reservation fees, which are fixed, monthly charges for the guaranteed reservation of pipeline access. Revenues under firm reservation fees also include fixed volumetric charges under MVCs. As of December 31, 2021,2023, the gathering system had total contracted firm reservation capacity (including contracted MVCs) of approximately 7.07.7 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 8.18.8 Bcf per day (inclusive of Eureka Midstream contracted capacity) as of December 31, 2021,2023, which included contracted firm reservation capacity of approximately 1.81.9 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 1413 years as of December 31, 2021.2023.

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

access to markets in Pennsylvania, West Virginia and Ohio and to the Mid-Atlantic, Northeastern, Midwestern and Gulf Coast markets through interconnect points with major interstate pipelines.

The Company provides transmission and storage services in two manners: firm service and interruptible service. Firm service contracts are typically long-term and often include firm reservation fees, which are fixed, monthly charges for the guaranteed reservation of pipeline and storage capacity. Volumetric-based fees can also be charged under firm contracts for firm volume transported or stored, as well as for volumes transported or stored in excess of the firm contracted volume. As of December 31, 2021,2023, the Company had firm capacity subscribed under firm transmission contracts of approximately 5.65.8 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 2.3approximately 2.6 Bcf per day of firm capacity commitments associated with the MVP and MVP Southgate projects. As of December 31, 2021,2023, 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 1312 years as of December 31, 2021.2023.

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 powerfuel its compressor stations and meet other requirements of the Company's transmission and storage systems.

buried water pipeline and two water storage facilities with 350,000 barrels of capacity, andas well as two interconnects with the Company’s existing Pennsylvania fresh water systems and will provideprovides services to producers in southwestern Pennsylvania. As of December 31, 2021, the Company’sThe Company plans to continue to expand its mixed water system included approximately eight milesin 2024, including the completion of buried pipeline.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-locatedstrategically 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 producerproducers in the U.S. based on average daily sales volumes as of December 31, 2021. The Company maintains a stable cash flow profile, with approximately 64%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 its operating revenues forthat date. For the year ended December 31, 20212023, approximately 70% of the Company's operating revenues were generated from firm reservation fees. Further, as discussed above,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 is expected(as well as the Company's revenues generally) may vary year to increase in future years as a result ofyear depending on various factors, including customer volumes and the 15-year termrates realizable under the Company's contracts, including the EQT Global GGA which includes anprovides 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 3.0 Bcf per day that became effectivethe Company and Operations" in Part 1, "Item 1. Business" of this Annual Report on April 1, 2020 and gradually steps up to 4.0 Bcf per day through December 2031 following theForm 10-K, in connection with MVP full in-service date of the MVP. ThisEQT Global GGA provides for more significant potential gathering MVC fee declines in certain contract structure enhances the stability of the Company's cash flows and limits its exposure to customer volume variability.years.

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 ESG and sustainability matters which the Company believes will help to distinctively position the Company and create value.

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.

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

Interstate pipelines may not charge rates or impose terms and conditions of service that, upon review by the FERC, are found to be unjust or unreasonable, unduly discriminatory or preferential. Rate design and the allocation of costs also can affect a pipeline's profitability. While the ratemaking process establishes the maximum rate that can be charged, interstate pipelines such as the Company's transmission and storage system are permitted to discount their firm and interruptible rates without further FERC authorization down to a specified minimum level, provided they do not unduly discriminate. In addition, pipelines are allowed to negotiate different rates with their customers, under certain circumstances. Changes to rates or terms and conditions of service, and contracts can be proposed by a pipeline company under Section 4 of the NGA, or the existing interstate transmission and storage rates, or terms and conditions of service andand/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, 2021,2023, 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. While the FERC currently exercises jurisdiction over the rates and terms of service for the Company’s FERC-regulated gathering services, these gathering facilities may not be subject to the FERC’s certification and construction authority. Prior to commencing construction of new or existing interstate transmission and storage facilities, an interstate pipeline must obtain (except in certain circumstances, such as where the activity is permitted under the FERC’s regulations or is authorized under the operator’s existing blanket certificate issued by the FERC) a certificate authorizing the construction, or file to amend its existing certificate, from the FERC.

