Equitrans Midstream (ETRN) Risk Analysis

Our and the MVP Joint Venture's interstate natural gas transmission and storage operations, as applicable, are regulated by the FERC under the NGA and the NGPA and the regulations, rules and policies promulgated under those and other statutes. Our and the MVP Joint Venture's FERC-regulated operations are pursuant to tariffs approved by the FERC that establish rates (other than market-based rate authority), cost recovery mechanisms and terms and conditions of service to our customers. The FERC's authority extends to a variety of matters relevant to our operations. For additional information, see "Regulatory Environment - FERC Regulation" under "Item 1. Business" in Part I of this Annual Report on Form 10-K. Pursuant to the NGA, existing interstate transmission and storage rates, terms and conditions of service, and contracts may be challenged by complaint and are subject to prospective change by the FERC. Additionally, rate increases, changes to terms and conditions of service and contracts proposed by a regulated interstate pipeline may be protested and such actions can be delayed and may ultimately be rejected by the FERC. As of the filing of this Annual Report on Form 10-K, we and the MVP Joint Venture currently hold authority from the FERC to charge and collect (i) "recourse rates," which are the maximum rates an interstate pipeline may charge for its services under its tariff, (ii) "discount rates," which are rates below the "recourse rates" and above a minimum level, (iii) "negotiated rates," which involve rates that may be above or below the "recourse rates," provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement, and (iv) market-based rates for some of our storage services from which we derive a small portion of our revenues. As of December 31, 2023, approximately 97% of our contracted firm transmission capacity was subscribed by customers under negotiated rate agreements under our tariff, rather than recourse, discount or market-based rate contracts. There can be no guarantee that we or the MVP Joint Venture will be allowed to continue to operate under such rates or rate structures for the remainder of those assets' operating lives. Customers, the FERC or other interested stakeholders, such as state regulatory agencies, may challenge our or the MVP Joint Venture's rates offered to customers or the terms and conditions of service included in our tariffs. Neither we nor the MVP Joint Venture have an agreement in place that would prohibit customers, including EQT or its affiliates, from challenging our or the MVP Joint Venture's rates or tariffs. Any successful challenge against rates charged for our or the MVP Joint Venture's transmission and storage services, as applicable, could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. Any changes to the FERC's policies regarding the natural gas industry may have an impact on us, including the FERC's approach to pro-competitive policies as it considers matters such as interstate pipeline rates and rules and policies that may affect rights of access to natural gas transmission capacity and transmission and storage facilities. The FERC and U.S. Congress may continue to evaluate changes in the NGA or new or modified FERC regulations or policies that may impact our or the MVP Joint Venture's operations and affect our or the MVP Joint Venture's ability to construct new facilities and the timing and cost of such new facilities, as well as the rates charged to our or the MVP Joint Venture's customers and the services provided. Our and the MVP Joint Venture's significant construction projects generally require review by multiple governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any agency's delay in the issuance of, or refusal to issue, authorizations or permits, issuance of such authorizations or permits with unanticipated conditions, or the loss of a previously-issued authorization or permit, for one or more of these projects may mean that we will not be able to pursue these projects or that they will be constructed in a manner or with capital requirements that we did not anticipate (as has been the case with our MVP project). Such delays, refusals, losses of permits, or resulting modifications to projects, certain of which we have experienced with respect to the MVP project and the originally contemplated MVP Southgate project, could materially and negatively impact the revenues and costs expected from these projects or cause us or our joint venture partners to abandon planned projects. Failure to comply with applicable provisions of the NGA, the NGPA, federal pipeline safety laws and certain other laws, as well as with the regulations, rules, orders, restrictions and conditions associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties. For example, the FERC is authorized to impose civil penalties of up to approximately $1.5 million (adjusted periodically for inflation) per violation, per day for violations of the NGA, the NGPA or the rules, regulations, restrictions, conditions and orders promulgated under those statutes. In addition, future federal, state or local legislation or regulations under which we or the MVP Joint Venture will operate may have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger or other business combination agreements. Even if such a lawsuit is without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on EQT's and Equitrans Midstream's respective liquidity and financial condition. Lawsuits that may be brought against EQT, Equitrans Midstream and their respective directors and/or officers could seek, among other things, injunctive relief or other equitable relief, including a request to rescind parts of the Merger Agreement even if already implemented and to otherwise enjoin the parties from consummating the EQT Transaction. One of the conditions to the closing of the EQT Transaction is that no injunction by any court or other tribunal of competent jurisdiction has been entered and continues to be in effect and no law has been adopted or is effective, in either case that prohibits or makes illegal the closing of the EQT Transaction. Consequently, if a plaintiff is successful in obtaining an injunction prohibiting completion of the EQT Transaction, that injunction may delay or prevent the EQT Transaction from being completed within the expected timeframe or at all.