On April 19, 2018, the FERC issued a Notice of Inquiry (2018 Notice of Inquiry) seeking information regarding whether, and if so how, it should revise its approach under its currently effective policy statement on the certification of new natural gas transportation facilities (Certificate Policy Statement). The formal comment period in this proceeding closed on June 25, 2018. On February 18, 2021, the FERC issued another Notice of Inquiry in the same proceeding that modified and expanded the inquiry and renewed its request for public comment (together with the 2018 Notice of Inquiry, the Certificate Policy Statement NOI). The formal comment period closed May 26, 2021. On February 18, 2022, the FERC issued an Updated Certificate Policy Statement. The Company is evaluatingOn 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 but at this time, itand the interim GHG policy and has taken no further action to date.

In 2024, there is not possible to predict the impacta possibility that the Updated Certificate Policy will have on the Company, if any.

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 had four commissioners in 2023. However, Commissioner James Danly left the FERC at the FERC changed in 2021,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 reestablished its full complementcould be without a quorum of fivethree 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. In 2021, FERC issued Order Nos. 871-B and -C (amending FERC regulations to prohibit the issuance of authorizations to proceed with construction while certain requests for rehearing are pending), demonstrated that it will consider climate change impacts in individual certificate proceedings, and incorporated enhanced environmental justice review in pipeline certificate orders. On February 18, 2022, the FERC issued an interim GHG policy. The Company is evaluating the interim GHG policy, but at this time, it is not possible to predict the impact that the interim GHG policy, or any future changes to that policy, will have on the Company, if any.

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.

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 two separate Interim Final Rules in October 2016 anda final rule effective December 20162, 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. The December 2016 Interim Final Rule, relating to underground gas storage facilities, went into effect in January 2017. PHMSA determined, however, that it would not issue enforcement citations to any operators for violations of provisions of the December 2016 Interim Final Rule that had previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issued a final rule. The final rule related to underground gas storage facilities became effective as of March 13, 2020.integrity

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 $220,000$266,000 per day for each violation and approximately $2.2$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 the above described or similarits regulatory compliance initiatives that are not reflected in its forecasted maintenance capital expenditures. The Company believes that its operations are in substantial compliance with all existing federal, state and local pipeline safety laws and regulations. However,initiatives. Additionally, the adoption of new laws and regulations, such as those proposed by PHMSA,the Mega Rule discussed above, could result in significant

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.

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 TSA security directives,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.

In addition, the Company's operations and construction activities may be subject to county and local ordinances that restrict the time, place or manner in which those operations and activities may be conducted.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of investigatory and remedial obligations and the issuance of orders enjoining future operations or imposing additional compliance requirements. Also, certain environmental statutes impose strict, and in some cases joint and several, liability for the cleanup and restoration of sites where hydrocarbons or wastes have been disposed or otherwise released regardless of the fault of the current site owner or operator. Consequently, the Company may be subject to environmental liability at its currently owned or operated facilities for conditions caused by others prior to the Company's involvement.

The Company has implemented programs and policies designed to keep its pipelines and other facilities in compliance with existing environmental laws and regulations, and the Company does not believe that the cost of its compliance with such legal requirements will have a material adverse effect on its business, financial condition, results of operations, liquidity or ability to pay dividends to its shareholders. Nonetheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and it is generally expected that such trend will likely increase under the Biden Administration. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be significantly in excess of the amounts the Company currently anticipates.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 indicatedannounced that it will reconsider that decision.be commencing a review of these NAAQS. In addition, in November 2021,December 2023, the EPA issued a proposedfinal rule that would makemakes 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 proposedfinal rule would also extendextends 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 and to minimize the costs of such compliance. While the Company believes that it is in substantial compliance with existing environmental laws and regulations, there is no assurance that the current conditions will continue in the future.

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.

In the ordinary course of the Company's operations, the Company generates wastes constituting solid wastes, and in some instances hazardous wastes, which are subject to the requirements of the Resource Conservation and Recovery Act (RCRA) and comparable state statutes. While the RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. While certain petroleum production wastes are excluded from RCRA's hazardous waste regulations, it is possible that these wastes will in the future be designated as "hazardous wastes" and be subject to more rigorous and costly disposal requirements, which could have a material adverse effect on the Company's maintenance capital expenditures and operating expenses.

The Company owns, leases or operates properties where petroleum hydrocarbons are being or have been handled for many years. The Company has generally utilized operating and disposal practices that are standard in the industry at the time, although petroleum hydrocarbons or other wastes may have been disposed of or released on or under the properties owned, leased or operated by the Company, or on or under the other locations where these petroleum hydrocarbons and wastes have been transported for treatment or disposal. Petroleum hydrocarbons or other wastes may have been disposed or released on certain of these properties by third parties that previously operated, owned or leased these properties and whose treatment and disposal or release of petroleum hydrocarbons and other wastes were not under the Company's control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination.

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

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.

order on "Tackling the Climate Crisis at Home and Abroad." This executive order contains sweeping direction to the executive branch to address climate issues. Among other things,As discussed further below, the order put a "pause" on any new oil andconstruction of interstate natural gas leasestransportation 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 public lands or in offshore waters pending completionEnvironmental Quality published new interim guidance entitled “National Environmental Policy Act Guidance on Consideration of a review byGreenhouse Gas Emissions and Climate Change.” Generally, the Departmentinterim guidance calls for increased scrutiny of the Interior. A district court issued an injunction haltingGHG effects of proposed federal action, including requiring agencies to quantify the leasing pause, butproposed action’s GHG emissions and relevant climate impacts. The interim guidance and increased review of the Biden Administration is appealing that decision. UnderGHG impacts of federal action has the executive order,potential to significantly delay or limit, and significantly increase the Interior Department issued a reportcost of, development of midstream infrastructure. The EPA announced its Climate Enforcement and Compliance Strategy in November 2021September 2023, which directs all enforcement and compliance programs in responsethe EPA to this executive order that recommends increasingaddress climate change, wherever appropriate, in every matter within their jurisdiction. The Compliance Strategy also directs the oilEPA to prioritize enforcement and gas royalties associated with fossil fuels extracted from public landscompliance actions to mitigate climate change and offshore waters.

The EPA regulates GHG emissions from new and modified facilities that are potential major sources of criteria pollutants under the Clean Air Act's Prevention of Significant Deterioration and Title V programs and has adopted regulations that require, among other things, preconstruction and operating permits for certain large stationary sources and the monitoring and reporting of GHGs from certain onshore oil and natural gas production sources on an annual basis.

In addition,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 2015,emission reductions that are at least equivalent to those that would be achieved under the U.S., Canada,November 2021 proposed rule (which is the case for new and modified sources and will be the U.K. participatedcase 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 United Nations Conference on Climate Change, which ledFederal 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 creationEPA finalizes this interpretation of the Paris Agreement. The Paris Agreement, which was signedIRA’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 U.S.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 April 2016, requires countriesa 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 review and "represent a progression" in their intended nationally determined contributions (which set GHG emission reduction goals) every five years beginning in 2020. The United States withdrew from the Paris Agreement in 2020; however, President Biden signed an executive order on January 20, 2021, for the United States to rejoin the Paris Agreement. The United States participated in the United Nations Conference on Climate Change in Glasgow, Scotland in November 2021 and was oneamend Subpart W of the countries entering into a Global Methane Pledge. One of the key pieces of the U.S. Methane Emissions Reduction Action Plan that was announced is the EPA’s proposed methane rules forGreenhouse Gas Reporting Rule (which governs GHG emissions by the oil and gas sector. In April 2021, the United States announced its commitment to reduce its greenhouse gas emissions by 50 to 52 percent from 2005 levels by 2030.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 reduction isrule 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 achieved,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 couldif we are considered to be “doing business in California” under the CCDAA and the CRFRA. Under the CCDAA, we may be required to reduce itsquantify 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 increaserequire new climate-related disclosure in SEC filings, including certain climate-related metrics and GHG emissions. The SEC proposal, which as of the Company’s costfiling of environmental compliance.

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

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.

On May 5, 2022, the government devise new environmental justice policies. Since that time, the White House Environmental Justice Advisory Committee has released recommendations that include new spending priorities, development of environmental justice impact assessment techniques, and legal enforcement recommendations. TheU.S. Department of Justice and the EPA Office of Enforcement and Compliance Assurance have issued policy statements indicating that both agencies will seek to enhance prosecution of(DOJ) launched a comprehensive environmental justice crimesenforcement strategy designed to guide the DOJ’s work and ensure use of all available tools to seek out wayspromote environmental justice. The strategy provides a roadmap for using DOJ’s civil and criminal enforcement authorities to addressadvance environmental justice through prioritizing enforcement of environmental and civil rights violations in overburdened communities. On the legal system.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 also issued a number of statements indicating that it will attempt to addressincreased its focus on environmental justice issues more substantially throughin 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 making. Itand enforcement and is unclearin the process of assessing whether and how these new policies will be implemented, andthey may affect the Company. Equitrans Midstream will continue to monitor new developments and assess whether and how they may affect the Company.