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.

Combating the effects of climate change continues to attract considerable attention in the United States and internationally, including from regulators, legislators, companies in a variety of industries, financial market participants, and other stakeholders. Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing risks and governmental actions that could have an adverse impact on our operations in the United States. Numerous proposals and regulations have been made and will continue to be made to monitor and limit existing GHG emissions, as well as to restrict or eliminate future emissions. Accordingly, our business and operations, and those in our value chain, including our producer customers, are subject to executive, regulatory, political, litigation, and financial risks associated with natural gas and the emission of GHGs. At the federal level, the United States has taken steps to address climate change through legislative action, executive actions, and regulatory initiatives pursuant to existing statutes, such as the Clean Air Act. The EPA released in December 2023 its final rule, which has not yet been published in the Federal Register as of the filing of this Annual Report on Form 10-K, regulating methane emissions from the oil and gas sector under the Clean Air Act. The Inflation Reduction Act of 2022 amended the Clean Air Act to require a "methane fee" for specific facilities that exceed GHG emission and/or methane intensity thresholds beginning in 2024. These new Clean Air Act regulations, as well as any other future laws or regulations that legislators or federal agencies may adopt, could have an adverse impact on our operations and results thereof. State and regional efforts could establish requirements in states in which our assets, employees or customers are located regardless of federal action. States where our, the MVP Joint Venture's or our customers' assets are located have entered or sought to enter into the Regional Greenhouse Gas Initiative (RGGI), which is a consortium of certain Northeastern and Mid-Atlantic states that set declining limits on CO2 emissions from fossil fuel fired power plants. Initiatives such as RGGI, if enforceable in our areas of operation, may result in increased uncertainty regarding demand for natural gas used in the generation of electricity, including in our operating markets. Beyond regional and state efforts, nationally, demand for natural gas used in the generation of electricity could also be affected by federal action, such as the EPA's proposed rulemaking to regulate GHG emissions from new and existing fossil fuel fired power plants. There remains considerable uncertainty surrounding the timing, scope and potential impact of future state, national and international action with respect to GHG emissions, including methane in particular. Although we continue to monitor legislative, regulatory, and judicial developments in this area to assess potential impacts on our operations and otherwise take efforts and invest funds proactively to limit and reduce GHG emissions from our facilities, we cannot predict what form future laws, regulations, and legal requirements relating to climate change might take. Nor can we predict the stringency of any such requirements, when they might become effective, or their exact effect on us. Further, laws, regulations, and other legal requirements relating to climate change are constantly changing or being interpreted or reinterpreted, and this may occur during the permitting and construction phases of our projects, and may result in increased costs and delays. Generally, development and implementation of processes to comply with changing legal requirements are likely to be costly and time consuming. Laws, regulations and legal requirements designed to reduce GHG emissions also may: (i) make some of our activities, or those of our customers, uneconomic or less economically advantageous to maintain or operate, which may affect the estimated fair values of underlying assets and results of operations; (ii) reduce the number of attractive business opportunities available to us and discourage investments in our securities; (iii) impose additional and costly compliance obligations such as new emission control requirements, taxes, fees or other costs on the release of GHGs, cause longer permitting timelines, require that we purchase allowances for emissions, expose us to regulatory penalties or affect our reputation; and (iv) adversely affect production of or demand for natural gas (such as by increasing the cost of producing natural gas, increasing the cost of producing electricity with natural gas, or prompting consumers to use renewable fuels). If any of the foregoing events were to occur, it may have an adverse effect on our business, financial condition, results of operations, liquidity or ability to pay dividends to our shareholders. Although future laws, regulations, and legal requirements relating to climate change could have a material impact on our industry and us, attempts at quantification are based on speculation of what may occur in the future which is inherently uncertain. Litigation risks