States are also in the process of reexamining environmental justice law and policy. Pennsylvania’s then governor signed anExecutive Order 2021-07 in October 2021. The executive order in October 2021 creatingpermanently created an Office of Environmental Justice within the Pennsylvania Department of Environmental Protection. It is tasked with revising Pennsylvania’sProtection, 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 policiesareas would be subject to specified enhanced public participation requirements, and examining ways to advancethe agency would prioritize inspections and enforcement in environmental justice issues.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. Ohio andIn 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 appearDepartment 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.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. Equitrans MidstreamThe Company will continue to monitor state legal and regulatory developments in this area and respond as appropriate.

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

As of December 31, 2021,2023, the Company had 766773 employees. During 2021,2023, the Company's overall turnover was just over6% (with more than 5% (with approximately 4.5% being voluntary turnover) of the total employee population.

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’sManagement'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."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.

Historically, we have provided EQT a substantial percentage of its natural gas gathering, transmission and water services. EQT accounted for approximately 59%61% of our revenues for the year ended December 31, 2021.2023. We expect to continue to derive a substantial majority of our revenues from EQT for the foreseeable future, including as a result of the EQT Global GGA.future.

Given the scope of our business relationship with EQT, any event, whether in our areas of operations or otherwise, that adversely affects EQT'sEQT’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:

EQT may reduce its capital spending in the future based on various factors, including corporate capital allocation strategies, regional takeaway constraints, commodity prices or other factors. Unless we are successful in attracting significant new customers, our ability to maintain or increase the capacity subscribed and volumes transported or gathered under service arrangements on our gathering, transmission and storage and water systems will depend on receiving consistent or increasing commitments from EQT. While EQT has dedicated a significant amount of its acreage to us and executed long-term contracts with substantial firm reservation and MVCs on our systems, it may determine in the future that drilling in areas outside of our current areas of operations is strategically more attractive to it, and other than the firm reservations and MVCs, it is under no contractual obligation to maintain its production dedicated to us. Moreover, as disclosed on December 13, 2021, EQT’s corporate capital allocation strategy continues to focus on capital efficiency, reducing indebtedness to achieve investment grade metrics, returning capital to its shareholders and free cash flow generation as opposed to volume growth. A 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.

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 executionoptimization 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 EQT Global GGA was based upon assumptions,MVP project, including regarding EQT’s forecasted drillingconstruction-related risks and production levelsadverse weather conditions, and volumes on our system, that our management believed appropriate atsuch risks or other risks may be realized in the time of execution. If anyfuture which may further adversely affect the timing and/or cost of the assumptions failMVP project.

Additionally, construction expenditures on projects generally occur over an extended period, yet we will not receive revenues from, those assumptions,or realize any material increases in cash flow as has occurreda 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 for example, the targeted full in-service date for the MVP, our ability to fully achieve the benefits we believed associated with the EQT Global GGA at the timeconstruction of its execution, as well asmidstream assets could adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders, may be adversely affected. Further, if EQT's volumetric volumes on our systems do not meet levels we assumed atshareholders.

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 underfor our or the EQT Global GGA,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.

"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 may be adversely affected. See “EQT Global GGA” in Note 6 to the consolidated financial statements for additional information.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 reduce or hold generally steady their rig count (and thereby delay or not increase production), delay turning wells in line, temporarily shut in portions of their production or otherwise take actions to slow production growth and/or 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 effected in 2020 by EQT and certain other of our customershave previously resulted in a decrease in our volumetric-based fee revenues for portions of 2020.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 take similar actionscurtail 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.

In addition, the amount of natural gas reserves underlying wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. We do not obtain independent evaluations of natural gas reserves connected to our systems. Accordingly, we do not have independent estimates of total reserves connected to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our systems are less than we anticipate,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, significant impairment charges, and reviewsin the future could result in, impairments of our assets, including our property, plant, and equipment, intangible assets, goodwill intangible and other long-lived assets andand/or our equity method investment in the MVP Joint Venture could result in future significant impairment charges.

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. For instance, energyAdditionally, 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, and in May and July 2021, thecyberattacks. The TSA has issued a series of security directives (and subsequent amendments/revisions thereto) 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 our third-party service providersthird 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 a result, our ITartificial intelligence (“AI”) capabilities improve and OT systems (or those of third parties) that are designed to protect against cyber risksgain widespread use, we may not prevent or detect allexperience cyberattacks created using AI or incidents related to the use of AI, which may be difficult to detect and deliberatemitigate 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, but nonesystems. 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 datethe 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 develop. Newrapidly 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 our technology service providers,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 11)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:

See Note 11 to the consolidated financial statements for a discussion of the Amended EQM Credit Facility and the 2021 Eureka Credit Facility. The Amended EQM Credit Facility contains certain negative covenants, that, among other things, establish for EQM a maximum Consolidated Leverage Ratio (as defined in the Amended EQM Credit Facility) that varies over the course of the term ranging fromcould not more than 5.95exceed 5.85 to 1.00 to not more than 5.00for 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 (which in limited circumstances may be increased for certain measurement periods following the consummation of certain acquisitions).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. EQM’s and Eureka’s ability to meet these covenants can be affected by events beyond their respective control and we cannot assure our shareholders that EQM or Eureka will continue to meet these covenants.

In addition, the Amended EQM Credit Facility and the 2021 Eureka Credit Facility each contain certain events of default, including the occurrence of a change of control.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

We and our subsidiaries may in the future incur additional debt. Our and our subsidiaries’ levels of debt could have important consequences to us, including the following:

Our ability to 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.

As of February 23, 2022,20, 2024, EQM’s credit ratings were Ba3 with a negativestable outlook, BB- with a stablenegative outlook and BB with a negative outlookon 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, uncertainty around the full in-service datetiming 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, operational risks, various financial tests, ESG matters, as well as analysis of various financial metrics. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time.

If any credit rating agency further downgrades or withdraws EQM’s ratings, including for reasons relating to the MVP project (such as for delays in the targeted full in-service date ofaffecting the MVP project or increases in such project’s targeted costs), EQM’s leverage or credit ratings of our customers, our and our subsidiaries’ respective access to the capital markets could become more challenging, borrowing costs will likely increase, our operating flexibility may be adversely affected, EQM may be required to provide additional credit assurance (the amount of which may be substantial), including the Cash Option Letter of Credit (as discussed in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations"), in support of commercial agreements such as joint venture agreements, and the potential pool of investors and funding sources may decrease.

In order to be considered investment grade, EQM must be rated Baa3 or higher by Moody’s, BBB- or higher by S&P and BBB- or higher by Fitch. EQM’s non-investment grade credit ratings have resulted in greater borrowing costs, including under the Amended EQM Credit Facility, and increased collateral requirements, including under the MVP Joint Venture’s limited liability company agreement, than if EQM’s credit ratings were investment grade.

In addition to causing, among other impacts, higher borrowing costs and/or more restrictive terms associated with modifications to existing debt instruments, any further downgrade could also require additional or more restrictive covenants on future

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.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.

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.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 continuing challenges tothe challenging environment for completing expansiontransmission 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 if associated gas production were to continue to recover and return to or exceed pre-COVID-19 pandemic levels)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.”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.customers or any other party and our credit policies cannot completely eliminate credit risk. Pursuant to thecertain agreements with EQT, Global GGA and the Credit Letter Agreement, amongst other things, (a) we agreed to relieve certain credit posting requirements for EQT, in an amount up to approximately $250 million under its commercial agreements with us, subject to EQT maintaining a minimum credit rating from two of three rating agencies of (i) Ba3 with Moody’s, (ii) BB- with S&P and (iii) BB- with Fitch. As of February 23, 2022, EQT’s public debt had sub-investment gradeFitch, 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 BB+ with a positive outlook at S&P, Ba1 with a stable outlook at Moody’s, and BB+ with a stable outlook at Fitch. 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. For example, thePeriods of low commodity price environment in 2019 and 2020prices 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.

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 project)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 legislation or other actions designed to prevent, disrupt or delay the development or operation of our assets and business.

Any event that delays or interrupts (or continues to delay or interrupt) the completion of expansion 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.

Failure to achieve growth could adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

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:

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, may developincluding EQT, have developed or acquireacquired 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 insteaddepending on the location of using ours.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

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, and is growing more widely available.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 particularly if prices forrelative to natural gas significantly increase relative tobased on price and other forms of energy as fuel)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.