relating to climate change continue to increase. Parties have brought suit against certain large oil and natural gas exploration and production companies, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change effects, such as rising sea levels, and therefore are responsible for resultant damages. Parties have also alleged that these companies have been aware of the adverse effects of climate change for some time but misled their investors and consumers by failing to adequately disclose those impacts. While we are not currently party to any such litigation as of the filing of this Annual Report on Form 10-K, we, joint ventures in which we participate, or third parties with which we do business could be named in future actions given that our or their business involves natural gas. Further, climate change-related factors may prompt governmental investigations or adversely affect the regulatory approval process for the construction and operation of midstream assets, as, for example, opposition parties have cited, and are likely to cite in the future, our and/or the MVP Joint Venture's direct and/or indirect GHG emissions as a specific concern during comment periods for regulatory permit reviews. Market forces driven by concern for climate change are also affecting (and are expected to continue to affect) the availability and cost of capital to companies in the fossil fuel sector. For example, climate change activists continue to direct their attention towards, among other things, sources of funding for fossil fuel energy companies, which has resulted in certain financial institutions, funds, and other sources of capital restricting or adding more burdensome terms to or altogether eliminating their investments in, or lending with respect to, fossil fuel energy-related activities and companies (as we have experienced with respect to the Amended EQM Credit Facility (as defined in Note 9), and in the future could experience). Further, such institutions are increasingly allocating funds to those industries and companies perceived as having better growth opportunities and/or stronger ESG metrics and practices. These market forces may adversely affect our ability to obtain financing in the future (and thus our pursuit of initiatives, such as growth projects) or achieve increases in our stock price, and these forces may also adversely affect our customers, which could result in, among other things, increased counterparty risk and/or decreased demand for our services. Further, the concern surrounding climate change is increasing demand for lower-carbon technologies and alternate forms of energy in the marketplace, which is driving innovation and investment in products that compete with natural gas. Continued momentum to develop and drive down the cost of competitive energy alternatives may adversely affect demand for natural gas and accordingly our producer customers. In addition to such transitional risks, climate change also may create physical risks to our business. Climate impacts, such as increasing temperatures, changing weather patterns, and more frequent or intense floods and storms, can pose serious challenges for our facilities, supply chains, employees, contractors, current and potential customers, and the communities in which we operate. In particular, our operations are primarily located in the Appalachian Basin, which is a rain-susceptible region and given its geography there is inherent risk associated with landslides which could increase with climate change. Further, climate-induced rainfall events and severe storms above and beyond historical estimates, magnitudes, and frequency could exceed the pre-designed environmental controls in place on our construction projects, and/or cause pipeline slips or other damage to our physical assets, especially facilities located in low-lying areas near streams and riverbanks and pipelines situated in landslide-prone and rain-susceptible regions, which may adversely affect or temporarily interrupt our operations. We may not be able to pass on resultant financial impacts to our customers or recover all costs related to mitigating these physical risks or repairing damage due to such events. Further, our ability to mitigate the adverse impacts of these events depends in part on the resilience of our environmental controls, facilities and the effectiveness of planning for disaster preparedness and response and business continuity, which plans may not fully encompass every potential climate-driven eventuality. Additionally, changing climate patterns could impact the demand for energy in the regions we currently and plan to serve. For example, extreme warm weather in the winter months may lead to decreased natural gas usage, which may affect our results of operations and financial condition. One or more of any such developments could have an adverse effect on our business, financial condition, results of operations, liquidity or ability to pay dividends to our shareholders. For additional information on GHG laws, regulations and other legal requirements applicable to us, see "Regulatory Environment - Environmental Matters" under "Item 1. Business" in Part I of this Annual Report on Form 10-K.