All of these competitive pressures could make it more difficult for us to retain our existing customers and/or attract new customers and/or additional volumes from existing customers as we seek to maintain and expand our business, which could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. In addition, competition, including from renewable and alternative energy, could intensify the negative impact of factors that decrease demand for natural gas in the markets served by our systems, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.

One of our exposures to market risk occurs at the time our existing contracts expire and are subject to renegotiation and renewal. BasedAs 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 total projected contractual revenues, including projected contractual revenues from future capacity expected from expansion projects that are not yet fully constructed for whichfavorable commercial terms, if at all. Further, we have executed firm contracts,also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our firm gathering contracts and firm transmission and storage contracts had weighted average remaining terms of approximately 14 years and 13 years, respectively, as of December 31, 2021.contract portfolio. The extension or replacementrenewal of existing contracts and entry into new contracts depends on a number of factors beyond our control, including, but not limited to,to: (i) the level of existing and new competition to provide services to our markets; the(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 uscertain of our services, see “Regulatory Environment –— FERC Regulation” under Part I, “Item 1. Business.”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 more 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 third-party 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.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, DominionEastern 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 amount of natural gas thatMVP Joint Venture's deliveries), our gathering systems can gather and transport previously has been, and inor the future wouldMVP Joint Venture's operations could be adversely affected, which hasresulting 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 and could, as applicable, reduce revenues from our gathering activities as well as transmission and storage activities.

Because we do not own these third-party pipelines or facilities, their continuing operation isand 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 continue shippingship 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

It is possible that costs to perform services under “negotiated rate” contracts could exceed the negotiated rates we have agreed to provide towith our customers. If this occurs, it could decrease the cash flow realized by our systems and, therefore, could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. Under FERC policy, a regulated service provider and a customer may mutually agree to a “negotiated rate,” and that contract must be filed with and accepted by the FERC. As of December 31, 2021,2023, 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.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 the MVP Joint Ventureour joint ventures or the joint venture relating to Eureka Midstream,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 operations of the MVP Joint Venture, Eureka Midstream and any joint ventures we may enter into in the future are subject to many of the same operational risks to which we are subject. For example, we may not be able to obtain financing at, or in respect of, a joint venture, which could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

Any completed acquisition involves potentialWe 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 things:

If risks such as the above are realized, or if an acquisitiona 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.

We currentlyIn 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.

Our operations are dependent upon key management, technical and professional personnel, and one or more of these individuals could leave our employment.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 iscontinues to be increased competition for experienced technical and other professionals, primarily in the corporate services functions, which could increase the costs associated with identifying, attracting and retaining such personnel. Additionally, a lack of employee engagement could lead to increased employee burnout, loss of productivity, increased propensity for errors, increased employee turnover, increased absenteeism, increased safety incidents and decreased customer satisfaction, which may in turn negatively impact our results of operations and financial condition. If we cannot identify, attract, develop, retain and engage key management, technical and professional personnel, along with other qualified employees, to support the various functions of our business, our ability to compete could be harmed.

For the years ended December 31, 2023, 2022 and 2021, 2020approximately 70%, 71% and 2019, approximately 64%, 66% and 58%, respectively, of our operating revenues were generated from firm reservation fees.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 executecontinue to seek to contractually minimize our exposure to commodity price risk in the future by executing long-term firm reservation fee, MVC and MVCARC contracts with new or existing customers, in the future, our efforts to obtain such contractual terms may not be successful. In addition, we may acquire or develop additional midstream assets in the future that do not provide services primarily based on capacity reservation charges, 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 than our current operations. Significantly greaterrisk. 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, as a result of our contractsand 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 18, 202216, 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 decrease may be substantial.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) income,, net, on our statements of consolidated comprehensive income andincome. 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 retaining necessary landattempting (or by virtue of the need to attempt) to acquire or to maintain use if we do not have valid rights-of-way or easements, if such rights-of-way or easements lapse or terminate or if our facilities are not properly located within the boundariesrights to land. See “Item 2. Properties” in Part I of such rights-of-way or easements.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.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.

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. WeAs 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, 2021,2023, 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. We do notNeither 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 we chargecharged to our or the MVP Joint Venture’s customers and the services we provide.provided.

AOur and the MVP Joint Venture’s significant construction projectprojects generally requiresrequire 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.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. For example, see “Developments, Market Trends and Competitive Conditions” under “Item 1. Business.” and “Item 3. Legal Proceedings.” for a discussion of certain such regulatory matters relevant to the MVP and the MVP Southgate projects.

Failure to comply with applicable provisions of the NGA, the NGPA, federal pipeline safety laws and certain other laws, as well as with the regulations, rules, orders, restrictions and conditions associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties. For example, the FERC is authorized to impose civil penalties of up to approximately $1.3$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 our natural gas gathering, transmission and storage businesses may have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

The DOT, acting through PHMSA, hasand certain state agencies certificated by PHMSA, have adopted regulations requiring pipeline operators to develop an integrity management programsprogram for transmission pipelines located where a leak or rupture could harmimpact 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 the pipelinethese operational assets have mitigated risks that could not affect the area.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 a high population area;sensitive areas; confirm maximum allowable operating pressures; maintain and improve processes for data

collection, integration and analysis; repair and remediate pipelinesfacilities as necessary; and implement preventive and mitigating actions. In addition to population sensitive areas, PHMSA has also 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.

ChangesThe 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—PipelineEnvironment — Safety and Maintenance” under “Item 1. Business.”Business” in Part I of this Annual Report on Form 10-K.

Our assets are primarily located in the Marcellus Shale fairway in southwestern Pennsylvania and northern West Virginia and the Utica Shale fairway in southeastern Ohio, and a substantial majority of the production that we receive from customers is produced from wells completed using hydraulic fracturing. Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells, particularly in unconventional resource plays like the Marcellus and Utica Shales. Hydraulic fracturing is typically regulated by state oil and gas commissions and similar agencies, but several federal agencies have asserted regulatory authority over aspects of the process, including the EPA, which finalized effluent limit guidelines allowing zero discharge of wastewater from shale gas extraction operations to publicly owned treatment plants in 2016 in addition to existing limits on direct discharges. Additionally, in response to increased public concern regarding the alleged potential impacts of hydraulic fracturing, the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels.

The U.S. Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing, while a number of states, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. Some states, such as Pennsylvania, have imposed fees on the drilling of new unconventional oil and gas wells. Some states have elected, and other states could elect, to prohibit hydraulic fracturing altogether. The Biden Administration temporarily banned new leases for oilIn addition, there are regulations existing and gas drilling onproposed at the federal lands in January 2021, butand state level that ban was subsequently blocked by a federal court.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, including the EPA. For example, in December 2016, the EPA issued its final report on a study it had conducted over several years regarding the effects of hydraulic fracturing on drinking water sources. The final report, contrary to several previously published draft reports issued by the EPA, found instances in which impacts to drinking water may occur. However, the report also noted significant data gaps that prevented the EPA from determining the extent or severity of these impacts. EPA has more recently sought input from states and stakeholders on approaches to management of wastewater produced from oil and gas extraction at onshore facilities, and published a summary of the input it received in May 2020.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, Pennsylvania’s governor has previouslyin Pennsylvania legislation was proposed legislation to impose a state severance tax on the extraction of natural resources, including natural gas produced from the Marcellus and Utica Shale formations, either in replacement of or in addition to the existing state impact fee. Pennsylvania’s legislature has not thus far advanced any of the governor’s severance tax proposals; however, severance tax legislation may continue to be proposed in future legislative sessions. Any such tax increase or change could adversely impact the earnings, cash flows and financial position of our customers and cause them to reduce their drilling in the areas in which we operate, which could negatively impact demand on our gathering, transmission and storage, and water services.

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

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, including EQT.

We are not required to declare and pay dividends to our common shareholders, and ourshareholders. 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 orstock. 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 are also may not entitled to pay any dividends on any junior securities, including any shares of our common stock, prior to paying the quarterly dividends payable to the holders of Equitrans Midstream Preferred Shares, including any previously accrued and unpaid dividends.

Our shareholders’ percentage of shares of our common stock outstanding or the issuance of other equity of us, and any resulting dilution, may cause holders to sell shares of our common stock or may create the perception that such sales may occur, either of which may adversely affect the market for, and the market value of, our common stock.

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.