The DOT, acting through PHMSA, and certain state agencies certificated by PHMSA, have adopted regulations requiring pipeline operators to develop an integrity management program for transmission pipelines located where a leak or rupture could impact high population sensitive areas (also known as High Consequence Areas or HCAs) and newly defined Moderate Consequence Areas (MCAs), and an integrity management program for storage wells, unless the operator effectively demonstrates by a prescriptive risk assessment that these operational assets have mitigated risks that could affect these predefined areas, as applicable. The regulations require operators, including us, to perform ongoing assessments of pipeline and storage integrity; identify and characterize applicable threats to pipeline segments and storage wells that could impact population sensitive areas; confirm maximum allowable operating pressures; maintain and improve processes for data collection, integration and analysis; repair and remediate facilities as necessary; and implement preventive and mitigating actions. In addition to population sensitive areas, PHMSA has recently adopted regulations extending existing design, operational and maintenance, and reporting requirements to onshore gathering pipelines in rural areas. Finally, new PHMSA regulations require operators of certain transmission pipelines to assess their integrity management and maintenance practices, comply with enhanced corrosion control and mitigation timelines, and follow new requirements for pipeline inspections following an extreme weather event or natural disaster. The cost and financial impact of compliance will vary and depend on factors such as the number and extent of maintenance determined to be necessary as a result of the application of our integrity management programs, and such costs and financial impact could have a material adverse effect on us. Further, our pipeline and storage integrity management programs depend in part on inspection tools and methodologies developed, maintained, enhanced and applied, and certain testing conducted, by certain third parties, many of which are widely utilized within the natural gas industry. Advances in these tools and methodologies could identify potential and/or additional integrity issues for our assets. Consequently, we may incur additional costs and expenses to remediate those newly identified or potential issues, and we may not have the ability to timely comply with applicable laws and regulations. Additionally, pipeline and storage safety laws and regulations are subject to change and failures to comply with pipeline and storage safety laws and regulations, including changes in such laws and regulations or interpretations thereof that result in more stringent or costly safety standards, could have a material adverse effect on us. For more information on the laws, regulations and risks applicable to us, including risks associated with compliance with the Mega Rule, see "Regulatory Environment - Safety and Maintenance" under "Item 1. Business" in Part I of this Annual Report on Form 10-K. We may, and joint ventures of which we are the operator could, as is the case with the MVP Joint Venture, become subject to consent orders and agreements relating to integrity matters. On October 3, 2023, PHMSA issued a consent order incorporating the terms of a consent agreement entered into by PHMSA and the Company as the operator of the MVP project (the MVP Consent Agreement). The MVP Consent Agreement resolves the Notice of Proposed Safety Order (NOPSO) that PHMSA issued to the Company on August 11, 2023, for the MVP project, without admission or denial of any of the allegations in the NOPSO. The MVP Consent Agreement outlines the steps being taken by the MVP Joint Venture to responsibly complete construction, including, among other things, enhancing MVP's existing coating, remediation and inspection processes, mandating or accelerating certain previously planned MVP inline inspections, accelerating the regulatory timeline for conducting cathodic protection surveys, and implementing additional measures to assess cathodic protection following MVP full in-service. The MVP Joint Venture has been conducting surveys and analyses and submitting reports to PHMSA in compliance with the requirements of the consent agreement. Failure to comply with the terms of the MVP Consent Agreement could have adverse effects on our business, including, in the case of the MVP Consent Agreement, adverse effects regarding MVP project completion.

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

Our ability to increase our customer-subscribed capacity and throughput and resulting revenue is subject to numerous factors beyond our control, including competition from producers' existing contractual obligations to competitors, the location of our assets relative to those of competitors for existing or potential producer customers (or such producer customers' own midstream assets), takeaway capacity constraints out of the Appalachian Basin, commodity prices, producers' optionality in utilizing our (relative to third-party) systems to fill downstream commitments, and the extent to which we have available capacity when and where shippers require it. To the extent that we lack available capacity on our systems for volumes, or we cannot economically increase capacity, we may not be able to compete effectively with third-party systems for additional natural gas production in our areas of operation and capacity constraints, as well as commodity prices, may, as has occurred in the past, adversely affect the degree to which natural gas production occurs in the Appalachian Basin, and relatedly the degree to which our systems are utilized. Our efforts to attract new customers or larger commitments from existing customers may be adversely affected by our desire to provide services pursuant to long-term firm contracts and contracts with MVCs. Our potential customers may prefer to obtain services under other forms of contractual arrangements which could require volumetric exposure or potentially direct commodity exposure, and we may not be willing to agree to such other forms of contractual arrangements.