Our Second Amended and Restated Articles of Incorporation and ThirdFifth 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:

These provisions, alone or together, could deter or delay hostile takeovers, proxy contests and changes in control or management of us. As a Pennsylvania corporation, we are also subject to provisions of Pennsylvania law, including certain provisions of Chapter 25 of the Pennsylvania Business Corporation Law (PBCL),PBCL, which, among other things, requires enhanced shareholder approval for certain transactions between us and a shareholder who is a party to the transaction or is treated differently from other shareholders and also prevents persons who become the beneficial owner of shares representing 20% or more of our voting power from engaging in certain business combinations without approval of our Board, and in some cases preventing consummation of the transaction for at least five years.

Any provision of our Second Amended and Restated Articles of Incorporation, or ThirdFifth 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 ThirdFifth Amended and Restated Bylaws provide that, unless our Board otherwise determines, the state and federal courts sitting in the judicial district of the Commonwealth of Pennsylvania, County of Allegheny, will be the sole and exclusive forum for any derivative action or proceeding brought on behalf of us, any action asserting a claim of breach of a fiduciary duty owed by any director or officer or other employee of ours to us or our shareholders, any action asserting a claim against us or any director or officer or other employee of us arising pursuant to any provision of the PBCL or our Second Amended and Restated Articles of Incorporation or Thirdand 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 ThirdFifth 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 agreementRegistration Rights Agreement with certain holders of the Equitrans Midstream Preferred Shares pursuant to which, among other things, we gave the Investorsinvestors certain rights to require us to file and maintain one or more registration statements with respect to the resale of the Equitrans Midstream Preferred Shares and the shares of our common stock that are issuable upon conversion of the Equitrans Midstream Preferred Shares, and which, upon request by certain Investors partyShares. In July 2023, pursuant to thethis Registration Rights Agreement, will require uswe filed a registration statement with the SEC to initiate underwritten offerings for theregister up to 30,018,446 Equitrans Midstream Preferred Shares and theup to 30,018,446 shares of our common stock that are issuable upon conversion of the Equitrans Midstream Preferred Shares and use our best efforts to cause the Equitrans Midstream Preferred Shares to be listed on the securities exchange on which the shares of our common stock are then listed. See Note 2held by such certain investors party to the consolidated financial statements for further information on the Equitrans Midstream Preferred Shares.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.

Under the tax matters agreement that EQT entered into with us, we may be required to indemnify EQT against any additional taxes and related amounts resulting from (i) an acquisition of all or a portion of our equity securities or assets, whether by merger or otherwise (and regardless of whether we participated in or otherwise facilitated the acquisition), (ii) other actions or failures to act by us or (iii) any of our representations, covenants or undertakings contained in any of the Separation-related

agreements and documents or in any documents relating to the IRS private letter ruling or the opinion of counsel being incorrect or violated. Any such indemnity obligations could be material.

If the IRS were to successfully assert that the EQM Merger or Share Purchasescertain 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 consolidated U.S. federal income tax return groupTax 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.

None.

The Company leases its corporate headquarters office in Canonsburg, Pennsylvania.

The Company's real property falls into two categories: (i) parcels that it owns in fee and (ii) parcels in which its interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the Company's operations. Certain lands on which the Company's pipelines and facilities are located are owned by the Company in fee title, and the Company believes that it has satisfactory title to these lands. The remainder of thelands 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.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.

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

In the ordinary course of business,From time to time, various legal and regulatory claims, investigations and proceedings are pending or threatened against the Company and its subsidiaries. While to the extent applicable the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims, investigations 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 bea reserve is appropriate for pending matters. Furthermore, after consultation with counsel and considering availablethe 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.

On December 29, 2022, the PHMSA issued the Company disputes these claimsa 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 ishiring 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 PADEP and CONSOL Energy Inc.PHMSA, pursuant to resolve these issues. Based on the discussion withconsent order, regarding the PADEP, the Company anticipates a notice of violation (NOV) will be issued. remaining three wells.

If additional penalties are pursued and ultimately imposed related to the Rager Mountain natural gas storage field incident, the penalties, couldindividually and/or in the aggregate, are expected to result in monetary sanctions in excess of $300,000. However,While the Company does not believe that the penalties, if imposed, wouldwill have a material adverse impact on the Company's financial condition, results of operations or liquidity.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.

The MVP Joint Venture is currently defendingThere remain certain agency actionslegal and judicial challengesregulatory matters relevant to the MVP any of which could affect the ability to complete or operate the project, including the following: